EPA Administrator Lisa P. Jackson signed the following 

document on December 2, 2011, and EPA is submitting it for 

publication in the Federal Register (FR). While we have 

taken steps to ensure the accuracy of this Internet version 

of the document, it is not the official version. Please 

refer to the official version in a forthcoming FR 

publication, which will appear on the Government Printing 

Office's FDSys website 

(http://fdsys.gpo.gov/fdsys/search/home.action). {It will 

also appear on Regulations.gov (http://www.regulations.gov) 

in Docket No. EPA-HQ-OAR-2011-0512}.

6560.50 

ENVIRONMENTAL PROTECTION AGENCY 

40 CFR Part 98 

[EPA-HQ-OAR-2011-0512; FRL-XXXX-X] 

RIN 2060-AR09 

Mandatory Reporting of Greenhouse Gases: Technical 

Revisions to the Petroleum and Natural Gas Systems Category 

of the Greenhouse Gas Reporting Rule 

AGENCY: Environmental Protection Agency (EPA). 

ACTION: Final Rule. 

SUMMARY: EPA is finalizing technical corrections and 

revisions to the petroleum and natural gas systems source 

category of the Greenhouse Gas Reporting Rule. Final 

changes include providing clarification on existing 

requirements, increasing flexibility for certain 

calculation methods, amending data reporting requirements, 
2 of 212 

This document is a prepublication version, signed by EPA Administrator Lisa P. Jackson on 

December 2, 2011. We have taken steps to ensure the accuracy of this version, but it is not the 

official version.

clarifying terms and definitions, and technical 

corrections. 

DATES: This rule is effective on December 28, 2011. 

ADDRESSES: EPA has established a docket for this action 

under Docket ID No. EPA-HQ-OAR-2011-0512. All documents in 

the docket are listed in the http://www.regulations.gov

index. 

Although listed in the index, some information may not 

be publicly available, e.g., confidential business 

information (CBI) or other information whose disclosure is 

restricted by statute. Certain other material, such as 

copyrighted material, is not placed on the Internet and is 

publicly available in hard copy only. Publicly available 

docket materials are available either electronically 

through http://www.regulations.gov or in hard copy at the 

EPA's Docket Center, EPA/DC, EPA West Building, Room 3334, 

1301 Constitution Ave., NW, Washington, DC. This Docket 

Facility is open from 8:30 a.m. to 4:30 p.m., Monday 

through Friday, excluding legal holidays. The telephone 

number for the Public Reading Room is (202) 566-1744, and 

the telephone number for the Air Docket is (202) 566-1742. 

FOR FURTHER INFORMATION CONTACT: Carole Cook, Climate 

Change Division, Office of Atmospheric Programs (MC-6207J), 

Environmental Protection Agency, 1200 Pennsylvania Ave., 
3 of 212 

This document is a prepublication version, signed by EPA Administrator Lisa P. Jackson on 

December 2, 2011. We have taken steps to ensure the accuracy of this version, but it is not the 

official version.

NW., Washington, DC 20460; telephone number: (202) 343-

9263; fax number: (202) 343-2342; e-mail address: 

GHGReportingRule@epa.gov. For technical information and 

implementation materials, please go to the website 

http://www.epa.gov/climatechange/emissions/subpart/w.html. 

To submit a question, select Rule Help Center, followed by 

“Contact Us.” 

Worldwide Web (WWW). In addition to being available 

in Docket ID No. EPA-HQ-OAR-2011-0512, following the 

Administrator's signature, an electronic copy of this final 

rule will also be available through the WWW on EPA's 

Greenhouse Gas Reporting Program website at 

http://www.epa.gov/climatechange/emissions/ghgrulemaking.ht

ml. 

SUPPLEMENTARY INFORMATION 

Regulated Entities. The Administrator determined that 

this action is subject to the provisions of Clean Air Act 

(CAA) section 307(d). These amended regulations could 

affect owners or operators of petroleum and natural gas 

systems. Regulated entities may include those listed in 

Table 1 of this preamble: 

Table 1. Examples of Affected Entities by Category 

Source 

Category NAICS Examples of affected facilities
4 of 212 

This document is a prepublication version, signed by EPA Administrator Lisa P. Jackson on 

December 2, 2011. We have taken steps to ensure the accuracy of this version, but it is not the 

official version.

Source 

Category NAICS Examples of affected facilities

Petroleum and 

Natural Gas 

Systems 

486210 Pipeline transportation of 

natural gas.

221210 Natural gas distribution 

facilities.

211 Extractors of crude petroleum 

and natural gas.

211112 Natural gas liquid extraction 

facilities.

Table 1 of this preamble is not intended to be 

exhaustive, but rather provides a guide for readers 

regarding facilities likely to be affected by this action. 

Other types of facilities not listed in the table could 

also be affected. To determine whether you are affected by 

this action, you should carefully examine the applicability 

criteria found in 40 CFR Part 98 subpart A, and 40 CFR Part 

98 subpart W. If you have questions regarding the 

applicability of this action to a particular facility, 

consult the person listed in the preceding FOR FURTHER 

INFORMATION CONTACT section. 

What is the effective date? This final rule is 

effective on December 28, 2011. Section 553(d) of the 

Administrative Procedure Act (APA), 5 U.S.C. Chapter 5, 

generally provides that rules may not take effect earlier 

than 30 days after they are published in the Federal 

Register. EPA is issuing this final rule under section CAA 

307(d)(1), which states: “The provisions of section 553 
5 of 212 

This document is a prepublication version, signed by EPA Administrator Lisa P. Jackson on 

December 2, 2011. We have taken steps to ensure the accuracy of this version, but it is not the 

official version.

through 557. . . of Title 5 shall not, except as expressly 

provided in this section, apply to actions to which this 

subsection applies.” Thus, section 553(d) of the APA does 

not apply to this rule. EPA is nevertheless acting 

consistently with the purposes underlying APA section 

553(d) in making this rule effective on December 28, 2011. 

Section 5 U.S.C. 553(d)(3) allows an effective date less 

than 30 days after publication “as otherwise provided by 

the agency for good cause found and published with the 

rule.” As explained below, EPA finds that there is good 

cause for parts of this rule to become effective on 

December 28, 2011 even though this will result in an 

effective date fewer than 30 days from the date of 

publication in the Federal Register. 

The purpose of the 30-day waiting period prescribed in 

5 U.S.C. 553(d) is to give affected parties a reasonable 

time to adjust their behavior and prepare before the final 

rule takes effect. That purpose, to provide affected 

parties a reasonable time to prepare for the rule before it 

comes into effect, is not necessary in this case, as most 

of the affected provisions in the final rule clarify 

existing provisions, provide flexibilities to sources 

covered by the reporting rule, or otherwise relieve a 

restriction. For example, this final rule clarifies the 
6 of 212 

This document is a prepublication version, signed by EPA Administrator Lisa P. Jackson on 

December 2, 2011. We have taken steps to ensure the accuracy of this version, but it is not the 

official version.

definition of some of the industry segments, and in some 

cases, provides further flexibility relating to reporting 

obligations that would otherwise have been required by the 

November 2010 Subpart W (the 2010 final rule) 75 FR 74458. 

Therefore, EPA finds good cause exists to make this rule 

effective on December 28, 2011. 

Judicial Review. Under CAA section 307(b)(1), 

judicial review of this final rule is available only by 

filing a petition for review in the U.S. Court of Appeals 

for the District of Columbia Circuit (the Court) by [INSERT 

THE DATE 60 DAYS AFTER THE DATE OF PUBLICATION OF THE FINAL 

RULE IN THE FEDERAL REGISTER]. Under CAA section 

307(d)(7)(B), only an objection to this final rule that was 

raised with reasonable specificity during the period for 

public comment can be raised during judicial review. 

Section 307(d)(7)(B) of the CAA also provides a mechanism 

for EPA to convene a proceeding for reconsideration, “[i]f 

the person raising an objection can demonstrate to EPA that 

it was impracticable to raise such objection within [the 

period for public comment] or if the grounds for such 

objection arose after the period for public comment (but 

within the time specified for judicial review) and if such 

objection is of central relevance to the outcome of the 

rule.” Any person seeking to make such a demonstration to 
7 of 212 

This document is a prepublication version, signed by EPA Administrator Lisa P. Jackson on 

December 2, 2011. We have taken steps to ensure the accuracy of this version, but it is not the 

official version.

us should submit a Petition for Reconsideration to the 

Office of the Administrator, Environmental Protection 

Agency, Room 3000, Ariel Rios Building, 1200 Pennsylvania 

Ave., NW., Washington, DC 20460, with a copy to the person 

listed in the preceding FOR FURTHER INFORMATION CONTACT

section, and the Associate General Counsel for the Air and 

Radiation Law Office, Office of General Counsel (Mail Code 

2344A), Environmental Protection Agency, 1200 Pennsylvania 

Ave., NW., Washington, DC 20004. Note, under CAA section 

307(b)(2), the requirements established by this final rule 

may not be challenged separately in any civil or criminal 

proceedings brought by EPA to enforce these requirements. 

Acronyms and Abbreviations. The following acronyms 

and abbreviations are used in this document. 

AGA American Gas Association 

AGR Acid Gas Removal 

API American Petroleum Institute 

AXPC American Exploration and Production Council 

BAMM Best Available Monitoring Methods 

BOEMRE Bureau of Ocean Energy Management, Regulation and 

Enforcement 

CAA Clean Air Act 

CBI confidential business information 

CEC Chesapeake Energy Corporation 

CEMS continuous emission monitoring systems 

cfd cubic feet per day 

CFR Code of Federal Regulations 

CH4 methane 
8 of 212 

This document is a prepublication version, signed by EPA Administrator Lisa P. Jackson on 

December 2, 2011. We have taken steps to ensure the accuracy of this version, but it is not the 

official version.

CO2 carbon dioxide 

CO2e CO2-equivalent 

COR certificate of representation 

e-GGRT electronic greenhouse gas reporting tool 

EIA Economic Impact Analysis 

EOR enhanced oil recovery 

EPA U.S. Environmental Protection Agency 

FCML Field Code Master List 

FERC Federal Energy Regulatory Commission 

FR Federal Register 

GHG greenhouse gas 

GPA Gas Processors Association 

GOR gas to oil ratio 

GRI Gas Research Institute 

Hp horsepower 

GWP global warming potential 

HHV high heat value 

IBR incorporation by reference 

ICR information collection request 

LDC Local Distribution Company 

ISO International Organization for Standardization 

kg kilograms 

LDCs local natural gas distribution companies 

LNG liquefied natural gas 

M&R meters and regulators 

mmBtu million British thermal units 

mmHg millimeters of Mercury 

MMscfd million standard cubic feet per day 

mTCO2e million metric tons carbon dioxide equivalent 

MRR mandatory GHG reporting rule 

N2O nitrous oxide 

NAICS North American Industry Classification System 

NGLs natural gas liquids 

NPS nominal pipe size 

NTTAA National Technology Transfer and Advancement Act 
9 of 212 

This document is a prepublication version, signed by EPA Administrator Lisa P. Jackson on 

December 2, 2011. We have taken steps to ensure the accuracy of this version, but it is not the 

official version.

OAQPS Office of Air Quality, Planning and Standards 

OMB Office of Management and Budget 

PHMSA Pipeline and Hazardous Material Safety 

Administration 

QA/QC quality assurance/quality control 

RFA Regulatory Flexibility Act 

SBA Small Business Administration 

SBREFA Small Business Regulatory Enforcement and 

Fairness Act 

T-D Transmission Distribution 

TSD technical support document 

U.S. United States 

UMRA Unfunded Mandates Reform Act of 1995 

USC United States Code 

TABLE OF CONTENTS 

I. Background 

A. Organization of this Preamble 

B. Background 

C. Legal Authority 

D. How Confidential Business Information Determinations 

and the Deferral of Inputs to Emission Equations are 

Affected by This Action 

E. How Do These Amendments Apply to 2012 Reports? 

II. Overview of Final Amendments to the General 

Provisions, and Petroleum and Natural Gas Systems Source 

Category and Responses to Major Public Comments 

A. Amendments to the General Provisions 

B. Responses to Major Comments Submitted on the General 

Provisions 

C. Final Amendments to the Petroleum and Natural Gas 

Systems Source Category 

D. Responses to Major Comments Submitted on the Petroleum 

and Natural Gas Systems Source Category 

III. Statutory and Executive Order Reviews 

A. Executive Order 12866: Regulatory Planning and Review 

and Executive Order 13563: Improving Regulation and 

Regulatory Review 
10 of 212 

This document is a prepublication version, signed by EPA Administrator Lisa P. Jackson on 

December 2, 2011. We have taken steps to ensure the accuracy of this version, but it is not the 

official version.

B. Paperwork Reduction Act 

C. Regulatory Flexibility Act (RFA) 

D. Unfunded Mandates Reform Act (UMRA) 

E. Executive Order 13132: Federalism 

F. Executive Order 13175: Consultation and Coordination 

with Indian Tribal Governments 

G. Executive Order 13045: Protection of Children from 

Environmental Health Risks and Safety Risks 

H. Executive Order 13211: Actions that Significantly 

Affect Energy Supply, Distribution, or Use 

I. National Technology Transfer and Advancement Act 

J. Executive Order 12898: Federal Actions to Address 

Environmental Justice in Minority Populations and LowIncome Populations 

K. Congressional Review Act 

I. Background 

A. Organization of This Preamble 

This preamble consists of three sections. The first 

section provides a brief history of 40 CFR part 98 and 40 

CFR part 98, subpart W (“subpart W”). 

The second section of this preamble summarizes the 

revisions made to specific requirements for subparts A and 

W being incorporated by this action. The amendments 

finalized in this action reflect the changes to subpart W 

proposed in two separate proposed rules (76 FR 56010, 76 FR 

47392). This section also describes the major changes made 

to this source category since proposal and provides a brief 

summary of significant public comments and EPA’s responses. 

Additional responses to significant comments can be located 

in the document, “Mandatory Reporting of Greenhouse Gases – 
11 of 212 

This document is a prepublication version, signed by EPA Administrator Lisa P. Jackson on 

December 2, 2011. We have taken steps to ensure the accuracy of this version, but it is not the 

official version.

Technical Revisions to the Petroleum and Natural Gas 

Systems Category of the Greenhouse Gas Reporting Rule: 

EPA’s Response to Public Comments” see EPA-HQ-OAR-2011-

0512. 

Finally, the last section discusses the various 

statutory and executive order requirements applicable to 

this rulemaking. 

B. Background 

This action finalizes amendments to provisions in 40 

CFR part 98, subpart A. The 2009 final GHG reporting rule 

was signed by the EPA Administrator Lisa Jackson on 

September 22, 2009 and published in the Federal Register on 

October 30, 2009 (74 FR 56260, October 30, 2009 hereinafter 

“GHGRP”). The 2009 final rule, which became effective on 

December 29, 2009, includes reporting of GHGs from various 

facilities and suppliers consistent with the 2008 

Consolidated Appropriation Act (Consolidated Appropriations 

Act, 2008, Public Law 110-161, 121 Stat. 1844, 2128). 

Subsequent notices were published in 2010 finalizing the 

requirements for subpart W (74 FR 74458). 

 In an earlier action, EPA proposed minor technical 

corrections to specific provisions in various subparts of 

the greenhouse gas reporting rule, including subpart W on 

August 4, 2011 (76 FR 47392), hereinafter “GHGRP 
12 of 212 

This document is a prepublication version, signed by EPA Administrator Lisa P. Jackson on 

December 2, 2011. We have taken steps to ensure the accuracy of this version, but it is not the 

official version.

Corrections Proposal”). In that action, EPA proposed 

several corrections to specific provisions in subpart W to 

address minor errors in equations and to correct certain 

erroneous citations. 

In this action, EPA is finalizing amendments to 

provisions in subpart W that were proposed in both the 

September 9, 2011 GHGRP Revisions Proposal action and the 

August 4, 2011 GHGRP Corrections Proposal action. Responses 

to comments submitted on both actions can be found in 

section II.C of this preamble and also under the document 

“Mandatory Reporting of Greenhouse Gases – Technical 

Revisions to the Petroleum and Natural Gas Systems Category 

of the Greenhouse Gas Reporting Rule: EPA’s Response to 

Public Comments” See EPA-HQ-OAR-2011-0512. 

C. Legal Authority

The EPA is promulgating these rule amendments under 

its existing CAA authority, specifically authorities 

provided in CAA section 114. 

As stated in the preamble to the 2009 final rule (74 

FR 56260, October 30, 2009), CAA section 114 provides EPA 

broad authority to require the information mandated by 40 

CFR part 98 because such data would inform and are relevant 

to the EPA’s obligation to carry out a wide variety of CAA 

provisions. As discussed in the preamble to the initial 
13 of 212 

This document is a prepublication version, signed by EPA Administrator Lisa P. Jackson on 

December 2, 2011. We have taken steps to ensure the accuracy of this version, but it is not the 

official version.

proposal (74 FR 16448, April 10, 2009), CAA section 

114(a)(1) authorizes the Administrator to require emissions 

sources, persons subject to the CAA, manufacturers of 

process or control equipment, and persons whom the 

Administrator believes may have necessary information to 

monitor and report emissions and provide such other 

information the Administrator requests for the purposes of 

carrying out any provision of the CAA. For further 

information about the EPA’s legal authority, see the 

preambles to the proposed and final rule, and related 

Response to Comments documents. 

D. How Confidential Business Information Determinations 

and the Deferral of Inputs to Emission Equations are 

Affected by This Action

The EPA finalized several rulemakings during 2011 in 

response to concerns related to the reporting and 

publication of information that may be considered 

confidential business information (CBI). For more 

information on the final action to defer the reporting 

deadline for data elements that are used by direct emitter 

reporters as inputs to emissions equations under EPA’s 

Greenhouse Gas Reporting Program, please see the Final CBI 

Deferral Rule (75 FR 53057, August 25, 2011, hereinafter 

referred to the “Final CBI Deferral Rule”). For more 
14 of 212 

This document is a prepublication version, signed by EPA Administrator Lisa P. Jackson on 

December 2, 2011. We have taken steps to ensure the accuracy of this version, but it is not the 

official version.

information generally on the various actions related to 

treatment of data that may be considered CBI, please see 

the GHG Reporting Program website dedicated to CBI at 

http://www.epa.gov/climatechange/emissions/CBI.html. 

On May 26, 2011, the EPA published confidentiality 

determinations for certain data elements required to be 

reported under 40 CFR part 98 and finalized amendments to 

the Special Rules Governing Certain Information Obtained 

Under the Clean Air Act, which authorizes the EPA to 

release or withhold as confidential reported data according 

to the confidentiality determinations for such data without 

taking further procedural steps (76 FR 30782, 2011 

hereinafter referred to as the “Final CBI Rule”). The 

Final CBI Rule addressed reporting of data elements in 34 

subparts which were determined not to be inputs to emission 

equations and therefore are always CBI and which are not 

eligible to be CBI. That rule did not make confidentiality 

determinations for eight subparts, including subpart W, for 

which reporting requirements were finalized after 

publication of the July 7, 2010 CBI proposal (75 FR 39094) 

and December 27, 2010 supplemental CBI proposal (75 FR 

43889). 

On August 25, 2011, the EPA published a final rule 

that deferred the reporting deadline for data elements that 
15 of 212 

This document is a prepublication version, signed by EPA Administrator Lisa P. Jackson on 

December 2, 2011. We have taken steps to ensure the accuracy of this version, but it is not the 

official version.

are used by direct emitter reporters as inputs to emission 

equations under the Mandatory Greenhouse Gas Reporting Rule 

(76 FR 53057, Final CBI Deferral Rule). The Final CBI 

Deferral Rule, included deferral of the deadline for 

reporting inputs to emissions equations based on the 2010 

final rule for 40 CFR part 98, subpart W (75 FR 74458). 

EPA intends to propose and finalize CBI determinations 

for 40 CFR part 98, subpart W in a separate action (or 

actions). This final rule does not affect the deferral of 

reporting nor the date until which the deadline is set for 

reporting those inputs to emissions equations for subpart 

W, which were finalized in the Final CBI Deferral Rule. 

For subpart W, EPA intends to finalize a deferral of any 

new or revised inputs affected by this final action prior 

to the 2012 reporting deadline. 

E. How Do These Amendments Apply to 2012 Reports?

We have determined that it is feasible for owners and 

operators covered by this rule to implement these technical 

amendments for the 2011 reporting year because the 

revisions primarily provide additional clarification 

regarding applicability, and the existing regulatory 

requirements generally do not change the type of 

information that must be collected, and do not materially 

affect how GHG emissions or quantities are calculated. Our 
16 of 212 

This document is a prepublication version, signed by EPA Administrator Lisa P. Jackson on 

December 2, 2011. We have taken steps to ensure the accuracy of this version, but it is not the 

official version.

rationale for this determination is explained in the 

preamble to the proposed rule amendments.

1

In response to comments submitted on the proposed 

rulemaking, we have reviewed the final amendments and 

determined that they can be implemented, as finalized, for 

the 2011 reporting year. Although in limited cases these 

amendments may introduce revisions to calculation 

procedures from those proposed (e.g., for taking 

measurements at the sub-basin level as opposed to the field 

level), in response to comment, EPA has introduced 

flexibilities in the final rule in order to ensure that 

there are no new monitoring requirements for 2011. 

 

As an example of the flexibility introduced in this 

final rule, in the GHGRP Revisions Proposal, EPA proposed 

an alternative approach to taking measurement at the field 

level, as suggested by industry, by proposing to take 

measurement at a sub-basin level. Industry requested that 

EPA reconsider the use of a field-level measurement plan 

for specific emissions sources including well venting for 

liquids unloading and well venting for well 

completions/workovers, by stating that it was not clear how 

to assign a field name to new wells, nor how to address 

wells that were not contained in the 2008 EIA Field Code 

 

1 76 FR 56010 (September 9, 2011).
17 of 212 

This document is a prepublication version, signed by EPA Administrator Lisa P. Jackson on 

December 2, 2011. We have taken steps to ensure the accuracy of this version, but it is not the 

official version.

Master List which was incorporated by reference in the 

Subpart W Final Rule. The foundation of the sub-basin 

approach is defining a sub-basin category through the use 

of a county level designation and the distinction of the 

type of hydrocarbon formation. The hydrocarbon formations 

can be grouped into five types: oil, high permeability gas, 

shale gas, coal seam, or other tight reservoir rock. For 

example, wells producing coal bed methane from formation 

“X” with wellhead coordinates within county “A” would be 

one sub-basin category. Further, wells producing from tight 

formation “Y” with wellhead coordinates within county “A” 

would be a second sub-basin category. In the event that a 

specific county includes more than one formation (e.g.,. 

coal bed methane and tight sands), then the reporter would 

use the most specific designation (e.g., coal bed methane). 

EPA analyzed the approach suggested by the industry and 

believes that the sub-basin category provides similar 

quality data as the EIA field code would provide, while 

still achieving the appropriate level of data 

representativeness. Please see Economic Impact Analysis 

Memorandum in Docket ID EPA-HQ-OAR-2011-0512. 

Therefore, as industry suggested, EPA proposed the 

alternative approach of using a sub-basin measurement level 

for measurement of specific emission sources in the onshore 
18 of 212 

This document is a prepublication version, signed by EPA Administrator Lisa P. Jackson on 

December 2, 2011. We have taken steps to ensure the accuracy of this version, but it is not the 

official version.

production industry segment, and is finalizing that 

approach in this action. For example, commenters were 

generally supportive of EPA’s proposed change to require 

calculation and reporting for onshore production at the 

sub-basin level, as opposed to the field level. However, 

one commenter requested to continue to use field as a 

classification mechanism for groups of wells within each 

basin. The commenter stated that they had already 

conducted field-level calculations for 2011. In response 

to this concern, and for the 2011 reporting year only, EPA 

is allowing reporters who took measurement at the field 

level to apply those measurements to the equivalent subbasins applicable to their facility as a best available 

monitoring method (BAMM). The use of a field-level 

measurement as a BAMM for a sub-basin measurement fits 

within a recently finalized action (76 FR 59533), where EPA 

granted subpart W reporters the option to use BAMM for all 

of 2011 without reporters being required to submit a 

request for approval from the Administrator. For data 

collection in 2012 and beyond, reporters must use the subbasin level for data collection. 

By way of further example, the 2010 final rule 

required facilities to assume that pneumatic pumps and 

pneumatic devices were operational the entire year. We 
19 of 212 

This document is a prepublication version, signed by EPA Administrator Lisa P. Jackson on 

December 2, 2011. We have taken steps to ensure the accuracy of this version, but it is not the 

official version.

proposed that instead of assuming operation for 8,760 hours 

per year, facilities would use their actual operating 

hours. While many reporters agreed with the proposed 

amendment, they encouraged EPA to retain the option of 

assuming 100 percent operation during the reporting year, 

so as not to require facilities to track operating hours. 

In this action, reporters now have the option to use actual 

operating hours or the default of 8,760 hours per year for 

both pneumatic devices and pneumatic pumps when calculating 

GHG emissions using equation W-1 and W-2 in 40 CFR 

98.233(a) and (b) respectively. Thus in any given data 

collection year, reporters now have the option of using the 

default or entering their estimated amount of hours for 

operation of their pneumatic devices and pumps. This 

option will not be limited to the 2011 data collection 

year. 

Lastly, the 2010 final rule requires reporters to take 

measurement once in a two year cycle, beginning with the 

first year of data collection, for emission sources 

including the gas well venting from completions or 

workovers with hydraulic fracturing emission source type. 

In this action, EPA is revising several provisions related 

to these emission sources and because the revisions are 

expected to be published late in the 2011 data collection 
20 of 212 

This document is a prepublication version, signed by EPA Administrator Lisa P. Jackson on 

December 2, 2011. We have taken steps to ensure the accuracy of this version, but it is not the 

official version.

year, EPA is allowing reporters additional flexibility by 

giving the option to take their first measurement in the 

second year as opposed to the first year, as is stated in 

the rule, 40 CFR 98.234(g). Reporters who chose this option 

must take their measurement before the September 28, 2011 

reporting deadline for subpart W. 

 

II. Overview of Final Amendments to the General 

Provisions, and Petroleum and Natural Gas Systems Source 

Category and Responses to Major Public Comments 

A. Amendments to the General Provisions 

 Purpose and Scope. In this action, EPA is amending 40 

CFR 98.1 of the general provisions by adding paragraph (c) 

which states that for the purposes of applying the terms 

owner and operator used in subpart A, facilities required 

to report under the onshore petroleum and natural gas 

production industry segment of 40 CFR part 98, subpart W 

will use the definition of onshore petroleum and natural 

gas production owner or operator in 40 CFR 98.238. 

 Definitions. EPA is finalizing amendments to 

definitions in 40 CFR 98.6. First, we are amending the 

text for the definition for continuous bleed pneumatic 

devices, in 40 CFR 98.6 to clarify that continuous bleed 

devices supply natural gas to process control devices, and 
21 of 212 

This document is a prepublication version, signed by EPA Administrator Lisa P. Jackson on 

December 2, 2011. We have taken steps to ensure the accuracy of this version, but it is not the 

official version.

not measurement devices, as suggested by the 2010 final 

rule. 

Secondly, we are amending the definition of 

intermittent bleed pneumatic devices, as proposed, to 

clarify that these devices automatically maintain the 

process conditions and that the devices are snap-acting or 

throttling devices that discharge all or a portion of the 

full volume of the actuator intermittently when control 

action is necessary. 

There were no other major changes to 40 CFR subpart A 

since the proposal. 

B. Responses to Major Comments Submitted on the General 

Provisions 

1. Further delineation of types of intermittent bleed 

pneumatic devices. 

Comment: Commenters were generally supportive of EPA’s 

proposal to clarify the definitions for pneumatic devices 

in the September 9, 2011 GHGRP Revisions Proposal. One 

commenter, however, specifically noted that further 

clarification to the definition for intermittent devices 

was necessary beyond the proposal and requested that EPA 

list out examples of intermittent bleed devices. 

Response: EPA believes that the definition for 

intermittent bleed pneumatic devices finalized in this 
22 of 212 

This document is a prepublication version, signed by EPA Administrator Lisa P. Jackson on 

December 2, 2011. We have taken steps to ensure the accuracy of this version, but it is not the 

official version.

action is sufficient for reporters to use as a guideline in 

determining what would constitute an intermittent bleed 

pneumatic device. The definition for intermittent pneumatic 

devices finalized in this action clarifies that these types 

of pneumatic devices automatically maintain the process 

conditions and discharge all or a portion of the full 

volume of the actuator intermittently. 

C. Final Amendments to the Petroleum and Natural Gas 

Systems Source Category

In this action, EPA is amending several provisions to 

the Final Subpart W Rule published in November 2010. The 

major amendments are listed in this section, followed by a 

more detailed summary of the final amendments to the 

various provisions. Where appropriate, it is indicated 

that an amendment was finalized as proposed, or an 

amendment as finalized that differed from the GHGRP 

Corrections proposal or the GHGRP Revisions proposal. 

Other changes and clarifications included in this section 

are administrative in nature. For a full description of 

the rationale for these and any other significant change to 

40 CFR part 98, subpart W, see the “Mandatory Reporting of 

Greenhouse Gases – Technical Revisions to the Petroleum and 

Natural Gas Systems Category of the Greenhouse Gas 

Reporting Rule: EPA’s Response to Public Comments” and 
23 of 212 

This document is a prepublication version, signed by EPA Administrator Lisa P. Jackson on 

December 2, 2011. We have taken steps to ensure the accuracy of this version, but it is not the 

official version.

section II.D Responses to Major Comments Submitted on the 

Petroleum and Natural gas Systems Source Category. 

Major Changes Since Proposal 

1. Calculating GHG Emissions

• Inclusion of clarification for emergency blowdown vent 

stack emission sources that are covered under 40 CFR 

98.233(i). 

• Revising calculation methodologies for natural gas 

distribution industry segment in 40 CFR 98.233(q) and 

40 CFR 98.233(r) to allow for reporters to use a 5 – 

year rolling survey plan. 

• Revising the emission factor for intermittent 

pneumatic devices. 

2. Data Reporting Requirements

• Not adopting the proposed amendments to include 

reporting of a unique name or ID for specified 

emissions sources under the onshore petroleum and 

natural gas production industry segment throughout 40 

CFR 98.236. 

• Replacing the term “a unique name or ID number for the 

blowdown vent stack” in 40 CFR 98.236(c)(7)(iii) to “a 

unique name or ID number for the unique volume type.” 

• Inclusion of data reporting requirements for natural 

gas distribution industry segment to reflect the 5 – 

year rolling survey plan. 

3. Definitions

• Revising definition for associated with a well-pad in 

40 CFR 98.238 by revising the last sentence. 

• Inclusion of a definition for a 5th sub-basin category 

for oil in the 40 CFR 98.238 sub-basin definitions. 

4. Emission Factor Tables

• Revising emission factors in tables W-1A, W-2, W-3, W4, W-5, W-6, and W-7 to adjust for 60o standard 

temperature and 14.7 psia pressure. 

The final amendments are organized following the 

different sections of the subpart W regulatory text 
24 of 212 

This document is a prepublication version, signed by EPA Administrator Lisa P. Jackson on 

December 2, 2011. We have taken steps to ensure the accuracy of this version, but it is not the 

official version.

beginning with 40 CFR 98.230 and going through 98.238. As 

described above in Section II.E., one of the major changes 

is for the onshore petroleum and natural gas production 

industry segment, where the reporting level has been 

changed from the field level to the sub-basin level. 

Source Category Definitions. In general, we are 

finalizing amendments to the source category definitions as 

proposed to clarify both the coverage of individual 

industry segments and the boundaries for different industry 

segments. The purpose of these amendments is primarily to 

clarify the coverage of the rule and ensure applicability 

under 40 CFR part 98 is as originally intended. 

Onshore Petroleum and Natural Gas Production. We are 

making several amendments to the definition for the onshore 

petroleum and natural gas production (also referred to as 

onshore production) industry segment in 40 CFR 

98.230(a)(2). First, EPA is revising the term “associated 

with a well-pad” to state that the onshore production 

industry segment includes equipment that is “on a single 

well-pad or associated with a single well-pad.” These 

equipment are included in the onshore production industry 

segment irrespective of the point of emissions from that 

equipment (e.g., if emissions from one or more pieces of 

onshore oil and gas production equipment are sent to a 
25 of 212 

This document is a prepublication version, signed by EPA Administrator Lisa P. Jackson on 

December 2, 2011. We have taken steps to ensure the accuracy of this version, but it is not the 

official version.

common header either to a flare or vent, that vent or flare 

would also be included). Next, EPA is amending the 

definition to clarify that both dehydrators and storage 

vessels that are on a single well-pad or associated with a 

single well-pad are included as types of equipment that are 

considered part of the onshore production industry segment 

if they are owned or operated by the onshore production 

owner or operator, including equipment that is leased, 

contracted or rented. 

 Finally, we are revising the text to state that 

enhanced oil recovery (EOR) operations that use either CO2

or natural gas are a part of this industry segment. 

Onshore Natural Gas Processing. EPA is including 

several clarifications to the onshore natural gas 

processing industry segment definition in 40 CFR 

98.230(a)(3). First, we are striking the term “and 

recovers” from the first sentence, in order to more clearly 

characterize the unique activities performed at natural gas 

processing plants. Second, we are revising the text to 

clarify that this industry segment includes one or a 

combination of the following three processes: separation of 

natural gas liquids (NGLs) from produced natural gas, 

separation of non-methane gases from produced natural gas, 

or separation of NGLs into one or more component mixtures. 
26 of 212 

This document is a prepublication version, signed by EPA Administrator Lisa P. Jackson on 

December 2, 2011. We have taken steps to ensure the accuracy of this version, but it is not the 

official version.

Third, we are amending the definition to clarify that 

separation means one or more of the following processes: 

forced extraction of natural gas liquids, sulfur and carbon 

dioxide removal, fractionation of NGLs, or the capture of 

CO2 separated from natural gas streams. Fourth, we are 

striking the phrase “this industry segment does not include 

reporting of emissions from gathering lines and boosting 

stations” because the final amendments already clarify the 

definition of “onshore natural gas processing” and 

therefore, it is unnecessary to discuss that which is 

excluded. Fifth, we are revising the threshold contained 

in the definition of the onshore natural gas processing 

segment to be 25 million standard cubic feet annual average 

daily throughput. Finally, we are replacing out the term 

“facility” with the term “plant”. 

Onshore Natural Gas Transmission Compression. EPA is 

finalizing several clarifications to the onshore natural 

gas transmission compression industry segment definition in 

40 CFR 98.230(a)(4). First, we are removing the term “at 

elevated pressure” to address confusion associated with 

what “elevated pressure” actually meant. Next, we are 

including a definition in 40 CFR 98.238 of transmission 

pipeline to address concerns that this term was undefined 

and could have a broader meaning than that which was 
27 of 212 

This document is a prepublication version, signed by EPA Administrator Lisa P. Jackson on 

December 2, 2011. We have taken steps to ensure the accuracy of this version, but it is not the 

official version.

intended in the 2010 final rule. We are defining a 

transmission pipeline to mean a Federal Energy Regulatory 

Commission (FERC) rate-regulated interstate pipeline, a 

state rate-regulated intrastate pipeline, or a pipeline 

that falls under the “Hinshaw Exemption” as referenced in 

Section 1(c) of the Natural Gas Act, 15 U.S.C. 717-717 

(w)(1994). 

Next, we are clarifying the definition for the 

transmission compression industry segment. The final rule 

provides that natural gas transmission compression 

facilities not only move natural gas from production fields 

or gas processing plants, but also move natural gas coming 

from other transmission compressors. In addition, we are 

explicitly stating that natural gas transmission 

compression facilities not only move natural gas into 

distribution pipelines, but also into liquefied natural gas 

storage or into underground storage. 

We are removing the term “natural gas dehydration” 

from the industry segment definition because this term did 

not represent a unique characteristic of facilities with 

natural gas transmission compression. Finally, we are 

removing the reference to “gathering lines and boosting 

stations” and “facility” for the same reasons as explained 
28 of 212 

This document is a prepublication version, signed by EPA Administrator Lisa P. Jackson on 

December 2, 2011. We have taken steps to ensure the accuracy of this version, but it is not the 

official version.

above relating to the onshore processing industry segment 

definition. 

Natural Gas Distribution. EPA is amending the natural 

gas distribution industry segment definition to further 

clarify applicability under the rule. First, we are 

replacing the term “city gate station” with the term 

“metering-regulating station” in 40 CFR 98.230(a)(8). This 

amendment is designed to more clearly express EPA’s intent 

using language readily understood by industry. As a 

harmonizing change, we are also adding a definition for the 

term “metering-regulating station” in 40 CFR 98.238 to 

state that, “[a]n above ground station that meters the flow 

rate, regulates the pressure, or both, of natural gas in a 

natural gas distribution facility. This does not include 

customer meters, customer regulators, or farm taps”. With 

this amendment, we are clarifying key concepts in the 

definition, without actually changing coverage by the rule. 

We are removing the parenthetical term “(not 

interstate transmission pipelines or intrastate 

transmission pipelines)” as this statement was not 

necessary. Instead we are adding a definition for 

“distribution pipeline” in 40 CFR 98.238 that clarifies 

that “distribution pipelines” are only those designated as 
29 of 212 

This document is a prepublication version, signed by EPA Administrator Lisa P. Jackson on 

December 2, 2011. We have taken steps to ensure the accuracy of this version, but it is not the 

official version.

such by the Pipeline and Hazardous Material Safety 

Administration (PHMSA) 49 CFR 192.3. 

Next, we are removing the term “excluding customer 

meters” and “physically deliver natural gas to end users” 

because the definition for “meter-regulator” stations 

described above already addresses this exclusion. 

Finally, we are amending the industry segment 

definition to explicitly state that the LDC reporting as a 

single facility is that which is operated in a single state 

and regulated as a separate operating company by a public 

utility commission or that is operated as an independent 

municipally-owned distribution system. This change ensures 

that the definition of LDC is consistent between subpart W 

and subpart NN. 

Greenhouse Gases to Report. We are amending several 

provisions for the greenhouse gases that must be reported 

in 40 CFR 98.232. 

We are amending 40 CFR 98.232(c) to clarify that the 

source listed in 40 CFR 98.232(c)(1) through (22) are on a 

single well-pad or associated with a single well-pad. This 

change is consistent with the final changes to the onshore 

production industry segment definition in 40 CFR 

98.230(a)(2) described above. In 40 CFR 98.232 (c)(22), EPA 

is replacing the term “production well pad” with “petroleum 
30 of 212 

This document is a prepublication version, signed by EPA Administrator Lisa P. Jackson on 

December 2, 2011. We have taken steps to ensure the accuracy of this version, but it is not the 

official version.

and natural gas production facility as defined in 98.238”. 

This change makes the term consistent with language used 

throughout Subpart W. 

Next, we are amending 40 CFR 98.232(i) by replacing 

the term “custody transfer city gate station” with the term 

“transmission-distribution transfer station” and replacing 

the term “non-custody transfer station” with the term 

“metering-regulating station.” We are amending the source 

types for this industry segment by removing the text 

“Customer meters are excluded.” This text was removed 

because it was no longer necessary with the addition of the 

term “transmission-distribution transfer station” and its 

definition. Further we are amending 40 CFR 98.232(i) to 

state that CO2, CH4 and N2O emissions are to be reported 

from the natural gas distribution industry segment. This 

clarification is consistent with the calculation procedures 

in 40 CFR 98.233. Finally, EPA added emissions sources 

that were already required to be reported under 40 CFR part 

98, subpart W but were not listed under 40 CFR 98.232 (i) 

(i.e., pipeline main equipment leaks, service line 

equipment leaks, and stationary combustion). 

Next, we are removing and reserving 40 CFR 98.232(j), 

as proposed, in order to address concerns raised that the 

inclusion of this provision resulted in confusion amongst 
31 of 212 

This document is a prepublication version, signed by EPA Administrator Lisa P. Jackson on 

December 2, 2011. We have taken steps to ensure the accuracy of this version, but it is not the 

official version.

reporters as they were unsure how this provision aligned 

with the flare emissions that are captured under the 

applicable emissions source calculations throughout 40 CFR 

98.233. Accordingly, we are also finalizing, as proposed, 

the introductory sentences to 40 CFR 98.232(d), (e), (f), 

(g), (h), and (i) to clarify that N2O emissions are also 

required to be reported under these industry segments. We 

are making a harmonizing change to 40 CFR 98.232(a), to 

remove the reference to 40 CFR 98.232 (j). 

Lastly, we are amending 40 CFR 98.232(k) to clarify 

that the onshore petroleum and natural gas production and 

natural gas distribution industry segments are to report 

their combustion emissions under 40 CFR part 98, subpart W, 

while the remaining industry segments are to report their 

combustion emissions under subpart C of part 98. 

Calculating Greenhouse Gas Emissions. We are making 

several clarifications, corrections, and amendments 

throughout 40 CFR 98.233. 

Natural Gas Pneumatic Device Venting. 

EPA is modifying Equation W-1 by adding the subscript 

“t” to the equation to represent the different device 

types. EPA is removing the subscript “s,” and the word 

“standard” from the definition of parameter Masss,i because 

mass emissions do not need to be reported at standard 
32 of 212 

This document is a prepublication version, signed by EPA Administrator Lisa P. Jackson on 

December 2, 2011. We have taken steps to ensure the accuracy of this version, but it is not the 

official version.

conditions. EPA is amending Equation W-1, to include a 

parameter “T” that estimates the total number of hours in a 

year the devices were operational instead of assuming that 

the natural gas pneumatic devices was operating the whole 

year. However, EPA has provided a value of 8760 hours for 

reporters to use as a default option. Further, EPA is 

clarifying that compositions in 40 CFR 98.233(u)(2)(i) may 

be used for the onshore petroleum and natural gas 

production in the definition for “GHGi”. However, for 

onshore natural gas transmission compression, and 

underground natural gas storage industry segments, set 

values of 0.975 for CH4 and 1.1 × 10-2 for CO2 are used. The 

value of 0.975 represents the methane fraction of total 

hydrocarbon (THC) which is the basis of the emission 

factors in Tables W-3 for Natural Gas Transmission 

Compression and Table W-4 for Underground Natural Gas 

Storage where the non-hydrocarbon fraction of pipeline 

quality gas (made up of primarily carbon dioxide and 

nitrogen) is approximately 2%. The carbon dioxide fraction 

of total hydrocarbons in Tables W-3 and W-4 is determined 

from public records on pipeline gas quality. The value of 

1.1 × 10-2 represents the ratio of CO2 to methane in 

transmission gas. Under the parameter definition of Convi, 

EPA amended the value of emission factors to 0.000403 for 
33 of 212 

This document is a prepublication version, signed by EPA Administrator Lisa P. Jackson on 

December 2, 2011. We have taken steps to ensure the accuracy of this version, but it is not the 

official version.

CH4 and 0.00005262 for CO2 to account for an error in the 

previous factor not being adjusted to standard conditions. 

EPA is revising 40 CFR 98.233(a) by adding 40 CFR 

98.233(a)(3), which allows reporters to determine the type 

of pneumatic devices using engineering estimation based on 

best available information. This amendment is in response 

to questions about how to determine whether a pneumatic 

device is continuous high bleed, continuous low bleed, or 

intermittent bleed and the burden associated with 

determining the type of pneumatic device. 

Lastly, the data reporting requirements in 40 CFR 

98.236(c)(1)(iv), which are associated with pneumatic 

devices, have been clarified to require aggregate emissions 

to be reported for all continuous high bleed pneumatic 

devices, for all intermittent bleed pneumatic devices, and 

for all continuous low bleed pneumatic devices separately 

at the facility level. 

Natural Gas Driven Pneumatic Pump Venting. 

We are amending Equation W-2 in 40 CFR 98.233(c), to 

include a parameter “T” that estimates the total number of 

hours in a year the pumps were operational instead of 

assuming that the pneumatic pump was operating the whole 

year. EPA has provided a value of 8760 hours for reporters 

to use as a default option. EPA is removing the subscript 
34 of 212 

This document is a prepublication version, signed by EPA Administrator Lisa P. Jackson on 

December 2, 2011. We have taken steps to ensure the accuracy of this version, but it is not the 

official version.

“s,” since mass emissions do not need to be reported at 

standard conditions. 

Acid Gas Removal (AGR) Vents. EPA is amending 40 CFR 

98.233(d) to clarify EPA’s intent and to correct errors. 

We are revising provisions in 40 CFR 98.233(d) to 

clarify how the four different methods are to be used for 

determining GHG emissions from acid gas removal units. 

First, we are amending 40 CFR 98.233(d)(1) to specify that 

the use of CEMS is required if a CO2 concentration monitor 

and volumetric flow rate monitor are installed. This 

amendment was made to clarify what conditions must be met 

to satisfy Tier 4 calculation requirement in Subpart C for 

Acid Gas Removal vents. EPA is allowing reporters the 

flexibility to follow the calculation, quality assurance, 

reporting, and recordkeeping requirements in Tier 4 in 

Subpart C, manufacturer instructions, or industry standard 

practice for CEMS units already in place. 

EPA is revising 40 CFR 98.233(d)(2), (d)(3), and 

(d)(4) to clarify that if a facility has a vent meter but 

no CEMs available, then they would use Calculation 

Methodology 2. If a facility has neither a CEMs available 

nor a vent meter in place (with the added flexibility to 

use industry consensus standards to calibrate the vent 
35 of 212 

This document is a prepublication version, signed by EPA Administrator Lisa P. Jackson on 

December 2, 2011. We have taken steps to ensure the accuracy of this version, but it is not the 

official version.

meters), then either Calculation Methodology 3 or 4 of 40 

CFR 98.233(d) may be used. 

Next, we are revising the equation used for estimating 

CO2 emissions from acid gas removal vents in Equation W-4A 

and Equation W-4B in Calculation Methodology 3 in 40 CFR 

98.233(d). This new equation addresses issues that arose 

with the previous equation, because that equation was 

better suited to situations where the change in CO2 volume 

fraction between the inlet gas and the outlet gas would be 

relatively low, such as 1 percent. These two new equations 

will increase the accuracy of the calculation while adding 

no additional burden to reporters because the same 

parameters are monitored. Further details on the revised 

equations have been provided in the memo “Acid Gas Removal 

Vents – Engineering Calculation Revisions” located in the 

docket: EPA-HQ-OAR-2011-0512. 

EPA is amending several associated data reporting 

requirements in 40 CFR 98.236(c)(3). First, we are 

clarifying that the annual average CO2 content should be 

reported for volume fraction measurements undertaken in 40 

CFR 98.233(d). Second, we are clarifying that reporters 

must report the annual quantity of CO2 recovered from the 

AGR unit and the CO2 emissions from the AGR unit separately. 

Third, we are finalizing the reporting of a unique ID for 
36 of 212 

This document is a prepublication version, signed by EPA Administrator Lisa P. Jackson on 

December 2, 2011. We have taken steps to ensure the accuracy of this version, but it is not the 

official version.

each AGR unit in industry segments other than onshore 

petroleum and natural gas production, as proposed (see 

Section II.D. of the preamble for further details on this 

issue). Lastly, we are asking reporters to indicate which 

methodology they are using to calculate emissions from 

AGRs. 

 Dehydrator Vents. EPA is amending several of the 

provisions in 40 CFR 98.233(e) for calculating GHGs from 

dehydrator vents. 

First, we are clarifying that the equipment threshold 

referenced throughout this section for glycol dehydrators 

is based on annual average daily throughput at standard 

conditions. This amendment was necessary to address 

ambiguity in the final rule provisions regarding 

determination of the average throughput. 

Next, we are clarifying that gases other than natural 

gas, such as nitrogen, flash gas from the flash tanks, or 

dry gas from the absorber, that are used as stripping 

gases satisfy the requirements stated in 40 CFR 

98.233(e)(1)(vii). EPA is also correcting the citation in 

40 CFR 98.233(e)(1)(xi), (e)(1)(xi)(A) through 

(e)(1)(xi)(C). 

Further, EPA clarified parameters in Equation W-5. EPA 

has finalized the use of 60 degree Fahrenheit and 14.7 psia 
37 of 212 

This document is a prepublication version, signed by EPA Administrator Lisa P. Jackson on 

December 2, 2011. We have taken steps to ensure the accuracy of this version, but it is not the 

official version.

as standard conditions for all of subpart W; therefore, 

parameter EFi was revised to reflect the standard 

conditions. In addition, EPA clarified that the parameter 

1,000 converts emissions from thousand standard cubic feet 

to standard cubic feet instead of cubic feet. 

Next, we are also amending 40 CFR 98.233(e)(6) to 

clarify that GHG mass emissions from glycol dehydrators are 

to be calculated from volumetric GHG emissions using 

calculations in 40 CFR 98.233(v) where as GHG volumetric 

and mass emissions from desiccant dehydrators should be 

calculated using paragraphs 40 CFR 98.233(u) and 98.233(v). 

Accordingly, we are clarifying in 40 CFR 98.236(c)(4) 

the requirement to report vented and flared emissions 

separately. We are also clarifying the data reporting 

requirements by specifying that should any vent gas 

controls be used on glycol dehydrators with a throughput 

less than 0.4 million standard cubic feet, that reporters 

must indicate that in their annual reports. Additionally, 

we are finalizing the reporting of a unique ID, as 

proposed, for each glycol dehydrator in industry segments 

other than onshore petroleum and natural gas production 

(see Section II.D. of the preamble for further details on 

this issue). Finally, we are clarifying that emissions 
38 of 212 

This document is a prepublication version, signed by EPA Administrator Lisa P. Jackson on 

December 2, 2011. We have taken steps to ensure the accuracy of this version, but it is not the 

official version.

from desiccant dehydrators must be reported at the facility 

level. 

Well Venting for Liquids Unloadings. First, we are 

revising 40 CFR 98.233(f) Calculation Methodology 1 by 

finalizing several amendments that were proposed, including 

that sampling is to be done at a sub-basin level as opposed 

to a field-level. Further, we are finalizing the provision 

stating that the average flow rate must be determined for 

one well in a tubing diameter group and pressure group in 

each sub-basin category. As proposed in the GHGRP Revisions 

Proposal, EPA has also added a definition for the term 

“pressure groups” in 40 CFR 98.238 to inform reporters of 

the ranges for the pressure groupings that are applicable 

to the sub-basins, and the types of pressures that may be 

used for those groupings. The pressure ranges, as proposed 

and finalized, were optimized using HPDI well counts in 5 

psig pressure increments from zero gauge pressure to 200 

psig. The fifth “unbounded” pressure range is “greater 

than 200 psig,” which EPA believes will have very few well 

liquids unloading venting to the atmosphere. The three 

tubing diameter ranges, equal or less than 1 inch, greater 

than 1 inch and equal or less than 2 inch, and greater than 

2 inch, were derived from gas well tubing suppliers’ 

specifications, as proposed. The relevancy of these 
39 of 212 

This document is a prepublication version, signed by EPA Administrator Lisa P. Jackson on 

December 2, 2011. We have taken steps to ensure the accuracy of this version, but it is not the 

official version.

pressure ranges and tubing diameter ranges is that liquids 

unloading venting is dependent on both the shut-in pressure 

of the reservoir (shut-in by liquids accumulation) and 

velocity of gas pushing liquids up the tubing, which is a 

function of tubing diameter. For further background on the 

selection of these pressure groupings and for the analysis 

done see “2011 Technical Revisions to the Petroleum and 

Natural Gas Systems Category of the GHG Reporting Rule: 

Summary of questions raised on Subpart W” docket number 

EPA-HQ-OAR-2011-0512-0015 and “Sub-Basin Entity Pressure 

Range Analysis” docket number EPA-HQ-OAR-2011-0016. 

EPA also clarified in 40 CFR 98.233 (f)(1)(i)(B) that 

the determined flow rate can be used for all other wells in 

that tubing diameter group and pressure group in a subbasin category. Finally EPA clarified in 40 CFR 98.233 

(f)(1)(i)(C) that a new producing sub-basin category must 

determine an average flow rate during the beginning of the 

first year of production. 

In this action, we are also including corrections to 

Equation W-7, as proposed. EPA is modifying Equation W-7 to 

address the ambiguity regarding tubing diameter group and 

pressure group combinations in a sub-basin. Furthermore 

the subscripts “t” and “q” were removed along with a 

summation sign to clarify that emissions are calculated for 
40 of 212 

This document is a prepublication version, signed by EPA Administrator Lisa P. Jackson on 

December 2, 2011. We have taken steps to ensure the accuracy of this version, but it is not the 

official version.

all wells in a tubing diameter group and pressure group in 

a sub-basin. Accordingly, subscripts “h” and “p” represent 

wells of the same tubing diameter group and pressure group. 

EPA is revising Equation W-8 and W-9 by correcting the 

definition for parameter Ea,n to be Es,n to accurately 

reflect that the calculated emissions should be in standard 

conditions and not actual conditions. The parameter 

definition was also modified to state that the emissions 

are at standard conditions. These revisions from actual 

conditions to standard conditions were necessary to 

maintain uniformity in the approach to calculating GHG 

emissions across 40 CFR subpart W. EPA is including 

revisions to the parameters in Equation W-8 and W-9 to 

account for each unloading instance, q, and for each well, 

p, in a pressure grouping and sub-basin category. In 

addition, the parameter W was added to define the limits of 

the summation. These amendments address ambiguity with the 

summation operation in the 2010 final rule for this 

equation. 

Next, we are amending the definition for “SFRp” to 

state that the average sales flow rate of gas is to be 

obtained at standard conditions. We are also clarifying 

that Equation W-33 is to be used to convert the sales flow 

rate from actual to standard conditions. In addition, the 
41 of 212 

This document is a prepublication version, signed by EPA Administrator Lisa P. Jackson on 

December 2, 2011. We have taken steps to ensure the accuracy of this version, but it is not the 

official version.

definition for parameter WDp has been clarified to mean the 

distance between the either the top of the well or the 

lowest packer to the bottom of the well. Furthermore, CDp in 

Equation W-8 and TDp in Equation W-9 represent the internal 

diameter of the casing and tubing, respectively. Finally, 

the reference to 40 CFR 98.233 (t) in 40 CFR 98.233 (f)(2) 

and 98.233 (f)(30) has been removed to avoid double 

correction for standard conditions. 

For parameter SPp in Equation W-8, EPA is allowing the 

use of shut-in pressure, surface pressure, or casing-totubing pressure of one well from the same sub-basin 

multiplied by the tubing pressure of each well in the same 

sub-basin. For parameter SPp in Equation W-9, EPA is 

allowing the use of an engineering estimate based on best 

available data to determine the sales line pressure. EPA is 

adding options and flexibility because of comments 

suggesting that the shut-in pressure is not known for all 

wells. Finally, the units for SPp in Equation W-8 and W-9 

have been corrected from pounds per square inch absolute 

instead of pounds per square inch atmosphere. 

Accordingly, in the data reporting requirements in 40 

CFR 98.236(c)(5), we are making a harmonizing change, 

consistent with the amendments described above. Separate 

reporting requirements have been included for Calculation 
42 of 212 

This document is a prepublication version, signed by EPA Administrator Lisa P. Jackson on 

December 2, 2011. We have taken steps to ensure the accuracy of this version, but it is not the 

official version.

Methodology 2 and 3 because emissions are not reported by 

well tubing diameter grouping and pressure grouping within 

each sub-basin category as in Calculation Methodology 1. 

All added requirements are data elements used in the 

engineering calculation in Equation W-8 and W-9. 

Gas Well Venting During Completions and Workovers from 

Hydraulic Fracturing. EPA is amending 40 CFR 98.233(g) to 

account for the changes in aggregation from field level to 

sub-basin category for taking measurements, as proposed. 

First, we are replacing the term “field” with “sub-basin 

and well type (horizontal vs. vertical) combination” in the 

parameter definitions and clarifying that the GHG emissions 

are determined for each sub-basin and well type 

combination. 

Next, we are amending Equation W-10A and adding 

Equation W-10B. Reporters can use Equation W-10A if the 

backflow from all the wells in a sub-basin and well-type 

combination are not being metered, where as reporters can 

use Equation W-10B if the backflow volumes from all wells 

in a sub-basin and well-type combination are being metered. 

In Equation W-10A, the time period parameter Tp is 

redefined to be the time of backflow for the completion or 

workover. Equation W-10A has a new parameter, FRM, which 

represents the ratio of backflow during completions and 
43 of 212 

This document is a prepublication version, signed by EPA Administrator Lisa P. Jackson on 

December 2, 2011. We have taken steps to ensure the accuracy of this version, but it is not the 

official version.

workovers to 30-day production rate. FRM is calculated in 

Equation W-12 by dividing the metered flowback volume from 

the measured well(s) by the 30 day production rate. This 

ratio allows reporters to determine a backflow rate for 

wells that are not measured using the first 30 days 

production flow rate (PRp), which is readily available to 

reporters. EPA also added a reference to 40 CFR 98.233 

(g)(3) in the parameter definition of SGp. 

EPA is adding Equation W-10B to allow reporters to 

determine emissions if the backflow volumes are measured 

for all wells in a sub-basin and well-type combination. 

Reporters must measure the complete backflow volume during 

the completion or workover. This is represented by the 

parameter FVp in Equation W-10B. 

In Equation W-10A and Equation W-10B, EPA is adding 

the parameter W, which is the number of wells completed or 

worked over using hydraulic fracturing in a sub-basin and 

well type combination, and, where appropriate, made the 

parameters applicable to each well p. These amendments 

correct the summation operator to make it mathematically 

accurate. 

 In Equation W-11C, EPA is finalizing amendments to 

allow reporters to use best engineering estimate based on 

best available data to determine whether the well flow of 
44 of 212 

This document is a prepublication version, signed by EPA Administrator Lisa P. Jackson on 

December 2, 2011. We have taken steps to ensure the accuracy of this version, but it is not the 

official version.

gas during backflow (i.e. FRp) is sonic or sub-sonic flow. 

EPA also clarified in 40 CFR 98.233(g)(1)(ii) that 

reporters can determine whether to use Equation W-11A, 

which is for sub-sonic flow, or Equation W-11B, which is 

for sonic flow. 

EPA is clarifying that paragraphs 40 CFR 98.233 

(g)(1)(iv) and 40 CFR 98.233 (g)(1)(v) are applicable to 

Equation W-10A only. EPA is replacing 40 CFR 98.233(g)(3) 

with 40 CFR 98.233(g)(5). Previously, the requirements 

stated in these paragraphs were duplicative. 

Lastly, we are finalizing several harmonizing changes 

to the data reporting requirements for this emissions 

source in 40 CFR 98.236 (c)(6)(i). We are indicating in 

the data reporting requirements that reporting is required 

for each sub-basin category and well type (horizontal or 

vertical) combination. EPA amended certain requirements to 

make them only applicable to Equation W-10A. In addition, 

EPA is clarifying that the flow rate and time 

determinations are for backflow during the completion or 

workover and not for when backflow is vented to the 

atmosphere or routed to flare. EPA is clarifying that the 

number of reduced emissions completions and the volume of 

gas recovered must be reported separately for well 

completions and workovers. EPA is also clarifying that 
45 of 212 

This document is a prepublication version, signed by EPA Administrator Lisa P. Jackson on 

December 2, 2011. We have taken steps to ensure the accuracy of this version, but it is not the 

official version.

emission vented directly to the atmosphere must be reported 

separately from emissions resulting from flaring of 

backflow gas from well completions and workovers with 

hydraulic fracturing. 

Gas Well Venting During Completions and Workovers 

Without Hydraulic Fracturing. In this section we are 

revising the introductory text by deleting the term “well 

workovers not involving hydraulic fracturing” because it 

was repetitive. EPA also added a reference to 40 CFR 

98.233(v) to convert CH4 and CO2 volumetric emissions to 

mass emission. 

Second EPA is requiring reporting on a sub-basin level 

instead of a field level. Thus, the term “field” has been 

changed to “sub-basin” in the definition for the parameter 

“Nwo” and “f” in Equation W-13, consistent with the proposed 

change from “field” to “sub-basin” across subpart W. 

Additionally, we are revising the parameters and their 

respective definitions to correctly represent standard 

conditions and not actual conditions. Finally, EPA is 

amending the summation operator in Equation W-13 to make it 

mathematically accurate. This includes adding the 

subscript “p”, which is an index for each completion 

without hydraulic fracturing in a sub-basin, and making 
46 of 212 

This document is a prepublication version, signed by EPA Administrator Lisa P. Jackson on 

December 2, 2011. We have taken steps to ensure the accuracy of this version, but it is not the 

official version.

specific parameters in Equation W-13 applicable to each 

well completion, “p”. 

In the associated reporting requirements in 40 CFR 

98.236 (c)(6)(ii), EPA clarified that only a total count of 

workovers that flare or vent gas to the atmosphere need to 

be reported. Additionally, EPA clarified that emissions 

from venting to the atmosphere and flaring must be reported 

separately. 

Blowdown Vent Stacks. In this action, EPA is removing 

the term “equipment” and “equipment type” in 40 CFR 

98.233(i) and replacing it with “unique physical volume” in 

this section. EPA also clarified the types of blowdowns 

covered. We are deleting the term “to atmosphere” because 

not every blowdown will result in the blowdown chamber 

being brought to atmospheric pressure, thus more fully 

portraying EPA’s intent to cover these types of 

“blowdowns.” 

Next, we are clarifying that we only intend to cover 

the types of blowdowns typically activated by operators, 

whether for what an operator might perceive as an emergency 

shutdown or when taking equipment out of service for 

operational or maintenance purposes. The term “activated 

by operators” implies that an operator was present at the 

time the blowdown was activated, and that the operator(s) 
47 of 212 

This document is a prepublication version, signed by EPA Administrator Lisa P. Jackson on 

December 2, 2011. We have taken steps to ensure the accuracy of this version, but it is not the 

official version.

manipulated automated or manual controls to isolate the 

equipment and open the blowdown valve(s). Whether the 

operator perceived this human intervention to isolate and 

blowdown equipment as stemming from a perceived emergency 

or routine operational or maintenance functions is 

unimportant because the operator has full knowledge of the 

timing and equipment being isolated and blown down to 

record for reporting purposes. It was not EPA’s intent to 

capture automated releases that do not involve human 

intervention, , such as pressure safety valve releases, 

pressure controlled venting, or compressors being 

automatically shut down for safety in the absence of 

operator presence or intervention. Such automated safety 

releases or equipment shutdowns may not have sufficient 

operator involvement to know the timing and exact nature of 

the gas release to make an accurate accounting. 

Also in this action, we are revising the numbering of 

Equation W-14 to be Equation W-14A, and adding an Equation, 

W-14B. We are adding Equation W-14B to allow facilities to 

track blowdowns by each occurrence. Equation W-14B allows 

reporters to account for situations where a unique physical 

volume may not be blown down to atmospheric pressure. 

For both equations, Vv has been changed to V. We are 

also clarifying that the parameter V is the actual physical 
48 of 212 

This document is a prepublication version, signed by EPA Administrator Lisa P. Jackson on 

December 2, 2011. We have taken steps to ensure the accuracy of this version, but it is not the 

official version.

volume of the blowdown equipment and not the gas volume. In 

both equations, the definition of parameter “N” has been 

changed to the number of times a particular unique physical 

volume is blowndown to the atmosphere. Finally, “Ts” has 

been set at 60 degrees Fahrenheit and “Ps” has been set at 

14.7 psia. 

Accordingly, revisions to 40 CFR 98.236(c)(7) were 

made to account for these amendments. We are revising the 

data reporting requirements for blowdown vent stacks by 

stating that emissions from unique volumes that are 

blowndown more than once during the calendar year must be 

reported by unique physical volume and the number of times 

that a particular volume is blowdown must be reported. For 

unique physical volumes that are blowndown only once during 

the calendar year, reporters can total the emission from 

all of the unique volumes and report an aggregate number. 

In addition, EPA added the requirement to report the number 

of unique volumes that are blowndown only once during the 

calendar year. 

Onshore Production Storage Tanks. EPA is amending 

several provisions in 40 CFR 98.233(j) for calculating GHGs 

from onshore production storage tanks. 

First, we are clarifying that the equipment threshold 

referenced throughout this section for onshore production 
49 of 212 

This document is a prepublication version, signed by EPA Administrator Lisa P. Jackson on 

December 2, 2011. We have taken steps to ensure the accuracy of this version, but it is not the 

official version.

storage tanks is based on an annual average daily 

throughput. This clarification was necessary to address 

ambiguity in the final rule regarding the determination of 

the throughput of oil. 

Next, we are making corrections to address erroneous 

citations in 40 CFR 98.233(j)(1)(vii) and 40 CFR 

98.233(j)(2). 

Next, in this action, EPA is replacing the term 

“field” in 40 CFR 98.233(j)(1)(vii)(B), 40 CFR 

98.233(j)(1)(vii)(C), and 40 CFR 98.233(j)(3)(i) with the 

term “sub-basin category” as per the discussion in Section 

II.C of the September 9, 2011 proposal preamble. EPA is 

also clarifying that reporting of CH4 and CO2 emissions 

determined using Calculation Methodologies 3 and 4 are on 

an annual basis. 

We are revising Equation W-15 to include a multiplier 

of 1,000 that converts emissions from thousand standard 

cubic feet to standard cubic feet so the calculation 

results in accurate units. Also, we are amending the 

definitions of the parameters, EFi and Count, to clarify 

that these parameters must be used for well-pad gas-liquid 

separators and for wells sending liquids straight to a tank 

without passing through any gas-liquid separators with 

throughput less than 10 barrels per day. Additionally, EPA 
50 of 212 

This document is a prepublication version, signed by EPA Administrator Lisa P. Jackson on 

December 2, 2011. We have taken steps to ensure the accuracy of this version, but it is not the 

official version.

is changing standard conditions to 60 degree Fahrenheit and 

14.7 psia; therefore, the emission factors for CH4 and CO2

at 60 degrees Fahrenheit replaced the existing values at 68 

degrees Fahrenheit. 

Lastly, in Equation W-16, we are amending the 

definition for the parameter En by correcting the erroneous 

citations, 40 CFR 98.233(j)(3) and (j)(5), and including 

the accurate citations, 40 CFR 98.233(j)(1), (j)(2), and 

(j)(4), instead. We are including a conversion factor in 

this equation such that the emissions are being determined 

on a yearly basis, as opposed to an hourly basis. We are 

deleting the parameter Et in the equation, because it is 

being accounted for in the revised equation and therefore 

is not necessary. 

Accordingly, we are clarifying several data reporting 

requirements in 40 CFR 98.236(c)(8) for this source. First, 

for Calculation Methodologies 1 and 2. Next, for 

Calculation Methodologies 3, 4, and 5, vented, flared, and 

recovered emissions must be reported for each GHG and all 

requirements must be reported at a sub-basin level. Next, 

we are correcting an erroneous citation in 40 CFR 

98.236(c)(8)(ii)(D). Finally, as proposed, EPA is adding 

the reporting of vented emissions for each gas at the subbasin level for improperly functioning dump valves. This 
51 of 212 

This document is a prepublication version, signed by EPA Administrator Lisa P. Jackson on 

December 2, 2011. We have taken steps to ensure the accuracy of this version, but it is not the 

official version.

data reporting requirement is based on the inputs to 

Equation W-16 in 40 CFR 98.233(j) and therefore will not 

place additional burden on reporters. 

Transmission Storage Tanks. EPA is amending several 

provisions in 40 CFR 98.233(k) for calculating GHGs from 

transmission storage tanks. 

First, we are revising 40 CFR 98.233(k)(1) to include 

an additional provision for monitoring the transmission 

storage tank vapor vent stack. With this amendment, 

reporters can either screen their tanks first by using the 

optical gas imaging instrument for 5 continuous minutes 

and, if a leak is detected, measure the leak according to 

the provisions in 40 CFR 98.234 consistent with the 2010 

final rule, or measure the tank vent vapors for 5 minutes 

either using a flow meter or high volume sampler, or 

alternatively a calibrated bag based on manufacturers 

specifications according to the provisions outlined in 40 

CFR 98.234. 

Next, EPA is clarifying that emissions, determined in 

40 CFR 98.233(k)(2) and (k)(4), are on an annual basis. 

Next, in 40 CFR 98.233(k)(4)(i), we are deleting the 

erroneous citation to 40 CFR 98.233(j)(1). Lastly, in 40 

CFR 98.233(k)(4)(ii), we are clarifying that flare stack 

calculation methodology from 40 CFR 98.233(n) should be 
52 of 212 

This document is a prepublication version, signed by EPA Administrator Lisa P. Jackson on 

December 2, 2011. We have taken steps to ensure the accuracy of this version, but it is not the 

official version.

used for emissions that are sent to a flare and not from 

the flare. 

EPA is amending two associated data reporting 

requirements in 40 CFR 98.236(c)(9). We are clarifying 

that vented and flared emissions for each GHG, must be 

reported for each transmission storage tank. Additionally, 

we are finalizing the reporting of a unique name or ID 

number, as proposed, for each transmission storage tank as 

per the discussion in Section II.D of this preamble. 

Well Testing Venting and Flaring. EPA is amending the 

calculation methodologies under this source to make them 

applicable to gas wells and to situations wherein 

production from a group of wells is routed through the same 

pipe. In particular, EPA is adding Equation W-17B which 

uses the production rate of a gas well to estimate well 

testing venting emissions from gas wells. Additionally, 

EPA is clarifying that both equations apply to one or more 

wells being tested. 

EPA is amending the data reporting requirements in 40 

CFR 98.236(c)(10), to clarify that for each GHG, reporters 

must report emissions from well testing venting and from 

well testing flaring separately. These emissions from well 

testing venting and well testing flaring are calculated 
53 of 212 

This document is a prepublication version, signed by EPA Administrator Lisa P. Jackson on 

December 2, 2011. We have taken steps to ensure the accuracy of this version, but it is not the 

official version.

individually in 40 CFR 98.233(l); therefore, this places no 

additional burden on reporters. 

Associated Gas Venting and Flaring. EPA is revising 

40 CFR 98.233(m)(1) to replace the term “field” with the 

term “sub-basin category” as per the discussion in Section 

II.C of the September 9, 2011, GHGRP Revisions Proposal. 

EPA is amending the data reporting requirements in 40 

CFR 98.236(c)(11), to clarify that for each GHG, reporters 

must report emissions from associated natural gas venting 

and from associated natural gas flaring separately. These 

emissions from associated natural gas venting and 

associated natural gas flaring are calculated separately in 

40 CFR 98.233(m); therefore, this places no additional 

burden on reporters. 

Flare Stack Emissions. EPA is amending several 

provisions in 40 CFR 98.233(n) for calculating GHGs from 

flare stacks. 

First, we are amending 40 CFR 98.233(n)(2)(ii) to 

clarify that reporters of onshore natural gas processing 

plants that solely fractionate a liquid stream, must use 

the GHG mole percent in feed natural gas liquid for all 

streams. This amendment addresses the lack of clarity in 

the final provisions on how natural gas processing plants 
54 of 212 

This document is a prepublication version, signed by EPA Administrator Lisa P. Jackson on 

December 2, 2011. We have taken steps to ensure the accuracy of this version, but it is not the 

official version.

that only fractionate liquid streams would determine their 

gas compositions. 

Next, we are revising 40 CFR 98.233(n)(2)(iii) to 

clarify that for any applicable industry segment, methane, 

in addition to ethane, propane, butane, pentane-plus and 

mixed light hydrocarbons, should be accounted for when the 

stream going to the flare is a hydrocarbon product stream. 

This correction ensures that the paragraph 40 CFR 

98.233(n)(2)(iii) is consistent with the Equation W-21. 

Next, we are clarifying the summation operator in 

Equation W-21 to make the equation mathematically correct. 

Additionally, we are clarifying, in 40 CFR 98.233(n)(11), 

that source types in 40 CFR 98.233 that send emissions to a 

flare and use Equations W-19 through W-21, must determine 

volumetric flow rate, parameter “Va”, in Equation W-19 

through W-21, at actual conditions. 

EPA did not intend to unnecessarily limit the 

measurement options for flares that operate and maintain a 

continuous emissions monitoring system (CEMS). EPA is now 

allowing the reporters to calculate CO2 emissions from 

flares that operate and maintain a CEMS, using Tier 4 

Calculation Methodology and all associated calculation, 

quality assurance, reporting, and recordkeeping 

requirements for Tier 4 in subpart C of this part (General 
55 of 212 

This document is a prepublication version, signed by EPA Administrator Lisa P. Jackson on 

December 2, 2011. We have taken steps to ensure the accuracy of this version, but it is not the 

official version.

Stationary Fuel Combustion Sources). This includes 

following the procedures for initial certification of the 

CEMS and the ongoing quality assurance requirements for the 

CEMS specified in 40 CFR 98.34(c). Also, EPA is exempting 

the reporting of CH4 and N2O emissions from flares that 

operate and maintain a CEMS. 

EPA is making several amendments to the data reporting 

requirements in 40 CFR 98.236(c)(12). First, we are 

amending requirements to clarify that uncombusted CH4 

emissions, combusted CO2 emissions, uncombusted CO2

emissions, and combustion-related N2O emissions must be 

reported separately. Second, we are adding the reporting 

of combined combusted and uncombusted CO2 emissions from 

flares that operate and maintain a CEMS. These uncombusted 

CH4, combusted CO2, uncombusted CO2, combustion-related N2O 

emissions, and combined combusted and uncombusted CO2

emissions from flares that operate and maintain a CEMS are 

calculated separately in 40 CFR 98.233(n); therefore, these 

requirements place no additional burden on reporters. 

Lastly, we are finalizing the reporting of a unique name or 

ID number, as proposed, for each flare stack under onshore 

natural gas processing as per the discussion in Section 

II.D of this preamble. 
56 of 212 

This document is a prepublication version, signed by EPA Administrator Lisa P. Jackson on 

December 2, 2011. We have taken steps to ensure the accuracy of this version, but it is not the 

official version.

Centrifugal Compressor Venting. EPA is finalizing 

amendments that were made across the sections in 40 CFR 

98.233 to standardize reporting for standard conditions. 

First, EPA is clarifying two parameter definitions under 

this source. First, in Equation W-24, we are amending the 

definition of parameter MTm to clarify that flow 

measurements must be determined in standard cubic feet per 

hour. Second, EPA is changing standard conditions to 60 

degree Fahrenheit and 14.7 psia; therefore, in Equation W25, the emission factors for GHGi at 68 degrees Fahrenheit 

were removed from the parameter EFi. 

Reciprocating Compressor Venting. EPA is finalizing 

amendments that were made across the section in 40 CFR 

98.233 to standardize reporting for standard conditions. 

First, EPA is clarifying two parameter definitions under 

this source. First, in Equation W-28, we are amending the 

definition of parameter MTm to clarify that flow 

measurements must be determined in standard cubic feet per 

hour. Second, EPA is changing standard conditions to 60 

degree Fahrenheit and 14.7 psia; therefore, in Equation W29, the emission factors for GHGi at 68 degrees Fahrenheit 

were removed from the parameter EFi. 

Leak Detection and Leaker Emission Factors. We are 

revising 40 CFR 98.233(q)(8) to remove the term “city gate 
57 of 212 

This document is a prepublication version, signed by EPA Administrator Lisa P. Jackson on 

December 2, 2011. We have taken steps to ensure the accuracy of this version, but it is not the 

official version.

stations at custody transfer” and replace with the term 

“transmission-distribution transfer stations” for the 

reasons described in Section II.C of the September 9, 2011 

GHGRP Revisions Proposal. We are also removing the term 

“meters and regulators” and replacing these terms with 

above ground “metering-regulating stations”. 

EPA is revising equation W-30A, previously designated 

at W-30A in the November 2010 final rule (75 FR 74458), to 

clarify the summation operator to make it mathematically 

correct. This clarification includes amending the term “x” 

to be the count of each equipment leak source as listed in 

Table W-7 and adding Tp, which is the total time the 

component p was found leaking and operational. We are also 

revising the parameter GHGi. For industry segments listed 

in 40 CFR 98.230(a)(4) and (a)(5), GHGi has been revised to 

0.974 for CH4 and 1.0 × 10-2 for CO2. For industry segments 

listed in 40 CFR 98.230(a)(6) and (a)(7), GHGi equals 1 for 

CH4 and 0 for CO2. For industry segments listed in 40 CFR 

98.230(a)(8), GHGi equals 1 for CH4 and 1.1×10-2 CO2. 

EPA is adding the option in 98.233(q)(8)(A) for 

natural gas distribution facilities to conduct monitoring 

at their transmission-distribution transfer stations over a 

multiple year period, not exceeding five years. For more 

information on the comments received and EPA’s response to 
58 of 212 

This document is a prepublication version, signed by EPA Administrator Lisa P. Jackson on 

December 2, 2011. We have taken steps to ensure the accuracy of this version, but it is not the 

official version.

this topic see Section II.D Responses to Major Comments 

submitted on the Petroleum and Natural Gas Systems Source 

Category of this preamble. Facilities that choose to use 

the multiple year option are required to conduct monitoring 

at roughly the same number of T-D stations over the cycle 

without repetition of the same T-D stations within the 

cycle. 

EPA is also adding a new Equation W-30B to account for 

emissions from leaking sources at above ground T-D transfer 

stations when the facility chooses to conduct monitoring at 

T-D transfer stations over a multiple year cycle. Equation 

W-30B maintains a rolling sum of emissions from T-D 

transfer stations that have been monitored over the 

multiple years in the cycle and results in a rolling 

average in Equation W-32 for each meter/regulator run. EPA 

has also added three terms t, n, and Tp,q that are in 

Equation W-30B. The term t defines the calendar year, n 

defines the number of years in the cycle over which all T-D 

transfer stations will be monitored, and Tp,q defines the 

total time the leak source p was found leaking and 

operational in the multiple year cycle. Finally, EPA has 

clarified that Equation W-30A applies to facilities listed 

in 40 CFR 98.230(a)(3)-(a)(7) and Equation W-30B applies to 

facilities listed in 40 CFR 98.230(a)(8). 
59 of 212 

This document is a prepublication version, signed by EPA Administrator Lisa P. Jackson on 

December 2, 2011. We have taken steps to ensure the accuracy of this version, but it is not the 

official version.

We are amending the data reporting requirements 

associated with the changes to 40 CFR 98.233(q) and (r) in 

40 CFR 98.236(c)(16). We are revising the requirements 

based on the revisions to the data calculation 

methodologies for Local Distribution Companies that choose 

to use the 5 year rolling survey plan. These revisions 

include provisions for facilities to report the total 

number of T-D stations at their facility, the number of 

years over which all T-D transfer stations will be 

monitored at least once, and the number of T-D stations 

that are being monitored in the calendar year. We are also 

amending the reporting requirements in 40 CFR 98.236(c)(16) 

to clarify that facilities must report CH4 emissions 

collectively by emission source type and CO2 emissions 

collectively by emission source type. 

Population Count and Emission Factors. We are 

finalizing several amendments in 40 CFR 98.233(r). First 

we are amending the definition of EFs in equation W-31 by 

replacing the term “non-custody transfer city-gate” with 

“meter/ regulator runs” at above grade “metering-regulating 

stations” for the reason stated in Section II.C of the 

September 9, 2011 proposal. We are also clarifying that 

the count in equation W-31 applies to the number of 
60 of 212 

This document is a prepublication version, signed by EPA Administrator Lisa P. Jackson on 

December 2, 2011. We have taken steps to ensure the accuracy of this version, but it is not the 

official version.

“meter/regulator runs” at all “metering-regulating 

stations” combined. 

We are also amending the term “count” in W-31 to 

elaborate and clarify how each industry segment should 

count the total number of equipment/components. In that 

same equation, for industry segments listed in 40 CFR 

98.230 (a)(4) and (a)(5), we are revising GHGi to 0.952 for 

CH4 and 1.0 × 10-2 for CO2. For industry segments listed in 

40 CFR 98.230(a)(6) and (a)(7), GHGi equals 1 for CH4 and 0 

for CO2. For industry segments listed in (a)(8), GHGi

equals 1 for CH4 and 1.1×10-2 CO2. 

Next, EPA is amending 40 CFR 98.233(r)(2)(i) to 

explicitly state how meters and piping are to be counted. 

Based on this amendment, owners or operators should use one 

count of meters/piping per well-pad. 

Further, EPA is amending 40 CFR 98.233(r)(6)(i) by 

replacing the term “below grade meters and regulators” with 

the term, “below grade metering-regulation stations”. EPA 

is also amending 40 CFR 98.233(r)(6)(ii) by referring to 

“metering-regulating stations” in place of “city gate” and 

to clarify that the emission factor for meter/regulator 

runs at all metering-regulating stations in Equation W-32 

is based on “transmission-distribution transfer stations” 
61 of 212 

This document is a prepublication version, signed by EPA Administrator Lisa P. Jackson on 

December 2, 2011. We have taken steps to ensure the accuracy of this version, but it is not the 

official version.

that were monitored over the years that constitute one 

complete cycle per 40 CFR 98.233(q)(8)(A). 

Lastly, we are revising Equation W-32 by revising 

definitions to EF, Es,i, and “Count” to reflect the change 

in terminology from “custody transfer” for above ground 

“metering-regulating” stations. We are also revising 

Equation W-32 to include a conversion factor to convert to 

hourly emissions. Also, equation W-32 is amended in 40 CFR 

98.233(r) so that the equation yields an EF in cubic feet 

per meter per hour to be used in Equation W-31 for above 

ground metering-regulating stations. Finally, the 

summation operator has been removed in Equation W-32 

because Es,i represents annual volumetric GHGi emissions at 

all T-D transfer stations, making the summation operator 

redundant. 

Volumetric Emissions. We are amending several 

provisions in 40 CFR 98.233(t). First, we are clarifying 

that reporters must calculate natural gas volumetric 

emissions at standard conditions by converting natural gas 

volumetric emissions at actual temperature and pressure to 

standard temperature and pressure. Next, the phrase “by 

converting actual temperature and pressure of natural gas 

emissions to standard temperature and pressure of natural 

gas” in 40 CFR 98.233(t)(2) was deleted because of 
62 of 212 

This document is a prepublication version, signed by EPA Administrator Lisa P. Jackson on 

December 2, 2011. We have taken steps to ensure the accuracy of this version, but it is not the 

official version.

redundancy. Next, EPA has changed standard condition to 60 

degree Fahrenheit and 14.7 psia; therefore, in Equations W33 and W-34, EPA is including these standard temperature 

and pressure values for Ts and Ps. Lastly, EPA is providing 

a ratio of 519.67/527.67 to convert volumetric emissions 

from 68°F to 60°F for reporters using 68 degrees Fahrenheit 

for standard temperature. 

GHG Volumetric Emissions. We are amending several 

provisions in 40 CFR 98.233(u). First, we are clarifying 

that reporters may determine the mole fraction of GHGs in 

natural gas by engineering estimate based on best available 

data unless EPA is requiring another method. Next, we are 

clarifying that when using a continuous gas composition 

analyzer, reporters must use an annual average of the 

values to determine the GHG mole fraction in produced 

natural gas. In addition, when reporters are not using a 

continuous gas composition analyzer, reporters must use an 

annual average gas composition based on the reporter’s most 

recent available sample analysis of the sub-basin category 

or facility, depending on the emission source, instead of 

the actual most recent gas composition based on available 

analysis in a sub-basin entity. 

Next, we are amending 40 CFR 98.233(u)(2)(ii) to 

clarify that reporters of onshore natural gas processing 
63 of 212 

This document is a prepublication version, signed by EPA Administrator Lisa P. Jackson on 

December 2, 2011. We have taken steps to ensure the accuracy of this version, but it is not the 

official version.

plants that solely fractionate a liquid stream, must use 

the GHG mole percent in feed natural gas liquid for all 

streams. This amendment addresses the lack of clarity in 

the final provisions on how natural gas processing plants 

that only fractionate liquid streams would determine their 

gas compositions. 

We are amending 40 CFR 98.233(u)(2)(iii) through 

(u)(2)(vii), to include 95 percent methane/1 percent CO2

default gas composition for the natural gas transmission 

compression, underground natural gas storage, LNG storage, 

and natural gas distribution industry segments and for LNG 

export facilities that receive gas from transmission 

pipelines unless specified otherwise in the Calculations 

for GHGs sections. Lastly, we are replacing the term 

“field” with the term “sub-basin category” as per the 

discussion in Section II.C of the September 9, 2011. 

GHG Mass Emissions. We are amending several 

provisions in 40 CFR 98.233(v). First, we are removing the 

phrase “at standard conditions” from the introductory text 

and the subscript “s,” and the word “standard” from the 

definition of parameter Masss,i because mass emissions do 

not need to be reported at standard conditions. Next, we 

are revising the definitions of parameters in Equation W-36 

to clarify that the equation also applies to N2O emissions. 
64 of 212 

This document is a prepublication version, signed by EPA Administrator Lisa P. Jackson on 

December 2, 2011. We have taken steps to ensure the accuracy of this version, but it is not the 

official version.

N2O emissions are calculated from stationary combustion and 

flares, and this edit is needed to convert the mass 

emissions of N2O to carbon dioxide equivalents of gas. 

Lastly, EPA has changed standard conditions to 60 degree 

Fahrenheit and 14.7 psia; therefore, the density values for 

CH4, CO2, and N2O at 68 degrees Fahrenheit were removed from 

the parameter ρi. 

EOR injection pump blowdown. We are amending two 

parameters in Equation W-37. First, we are removing the 

subscript “c” from the parameter Massc,i and the phrase “at 

critical conditions” from the definition of parameter 

Massc,i because mass emissions do not need to be reported at 

critical conditions. Second, we are amending the parameter 

GHGi and Massc,i, to read GHGCO2 and MassCO2, to clarify that 

Equation W-37 only calculates CO2 emissions. 

EPA is clarifying the data reporting requirements in 

40 CFR 98.236(c)(17) to state that annual emissions for 

each GHG, must be reported for each EOR pump. 

EOR hydrocarbon liquids dissolved CO2. We are amending 

the parameter MasssCO2 by removing the subscript “s” and the 

phrase “at standard conditions” from the definition of 

parameter Masss,CO2 because mass emissions do not need to be 

reported at standard conditions. 
65 of 212 

This document is a prepublication version, signed by EPA Administrator Lisa P. Jackson on 

December 2, 2011. We have taken steps to ensure the accuracy of this version, but it is not the 

official version.

EPA is clarifying the data reporting requirements in 

40 CFR 98.236(c)(18) to state that all parameters, 

including annual CO2 emissions, must be at a sub-basin 

level. 

Onshore Production and Distribution Combustion 

Emissions. EPA is making several amendments to the 

provisions in 40 CFR 98.233(z). 

First, we are clarifying that Calculation 

Methodologies in 40 CFR 98.233(z)(1) and (z)(2) apply to 

all stationary or portable equipment except external fuel 

combustion sources with a rated heat capacity equal to or 

less than 5 mmBtu/hr. In addition, 40 CFR 98.233(z)(1) and 

(z)(2) apply to all internal fuel combustion sources, with 

a rated heat capacity equal to or less than 1 mmBtu/hr (not 

compressor-drivers). EPA is clarifying that for units below 

the 5 mmBtu/hr and 1 mmBTU/hr threshold, outlined in 40 CFR 

98.233(z)(3) and (z)(4), reporters do not need to report 

combustion emissions or include these emissions for 

threshold determination in 40 CFR 98.231(a). Instead, 

reporters must report the type and number of each external 

fuel combustion unit and each internal fuel combustion unit 

below the equipment threshold. 

EPA is clarifying when owners or operators of onshore 

production and distribution facilities must use the methods 
66 of 212 

This document is a prepublication version, signed by EPA Administrator Lisa P. Jackson on 

December 2, 2011. We have taken steps to ensure the accuracy of this version, but it is not the 

official version.

in 40 CFR subpart C to calculate combustion-related 

emissions and when they must use methods outlined in 40 CFR 

98.233(z) to calculate combustion-related emissions. EPA is 

clarifying that facilities using subpart C to calculate 

emissions can use any Tier listed in subpart C. Regardless 

of the Tier used, facilities must follow the corresponding 

calculation, quality assurance, reporting, and 

recordkeeping requirements of that Tier. 

EPA is amending the requirements for units combusting 

field gas, process vent gas, a blend containing field gas 

or process vent gas, or natural gas that is not of pipeline 

quality or that has a high heat value of less than 950 Btu 

per standard cubic feet. In this action, EPA is allowing 

the use of company records for the purposes of calibration 

for this equipment. 

Next, EPA is including an engineering equation, W-39B, 

to determine the annual CH4 emissions from portable or 

stationary fuel combustion sources. We are also clarifying 

the summation operator to make the existing equation, W-39A 

that calculates annual CO2 emissions from portable or 

stationary fuel combustion sources, mathematically 

accurate. Additionally, we are also including a combustion 

efficiency parameter in Equation W-39A. 
67 of 212 

This document is a prepublication version, signed by EPA Administrator Lisa P. Jackson on 

December 2, 2011. We have taken steps to ensure the accuracy of this version, but it is not the 

official version.

We are making several amendments to Equation W-40. 

First, we are changing the parameter N2O to MassN2O because 

this equation calculates the annual N2O mass emissions from 

the combustion of a particular type of fuel. Second, we are 

amending an incorrect exponent to account for the 

conversion factor from kilograms to metric tons. Lastly, we 

are providing actual values in the definition of parameter 

HHV in Equation W-40. 

Accordingly, EPA is amending the data reporting 

requirements in 40 CFR 98.236(c)(19) for external fuel 

combustion sources with a rated heat capacity greater than 

5 mmBtu/hr , and internal fuel combustion sources 

(excluding a compressor-driver), with a rated heat capacity 

equal to or less than 1 mmBtu/hr, and internal fuel 

combustion sources. First, we are clarifying that for 

external fuel combustion sources with a rated heat capacity 

larger than 5mmBtu/hr, the emissions for each GHG must be 

reported by type of unit. Second, we are clarifying that 

for internal fuel combustion sources, with a rated heat 

capacity equal to or less than 1 mmBtu/hr (excluding a 

compressor-driver), only the cumulative number of units 

must be reported by type of unit. Lastly, we are clarifying 

that for internal fuel combustion units, the emissions for 

each GHG must be reported by type of unit. 
68 of 212 

This document is a prepublication version, signed by EPA Administrator Lisa P. Jackson on 

December 2, 2011. We have taken steps to ensure the accuracy of this version, but it is not the 

official version.

Monitoring and QA/QC Requirements. We are finalizing 

several amendments to the monitoring and QA/QC requirements 

in 40 CFR 98.234. 

First, we are amending the language in 40 CFR 

98.234(a)(1) by removing and reserving the text in 40 CFR 

98.234(a)(4) and combining it with 40 CFR 98.234(a)(1), 

thus resulting in one consolidated paragraph for optical 

gas imaging instrument provisions. We are also explicitly 

stating exceptions to the requirement under the Alternative 

work practice for monitoring equipment leaks. Those 

exceptions are 1) the monitoring frequency is annual and 2) 

the detection sensitivity is 60 grams per hour. In 

addition, EPA is requiring that the gas chosen during the 

instrument check must be methane. Finally, EPA is 

clarifying that video recordings are not required to be 

retained for the purposes of 40 CFR 98, subpart W. 

Next, we are amending the language in 40 CFR 

98.234(a)(2) to state that Method 21 compliant instruments 

may be used to monitor inaccessible emissions sources. It 

is not EPA’s intent here to require reporters to use unsafe 

methods to reach inaccessible emission sources using Method 

21 compliant equipment. Rather EPA is allowing the use of 

Method 21 compliant leak detection equipment where the 

reporter can access inaccessible sources using safe 
69 of 212 

This document is a prepublication version, signed by EPA Administrator Lisa P. Jackson on 

December 2, 2011. We have taken steps to ensure the accuracy of this version, but it is not the 

official version.

options, such as the use of a bucket truck. EPA still 

requires the use of optical imaging cameras to reach 

inaccessible emission sources where the reporter cannot use 

Method 21 compliant leak detection equipment safely. EPA 

allows the use of method 21 for all source types, although 

an optical gas imaging instrument must be used in cases 

where a reporter deems a source type inaccessible. EPA 

expects the reporters will use an optical gas imaging 

instrument in order to ensure safety when monitoring 

inaccessible source types. Lastly, based on questions 

raised by industry, we are clarifying in 40 CFR 

98.234(a)(5) the type of acoustic leak detection devices 

that may be used. In particular the “gun” type instrument, 

which is aimed at the equipment from a distance to detect 

the acoustic signal of leakage, is not an allowable 

instrument under this rule. This type of equipment cannot 

distinguish between external leakage to the atmosphere and 

internal, through-valve leakage, which acoustic leak 

detection devices are used for under this rule. EPA is 

also further specifying that the “stethoscope” type 

acoustic detector that senses through valve leakage when 

put in contact with the valve body, but does not have the 

leakage estimating correlations, is permissible for leak 

detection only under this rule. 
70 of 212 

This document is a prepublication version, signed by EPA Administrator Lisa P. Jackson on 

December 2, 2011. We have taken steps to ensure the accuracy of this version, but it is not the 

official version.

We are including an editorial revision in 40 CFR 

98.234(c) for calibrated bagging to specify that those 

using the calibrated bag for sampling, must ensure that the 

emissions are at a temperature below which the bag 

manufacturer specifies for safe handling. EPA is also 

clarifying in 40 CFR 98.234 (d)(3) that emission volumes 

determined using the high volume sampler can be converted 

to standard conditions using 40 CFR 98.233(t). Finally, we 

are revising Equation W-41 to insert missing variables “a” 

and “b” from the Peng Robinson equation. 

Data Reporting Requirements. The amendments to the 

reporting requirements for various emission source types 

have been are discussed under the corresponding emission 

source paragraphs in this section of the preamble. 

Additionally, EPA is making the following amendments to the 

general reporting requirements in 40 CFR 98.236. 

First, we are amending 40 CFR 98.236(b) to clarify 

that facilities reporting under the offshore petroleum and 

natural gas production industry segment must report 

emissions for each GHG, as applicable to the source type, 

for each emissions source type listed in the most recent 

Bureau of Ocean Energy Management and Regulatory 

Enforcement (BOEMRE) study. 
71 of 212 

This document is a prepublication version, signed by EPA Administrator Lisa P. Jackson on 

December 2, 2011. We have taken steps to ensure the accuracy of this version, but it is not the 

official version.

Next, we are clarifying that if a facility operates 

under more than one industry segment, reporters must report 

the data from each piece of equipment under the industry 

segment in which the equipment is most used. Additionally, 

we are clarifying that if a source type routes gas to a 

flare, reporters must report vented and flared emissions 

separately for each gas. These vented and flared emissions 

must be reported under the respective source type and not 

under the flare stack source type. 

Finally, EPA is including the reporting of average API 

gravity of the hydrocarbon liquids produced, average gas to 

oil ratio, and average low pressure separator pressure per 

oil sub-basin category for onshore production reporters. 

Records that must be retained. EPA is clarifying that 

records that must be retained under 40 CFR 98.3(g)(2)(i) of 

the general provisions must include an explanation of how 

company records, engineering estimation, or best available 

information are used to calculate each applicable parameter 

under this subpart. This requirement is already included 

in 40 CFR 98.3(g)(2)(i) and including this requirement in 

Subpart W provides further clarity on the records 

facilities are required to keep. 
72 of 212 

This document is a prepublication version, signed by EPA Administrator Lisa P. Jackson on 

December 2, 2011. We have taken steps to ensure the accuracy of this version, but it is not the 

official version.

Definitions. EPA is amending several definitions in 

40 CFR 98.238, and in some cases, adding and removing 

definitions in 40 CFR 98.238. 

Associated With a Single Well-Pad. We are including a 

definition for “associated with a single well-pad” to 

clearly demarcate the extent of the boundary of onshore 

production facilities. This definition more clearly 

portrays expresses EPA’s intent that the association be 

defined by the hydrocarbon stream from one or more wells 

located on a single well-pad. Where the point of 

combination is located off that single well-pad, the 

association with a single well-pad ends where the stream 

from a single well-pad is combined with streams from one or 

more additional single well-pads. Storage tanks located on 

a well pad are considered part of the onshore production 

industry segment. 

Distribution Pipeline. We are adding a definition for 

distribution pipelines to clarify our intent for coverage 

for the natural gas distribution industry segment. 

Facility With Respect to Natural Gas Distribution. We 

are revising the definition for facility with respect to 

natural gas distribution by replacing the term “metering 

stations, and regulating” with the term “meteringregulating” and by clarifying that the collection of all 
73 of 212 

This document is a prepublication version, signed by EPA Administrator Lisa P. Jackson on 

December 2, 2011. We have taken steps to ensure the accuracy of this version, but it is not the 

official version.

distribution pipelines and metering-regulating stations 

operated by an LDC within a single state must be included. 

Facility with respect to onshore petroleum and natural 

gas production. We are revising the definition for facility 

with respect to onshore production by clarifying that it 

includes all petroleum or natural gas equipment on a single 

well-pad or associated with a single well-pad and CO2 EOR 

operations that are under common ownership or common 

control including leased, rented, or contracted activities 

by an onshore petroleum and natural gas production owner or 

operator and that are located in a single hydrocarbon basin 

as defined in §98.238. 

Farm Taps. We are revising the definition for farm 

taps in 40 CFR 98.238 by removing the statement “[t]he gas 

may or may not be metered, but always does not pass through 

a city gate station” as this statement is unnecessary. 

Flare. We are adding a definition of flare, specific 

to subpart W, to address questions received during 

implementation of the 2010 final rule about what 

constitutes a flare. This definition clarifies that a 

flare may be either at ground level or elevated and that a 

flare may use an open or enclosed flame to combust waste 

gases without energy recovery. The intent of this 
74 of 212 

This document is a prepublication version, signed by EPA Administrator Lisa P. Jackson on 

December 2, 2011. We have taken steps to ensure the accuracy of this version, but it is not the 

official version.

definition is to include devices that combust waste gases 

without energy recovery. 

Forced Extraction of Natural Gas Liquids. We are 

adding a definition for forced extraction, as proposed, to 

limit the use of forced extraction to specific processes. 

With this definition, EPA is clarifying that “forced 

extraction of natural gas liquids” means removal of ethane 

or higher carbon number hydrocarbons existing in the vapor 

phase in natural gas, by removing ethane or heavier 

hydrocarbons derived from natural gas into natural gas 

liquids by means of a forced extraction process. Forced 

extraction processes include but are not limited to 

refrigeration, absorption (lean oil), cryogenic expander, 

and combinations of these processes. 

Gas Well. We are removing the definition of gas well 

from 40 CFR 98.238. Gas wells are defined within the 

revised definition of sub-basin category. 

Horizontal Well. We are including a definition for 

horizontal well in conjunction with the change from field 

level reporting to sub-basin category. With this 

definition, we are stating that a horizontal well means a 

well bore that has a planned deviation from primarily 

vertical to a primarily horizontal inclination or 
75 of 212 

This document is a prepublication version, signed by EPA Administrator Lisa P. Jackson on 

December 2, 2011. We have taken steps to ensure the accuracy of this version, but it is not the 

official version.

declination tracking in parallel with and through the 

target formation. 

Metering-regulating station. We are adding this 

definition to clarify that metering-regulating stations are 

stations that meter the flowrate, regulate the pressure, or 

both, of natural gas in a natural gas distribution 

facility. These do not include customer meters, customer 

regulators, or farm taps. 

Natural Gas. We are adding this definition, as 

proposed, to clarify that natural gas means a naturally 

occurring mixture or process derivative of hydrocarbon and 

non-hydrocarbon gases found in geologic formations beneath 

the earth’s surface, of which its constituents include, but 

are not limited to, methane, heavier hydrocarbons and 

carbon dioxide. Additionally, we are clarifying that 

natural gas may be field quality, pipeline quality, or 

process gas. 

Oil Well. We are removing the definition for oil well 

from 40 CFR 98.238. Oil wells are defined within the 

revised definition of sub-basin category. 

Pressure groups. We are adding a definition of 

pressure groups, as proposed, as applicable to each subbasin to clarify that pressure groups are: less than or 

equal to 25 psig; greater than 25 psig and less than or 
76 of 212 

This document is a prepublication version, signed by EPA Administrator Lisa P. Jackson on 

December 2, 2011. We have taken steps to ensure the accuracy of this version, but it is not the 

official version.

equal to 60 psig; greater than 60 psig and less than or 

equal to 110 psig; greater than 110 psig and less than or 

equal to 200 psig; and greater than 200 psig. The pressure 

in the context of pressure groups is either the well shutin pressure; well casing pressure; or you may use the 

casing-to-tubing pressure of one well from the same subbasin multiplied by the tubing pressure for each well in 

the sub-basin. 

Sub-Basin Category. We are including a definition for 

a sub-basin category in conjunction with the change in 

measurement from field to sub-basin level. Based on this 

definition, a sub-basin means a subdivision of a basin into 

the unique combination of wells with the surface 

coordinates within the boundaries of an individual county 

and subsurface completion in one or more of each of the 

following five formation types: oil, high permeability gas, 

shale gas, coal seam, or other tight reservoir rock. The 

distinction between high permeability gas and tight gas 

reservoirs shall be designated as follows: high 

permeability gas reservoirs with >0.1 millidarci 

permeability, and tight gas reservoirs with ≤0.1 millidarci 

permeability. Permeability for a reservoir type shall be 

determined by engineering estimate. Wells that produce from 

high permeability gas, shale gas, coal seam, or other tight 
77 of 212 

This document is a prepublication version, signed by EPA Administrator Lisa P. Jackson on 

December 2, 2011. We have taken steps to ensure the accuracy of this version, but it is not the 

official version.

reservoir rock are considered gas wells; gas wells 

producing from more than one of these formation types shall 

be classified into only one type based on the formation 

with the most contribution to production as determined by 

engineering knowledge. All wells that produce hydrocarbon 

liquids and do not meet the definition of a gas well in 

this sub-basin category definition are considered to be in 

the oil formation. All emission sources that handle 

condensate from gas wells in high permeability gas, shale 

gas, or tight reservoir rock formations are considered to 

be in the formation that the gas well belongs to and not in 

the oil formation. 

Transmission-Distribution (TD) transfer station. As 

proposed, EPA is adding a definition for Transmission 

Distribution (TD) transfer station to define what was 

previously termed “custody transfer” in the final rule. 

This definition was necessary to further clarify EPA’s 

intent, which was not for the term “custody transfer” to be 

defined in the context of ownership of gas transfer. The 

TD transfer station means a meter-regulating station where 

a local distribution company takes part or all of the 

natural gas from a transmission pipeline and puts it into a 

distribution pipeline. 
78 of 212 

This document is a prepublication version, signed by EPA Administrator Lisa P. Jackson on 

December 2, 2011. We have taken steps to ensure the accuracy of this version, but it is not the 

official version.

Transmission Pipeline. We are finalizing a definition 

as proposed for transmission pipeline to clarify that 

transmission pipelines are clearly designated as such by 

the Federal Energy Regulatory Commission for interstate 

transmission pipelines, individual States for intrastate 

transmission pipelines, and the Hinshaw exemption under the 

Natural Gas Act for Hinshaw transmission pipelines. 

Tubing diameter groups. We are finalizing a 

definition for tubing diameter groups, as proposed, to 

clarify that tubing diameter groups are: less than or equal 

to 1 inch; greater than 1 inch and less than 2 inch; and 

greater than or equal to 2 inch. 

Tubing systems. We are finalizing a definition of 

tubing systems, as proposed, to clarify that tubing systems 

means piping equal to or less than one half inch diameter 

as per nominal pipe size. 

Vertical Well. We are finalizing a definition for 

vertical wells, as proposed, to coincide with the change 

from field level reporting to sub-basin category, EPA is 

adding a distinction for calculating emissions from 

horizontal wells and vertical wells. With this definition, 

a vertical well means a well bore that is primarily 

vertical but might have some unintentional deviation or one 

or more intentional deviations to enter one or more 
79 of 212 

This document is a prepublication version, signed by EPA Administrator Lisa P. Jackson on 

December 2, 2011. We have taken steps to ensure the accuracy of this version, but it is not the 

official version.

subsurface targets that are off-set horizontally from the 

surface location, intercepting the targets either 

vertically or at an angle. 

Well Testing Venting and Flaring. We are finalizing, 

as proposed, a definition for well testing venting and 

flaring. This definition says that well testing venting 

and flaring means venting and/or flaring of natural gas at 

the time the production rate of a well is determined (i.e., 

the well testing) through a choke (an orifice restriction). 

Based on this revised definition, if well testing is 

conducted immediately after well completion or workover 

then it would be considered part of a completion or 

workover. 

Emission Factor Tables. We are amending several 

emission factors in subpart W in response to comments 

requesting that the emission factors be adjusted to reflect 

a consistent standard temperature and pressure used for 

calculation methodologies in 40 CFR 98.233. Specifically, 

we are revising all of the entries to 60 degrees Fahrenheit 

for Tables W-1A and W-2 through W-6 and revising the 

entries for “Low Continuous Bleed Pneumatic Device Vents”,

“

High Continuous Bleed Pneumatic Device Vents”, and

“

Intermittent Bleed Pneumatic Device Vents” to whole gas 

emission factors in Table W-1A. Additionally, we are 
80 of 212 

This document is a prepublication version, signed by EPA Administrator Lisa P. Jackson on 

December 2, 2011. We have taken steps to ensure the accuracy of this version, but it is not the 

official version.

revising the entries for “Leaker Emission Factors - 

Transmission-Distribution Transfer Station Components, Gas 

Service,” “Population Emission Factors - Below Grade 

Metering-Regulating Station Components, Gas Service,” 

“Population Emission Factors - Distribution Mains, Gas 

Service,” and “Population Emission Factors - Distribution 

Mains, Gas Service” to 60 degrees Fahrenheit. 

D. Responses to Major Comments Submitted on the Petroleum 

and Natural Gas Systems Source Category 

This section contains a brief summary of major 

comments and responses on the proposed amendments to 

subpart W published in GHGRP Corrections Proposal and the 

GHGRP Revisions Proposal. Responses to additional comments 

received on those proposals can be found in the document, 

“Mandatory Reporting of Greenhouse Gases – Technical 

Revisions to the Petroleum and Natural Gas Systems Category 

of the Greenhouse Gas Reporting Rule: EPA’s Response to 

Public Comments” see docket EPA-HQ-OAR-2011-0512. 

1. Pressure groupings. 

Comment: EPA received comments requesting two pressure 

ranges for calculating emissions from liquids unloading of 

gas wells in 40 CFR 98.233(f) as opposed to the September 

9, 2011 proposal, which proposed five pressure ranges, four 

bounded ranges between 0 – 200 psig and one unbounded range 
81 of 212 

This document is a prepublication version, signed by EPA Administrator Lisa P. Jackson on 

December 2, 2011. We have taken steps to ensure the accuracy of this version, but it is not the 

official version.

above 200 psig, for this source. Commenters also requested 

clarification as to whether the proposed pressure ranges 

would apply across the sub-basin, including both 

conventional and unconventional wells. Finally, commenters 

were unclear as to what pressure types were to be used for 

the pressure groupings, and requested clarification as to 

whether the groupings were based on surface pressure or a 

different type of pressure. 

Response: In response to the commenters first point, 

EPA has concluded that the five pressure ranges finalized 

in this action are appropriate for methodology 1 of 40 CFR 

98.233(f). Greenhouse gas emissions resulting from well 

liquids unloading , regardless of what type of reservoir or 

gas well is involved, must be reported in the pressure 

range based on shut-in pressure as defined in 40 CFR 98.238 

Definitions, Pressure Group. To avoid confusion, EPA is 

discontinuing the use of the terms “conventional” and 

“unconventional” because these terms have different 

meanings within the industry. The volume of gas released 

during an unloading is directly related to the wellhead 

pressure. EPA analyzed different numbers of pressure 

groupings and selected the optimal number of pressure 

groupings that resulted in minimal error while managing 

burden. In this action, reporters are to estimate emissions 
82 of 212 

This document is a prepublication version, signed by EPA Administrator Lisa P. Jackson on 

December 2, 2011. We have taken steps to ensure the accuracy of this version, but it is not the 

official version.

from one well with a unique tubing diameter grouping and 

pressure grouping combination in a sub-basin, and apply 

that value to all wells with that tubing diameter grouping 

and pressure grouping in that same sub-basin. 

Please refer to the Pressure Analysis document in EPAHQ-OAR-2011-0512-0016 for background on the analysis. EPA 

evaluated several different pressure groupings and their 

appropriateness to this emissions source, including the 

option suggested by the commenter, of two pressure 

groupings. Based on EPA’s analysis documented in the memo 

to the docket, industry’s suggestion of using only two 

pressure groupings would not provide the sufficient amount 

of accuracy in characterizing similar wells in the same 

sub-basin. Based on the five pressure groupings, EPA 

estimates that the minimum error would be about 30 percent 

from all wells that would report. However, if the number of 

ranges were reduced to 2 pressure groupings then the 

minimum error that would result from all wells is about 65 

percent. These error estimates are based on theoretical 

calculations, not accounting for error in meter reading and 

human error. Given the large error in the two pressure 

grouping scenario, EPA has determined that a 5 pressure 

grouping is the optimal for balancing burden to monitor 

versus the quality of data required to inform policy. 
83 of 212 

This document is a prepublication version, signed by EPA Administrator Lisa P. Jackson on 

December 2, 2011. We have taken steps to ensure the accuracy of this version, but it is not the 

official version.

To address the commenter’s question about whether or 

not the five pressure groupings would apply to emission 

sources other than the liquids unloading emission source, 

EPA believes that final the provisions provide sufficient 

clarification. In particular, EPA has clarified in 40 CFR 

98.233(f) that the five pressure groupings apply to the 

liquids unloading emissions source only. Furthermore, EPA 

has added a definition for pressure groupings in 40 CFR 

98.238 to explicitly state what those pressure groupings 

apply to the liquids unloading emission source. Pressure 

groupings apply only to gas wells for liquids unloading as 

specified in 40 CFR 98.233(f), and do not apply to the oil 

sub-basin formation. 

Finally, in response to the commenters’ request for 

clarity as to what types of pressures are used in the 

pressure grouping, EPA has finalized a definition for 

pressure groupings that clarifies that the well shut-in 

pressure just before liquids unloading, well casing 

pressure just before liquids unloading, or casing to tubing 

pressure of one well just before liquids unloading from the 

same sub-basin can be used for the pressure groupings. 

2. Data Reporting Requirements of 40 CFR 98.236(e).

Comment: EPA received comments on data reporting 

requirements for sub-basins in 40 CFR 98.236(e), 
84 of 212 

This document is a prepublication version, signed by EPA Administrator Lisa P. Jackson on 

December 2, 2011. We have taken steps to ensure the accuracy of this version, but it is not the 

official version.

specifically that API gravity, average gas to oil ratio and 

average low pressure separator pressure are not available 

or appropriate for applications to each of the sub-basin 

categories. The commenters assert for example, that dry gas 

production areas, such as coal-bed methane, will not have 

API gravity or gas to oil ratios to report for a sub-basin. 

Commenters further noted that this reporting requirement is 

applicable only to an oil production sub-basin category. 

Response: EPA agrees and has amended 40 CFR 98.236(e) 

to clearly indicate that only onshore petroleum and natural 

gas production reporters must report the average API 

gravity of their hydrocarbon liquids produced and the 

average gas to oil ratio per the oil formation sub-basin 

entity as defined in 40 CFR 98.238. 

In September 2011, EPA proposed additional data 

reporting requirements for onshore petroleum and natural 

gas production reporters to report the average API gravity 

of the hydrocarbon liquids produced, average gas to oil 

ratio, and average low pressure separator pressure per subbasin entity. With the exception of the low pressure 

separator pressure , this information is already known to 

operators. In order to pay royalties and taxes, producers 

routinely conduct analyses on their produced crude oil to 

determine the gas to oil ratio and API gravity. Therefore, 
85 of 212 

This document is a prepublication version, signed by EPA Administrator Lisa P. Jackson on 

December 2, 2011. We have taken steps to ensure the accuracy of this version, but it is not the 

official version.

EPA has determined that this requirement would impose no 

additional burden on the industry. 

3. Unique name or ID reporting requirements.

Comment: Several commenters representing the 

transmission compression industry segment noted that the 

proposed requirement to report unique ID’s for the 

transmission storage tank source type would not provide 

meaningful information and that the requirement was 

inappropriate because it did not apply to the monitored 

source. Furthermore, these commenters noted that in some 

cases, multiple tanks are linked to a single vent, and 

having a requirement to report a unique ID for each tank 

would not be useful, since the vent, not the tank, is the 

monitored source. These commenters stated that this 

requirement should be removed from the final rule. 

Response: EPA agrees with the commenters, in part, 

and has revised the data reporting requirements for the 

transmission storage tank emissions source in 40 CFR 98.236 

to more appropriately track the emissions at the vent and 

not the tank. In this action, 40 CFR 98.236(c)(9)(iii) has 

been clarified to state that a unique name or ID shall be 

assigned to the vent line. 

To meet the requirements of the 2010 final rule, which 

require reporting for each tank, owners and operators need 
86 of 212 

This document is a prepublication version, signed by EPA Administrator Lisa P. Jackson on 

December 2, 2011. We have taken steps to ensure the accuracy of this version, but it is not the 

official version.

to have a mechanism for tracking emissions from each 

storage tank. Further, to meet the reporting requirements, 

and requirements for resubmission of an annual GHG report 

in the event that EPA or the facility owner or operator 

identifies a substantive error (see 40 CFR 98.3(h)), owners 

and operators need to have a mechanism to assign the 

emissions they reported from an individual tank to the 

entry that they include in the electronic GHG Reporting 

tool (e-GGRT) for that same tank. For this reason, EPA has 

determined that the assignment of a unique ID is not new, 

nor does it introduce any new requirement that was not 

already required by the 2010 final rule. Rather this 

addition is providing clarification of the existing 

reporting requirements. Therefore, in this action, EPA is 

finalizing the requirement to report a unique name or ID 

number for vents in transmission storage tanks in 40 CFR 

98.236 (c)(9), as well as glycol dehydrators in the natural 

gas processing industry segment in 40 CFR 98.236 (c)(4), 

acid gas removal vents in the natural gas processing 

industry segment in 40 CFR 98.236(c)(3), and flare stacks 

in the onshore natural gas processing industry segment in 

40 CFR 98.236(c)(12). EPA is also finalizing the 

requirement to report the unique name or ID for the unique 

physical volume for blowdowns in 40 CFR 98.236 (c)(7) for 
87 of 212 

This document is a prepublication version, signed by EPA Administrator Lisa P. Jackson on 

December 2, 2011. We have taken steps to ensure the accuracy of this version, but it is not the 

official version.

transmission compression, gas processing, and LNG import 

and export industry segments. 

To address the commenters comment that the unique name 

or ID is unnecessary for the transmission storage tanks 

emission source, EPA believes that this information is 

critical and has finalized this provision for other 

emissions sources including the flare emissions source and 

for unique blowdown physical volumes. In addition, EPA 

believes that these particular emission sources are not 

mobile and are generally stationary at a given facility. 

For example, for a source such as transmission storage 

tanks, the unique ID would inform EPA on where emissions 

are occurring, and over a time period of several years, 

would inform the Agency of the emissions trends associated 

with that particular emissions source at the facility. 

Comment: EPA received comment specific to the 

reporting of a unique name or ID for the gas to liquid 

separators in the onshore production industry segment. 

Commenters noted that the proposed requirements to report 

unique ID will have no impact on the current emissions 

inputs or data quality, and are contradictory to industry’s 

efforts to work with EPA to complete an accurate GHG 

inventory within a manageable reporting burden and 

resources. Additionally, the commenter asserted that 
88 of 212 

This document is a prepublication version, signed by EPA Administrator Lisa P. Jackson on 

December 2, 2011. We have taken steps to ensure the accuracy of this version, but it is not the 

official version.

creating unique equipment identifiers neither adds to the 

level of accuracy of calculated emissions, nor does it 

provide information that is not already available through 

the currently reported individual equipment counts and 

reported CO2 and CH4 emissions totals that are already part 

of the GHGRP. In onshore production, the commenter contends 

that the identifier data requested by EPA will not be 

usable at the individual equipment level due to the dynamic 

nature of the sector and the fact that the identifiers may 

be tied to well names or locations and hence be different 

every year due to frequent equipment movement, change-outs 

and replacements that routinely occur at oil and gas well 

sites. 

Response: EPA agrees that for the onshore production 

segment, a unique name or ID number may be difficult to 

assign for portable equipment that may move from one 

location to another. 

EPA initially proposed data reporting requirements of 

unique name or ID number in the onshore production industry 

segment for the following emission sources; acid gas 

removal units, glycol dehydrators, wellhead separators or 

storage tanks, flare stacks, and EOR injection pumps. 

However, after evaluating the comments received, EPA 

believes that reporting of these particular emission 
89 of 212 

This document is a prepublication version, signed by EPA Administrator Lisa P. Jackson on 

December 2, 2011. We have taken steps to ensure the accuracy of this version, but it is not the 

official version.

sources in the onshore production industry segment, which 

has a definition of facility at the basin level, would be 

sufficient without a unique name or ID , although some 

information to track emissions from specific pieces of 

equipment over time could be lost, because the data will 

ultimately be reported at the facility level. EPA agrees 

with the commenter that tracking of a particular emission 

source that may be moved from one site to the next may pose 

a problem to certain reporters who would find it difficult 

to track an emission source to this level. Onshore 

producers may often replace equipment in a process with 

other equipment either for maintenance purposes or to size 

the equipment as the well production rate varies over time. 

Given these issues that are unique to onshore production 

segment, therefore EPA is not requiring unique name or ID 

number in onshore production. EPA recognizes that removing 

this requirement for onshore production could potentially 

result in the loss of equipment-specific information that 

could be useful for future policy analysis and we may 

continue to evaluate this for future rulemakings. 

 

4. Transmission-distribution transfer station reporting.

Comment: Commenters generally agreed with the proposed 

definition for transmission – distribution transfer station 
90 of 212 

This document is a prepublication version, signed by EPA Administrator Lisa P. Jackson on 

December 2, 2011. We have taken steps to ensure the accuracy of this version, but it is not the 

official version.

proposed in the GHGRP Revisions Proposal. However, 

commenters stated that the proposed definition for 

transmission-distribution transfer station would require 

many more stations to be included in the leak detection 

survey requirement, and that it would be an unreasonable 

burden. In addition, commenters noted that the stations 

that would be surveyed are small and remote stations and 

this would lead to an added burden to survey for leaks. 

Finally, commenters urged EPA to adopt a threshold to 

exclude small stations from monitoring for GHG emissions. 

One commenter, specifically noted that one of their member 

companies completed surveys of 162 stations in 2011, and 

out of 32,400 components measured, only 18 leaking 

components were found. The commenter noted that they 

surveyed their members in October 2011 and received 

responses from 42 larger member LDCs. Of those 42 LDCs, 

that the commenter stated that a total of 20,781 stations 

would appear to fall within the final definition for 

transmission – distribution stations. One commenter 

specifically suggested having a percentage of the stations 

report and using that percentage to forecast emissions for 

the other stations. Further, several other commenters 

suggested using a threshold to reduce the number of leak 

surveys required. 
91 of 212 

This document is a prepublication version, signed by EPA Administrator Lisa P. Jackson on 

December 2, 2011. We have taken steps to ensure the accuracy of this version, but it is not the 

official version.

Response: EPA notes that the number of reporters 

(i.e., LDCs) that EPA estimated would be reporting under 

the natural gas distribution industry segment under subpart 

W has not changed. Because this industry segment has a 

high level of uncertainty in the context of knowing the 

exact number of stations that would be covered under the 

rule, EPA would like to note that based on the limited 

information submitted by the commenter, it could be a 

possibility that the number of stations covered under the 

subpart W rule (75 FR 74458) between the 2010 final rule 

and what is being finalized in this action may have 

increased. It was not EPA’s intent to increase the number 

of surveys required. Therefore, after considering the two 

suggestions by commenters, EPA is finalizing an option that 

would allow facilities to conduct a leak detection survey 

once in any five consecutive calendar years for each 

station. EPA added the five consecutive year leak 

detection period to potentially coincide with reporters’ 

existing inspection requirement under DOT regulations. 

Therefore, the annual burden to reporters will not increase 

as a result of this revision. See TransmissionDistribution Transfer Station docket memo in docket # EPAHQ-OAR-2011-0512. 
92 of 212 

This document is a prepublication version, signed by EPA Administrator Lisa P. Jackson on 

December 2, 2011. We have taken steps to ensure the accuracy of this version, but it is not the 

official version.

 In this action, EPA is amending 40 CFR 98.233(q)(8) 

by allowing each above grade transmission-distribution 

transfer station the option to conduct a leak detection 

survey at least once in any five consecutive calendar 

years, with a minimum of 20 percent of their total number 

of stations being leak surveyed annually. Reporters 

choosing to use this option would use a five year rolling 

average of their transmission-distribution transfer station 

leaking component counts to calculate emissions. In 

accordance with the calculation requirements, these 

reporters would also define in their monitoring plan how 

the annual leak surveys represent cross sections of the 

total number of stations. 

Furthermore, EPA evaluated Department of 

Transportation (DOT) regulations for comparison in the 

context of monitoring frequency. As provided in the 

November 2010 docket memorandum “Understanding the 

Substance of DOT Regulations and Comparing them to the 

Subpart W Requirements,” DOT requires leak detection 

surveys annually for more populated areas and every five 

years for less populated locations. Although the DOT 

regulations covering various stations are not duplicative 

of EPA regulations under the Greenhouse Gas Reporting 

Program, providing the option to align the survey 
93 of 212 

This document is a prepublication version, signed by EPA Administrator Lisa P. Jackson on 

December 2, 2011. We have taken steps to ensure the accuracy of this version, but it is not the 

official version.

frequencies for both requirements may reduce burden for 

some reporters. EPA added the five consecutive year leak 

detection period to potentially coincide with reporters’ 

leak inspection requirement under DOT regulations in order 

to give reporters the opportunity to fulfill Subpart W 

requirements during the regular DOT survey or maintenance 

visit. 

In response to the commenters’ assertion that the 

final definition for transmission – distribution transfer 

stations disproportionately covers stations that are small 

and remote, and in response to the commenters’ suggestion 

to implement a threshold by which small stations would be 

exempt from being surveyed for leaks, EPA disagrees that 

the size of the station should impact whether leaks are 

surveyed because small stations in remote locations are 

potentially large sources of emissions, for example, due to 

aging equipment and or potentially infrequent operator 

maintenance. 

DOT regulations focus on public safety, and as such 

facilities near business districts are inspected annually. 

Conversely, facilities farther away from business districts 

may be inspected less frequently and receive less frequent 

and less consistent maintenance attention, increasing the 

chance that small or remote facilities are large emitters. 
94 of 212 

This document is a prepublication version, signed by EPA Administrator Lisa P. Jackson on 

December 2, 2011. We have taken steps to ensure the accuracy of this version, but it is not the 

official version.

Therefore, EPA decided not to exclude remote stations. In 

this action, EPA is finalizing an option for transmissiondistribution transfer stations that allows for surveying 

stations over a five year period as opposed to surveying 

all stations annually. Thus the annual burden is not 

increased and the necessary data is collected over a longer 

period of time. 

5. Associated with a single well-pad. 

Comment: EPA received several comments requesting 

clarification on the intent of the proposed definition of 

“associated with single well-pad” in 40 CFR 98.238. 

Commenters submitted several diagrams depicting various 

configurations of equipment associated with the onshore 

production industry segment and requested EPA’s 

confirmation of their understanding of which types of 

equipment would fall under the definition for “associated 

with a well-pad.” 

Response: In the proposed rule, the definition stated 

that onshore production storage tanks off of a well pad 

were included in the equipment that was considered to be 

associated with a well pad. After considering the comments 

received, EPA is amending the proposed definition of 

“associated with a single well-pad” in 40 CFR 98.238 to 

clarify that onshore production reporters do not report 
95 of 212 

This document is a prepublication version, signed by EPA Administrator Lisa P. Jackson on 

December 2, 2011. We have taken steps to ensure the accuracy of this version, but it is not the 

official version.

emissions from separators or tanks that receive oil from 

combined streams from multiple well-pads that are not on a 

single well-pad or associated with a single well-pad. 

However, under 40 CFR 98.233(j), onshore production 

reporters must report emissions from separators or tanks 

that are on a single well-pad or associated with a single 

well-pad. 

6. Equipment threshold for internal combustion engines.

Comment: In the GHGRP Revisions Proposal, EPA 

solicited comments on whether a 1 MMBtu/hr is sufficient to 

exclude all temporary and small (not compressor-drivers) 

internal combustion equipment. EPA received comments 

stating that a similar threshold to that which was in the 

2010 final rule for external combustion devices should be 

applied to all internal combustion devices. Several 

commenters representing the natural gas distribution 

industry segment agreed with the proposal, but requested 

that the 1 mmBtu/hr threshold also be applied to natural 

gas engines. Further, commenters representing the onshore 

production industry segment noted that lease fuel is 

reported by the Energy Information Administration (EIA) 

which could be used to sufficiently characterize combustion 

emissions from devices on well pads and therefore internal 
96 of 212 

This document is a prepublication version, signed by EPA Administrator Lisa P. Jackson on 

December 2, 2011. We have taken steps to ensure the accuracy of this version, but it is not the 

official version.

combustion devices below 5 MMBtu/hr should not be required 

to be reported. 

Response: EPA disagrees that a threshold of 5 MMBtu 

should be applied to internal combustion devices, as was 

done for external combustion devices in the November 2010 

final rule for subpart W. In this action, EPA is finalizing 

a threshold of 1 MMBtu/hr threshold in 40 CFR 98.233(z) for 

internal combustion equipment. EPA has also clarified in 

the final provisions for this rule that this 1mmBtu 

threshold does not apply to compressor-drivers. 

In considering potential equipment thresholds for 

internal combustion engines (not compressor-drivers), EPA 

collected and reviewed data on the horsepower rating of 

small, portable internal combustion engines that may be 

brought to a wellhead for periodic maintenance and 

construction. Such equipment can include electric 

generators for arc welding, electric generators powering 

portable flood-lighting, and electrical generators or 

gasoline engines powering air compressors (for sand 

blasting or pneumatic tools). For lighting, the industrial 

generators were almost exclusively below 12 horsepower 

(hp), with the highest found being 13.9 hp. For welding 

machines, we assumed that operators would use standard 

portable generators, since specific information on these 
97 of 212 

This document is a prepublication version, signed by EPA Administrator Lisa P. Jackson on 

December 2, 2011. We have taken steps to ensure the accuracy of this version, but it is not the 

official version.

types of machines was scarce. Most portable industrial 

generators are rated between 15–40 hp, with the largest one 

found being 67 hp. As a result, EPA determined that a 1 

mmBtu/hour threshold, which equates to 393 hp, will exclude 

these smaller internal combustion devices. EPA has also 

determined that a 1 mmBtu/hour threshold may exclude a 

significant number of internal combustion engines on 

wellhead compressors, and is thus not applying this 

threshold to compressor-drivers. The equipment that would 

be excluded, if the threshold were raised above 1 mmBtu 

could include drilling rigs, workover rigs and hydraulic 

fracture pump engines, for example. EPA deems it necessary 

to collect data on these compressors to inform future 

policy because they are potentially large source of 

emissions and also there is not sufficient and reliable 

data available on these types of emissions sources. In 

response to the commenters’ assertion that the information 

is reported by the EIA and therefore is not necessary to be 

reported under the greenhouse gas reporting rule, the EIA 

data is reported on a voluntary basis and the requirements 

for reporting are not standardized. As a result, the data 

available through EIA is not sufficiently accurate to 

exclude combustion devices from reporting. 
98 of 212 

This document is a prepublication version, signed by EPA Administrator Lisa P. Jackson on 

December 2, 2011. We have taken steps to ensure the accuracy of this version, but it is not the 

official version.

Regarding the Commenters’ request for the same 5 

mmBtu/hour threshold for internal combustion as applied to 

external combustion, EPA is not accepting this change, 

because it could potentially exclude virtually all wellhead 

compressors and engines, including those associated from 

drilling rigs which are large sources of GHG emissions. 

Comments on the subpart W proposed rule (75 FR 18608) 

included detailed itemization of heaters on tanks, 

separators, dehydrators and pipelines, often for winter 

freeze protection, with estimated numbers of these external 

combustion devices. From this information, EPA developed 

the 5 mmBtu/hour threshold to exclude reporting of 

emissions from these many sources which are not necessarily 

operated all year long and for which detailed records are 

not maintained on when winter heating is turned on and off, 

often by automated temperature controls. Similar data was 

not provided for internal combustion engines, and EPA does 

not have a good public record of the number of these 

engines or their typical duty. 

7. Reporting 2011 data under amended rule. 

Comment: Several commenters requested that EPA resolve 

certain areas of uncertainty for calendar year 2011 data 

collection in the context of when the proposed revisions 

and technical corrections would be finalized for 40 CFR 
99 of 212 

This document is a prepublication version, signed by EPA Administrator Lisa P. Jackson on 

December 2, 2011. We have taken steps to ensure the accuracy of this version, but it is not the 

official version.

part 98, subpart W. Specifically, API raised concerns about 

two emissions sources; gas well venting during completions 

and workovers with hydraulic fracturing, and well venting 

for liquids unloading. API requested that for these two 

emission sources reporters be allowed the option to collect 

data in 2012 to meet the 2011 reporting requirements. 

 Response: EPA agrees that for the emission sources 

noted by the commenter; gas well venting from completions 

and workovers with hydraulic fracturing, and the well 

venting for liquids unloading emission source types, that 

reporters may use 2012 data collected prior to September 

28, 2012 for reporting for the 2 year period – 2011 – 2012. 

Based on the provisions in the final rule for subpart 

W published in November 2010, reporters are to collect data 

every other year for use in the calculation methodologies 

outlined in the rule. Because of the timing in finalizing 

the technical corrections and technical revisions to 

subpart W, EPA believes that it would be appropriate for 

reporters to be allowed to use 2012 data collected prior to 

September 28, 2012 for reporting for the 2 year period – 

2011 – 2012. EPA believes that for this first two years of 

data collection for these emission sources that this would 

fall within the procedures for estimating missing data in 

40 CFR 98.235. In addition, as previously mentioned, the 
100 of 212 

This document is a prepublication version, signed by EPA Administrator Lisa P. Jackson on 

December 2, 2011. We have taken steps to ensure the accuracy of this version, but it is not the 

official version.

measurement taken for the 2011-2012 data collection 

requirement must be taken in sufficient time to be reported 

by the September 28, 2011 reporting deadline for facilities 

reporting for onshore production. Where applicable, EPA 

asserts that reporters may use the procedures available in 

40 CFR 98.235 for estimating missing data. 

8. Blowdown vent stacks: emergency blowdown.

Comment: Commenters noted ambiguity with the proposed 

revisions to account for emergency blowdowns and requested 

that EPA clarify that emergency events are excluded from 

blowdown vent stack emissions reporting. Commenters 

further suggested that EPA delete reporting of emissions 

from emergency blowdowns. 

Response: EPA’s intent is not to cover the blowdowns 

that are automatically monitored by a computer system which 

performs numerous actions for accident protection. EPA’s 

intent is to cover those blowdown events that require human

or manned intervention. To clarify this intent, Section 

98.233 (i) has been amended to clarify that blowdown vent 

emissions must include blowdowns from depressurizing 

equipment to reduce system pressure for planned or 

emergency shutdowns resulting from human intervention or to 

take equipment out of service for maintenance (excluding 
101 of 212 

This document is a prepublication version, signed by EPA Administrator Lisa P. Jackson on 

December 2, 2011. We have taken steps to ensure the accuracy of this version, but it is not the 

official version.

depressurizing to a flare, over-pressure relief, operating 

pressure control venting, etc.). Any equipment blowdown 

initiated by operator intervention (as opposed to automated 

controls that function in the absence of operator 

intervention), allows the operator to document the 

necessary data to determine the blowdown volume. In other 

words, if any instrument indicates that equipment needs to 

be taken out of service for any reason including what an 

operator might consider an emergency, and the operator 

actuates the automatic controls that isolate that equipment 

and opens the blowdown vent, then the operator can 

reasonably document what unique physical volume is isolated 

and depressurized, and what the starting and ending 

pressures are. 

The blowdown events that are excluded include controls 

which cause venting in the absence of any operator presence 

or interaction. Examples include over-pressure relief 

valves, operational pressure controls, or automated 

emergency shutdown that includes opening vents to isolate 

and depressurize equipment without any human intervention. 

9. Addition of oil formation type in the sub-basin 

category definition. 

Comment: In September 2011, EPA proposed a definition 

for sub-basin category to replace the November 2010 
102 of 212 

This document is a prepublication version, signed by EPA Administrator Lisa P. Jackson on 

December 2, 2011. We have taken steps to ensure the accuracy of this version, but it is not the 

official version.

delineation of wells within a basin according to fields. 

Commenters were supportive of the definition but suggested 

some modifications to the structure of the definition. For 

example, commenters pointed out that there was no formation 

defined for oil production. There are emission sources such 

as storage tanks that have to report emissions by sub-basin 

category. However, wells that produce oil and are not 

located in one of the four gas formations (shale gas, tight 

reservoir rock, coal seam, and conventional gas) were not 

represented in the September 2011 definition of the subbasin category. Commenters requested that an oil formation 

type be added to the sub-basin category definition. 

Response: EPA agrees with the commenters and has added 

oil formation type to the definition of sub-basin category 

in 40 CFR 98.238. Any well that produces hydrocarbon 

liquids and is not located in one of the four gas 

formations is now designated as oil formation. EPA notes 

that hydrocarbon liquids produced from wells in the gas 

formation (i.e. condensate) has to be accounted for in the 

respective gas formation and not the oil formation. The 

emission characteristics of hydrocarbon liquids produced in 

gas formations are different from hydrocarbon liquids 

produced in oil formations. Furthermore, EPA has removed 

the November 2010 definitions of oil wells and gas wells, 
103 of 212 

This document is a prepublication version, signed by EPA Administrator Lisa P. Jackson on 

December 2, 2011. We have taken steps to ensure the accuracy of this version, but it is not the 

official version.

since these were in conflict with the definition of subbasin category. The November 2010 definitions for oil and 

gas wells were linked to the zones or reservoirs from which 

they were producing. However, the sub-basin category 

definition uses formation type. To keep all definitions 

interrelated and avoid conflicts EPA now defines a gas well 

as one which produces from a gas formation, and an oil well 

as one which produces from an oil formation in the subbasin category definition. 

10. Dehydrators owned and operated by third parties. 

Comment: EPA has received comments questioning the 

treatment of equipment such as a dehydrator located on a 

well-pad, but owned and operated by the gas processor, not 

the producer. One commenter noted that in the September 

2011 proposal under §98.230(a)(2), dehydrators are still 

referenced in the onshore petroleum and natural gas 

production industry segment. This commenter then stated 

that dehydrators located on a well-pad and owned and 

operated by a gas processor should not report under onshore 

natural gas production because the gas processor is not a 

production owner or operator. 

Response: The facility definition for onshore 

production in 40 CFR 98.238 is defined as all petroleum or 

natural gas equipment on a single well-pad or associated 
104 of 212 

This document is a prepublication version, signed by EPA Administrator Lisa P. Jackson on 

December 2, 2011. We have taken steps to ensure the accuracy of this version, but it is not the 

official version.

with a single well-pad and CO2 EOR operations that are under 

common ownership or common control including leased, 

rented, or contracted activities by an onshore petroleum 

and natural gas production owner or operator and that are 

located in a single hydrocarbon basin. Reporters need to 

evaluate their situation against that definition to make a 

determination regarding the applicability of a dehydrator. 

III. Statutory and Executive Order Reviews 

A. Executive Order 12866: Regulatory Planning and Review 

and Executive Order 13563: Improving Regulation and 

Regulatory Review 

This action is not a "significant regulatory action" 

under the terms of Executive Order 12866 (58 FR 51735, 

October 4, 1993) and is therefore not subject to review 

under Executive Orders 12866 and 13563 (76 FR 3821, January 

21, 2011). 

B. Paperwork Reduction Act

This action finalizes amendments to reporting 

methodologies in subpart W and amendments to clarify 

monitoring methodologies and data reporting requirements. 

In many cases, the amendments to the reporting requirements 

do not increase reporting burden but rather, ensure that 

the reporting requirements conform more closely to current 

industry practices. Therefore, the amendments to the 
105 of 212 

This document is a prepublication version, signed by EPA Administrator Lisa P. Jackson on 

December 2, 2011. We have taken steps to ensure the accuracy of this version, but it is not the 

official version.

information collection requirements have been submitted for 

approval to the Office of Management and Budget (OMB) under 

the Paperwork Reduction Act, 44 U.S.C. 3501 et seq. The 

Information Collection Request (ICR) document has been 

assigned EPA ICR number 2376.05. 

The Office of Management and Budget has previously 

approved the information collection requirements contained 

in the existing rules, 40 CFR part 98 subpart W (75 FR 

74458), under the provisions of the Paperwork Reduction 

Act, 44 U.S.C. 3501 et seq. and has assigned OMB control 

number 2060-0651 and 2060-0650 respectively. The OMB 

control numbers for EPA's regulations in 40 CFR are listed 

in 40 CFR Part 9. Burden is defined at 5 CFR 1320.3(b). 

An agency may not conduct or sponsor, and a person is 

not required to respond to, a collection of information 

unless it displays a currently valid OMB control number. 

C. Regulatory Flexibility Act(RFA)

The Regulatory Flexibility Act (RFA) generally 

requires an agency to prepare a regulatory flexibility 

analysis of any rule subject to notice and comment 

rulemaking requirements under the Administrative Procedure 

Act or any other statute unless the agency certifies that 

the rule will not have a significant economic impact on a 

substantial number of small entities. Small entities 
106 of 212 

This document is a prepublication version, signed by EPA Administrator Lisa P. Jackson on 

December 2, 2011. We have taken steps to ensure the accuracy of this version, but it is not the 

official version.

include small businesses, small organizations, and small 

governmental jurisdictions. 

For purposes of assessing the impacts of this action 

on small entities, small entity is defined as: (1) a small 

business as defined by the Small Business Administration’s 

(SBA)regulations at 13 CFR 121.201; (2) a small 

governmental jurisdiction that is a government of a city, 

county, town, school district or special district with a 

population of less than 50,000; and (3) a small 

organization that is any not-for-profit enterprise which is 

independently owned and operated and is not dominant in its 

field. 

After considering the economic impacts of this action 

on small entities, I certify that this action will not have 

a significant economic impact on a substantial number of 

small entities. In determining whether a rule has a 

significant economic impact on a substantial number of 

small entities, the impact of concern is any significant 

adverse economic impact on small entities, since the 

primary purpose of the regulatory flexibility analyses is 

to identify and address regulatory alternatives “which 

minimize any significant economic impact of the rule on 

small entities” 5 U.S.C. 603 and 604. Thus, an agency may 

certify that a rule will not have a significant economic 
107 of 212 

This document is a prepublication version, signed by EPA Administrator Lisa P. Jackson on 

December 2, 2011. We have taken steps to ensure the accuracy of this version, but it is not the 

official version.

impact on a substantial number of small entities if the 

rule relieves regulatory burden, or otherwise has a 

positive economic effect on all of the small entities 

subject to the rule. 

As part of the process for finalization of the subpart 

W rule (75 FR 74458), EPA undertook specific steps to 

evaluate the effect of that final rule on small entities. 

Under that final rule for subpart W (75 FR 74458) EPA 

conducted a screening assessment comparing compliance costs 

to onshore petroleum and natural gas industry specific 

receipts data for establishments owned by small businesses. 

The results of that screening analysis, as detailed in the 

preamble to the final rule for subpart W (75 FR 74482), 

demonstrated that the cost-to-sales ratios were less than 

one percent for establishments owned by small businesses 

that EPA considered most likely to be covered by the 

reporting program. The results of that analysis can be 

found in the preamble to the final rule (75 FR 74485). 

Based on the final amendments in this action, EPA has 

increased flexibility in the selection of methods used for 

calculating GHG’s by providing alternative methods where 

appropriate, revised specific methods in the rule to 

clarify requirements, clarified specific provisions related 

to applicability to clearly state EPA’s intent, corrected 
108 of 212 

This document is a prepublication version, signed by EPA Administrator Lisa P. Jackson on 

December 2, 2011. We have taken steps to ensure the accuracy of this version, but it is not the 

official version.

technical errors in equations, and revised specific 

provisions to further clarify what must be reported and 

where measurement must be taken at a facility. These 

revisions do not add additional burden on reporters but 

maintain the data quality of the information being reported 

to EPA, and in many cases reduce burden. We have therefore 

concluded that this action will relieve regulatory burden 

for all affected small entities. 

D. Unfunded Mandates Reform Act(UMRA)

Title II of the Unfunded Mandates Reform Act of 1995 

(UMRA), 2 U.S.C. 1531–1538, requires Federal agencies, 

unless otherwise prohibited by law, to assess the effects 

of their regulatory actions on State, local, and Tribal 

governments and the private sector. Federal agencies must 

also develop a plan to provide notice to small governments 

that might be significantly or uniquely affected by any 

regulatory requirements. The plan must enable officials of 

affected small governments to have meaningful and timely 

input in the development of EPA regulatory proposals with 

significant Federal intergovernmental mandates and must 

inform, educate, and advise small governments on compliance 

with the regulatory requirements. 

These final rule amendments do not contain a Federal 

mandate that may result in expenditures of $100 million or 
109 of 212 

This document is a prepublication version, signed by EPA Administrator Lisa P. Jackson on 

December 2, 2011. We have taken steps to ensure the accuracy of this version, but it is not the 

official version.

more for state, local, and tribal governments, in the 

aggregate, or the private sector in any one year. Thus, 

the final rule amendments are not subject to the 

requirements of section 202 and 205 of the UMRA. This 

action is also not subject to the requirements of section 

203 of UMRA because it contains no regulatory requirements 

that might significantly or uniquely affect small 

governments. 

E. Executive Order 13132: Federalism

This action does not have federalism implications. It 

will not have substantial direct effects on the States, on 

the relationship between the national government and the 

States, or on the distribution of power and 

responsibilities among the various levels of government, as 

specified in Executive Order 13132. 

Few, if any, State or local government facilities 

would be affected by the provisions in this final rule. 

This regulation also does not limit the power of States or 

localities to collect GHG data and/or regulate GHG 

emissions. Thus, Executive Order 13132 does not apply to 

this action. 

F. Executive Order 13175: Consultation and Coordination 

with Indian Tribal Governments
110 of 212 

This document is a prepublication version, signed by EPA Administrator Lisa P. Jackson on 

December 2, 2011. We have taken steps to ensure the accuracy of this version, but it is not the 

official version.

This action does not have tribal implications, as 

specified in Executive Order 13175 (65 FR 67249, November 

9, 2000). During the finalization of subpart W in 2010 (75 

FR 74458), EPA undertook the necessary steps to determine 

the impact of those rules on tribal entities and provided 

supporting documentation demonstrating the results of the 

Agency’s analyses. And in several cases, the amendments to 

the reporting requirements would potentially reduce the 

reporting burden. Thus, Executive Order 13175 does not 

apply to this action. 

Although Executive Order 13175 does not apply to this 

action, EPA consulted with tribal officials during the 

development of the subpart W (75 FR 74458). A summary of 

the concerns raised during that consultation and EPA’s 

response to those concerns is provided in Sections VIII.E 

and VIII.F of the preamble to the 2009 final rule and 

Section IV.F of the preamble to the 2010 final rule for 

subpart W (75 FR 74485). 

G. Executive Order 13045: Protection of Children from 

Environmental Health Risks and Safety Risks

EPA interprets Executive Order 13045 (62 FR 19885, 

April 23, 1997) as applying only to those regulatory 

actions that concern health or safety risks, such that the 

analysis required under section 5-501 of the Executive 
111 of 212 

This document is a prepublication version, signed by EPA Administrator Lisa P. Jackson on 

December 2, 2011. We have taken steps to ensure the accuracy of this version, but it is not the 

official version.

Order has the potential to influence the regulation. This 

action is not subject to Executive Order 13045 because it 

does not establish an environmental standard intended to 

mitigate health or safety risks. 

H. Executive Order 13211: Actions that Significantly 

Affect Energy Supply, Distribution, or Use

This action is not subject to Executive Order 13211 

(66 FR 28355, May 22, 2001), because it is not a 

significant regulatory action under Executive Order 12866. 

I. National Technology Transfer and Advancement Act

Section 12(d) of the National Technology Transfer and 

Advancement Act of 1995 (NTTAA), Public Law No. 104-113, 

12(d) (15 U.S.C. 272 note) directs EPA to use voluntary 

consensus standards in its regulatory activities unless to 

do so would be inconsistent with applicable law or 

otherwise impractical. Voluntary consensus standards are 

technical standards (e.g., materials specifications, test 

methods, sampling procedures, and business practices) that 

are developed or adopted by voluntary consensus standards 

bodies. NTTAA directs EPA to provide Congress, through 

OMB, explanations when the Agency decides not to use 

available and applicable voluntary consensus standards. 
112 of 212 

This document is a prepublication version, signed by EPA Administrator Lisa P. Jackson on 

December 2, 2011. We have taken steps to ensure the accuracy of this version, but it is not the 

official version.

This final action does not involve technical 

standards. Therefore, EPA did not consider the use of any 

voluntary consensus standards. 

J. Executive Order 12898: Federal Actions to Address 

Environmental Justice in Minority Populations and LowIncome Populations

Executive Order 12898 (59 FR 7629, February 16, 1994) 

establishes federal executive policy on environmental 

justice. Its main provision directs federal agencies, to 

the greatest extent practicable and permitted by law, to 

make environmental justice part of their mission by 

identifying and addressing, as appropriate, 

disproportionately high and adverse human health or 

environmental effects of their programs, policies, and 

activities on minority populations and low-income 

populations in the United States. 

EPA has determined that this action will not have 

disproportionately high and adverse human health or 

environmental effects on minority or low-income populations 

because it does not affect the level of protection provided 

to human health or the environment because it is a rule 

addressing information collection and reporting procedures. 

K. Congressional Review Act
113 of 212 

This document is a prepublication version, signed by EPA Administrator Lisa P. Jackson on 

December 2, 2011. We have taken steps to ensure the accuracy of this version, but it is not the 

official version.

The Congressional Review Act, 5 U.S.C. 801 et seq., as 

added by the Small Business Regulatory Enforcement Fairness 

Act of 1996 (SBREFA), generally provides that before a rule 

may take effect, the agency promulgating the rule must 

submit a rule report, which includes a copy of the rule, to 

each House of the Congress and to the Comptroller General 

of the United States. EPA will submit a report containing 

this rule and other required information to the U.S. 

Senate, the U.S. House of Representatives, and the 

Comptroller General of the U.S. A Major rule cannot take 

effect until 60 days after it is published in the Federal 

Register. This action is not a “major rule” as defined by 

5 U.S.C. 804(2). This rule will be effective on December 

28, 2011. 
Mandatory Reporting of Greenhouse Gases: Technical 

Revisions to the Petroleum and Natural Gas Systems Source 

Category of the Greenhouse Gas Reporting Rule 

Page 114 of 212 

List of Subjects in 40 CFR Part 98

Environmental protection, Administrative practice and 

procedure, Greenhouse gases, Suppliers, Reporting and 

recordkeeping requirements. 

Dated:___ 

 

Lisa P. Jackson, 

Administrator. 
Page 115 of 212 

This document is a prepublication version, signed by EPA Administrator Lisa P. Jackson on 

December 2, 2011. We have taken steps to ensure the accuracy of this version, but it is not the 

official version.

For the reasons stated in the preamble, title 40, 

chapter I, of the Code of Federal Regulations is amended as 

follows: 

PART 98—[AMENDED] 

1. The authority citation for part 98 continues to 

read as follows: 

Authority: 42 U.S.C. 7401-7671q. 

Subpart A-[Amended] 

2. Section 98.1 is amended by adding paragraph (c) to 

read as follows: 

* * * * * 

§98.1 Purpose and scope.

(c) For facilities required to report under onshore 

petroleum and natural gas production under subpart W of 

this part, the terms Owner and Operator used in subpart A 

have the same definition as Onshore petroleum and natural 

gas production owner or operator

3. Section 98.6 is amended by revising the 

definitions of “Continuous bleed” and “Intermittent bleed 

pneumatic devices” to read as follows: 

, as defined in §98.238 of 

this part. 

* * * * * 

§98.6 Definitions.
Page 116 of 212 

This document is a prepublication version, signed by EPA Administrator Lisa P. Jackson on 

December 2, 2011. We have taken steps to ensure the accuracy of this version, but it is not the 

official version.

Continuous bleed

* * * * * 

 means a continuous flow of pneumatic 

supply natural gas to the process control 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 

all or a portion of the full volume of the actuator 

intermittently when control action is necessary, but do not 

bleed continuously. 

Subpart W—[Amended] 

4. Section 98.230 is amended by revising paragraphs 

(a)(2) through (a)(4), and (a)(8) to read as follows: 

(a) * * * 

§98.230 Definition of the source category.

* * * * * 
Page 117 of 212 

This document is a prepublication version, signed by EPA Administrator Lisa P. Jackson on 

December 2, 2011. We have taken steps to ensure the accuracy of this version, but it is not the 

official version.

(2) Onshore petroleum and natural gas production. 

Onshore petroleum and natural gas production means all 

equipment on a single well-pad or associated with a single 

well-pad (including but not limited to compressors, 

generators, dehydrators, storage vessels, and portable nonself-propelled equipment which includes well drilling and 

completion equipment, workover equipment, gravity 

separation equipment, auxiliary non-transportation-related 

equipment, and leased, rented or contracted equipment) used 

in the production, extraction, recovery, lifting, 

stabilization, separation or treating of petroleum and/or 

natural gas (including condensate). This equipment also 

includes associated storage or measurement vessels and all 

enhanced oil recovery (EOR) operations using CO2 

(3) 

or natural 

gas injection, and all petroleum and natural gas production 

equipment located on islands, artificial islands, or 

structures connected by a causeway to land, an island, or 

an artificial island. 

Onshore natural gas processing. Natural gas 

processing means the separation of natural gas liquids 

(NGLs) or non-methane gases from produced natural gas, or 

the separation of NGLs into one or more component mixtures. 

Separation includes one or more of the following: forced 

extraction of natural gas liquids, sulfur and carbon 
Page 118 of 212 

This document is a prepublication version, signed by EPA Administrator Lisa P. Jackson on 

December 2, 2011. We have taken steps to ensure the accuracy of this version, but it is not the 

official version.

dioxide removal, fractionation of NGLs, or the capture of 

CO2

(4) 

 separated from natural gas streams. This segment also 

includes all residue gas compression equipment owned or 

operated by the natural gas processing plant. This 

industry segment includes processing plants that 

fractionate gas liquids, and processing plants that do not 

fractionate gas liquids but have an annual average 

throughput of 25 MMscf per day or greater. 

Onshore natural gas transmission compression

* * * * * 

. 

Onshore natural gas transmission compression means any 

stationary combination of compressors that move natural gas 

from production fields, natural gas processing plants, or 

other transmission compressors through transmission 

pipelines to natural gas distribution pipelines, LNG 

storage facilities, or into underground storage. In 

addition, a transmission compressor station includes 

equipment for liquids separation, and tanks for the storage 

of water and hydrocarbon liquids. Residue (sales) gas 

compression that is part of onshore natural gas processing 

plants are included in the onshore natural gas processing 

segment and are excluded from this segment. 

(8) Natural gas distribution. Natural gas 

distribution means the distribution pipelines and metering 
Page 119 of 212 

This document is a prepublication version, signed by EPA Administrator Lisa P. Jackson on 

December 2, 2011. We have taken steps to ensure the accuracy of this version, but it is not the 

official version.

and regulating equipment at metering-regulating stations 

that are operated by a Local Distribution Company (LDC) 

within a single state that is regulated as a separate 

operating company by a public utility commission or that is 

operated as an independent municipally-owned distribution 

system. This segment also excludes customer meters and 

regulators, infrastructure, and pipelines (both interstate 

and intrastate) delivering natural gas directly to major 

industrial users and farm taps upstream of the local 

distribution company inlet. 

* * * * * 

5. Section 98.232 is amended by: 

a. Revising paragraph (a). 

b. Revising paragraph (c) introductory text. 

c. Revising paragraph (c)(22). 

d. Revising paragraph (d) introductory text. 

e. Revising paragraph (e) introductory text. 

f. Revising paragraph (f) introductory text. 

g. Revising paragraph (g) introductory text. 

h. Revising paragraph (h) introductory text. 

i. Revising paragraph (i). 

j. Removing and reserving paragraph (j). 

k. Revising paragraph (k). 

The revisions read as follows: 
Page 120 of 212 

This document is a prepublication version, signed by EPA Administrator Lisa P. Jackson on 

December 2, 2011. We have taken steps to ensure the accuracy of this version, but it is not the 

official version.

(a) You must report CO

§98.232 GHGs to report.

2, CH4, and N2O emissions from 

each industry segment specified in paragraph (b) through 

(i) of this section, CO2, CH4, and N2

* * * * * 

O emissions from each 

flare as specified in paragraph (b) through (i) of this 

section, and stationary and portable combustion emissions 

as applicable as specified in paragraph (k) of this 

section. 

(c) For an onshore petroleum and natural gas 

production facility, report CO2, CH4, and N2

* * * * * 

O emissions from 

only the following source types on a single well-pad or 

associated with a single well-pad: 

(22) You must use the methods in §98.233(z) and 

report under this subpart the emissions of CO2, CH4, and N2O 

from stationary or portable fuel combustion equipment that 

cannot move on roadways under its own power and drive 

train, and that is located at an onshore petroleum and 

natural gas production facility as defined in §98.238. 

Stationary or portable equipment are the following 

equipment, which are integral to the extraction, 

processing, or movement of oil or natural gas: well 

drilling and completion equipment, workover equipment, 
Page 121 of 212 

This document is a prepublication version, signed by EPA Administrator Lisa P. Jackson on 

December 2, 2011. We have taken steps to ensure the accuracy of this version, but it is not the 

official version.

natural gas dehydrators, natural gas compressors, 

electrical generators, steam boilers, and process heaters. 

 (d) For onshore natural gas processing, report CO2, 

CH4, and N2

* * * * * 

O emissions from the following sources: 

(e) For onshore natural gas transmission compression, 

report CO2, CH4, and N2

* * * * * 

O emissions from the following 

sources: 

(f) For underground natural gas storage, report CO2, 

CH4, and N2O

* * * * * 

emissions from the following sources: 

(g) For LNG storage, report CO2, CH4, and N2

* * * * * 

O 

emissions from the following sources: 

(h) LNG import and export equipment, report CO2, CH4, 

and N2

* * * * * 

O emissions from the following sources: 

(i) For natural gas distribution, report CO2, CH4, and 

N2

(1) Meters, regulators, and associated equipment at 

above grade transmission-distribution transfer stations, 

including equipment leaks from connectors, block valves, 

O emissions from the following sources: 
Page 122 of 212 

This document is a prepublication version, signed by EPA Administrator Lisa P. Jackson on 

December 2, 2011. We have taken steps to ensure the accuracy of this version, but it is not the 

official version.

control valves, pressure relief valves, orifice meters, 

regulators, and open ended lines. 

(2) Equipment leaks from vaults at below grade 

transmission-distribution transfer stations. 

(3) Meters, regulators, and associated equipment at 

above grade metering-regulating station. 

(4) Equipment leaks from vaults at below grade 

metering-regulating stations. 

(5) Pipeline main equipment leaks. 

(6) Service line equipment leaks. 

(7) Report under subpart W of this part the emissions 

of CO2, CH4, and N2

 (j) [Reserved] 

O emissions from stationary fuel 

combustion sources following the methods in §98.233(z) 

(k) Report under subpart C of this part (General 

Stationary Fuel Combustion Sources) the emissions of CO2, 

CH4, and N2O from each stationary fuel combustion unit by 

following the requirements of subpart C except for 

facilities under onshore petroleum and natural gas 

production and natural gas distribution. Onshore petroleum 

and natural gas production facilities must report 

stationary and portable combustion emissions as specified 

in paragraph (c) of this section. Natural gas distribution 
Page 123 of 212 

This document is a prepublication version, signed by EPA Administrator Lisa P. Jackson on 

December 2, 2011. We have taken steps to ensure the accuracy of this version, but it is not the 

official version.

facilities must report stationary combustion emissions as 

specified in paragraph (i) of this section. 

* * * * * 

6. Section 98.233 is amended by: 

a. In paragraph (a), revising Equation W-1 and its 

definitions. 

b. Adding paragraph (a)(3). 

c. In paragraph (c), revising Equation W-2 and its 

definitions. 

d. Revising paragraphs (d) introductory text and 

(d)(1). 

e. Revising the first sentence of paragraph (d)(2) 

and the definition “Vs

f. Revising paragraph (d)(3). 

” in Equation W-3. 

g. Revising the first sentence of paragraph (d)(4) 

introductory text. 

h. Revising paragraph (e) introductory text, (e)(1) 

introductory text, (e)(1)(vii), (e)(1)(xi) introductory 

text, (e)(1)(xi)(A) through (C), and (e)(2) introductory 

text. 

i. In paragraph (e)(2), revising the definition of 

“EFi

j. Revising the first sentence of paragraph (e)(5) 

introductory text. 

”, “Count”, and “1000” in Equation W-5. 
Page 124 of 212 

This document is a prepublication version, signed by EPA Administrator Lisa P. Jackson on 

December 2, 2011. We have taken steps to ensure the accuracy of this version, but it is not the 

official version.

k. Revising paragraph (e)(6). 

l. Revising paragraph (f)(1) introductory text. 

m. Revising paragraphs (f)(1)(i)(A) through 

(f)(1)(i)(C). 

n. Revising paragraph (f)(2). 

o. In paragraph (f)(3) introductory text, revising 

Equation W-9 and its definitions. 

p. Removing and reserving paragraphs (f)(3)(i) and 

(f)(3)(ii). 

q. Revising paragraph (g) introductory text. 

r. Revising paragraphs (g)(1) introductory text and 

(g)(1)(i). 

s. Revising paragraph (g)(1)(ii) introductory text; 

redesignating Equation W-11 as Equation W-11A and Equation 

W-12 as Equation W-11B respectively; and adding new 

Equation W-11C and W-12 and the definitions of parameters 

in Equations W-11C and W-12. 

t. Redesignating paragraphs (g)(1)(ii)(A) through 

(g)(1)(ii)(C) as paragraphs (g)(1)(iii) through (g)(1)(v) 

and revising newly redesignated paragraphs (g)(1)(iii) 

through (g)(1)(v). 

u. Removing paragraph (g)(1)(ii)(D). 

v. Revising paragraph (g)(3). 
Page 125 of 212 

This document is a prepublication version, signed by EPA Administrator Lisa P. Jackson on 

December 2, 2011. We have taken steps to ensure the accuracy of this version, but it is not the 

official version.

w. Removing paragraph (g)(5) and redesignating 

paragraph (g)(6), (g)(6)(i), and (g)(6)(ii) as (g)(5), 

(g)(5)(i), and (g)(5)(ii). 

x. Revising paragraph (h) introductory text. 

y. Removing paragraph (h)(1). 

z. Redesignating paragraphs (h)(2) and (h)(3) 

introductory text as paragraphs (h)(1) and (h)(2) 

introductory text, respectively, and revising newly 

redesignated paragraph (h)(1). 

aa. Revising paragraph (i). 

bb. Revising the first sentence of paragraph (j)(1) 

and revising paragraphs (j)(1)(vii) introductory text, 

(j)(1)(vii)(B), and (j)(1)(vii)(C). 

cc. Revising paragraph (j)(2). 

dd. Revising paragraph (j)(3) introductory text and 

paragraph (j)(3)(i). 

ee. Revising paragraph (j)(4) introductory text. 

ff. In paragraph (j)(5), revising Equation W-15, 

revising the definitions of “EFi

gg. In paragraph (j)(8), revising Equation W-16, 

revising the definition of “En”, removing the definition of 

“Et”, and defining the use of “8,760”. 

” and “Count”, and adding 

the definition of “1,000”. 
Page 126 of 212 

This document is a prepublication version, signed by EPA Administrator Lisa P. Jackson on 

December 2, 2011. We have taken steps to ensure the accuracy of this version, but it is not the 

official version.

hh. Revising paragraphs (k) introductory text, 

(k)(1), (k)(2) introductory text, (k)(2)(i), and (k)(4); 

and adding new paragraph (k)(2)(iv). 

ii. Revising paragraph (l)(1). 

jj. Revising paragraph (l)(3). 

kk. Revising paragraph (m)(1) and revising equation 

W-18 and its definitions in paragraph (m)(3). 

ll. Revising paragraph (n)(2)(ii) and (n)(2)(iii), 

and in paragraph (n)(4), revising Equation W-21. 

mm. Redesignating paragraph (n)(9) as paragraph 

(n)(10) and adding new paragraphs (n)(9) and (n)(11). 

nn. In paragraph (o)(6), revising the definition of 

“MTm

oo. In paragraph (o)(7), revising the definition of 

“EF

” in Equation W-24. 

i

pp. In paragraph (p)(7)(i) introductory text, 

revising the definition of “MT

” in Equation W-25. 

m

qq. In paragraph (p)(9), revising the definition of 

“EF

” in Equation W-28. 

i

rr. Revising paragraph (q) introductory text. 

” in Equation W-29. 

ss. Revising paragraph (q)(8). 

tt. Revising paragraph (r) introductory text and the 

definitions in Equation W-31. 
Page 127 of 212 

This document is a prepublication version, signed by EPA Administrator Lisa P. Jackson on 

December 2, 2011. We have taken steps to ensure the accuracy of this version, but it is not the 

official version.

uu. Revising paragraphs (r)(2)(i)(A), (r)(6)(i), 

(r)(6)(ii). 

vv. Revising introductory texts for paragraphs (t) 

and (t)(1), and revising the definitions of “Ts” and “Ps

ww. Revising paragraph (t)(2) and the parameters “T

” 

in Equation W-33. 

s” 

and “Ps

xx. Adding paragraph (t)(3). 

” in Equation W-34. 

yy. Revising paragraph (u) introductory text, 

paragraph (u)(2). 

zz. In paragraph (v), revising the only sentence of 

paragraph (v), Equation W-36, and the definitions of 

“Masss,i”, “Es,i”, and “ρi

aaa. In paragraph (w)(3), revising Equation W-37 and 

the definitions of parameters “Mass” and “GHG”. 

” in Equation W-36. 

bbb. In paragraph (x)(2), revising Equation W-38 and 

the definitions of parameter “Mass”. 

ccc. Revising paragraph (z) introductory text, 

(z)(1),(z)(2) and (z)(3). 

ddd. Redesignating paragraphs (z)(4), (z)(5), and 

(z)(6) as (z)(2)(iv), (z)(2)(v), and (z)(2)(vi), 

respectively. 
Page 128 of 212 

This document is a prepublication version, signed by EPA Administrator Lisa P. Jackson on 

December 2, 2011. We have taken steps to ensure the accuracy of this version, but it is not the 

official version.

eee. In newly redesignated paragraph (z)(2)(vi), 

revising Equation W-40, revising the definitions of 

“Mass,N2O

fff. Adding paragraph (z)(4). 

” and “HHV”, and adding the definition of “GWP”. 

ggg. Removing paragraph (z)(6)(i) through (z)(6)(iii). 

hhh.

The revisions read as follows: 

(a) * * * 

§98.233 Calculating GHG emissions.

Mass ,it = Count EFtt GHGi**** TConv ti (Eq. W-1) 

Where: 

Masst,i = Annual total mass GHG emissions in metric tons 

CO2e per year from a natural gas pneumatic device 

vent of type “t”, for GHGi

Count

. 

t

EF

 = Total number of natural gas pneumatic devices of 

type “t” (continuous high bleed, continuous low 

bleed, intermittent bleed) as determined in 

paragraph (a)(1), (a)(2), and (a)(3) of this 

section. 

t

GHG

 = 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. 

i = For onshore petroleum and natural gas production 

facilities, concentration of GHGi, CH4, or CO2, in 

natural gas as defined in paragraph (u)(2)(i) of 

this section and for onshore natural gas 

transmission compression and underground natural 

gas storage, GHGi equals 0.975 for CH4 and 1.1 ×

10-2 for CO2. 
Page 129 of 212 

This document is a prepublication version, signed by EPA Administrator Lisa P. Jackson on 

December 2, 2011. We have taken steps to ensure the accuracy of this version, but it is not the 

official version.

Convi = Conversion from standard cubic feet to metric 

tons CO2e; 0.000403 for CH4, and 0.00005262 for 

CO2

T

. 

t

* * * * * 

 = Average estimated number of hours in the 

operating year the devices, of each type t, were 

operational. Default is 8760 hours. 

(3) For all industry segments, determine the type of 

pneumatic device using engineering estimates based on best 

available information. 

* * * * * 

(c) * * * 

Mass Count EF GHG TConv i = i i

**** (Eq. W-2) 

 

Where: Massi = Annual total mass GHG emissions in 

metric tons CO2e per year from all natural gas 

pneumatic pump venting, for GHGi

Count = Total number of natural gas pneumatic pumps. 

. 

EF = Population emissions factors for natural gas 

pneumatic pump venting listed in Tables W-1A of 

this subpart for onshore petroleum and natural 

gas production. 

GHGi = Concentration of GHGi, CH4, or CO2

Conv

, in produced 

natural gas as defined in paragraph (u)(2)(i) of 

this section. 

i = Conversion from standard cubic feet to metric 

tons CO2e; 0.000403 for CH4, and 0.00005262 for 

CO2

T = Average estimated number of hours in the 

operating year the pumps were operational. 

Default is 8760 hours. 

. 

 (d) Acid gas removal (AGR) vents. For AGR vent 

(including processes such as amine, membrane, molecular 
Page 130 of 212 

This document is a prepublication version, signed by EPA Administrator Lisa P. Jackson on 

December 2, 2011. We have taken steps to ensure the accuracy of this version, but it is not the 

official version.

sieve or other absorbents and adsorbents), calculate 

emissions for CO2 only (not CH4

(1) 

) vented directly to the 

atmosphere or through a flare, engine (e.g., permeate from 

a membrane or de-adsorbed gas from a pressure swing 

adsorber used as fuel supplement), or sulfur recovery plant 

using any of the calculation methodologies described in 

paragraph (d) of this section, as applicable. 

Calculation Methodology 1. If you operate and 

maintain a CEMS that has both a CO2 concentration monitor 

and volumetric flow rate monitor, you must calculate CO2

emissions under this subpart by following the Tier 4 

Calculation Methodology and all associated calculation, 

quality assurance, reporting, and recordkeeping 

requirements for Tier 4 in subpart C of this part (General 

Stationary Fuel Combustion Sources). Alternatively, you 

may follow the manufacturer’s instructions or industry 

standard practice. If a CO2 concentration monitor and 

volumetric flow rate monitor are not available, you may 

elect to install a CO2 concentration monitor and a 

volumetric flow rate monitor that comply with all of the 

requirements specified for the Tier 4 Calculation 

Methodology in subpart C of this part (General Stationary 

Fuel Combustion). The calculation and reporting of CH4 and 
Page 131 of 212 

This document is a prepublication version, signed by EPA Administrator Lisa P. Jackson on 

December 2, 2011. We have taken steps to ensure the accuracy of this version, but it is not the 

official version.

N2

 (2) 

O emissions is not required as part of the Tier 4 

requirements for AGRs. 

Calculation Methodology 2. If CEMS is not 

available but a vent meter is installed, use the CO2

* * * * * 

composition and annual volume of vent gas to calculate 

emissions using Equation W-3 of this section. 

VS

* * * * * 

 = Total annual volume of vent gas flowing out of 

the AGR unit in cubic feet per year at actual 

conditions as determined by flow meter using 

methods set forth in §98.234(b). Alternatively, 

you may follow the manufacturer’s instructions or 

industry standard practice for calibration of the 

vent meter. 

(3) Calculation Methodology 3. If CEMS or a vent 

meter is not installed, you may use the inlet or outlet gas 

flow rate of the acid gas removal unit to calculate 

emissions for CO2 using Equations W-4A or W-4B of this 

section. If inlet gas flow rate is known, use Equation W4A. If outlet gas flow rate is known, use Equation W-4B. 





 





−

− ∗=

O

I O

a CO in Vol

VolVol VE

1 2, (Eq. W-4A) 





 





−

− ∗=

I

I O

a CO out Vol

VolVol VE

1 2, (Eq. W-4B) 

Where: 
Page 132 of 212 

This document is a prepublication version, signed by EPA Administrator Lisa P. Jackson on 

December 2, 2011. We have taken steps to ensure the accuracy of this version, but it is not the 

official version.

Ea, CO2 = Annual volumetric CO2

V

 emissions at actual 

conditions, in cubic feet per year. 

in

V

 = Total annual volume of natural gas flow into the 

AGR unit in cubic feet per year at actual 

condition as determined using methods specified 

in paragraph (d)(5) of this section. 

out

Vol

 = Total annual volume of natural gas flow out of 

the AGR unit in cubic feet per year at actual 

condition as determined using methods specified 

in paragraph (d)(5) of this section. 

I = Volume fraction of CO2

Vol

 content in natural gas into 

the AGR unit as determined in paragraph (d)(7) of 

this section. 

o = Volume fraction of CO2 content in natural gas out 

of the AGR unit as determined in paragraph (d)(8) 

of this section. 

 (4) Calculation Methodology 4. If CEMS or a vent 

meter is not installed, you may calculate emissions using 

any standard simulation software packages, such as 

AspenTech HYSYS®

 and API 4679 AMINECalc, that uses the PengRobinson equation of state, and speciates CO2

* * * 

 emissions. 

* * * * * 

(e) Dehydrator vents. For dehydrator vents, 

calculate annual CH4, CO2 and N2

(1) 

O emissions using any of the 

calculation methodologies described in paragraph (e) of 

this section. 

Calculation Methodology 1. Calculate annual mass 

emissions from dehydrator vents with annual average daily 

throughput greater than or equal to 0.4 million standard 
Page 133 of 212 

This document is a prepublication version, signed by EPA Administrator Lisa P. Jackson on 

December 2, 2011. We have taken steps to ensure the accuracy of this version, but it is not the 

official version.

cubic feet per day using a software program, such as 

AspenTech HYSYS® or GRI-GLYCalc, that uses the PengRobinson equation of state to calculate the equilibrium 

coefficient, speciates CH4 and CO2

* * * * * 

 emissions from 

dehydrators, and has provisions to include regenerator 

control devices, a separator flash tank, stripping gas and 

a gas injection pump or gas assist pump. A minimum of the 

following parameters determined by engineering estimate 

based on best available data must be used to characterize 

emissions from dehydrators: 

(vii) Use of stripping gas. 

* * * * * 

(xi) Wet natural gas composition. Determine this 

parameter by selecting one of the methods described under 

paragraph (e)(1)(xi) of this section. 

(A) Use the wet natural gas composition as defined in 

paragraph (u)(2)(i) or (u)(2)(ii) of this section. 

(B) If wet natural gas composition cannot be 

determined using paragraph (u)(2)(i) or (u)(2)(ii) of this 

section, select a representative analysis. 

(C) 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 
Page 134 of 212 

This document is a prepublication version, signed by EPA Administrator Lisa P. Jackson on 

December 2, 2011. We have taken steps to ensure the accuracy of this version, but it is not the 

official version.

practice as specified in §98.234(b) to sample and analyze 

wet natural gas composition. 

* * * * * 

(2) Calculation Methodology 2. Calculate annual CH4

and CO2

* * * * * 

 emissions from glycol dehydrators with annual 

average daily throughput less than 0.4 million standard 

cubic feet per day using Equation W-5 of this section: 

EFi = Population emission factors for glycol 

dehydrators in thousand standard cubic feet 

per dehydrator per year. Use 73.4 for CH4 and 

3.21 for CO2

Count = Total number of glycol dehydrators with 

throughput less than 0.4 million standard 

cubic feet per day. 

 at 60°F and 14.7 psia. 

1000 = Conversion of EFi

* * * * * 

 in thousand standard cubic feet 

to standard cubic feet. 

(5) Dehydrators that use desiccant shall calculate 

emissions from the amount of gas vented from the vessel 

when it is depressurized for the desiccant refilling 

process using Equation W-6 of this section. * * * 

* * * * * 

(6) For glycol dehydrators, both CH4 and CO2 mass 

emissions shall be calculated from volumetric GHGi emissions 

using calculations in paragraph (v) of this section. For 

dehydrators that use desiccant, both CH4 and CO2 volumetric 
Page 135 of 212 

This document is a prepublication version, signed by EPA Administrator Lisa P. Jackson on 

December 2, 2011. We have taken steps to ensure the accuracy of this version, but it is not the 

official version.

and mass emissions shall be calculated from volumetric 

natural gas emissions using calculations in paragraphs (u) 

and (v) of this section. 

 (f) * * * 

(1) Calculation Methodology 1. For one well of each 

unique well tubing diameter group and pressure group 

combination in each sub-basin category (see §98.238 for the 

definitions of tubing diameter group, pressure group, and 

sub-basin category), where gas wells are vented to the 

atmosphere to expel liquids accumulated in the tubing, a 

recording flow meter shall be installed on the vent line 

used to vent gas from the well (e.g., on the vent line off 

the wellhead separator or atmospheric storage tank) 

according to methods set forth in §98.234(b). Calculate 

emissions from well venting for liquids unloading using 

Equation W-7 of this section. 

∑=

=

h

p

na TE FRpp

1

, (Eq. W-7) 

Where: 

Ea,n

h = Total number of wells of the same tubing diameter 

group and pressure group combination in a subbasin. 

 = Annual natural gas emissions for all wells of the 

same tubing diameter group and pressure group 

combination in a sub-basin at actual conditions 

in cubic feet. 
Page 136 of 212 

This document is a prepublication version, signed by EPA Administrator Lisa P. Jackson on 

December 2, 2011. We have taken steps to ensure the accuracy of this version, but it is not the 

official version.

p = Wells 1 through h of the same tubing diameter 

group and pressure group combination in a subbasin. 

Tp

FR

 = Cumulative amount of time in hours of venting 

from the measured well, p, of the same tubing 

diameter group and pressure group combination in 

a sub-basin during the year. 

p = Average flow rate in cubic feet per hour of a 

measured well venting for the duration of the 

liquids unloading, under actual conditions as 

determined in paragraph (f)(1)(i) of this 

section. 

(i) * * * 

(A) The average flow rate per hour of venting is 

calculated for each unique tubing diameter group and 

pressure group combination in each sub-basin category by 

dividing the recorded total flow by the recorded time (in 

hours) for a single liquid unloading with venting to the 

atmosphere. 

(B) This average flow rate per hour is applied to all 

wells in the same pressure group that have the same tubing 

diameter group, for the number of hours of venting these 

wells. 

(C) A new average flow rate is calculated every other 

calendar year for each reporting sub-basin category 

starting the first calendar year of data collection. For a 

new producing sub-basin category, an average flow rate is 

calculated beginning in the first year of production. 
Page 137 of 212 

This document is a prepublication version, signed by EPA Administrator Lisa P. Jackson on 

December 2, 2011. We have taken steps to ensure the accuracy of this version, but it is not the 

official version.

* * * * * 

(2) Calculation Methodology 2. Calculate the total 

emissions for well venting for liquids unloading using 

Equation W-8 of this section. 

∑ (( ) ) ∑( ( ) ) = =

−

















+×××××= ×−×

W

p

V

q

ns p p pp q qp qp

p

VE SPWDCD SFR HR Z

1 1

, ,

3 2

, 1037.0 0.1 (Eq. W-8) 

Where: 

Es,n

W = Total number of wells with well venting for 

liquids unloading for each sub-basin. 

 = Annual natural gas emissions at standard 

conditions, in cubic feet/year. 

0.37×10-3

CD

 = {3.14 (pi)/4}/{14.7*144} (psia converted to 

pounds per square feet). 

p

WD

 = Casing internal diameter for each well, p, in 

inches. 

p

SP

 = Well depth from either the top of the well or 

the lowest packer to the bottom of the well, 

for each well, p, in feet. 

p

V

 = Shut-in pressure or surface pressure for wells 

with tubing production and no packers or casing 

pressure for each well, p, in pounds per square 

inch absolute (psia) or casing-to-tubing 

pressure of one well from the same sub-basin 

multiplied by the tubing pressure of each well, 

p, in the sub-basin, in pounds per square inch 

absolute (psia). 

p

SFR

 = Number of vents per year per well, p. 

p

HR

 = Average flow-line rate of gas for well, p, at 

standard conditions in cubic feet per hour. 

Use Equation W-33 to calculate the average 

flow-line rate at standard conditions. 

p,q = Hours that each well, p , was left open to the 

atmosphere during unloading, q. 
Page 138 of 212 

This document is a prepublication version, signed by EPA Administrator Lisa P. Jackson on 

December 2, 2011. We have taken steps to ensure the accuracy of this version, but it is not the 

official version.

1.0 = Hours for average well to blowdown casing 

volume at shut-in pressure. 

Zp,q = If HRp,q is less than 1.0 then Zp,q is equal to 

0. If HRp,q is greater than or equal to 1.0 

then Zp,q

 (3) * * * 

 is equal to 1. 

∑ (( ) ) ∑( ( ) ) = =

−





 





+×××××= ×−×

W

p

V

q

ns p p pp q qp qp

p

VE TD SPWD SFR HR Z

1 1

, ,

3 2

, 1037.0 5.0 (Eq. W-9) 

Where: 

Es,n

W = Total number of wells with well venting for 

liquids unloading for each sub-basin. 

 = Annual natural gas emissions at standard 

conditions, in cubic feet/year. 

0.37×10-3

TD

 = {3.14 (pi)/4}/{14.7*144} (psia converted to 

pounds per square feet). 

p

WD

 = Tubing internal diameter for each well, p, in 

inches. 

p

SP

 = Tubing depth to plunger bumper for each well, 

p, in feet. 

p

V

 = Flow-line pressure for each well, p, in pounds 

per square inch absolute (psia), using 

engineering estimate based on best available 

data. 

p

SFR

 = Number of vents per year for each well, p. 

p

HR

 = Average flow-line rate of gas for well, p, at 

standard conditions in cubic feet per hour. 

Use Equation W-33 to calculate the average 

flow-line rate at standard conditions. 

p,q

0.5 = Hours for average well to blowdown tubing 

volume at flow-line pressure. 

 = Hours that each well, p, was left open to the 

atmosphere during each unloading, q. 

Zp,q = If HRp,q is less than 0.5 then Zp,q is equal to 

0. If HRp,q is greater than or equal to 0.5 

then Zp,q is equal to 1. 
Page 139 of 212 

This document is a prepublication version, signed by EPA Administrator Lisa P. Jackson on 

December 2, 2011. We have taken steps to ensure the accuracy of this version, but it is not the 

official version.

 (i) [Reserved] 

(ii) [Reserved] 

(g) Gas well venting during completions and workovers 

from hydraulic fracturing. Calculate CH4, CO2 and N2O 

annual emissions from gas well venting during completions 

involving hydraulic fracturing in wells and well workovers 

using Equation W-10A or Equation W-10B of this section. 

Equation W-10A applies to well venting when the backflow 

rate is measured or calculated, Equation W-10B applies when 

the backflow vent or flare volume is measured. Use 

Equation W-10A if the flow rate for backflow during well 

completions and workovers from hydraulic fracturing is 

known for the specified number of wells per paragraph 

(g)(1) in a sub-basin and well type (horizontal or 

vertical) combination. Use Equation W-10B if the flow 

volume for backflow during well completions and workovers 

from hydraulic fracturing is known for all wells in a subbasin and well type (horizontal or vertical) combination. 

Both CH4 and CO2 volumetric and mass emissions shall be 

calculated from volumetric total gas emissions using 

calculations in paragraphs (u) and (v) of this section. 

∑[ ] =

−−××=

W

p

ns TE p PRFRM p p SGEnF p

1

, (Eq. W-10A) 
Page 140 of 212 

This document is a prepublication version, signed by EPA Administrator Lisa P. Jackson on 

December 2, 2011. We have taken steps to ensure the accuracy of this version, but it is not the 

official version.

∑[ ] =

−=

W

p

E ns FVp EnFp

1

, (Eq. W-10B) 

Where: 

Es,n

W = Total number of wells completed or worked over 

using hydraulic fracturing in a sub-basin and 

well type (horizontal vs. vertical) combination. 

 = Annual volumetric total gas emissions in cubic 

feet at standard conditions from gas well venting 

during completions or workovers following 

hydraulic fracturing for each sub-basin and well 

type (horizontal vs. vertical) combination. 

Tp

FRM = Ratio of backflow during well completions and 

workovers from hydraulic fracturing to 30-day 

production rate from Equation W-12. 

 = Cumulative amount of time of backflow for the 

completion or workover, in hours, for each well, 

p, in a sub-basin and well type (horizontal vs. 

vertical) combination during the reporting year. 

PRp

EnF

 = First 30-day average production flow rate in 

standard cubic feet per hour of each well p, 

under actual conditions, converted to standard 

conditions, as required in paragraph (g)(1) of 

this section. 

p = Volume of CO2 or N2 injected gas in cubic feet at 

standard conditions that was injected into the 

reservoir during an energized fracture job for 

each well p. If the fracture process did not 

inject gas into the reservoir, then EnFp is 0. If 

injected gas is CO2, then EnFp

SG

 is 0. 

p = Volume of natural gas in cubic feet at standard 

conditions that was recovered into a flow-line 

for well p as per paragraph (g)(3) of this 

section. This parameter includes any natural gas 

that is injected into the well for clean-up. If 

no gas was recovered, SGp

FV

 is 0. 

p = Flow volume of each well (p) in standard cubic 

feet per hour measured using a recording flow 

meter (digital or analog) on the vent line to 

measure backflow during the completion or 
Page 141 of 212 

This document is a prepublication version, signed by EPA Administrator Lisa P. Jackson on 

December 2, 2011. We have taken steps to ensure the accuracy of this version, but it is not the 

official version.

workover according to methods set forth in 

§98.234(b). 

 (1) The average flow rate for backflow during well 

completions and workovers from hydraulic fracturing shall 

be determined using measurement(s) for calculation 

methodology 1 or calculation(s) for calculation methodology 

2 described in this paragraph (g)(1) of this section. If 

Equation W-10A is used, the number of measurements or 

calculations shall be determined per sub-basin and well 

type (horizontal or vertical) as follows: one measurement 

or calculation for less than or equal to 25 completions or 

workovers; two measurements or calculations for 26 to 50 

completions or workovers; three measurements or 

calculations for 51 to 100 completions or workovers; four 

measurements or calculations for 101 to 250 completions or 

workovers; and five measurements or calculations for 

greater than 250 completions or workovers. 

(i) Calculation Methodology 1. When using Equation 

W-10A, for each measured well completion(s) in each gas 

producing sub-basin category and well type (horizontal or 

vertical) combination and for each measured well 

workover(s) in each gas producing sub-basin category and 

well type (horizontal or vertical) combination, a recording 

flow meter (digital or analog) shall be installed on the 
Page 142 of 212 

This document is a prepublication version, signed by EPA Administrator Lisa P. Jackson on 

December 2, 2011. We have taken steps to ensure the accuracy of this version, but it is not the 

official version.

vent line, ahead of a flare or vent if used, to measure the 

backflow rate according to methods set forth in §98.234(b). 

(ii) Calculation Methodology 2

* * * * * 

. When using Equation W10A, for each calculated horizontal well completion and 

each calculated vertical well completion in each gas 

producing sub-basin category and for each calculated well 

horizontal workover and for each calculated vertical well 

workover in each gas producing sub-basin category, record 

the well flowing pressure upstream (and downstream in 

subsonic flow) of a well choke according to methods set 

forth in §98.234(b) to calculate the well backflow during 

well completions and workovers from hydraulic fracturing. 

Calculate emissions using Equation W-11A of this section 

for subsonic flow or Equation W-11B of this section for 

sonic flow. Use best engineering estimate based on best 

available data along with Equation W-11C of this section to 

determine whether the predominant flow is sonic or 

subsonic. If the value of R in Equation W-11C is greater 

than or equal to 2, then flow is sonic; otherwise, flow is 

subsonic: 

2

1

P R = P

(Eq. W-11C) 
Page 143 of 212 

This document is a prepublication version, signed by EPA Administrator Lisa P. Jackson on 

December 2, 2011. We have taken steps to ensure the accuracy of this version, but it is not the 

official version.

Where: 

R = Pressure ratio 

P1 = Pressure upstream of the restriction orifice in 

pounds per square inch absolute. 

P2 = Pressure downstream of the restriction orifice in 

pounds per square inch absolute. 

(iii) For Equation W-10A, the ratio of backflow rate 

during well completions and workovers from hydraulic 

fracturing to 30-day production rate is calculated using 

Equation W-12 of this section. 

∑

∑

=

= = W

p

p

W

p

p

PR

FR

FRM

1

1 (Eq. W-12) 

Where: 

FRM = Ratio of backflow rate during well completions 

and workovers from hydraulic fracturing to 30-day 

production rate. 

FRp

PR

 = Measured backflow rate from Calculation 

Methodology 1 or calculated flow rate from 

Calculation Methodology 2 in standard cubic feet 

per hour for well(s) p for each sub-basin and 

well type (horizontal or vertical) combination. 

You may not use flow volume as used in Equation 

W-10B converted to a flow rate for this 

parameter. 

p

W = Number of wells completed or worked over using 

hydraulic fracturing in a sub-basin and well type 

formation. 

 = First 30-day production rate in standard cubic 

feet per hour for each well p that was measured 

in the sub-basin and well type combination. 
Page 144 of 212 

This document is a prepublication version, signed by EPA Administrator Lisa P. Jackson on 

December 2, 2011. We have taken steps to ensure the accuracy of this version, but it is not the 

official version.

(iv) For Equation W-10A, the ratio of backflow rate 

during well completions and workovers from hydraulic 

fracturing to 30-day production rate for horizontal and 

vertical wells are applied to all horizontal and vertical 

well completions in the gas producing sub-basin and well 

type combination and to all horizontal and vertical well 

workovers, respectively, in the gas producing sub-basin and 

well type combination for the total number of hours of 

backflow for each of these wells. 

(v) For Equation W-10A, new flow rates for horizontal 

and vertical gas well completions and horizontal and 

vertical gas well workovers in each sub-basin category 

shall be calculated once every two years starting in the 

first calendar year of data collection. 

* * * * * 

(3) Determine if the backflow gas from the well 

completion or workover from hydraulic fracturing is 

recovered with purpose designed equipment that separates 

natural gas from the backflow, and sends this natural gas 

to a flow-line (e.g., reduced emissions completion or 

workovers). 

(i) Use the factor SGP in Equation W-10A of this 

section, to adjust the emissions estimated in paragraphs 

(g)(1) through (g)(4) of this section by the magnitude of 
Page 145 of 212 

This document is a prepublication version, signed by EPA Administrator Lisa P. Jackson on 

December 2, 2011. We have taken steps to ensure the accuracy of this version, but it is not the 

official version.

emissions captured using purpose designed equipment that 

separates saleable gas from the backflow as determined by 

engineering estimate based on best available data. 

(ii) [Reserved] 

(iii) Calculate gas volume at standard conditions 

using calculations in paragraph (t) of this section. 

* * * * * 

 (h) Gas well venting during completions and 

workovers without hydraulic fracturing. Calculate CH4, CO2

and N2O emissions from each gas well venting during well 

completions and workovers not involving hydraulic 

fracturing using Equation W-13 of this section: 

p

f

p

ns NE wo * EFwo p

* TV

1

, ∑=

= + (Eq. W-13) 

Where: 

 

Es,n

N

 = Annual natural gas emissions in standard cubic 

feet from a gas well venting during well 

completions and workovers without hydraulic 

fracturing. 

wo

EF

 = Number of workovers per sub-basin category that 

flare gas or vent gas to the atmosphere and do 

not involve hydraulic fracturing in the reporting 

year. 

wo = Emission Factor for non-hydraulic fracture well 

workover venting in standard cubic feet per 

workover. EFwo = 3114 standard cubic feet natural 
Page 146 of 212 

This document is a prepublication version, signed by EPA Administrator Lisa P. Jackson on 

December 2, 2011. We have taken steps to ensure the accuracy of this version, but it is not the 

official version.

gas per well workover without hydraulic 

fracturing. 

p = Well completions 1 through f in a sub-basin. 

f = Total number of well completions without 

hydraulic fracturing in a sub-basin category. 

Vp

T

 = Average daily gas production rate in standard 

cubic feet per hour for each well completion 

without hydraulic fracturing, p. This is the 

total annual gas production volume divided by 

total number of hours the wells produced to the 

flow-line. For completed wells that have not 

established a production rate, you may use the 

average flow rate from the first 30 days of 

production. In the event that the well is 

completed less than 30 days from the end of the 

calendar year, the first 30 days of the 

production straddling the current and following 

calendar years shall be used. 

p

 (1) Volumetric emissions for both CH

 = Time each well completion without hydraulic 

fracturing, p, was venting in hours during the 

year. 

4 and CO2 shall 

be calculated from volumetric natural gas emissions using 

calculations in paragraph (u) of this section. Mass 

emissions for both CH4 and CO2

* * * * * 

 shall be calculated from 

volumetric natural gas emissions using calculations in 

paragraphs (v) of this section. 

(i) Blowdown vent stacks. Calculate CO2 and CH4

blowdown vent stack emissions from depressurizing 

equipment(s) to reduce system pressure for planned or 

emergency shutdowns resulting from human intervention or to 

take equipment out of service for maintenance (excluding 
Page 147 of 212 

This document is a prepublication version, signed by EPA Administrator Lisa P. Jackson on 

December 2, 2011. We have taken steps to ensure the accuracy of this version, but it is not the 

official version.

depressurizing to a flare, over-pressure relief, operating 

pressure control venting and blowdown of non-GHG gases; 

desiccant dehydrator blowdown venting before reloading is 

covered in paragraph (e)(5) of this section) as follows: 

(1) Calculate the unique physical volume (including 

pipelines, compressor case or cylinders, manifolds, suction 

bottles, discharge bottles, and vessels) between isolation 

valves determined by engineering estimates based on best 

available data. 

(2) If the unique physical volume between isolation 

valves is greater than or equal to 50 cubic feet, retain 

logs of the number of blowdowns for each unique physical 

volume (including but not limited to compressors, vessels, 

pipelines, headers, fractionators, and tanks). Unique 

physical volumes smaller than 50 cubic feet are exempt from 

reporting under paragraph (i) of this section. 

(3) Calculate the total annual venting emissions for 

unique volumes using either Equation W-14A or W-14B of this 

section. 

( )

( ) 













 −















+

+ = CV

PT

PT

VNE

sa

as

ns *

67.459

67.459 , * (Eq. W-14A) 

Where: 

ES,N = Annual natural gas venting emissions at standard 

conditions from blowdowns in cubic feet. 
Page 148 of 212 

This document is a prepublication version, signed by EPA Administrator Lisa P. Jackson on 

December 2, 2011. We have taken steps to ensure the accuracy of this version, but it is not the 

official version.

N = Number of occurrences of blowdowns for each 

unique physical volume in calendar year. 

V = Unique physical volume (including pipelines, 

compressors and vessels) between isolation valves 

in cubic feet. 

C = Purge factor that is 1 if the unique physical 

volume is not purged or zero if the unique 

physical volume is purged using non-GHG gases. 

Ts = Temperature at standard conditions (60o

T

F). 

a = Temperature at actual conditions in the unique 

physical volume (o

P

F). 

s

P

 = Absolute pressure at standard conditions (14.7 

psia). 

a = Absolute pressure at actual conditions in the 

unique physical volume (psia). 

( )( )

( ) ∑= 































+

−+ =

N

p sa

peapbas

ns PT

PPT

VE

1

,,,,

, 67.459

67.459

 (Eq. W-14B) 

Where: 

Es,n = 

p = Individual occurrence of blowdown for the same 

unique physical volume. 

Annual natural gas venting emissions at standard 

conditions from blowdowns in cubic feet. 

N = Number of occurrences of blowdowns for each 

unique physical volume in the calendar year. 

V = Total physical volume (including pipelines, 

compressors and vessels) between isolation valves 

in cubic feet for each blowdown “p.” 

Ts = Temperature at standard conditions (60o

T

F). 

a = Temperature at actual conditions in the unique 

physical volume (o

P

F) for each blowdown “p”. 

s = Absolute pressure at standard conditions (14.7 

psia). 
Page 149 of 212 

This document is a prepublication version, signed by EPA Administrator Lisa P. Jackson on 

December 2, 2011. We have taken steps to ensure the accuracy of this version, but it is not the 

official version.

Pa,b,p

P

 = Absolute pressure at actual conditions in the 

unique physical volume (psia) at the beginning of 

the blowdown “p”. 

a,e,p

 (4) Calculate both CH

 = Absolute pressure at actual conditions in the 

unique physical volume (psia) at the end of the 

blowdown “p”; 0 if blowdown volume is purged 

using non-GHG gases. 

4 and CO2

(j) * * * 

 volumetric and mass 

emissions using calculations in paragraph (u) and (v) of 

this section. 

(1) Calculation Methodology 1.

* * * * * 

 For separators with 

annual average daily throughput of oil greater than or 

equal to 10 barrels per day. * * * 

(vii) Separator oil composition and Reid vapor 

pressure. If this data is not available, determine these 

parameters by selecting one of the methods described under 

paragraph (j)(1) (vii) of this section. 

* * * * * 

(B) If separator oil composition and Reid vapor 

pressure data are available through your previous analysis, 

select the latest available analysis that is representative 

of produced crude oil or condensate from the sub-basin 

category. 

(C) Analyze a representative sample of separator oil 

in each sub-basin category for oil composition and Reid 
Page 150 of 212 

This document is a prepublication version, signed by EPA Administrator Lisa P. Jackson on 

December 2, 2011. We have taken steps to ensure the accuracy of this version, but it is not the 

official version.

vapor pressure using an appropriate standard method 

published by a consensus-based standards organization. 

 (2) Calculation Methodology 2. Calculate annual CH4

and CO2 emissions from onshore production storage tanks for 

wellhead gas-liquid separators with annual average daily 

throughput of oil greater than or equal to 10 barrels per 

day by assuming that all of the CH4 and CO2

(3) 

 in solution at 

separator temperature and pressure is emitted from oil sent 

to storage tanks. 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 as described in §98.234(b) to 

sample and analyze separator oil composition at separator 

pressure and temperature. 

Calculation Methodology 3. For wells with annual 

average daily oil production greater than or equal to 10 

barrels per day that flow directly to atmospheric storage 

tanks without passing through a wellhead separator, 

calculate annual CH4 and CO2

(i) If well production oil and gas compositions are 

available through your previous analysis, select the latest 

available analysis that is representative of produced oil 

 emissions by either of the 

methods in paragraph (j)(3) of this section: 
Page 151 of 212 

This document is a prepublication version, signed by EPA Administrator Lisa P. Jackson on 

December 2, 2011. We have taken steps to ensure the accuracy of this version, but it is not the 

official version.

and gas from the sub-basin category and assume all of the 

CH4 and CO2

* * * * * 

 in both oil and gas are emitted from the tank. 

(4) Calculation Methodology 4. For wells with annual 

average daily oil production greater than or equal to 10 

barrels per day that flow to a separator not at the well 

pad, calculate annual CH4 and CO2

* * * * * 

 emissions by either of the 

methods in paragraph (j)(4) of this section: 

(5) * * * 

1000** E , EF Count = iis

(Eq. W-15) 

Where: 

* * * * * 

EFi = Population emission factor for separators or 

wells in thousand standard cubic feet per 

separator or well per year, for crude oil use 4.2 

for CH4 and 2.8 for CO2 at 60°F and 14.7 psia, and 

for gas condensate use 17.6 for CH4 and 2.8 for 

CO2

Count = Total number of separators or wells with 

throughput less than 10 barrels per day. 

 at 60°F and 14.7 psia. 

1,000 = Conversion to cubic feet 

* * * * * 

(8) * * * 

( )



 



  + −  



 = n

n

n

n

is n T

E

T

E

CFE 8760*

8760

*

8760

* , (Eq. W-16) 
Page 152 of 212 

This document is a prepublication version, signed by EPA Administrator Lisa P. Jackson on 

December 2, 2011. We have taken steps to ensure the accuracy of this version, but it is not the 

official version.

Where: 

* * * * * 

En

* * * * * 

 = Storage tank emissions as determined in 

Calculation Methodologies 1, 2, or 4 in 

paragraphs (j)(1), (j)(2) and (j)(4) of this 

section (with wellhead separators) in standard 

cubic feet per year. 

8,760 = Conversion to hourly emissions. 

* * * * * 

(k) Transmission storage tanks. For vent stacks 

connected to one or more transmission condensate storage 

tanks, either water or hydrocarbon, without vapor recovery, 

in onshore natural gas transmission compression, calculate 

CH4, CO2 and N2O 

(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 or high volume 

sampler according to methods in §98.234(b) through (d) for 

a duration of 5 minutes, or a calibrated bag according to 

methods in §98.234(b). 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). 

annual emissions from compressor scrubber 

dump valve leakage as follows: 
Page 153 of 212 

This document is a prepublication version, signed by EPA Administrator Lisa P. Jackson on 

December 2, 2011. We have taken steps to ensure the accuracy of this version, but it is not the 

official version.

(2) If the tank vapors from the vent stack 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 quantify 

annual emissions: 

(i) Use a meter, such as a turbine meter, calibrated 

bag, or high flow sampler to estimate tank vapor volumes 

from the vent stack 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 paragraph 

§98.233(k)(1) of this section to detect continuous leakage, 

this serves as the measurement. 

* * * * * 

(iv) Calculate GHG volumetric and mass emissions at 

standard conditions using calculations in paragraphs (t), 

(u), and (v) of this section, as applicable to the 

monitoring equipment used. * * * * * 

(4) Calculate annual emissions from storage tanks to 

flares as follows: 

(i) Use the storage tank emissions volume and gas 

composition as determined in paragraphs (k)(1) through 

(k)(3) of this section. 
Page 154 of 212 

This document is a prepublication version, signed by EPA Administrator Lisa P. Jackson on 

December 2, 2011. We have taken steps to ensure the accuracy of this version, but it is not the 

official version.

(ii) Use the calculation methodology of flare stacks 

in paragraph (n) of this section to determine storage tank 

emissions sent to a flare. 

(l) * * * 

(1) Determine the gas to oil ratio (GOR) of the 

hydrocarbon production from oil well(s) tested. Determine 

the production rate from gas well(s) tested. 

* * * * * 

(3) Estimate venting emissions using Equation W-17A or 

Equation W-17B of this section. 

E ,na = GOR FR** D (Eq. W-17A) 

E ,na = PR*D (Eq. W-17B) 

Where: 

Ea,n

GOR = Gas to oil ratio in cubic feet of gas per barrel 

of oil; oil here refers to hydrocarbon liquids 

produced of all API gravities. 

 = Annual volumetric natural gas emissions from 

well(s) testing in cubic feet under actual 

conditions. 

FR = Flow rate in barrels of oil per day for the oil 

well(s) being tested. 

PR = Average annual production rate in cubic feet per 

day for the gas well(s) being tested. 

D = Number of days during the year, the well(s) is 

tested. 

* * * * * 

(m) * * * 
Page 155 of 212 

This document is a prepublication version, signed by EPA Administrator Lisa P. Jackson on 

December 2, 2011. We have taken steps to ensure the accuracy of this version, but it is not the 

official version.

(1) Determine the GOR of the hydrocarbon production 

from each well whose associated natural gas is vented or 

flared. If GOR from each well is not available, the GOR 

from a cluster of wells in the same sub-basin category 

shall be used. 

* * * * * 

(3) * * * 

∑∑= =

= ∗

y

q

x

p

E na GOR V qpqp

1 1

, ,, (Eq. W-18) 

Where: 

Ea,n

GOR

 = Annual volumetric natural gas emissions, at the 

facility level, from associated gas venting under 

actual conditions, in cubic feet. 

p,q

V

 = Gas to oil ratio, for well p in sub-basin q, in 

cubic feet of gas per barrel of oil; oil here 

refers to hydrocarbon liquids produced of all API 

gravities. 

p,q

x = Total number of wells in sub-basin that vent or 

flare associated gas. 

 = Volume of oil produced, for well p in sub-basin 

q, in barrels in the calendar year during which 

associated gas was vented or flared. 

y = Total number of sub-basins in a basin that 

contain wells that vent or flare associated gas. 

* * * * * 

(n) * * * 

(2) * * * 

* * * * * 
Page 156 of 212 

This document is a prepublication version, signed by EPA Administrator Lisa P. Jackson on 

December 2, 2011. We have taken steps to ensure the accuracy of this version, but it is not the 

official version.

(ii) For onshore natural gas processing, when the 

stream going to flare is natural gas, use the GHG mole 

percent in feed natural gas for all streams upstream of the 

de-methanizer or dew point control, and GHG mole percent in 

facility specific residue gas to transmission pipeline 

systems for all emissions sources downstream of the demethanizer overhead or dew point control for onshore 

natural gas processing facilities. For onshore natural gas 

processing plants that solely fractionate a liquid stream, 

use the GHG mole percent in feed natural gas liquid for all 

streams. 

(iii) For any applicable industry segment, when the 

stream going to the flare is a hydrocarbon product stream, 

such as methane, ethane, propane, butane, pentane-plus and 

mixed light hydrocarbons, then you may use a representative 

composition from the source for the stream determined by 

engineering calculation based on process knowledge and best 

available data. 

* * * * * 

(4) * * * 

* * * * * 

( ) ∑( ) =

=

5

1

2,

***

J

a CO RYV jja E combusted η (Eq. W-21) 

* * * * * 
Page 157 of 212 

This document is a prepublication version, signed by EPA Administrator Lisa P. Jackson on 

December 2, 2011. We have taken steps to ensure the accuracy of this version, but it is not the 

official version.

(9) If you operate and maintain a CEMS that has both 

a CO2 concentration monitor and volumetric flow rate 

monitor, you must calculate only CO2 emissions for the 

flare. You must follow the Tier 4 Calculation Methodology 

and all associated calculation, quality assurance, 

reporting, and recordkeeping requirements for Tier 4 in 

subpart C of this part (General Stationary Fuel Combustion 

Sources). If a CEMS is used to calculate flare stack 

emissions, the requirements specified in paragraphs (n)(1) 

through (n)(7) are not required. If a CO2 concentration 

monitor and volumetric flow rate monitor are not available, 

you may elect to install a CO2 concentration monitor and a 

volumetric flow rate monitor that comply with all of the 

requirements specified for the Tier 4 Calculation 

Methodology in subpart C of this part (General Stationary 

Fuel Combustion). 

* * * * * 

(11) If source types in §98.233 use Equations W-19 

through W-21 of this section, use estimate of emissions 

under actual conditions for the parameter, Va

(o) * * * 

, in these 

equations. 
Page 158 of 212 

This document is a prepublication version, signed by EPA Administrator Lisa P. Jackson on 

December 2, 2011. We have taken steps to ensure the accuracy of this version, but it is not the 

official version.

(6) * * * 

* * * * * 

MTm

* * * * * 

 = Flow Measurements from all centrifugal compressor 

vents in each mode in (o)(1)(i) through 

(o)(1)(iii) of this section in standard cubic 

feet per hour. 

(7) * * * 

* * * * * 

EFi = Emission factor for GHGi. Use 1.2 x 107

 standard 

cubic feet per year per compressor for CH4 and 

5.30 x 105 thousand standard cubic feet per year 

per compressor for CO2

* * * * * 

 at 60°F and 14.7 psia. 

(p) * * * 

(7) * * * 

(i) * * * 

* * * * * 

MTm

* * * * * 

 = Meter readings from all reciprocating compressor 

vents in each and mode, m, in standard cubic feet 

per hour. 

(9) * * * 

* * * * * 

EFi = Emission factor for GHGi. Use 9.48 x 103 standard 

cubic feet per year per compressor for CH4 and 

5.27 x 102 standard cubic feet per year per 

compressor for CO2

* * * * * 

 at 60°F and 14.7 psia. 
Page 159 of 212 

This document is a prepublication version, signed by EPA Administrator Lisa P. Jackson on 

December 2, 2011. We have taken steps to ensure the accuracy of this version, but it is not the 

official version.

(q) Leak detection and leaker emission factors. You 

must use the methods described in §98.234(a) to conduct 

leak detection(s) of equipment leaks from all component 

types listed in §98.232(d)(7), (e)(7), (f)(5), (g)(3), 

(h)(4), and (i)(1). This paragraph (q) applies to 

component types in streams with gas content greater than 10 

percent CH4 plus CO2 by weight. Component types in streams 

with gas content less than 10 percent CH4 plus CO2 by weight 

do not need to be reported. Tubing systems equal to or 

less than one half inch diameter are exempt from the 

requirements of this paragraph (q) and do not need to be 

reported. If equipment leaks are detected for sources 

listed in this paragraph (q), calculate equipment leak 

emissions per component type per reporting facility using 

Equations W-30A or W-30B of this section for each component 

type. Use Equation W-30A for industry segments listed in 

98.230(a)(3)-(a)(7). Use Equation W-30B for industry 

segments listed in 98.230(a)(8). 

∑( ) =

=

x

p

E is GHGi EF Tp

1

, ** (Eq. W-30A) 

∑ ∑( ) +−= =

=

t

ntq

x

p

E is GHGi EF T qp

1 1

, * * , (Eq. W-30B) 

Where: 
Page 160 of 212 

This document is a prepublication version, signed by EPA Administrator Lisa P. Jackson on 

December 2, 2011. We have taken steps to ensure the accuracy of this version, but it is not the 

official version.

Es,i

x = Total number of each component type. 

 = Annual total volumetric GHG emissions at standard 

conditions from each component type in cubic 

feet, as specified in (q)(1) through (q)(8) of 

this section. 

EF = Leaker emission factor for specific component 

types listed in Table W-2 through Table W-7 of 

this subpart. 

GHGi = For onshore natural gas processing facilities, 

concentration of GHGi, CH4 or CO2, in the total 

hydrocarbon of the feed natural gas; for onshore 

natural gas transmission compression and 

underground natural gas storage, GHGi equals 0.975 

for CH4 and 1.1 × 10-2 for CO2; for LNG storage 

and LNG import and export equipment, GHGi equals 1 

for CH4 and 0 for CO2; and for natural gas 

distribution, GHGi equals 1 for CH4 and 1.1×10-2

CO2

T

. 

p

t = Calendar year of reporting. 

 = The total time the component, p, was found 

leaking and operational, in hours. If one leak 

detection survey is conducted, assume the 

component was leaking for the entire calendar 

year. If multiple leak detection surveys are 

conducted, assume that the component found to be 

leaking has been leaking since the previous 

survey (if not found leaking in the previous 

survey) or the beginning of the calendar year (if 

it was found leaking in the previous survey). 

For the last leak detection survey in the 

calendar year, assume that all leaking components 

continue to leak until the end of the calendar 

year. 

n = The number of years over which one complete cycle 

of leak detection is conducted over all the T-D 

transfer stations in a natural gas distribution 

facility; 0 < n ≤ 5. For the first (n-1) calendar 

years of reporting the summation in Equation W30B should be for years that the data is 

available. 

Tp,q = The total time the component, p, was found 

leaking and operational, in hours, in year q. If 

one leak detection survey is conducted, assume 
Page 161 of 212 

This document is a prepublication version, signed by EPA Administrator Lisa P. Jackson on 

December 2, 2011. We have taken steps to ensure the accuracy of this version, but it is not the 

official version.

the component was leaking for the entire period 

n. If multiple leak detection surveys are 

conducted, assume that the component found to be 

leaking has been leaking since the previous 

survey (if not found to be leaking in the 

previous survey) or the beginning of the calendar 

year (if it was found to be leaking in the 

previous survey). For the last leak detection 

survey in the cycle, assume that all leaking 

components continue to leak until the end of the 

cycle. 

* * * * * 

(8) Natural gas distribution facilities for above 

grade transmission-distribution transfer stations, shall 

use the appropriate default leaker emission factors listed 

in Table W-7 of this subpart for equipment leaks detected 

from connectors, block valves, control valves, pressure 

relief valves, orifice meters, regulators, and open ended 

lines. Leak detection at natural gas distribution 

facilities is only required at above grade stations that 

qualify as transmission-distribution transfer stations. 

Below grade transmission-distribution transfer stations and 

all metering-regulating stations that do meet the 

definition of transmission-distribution transfer stations 

are not required to perform component leak detection under 

this section. 
Page 162 of 212 

This document is a prepublication version, signed by EPA Administrator Lisa P. Jackson on 

December 2, 2011. We have taken steps to ensure the accuracy of this version, but it is not the 

official version.

(i) Natural gas distribution facilities may choose to 

conduct leak detection at the T-D transfer stations over 

multiple years, not exceeding a five year period to cover 

all T-D transfer stations. If the facility chooses to use 

the multiple year option then the number of T-D transfer 

stations that are monitored in each year should be 

approximately equal across all years in the cycle without 

monitoring the same station twice during the multiple year 

survey. 

(ii) [Reserved] 

(r) Population count and emission factors. This 

paragraph applies to emissions sources listed in §98.232 

(c)(21), (f)(5), (g)(3), (h)(4), (i)(2), (i)(3), (i)(4), 

(i)(5), and (i)(6) on streams with gas content greater than 

10 percent CH4 plus CO2 by weight. Emissions sources in 

streams with gas content less than 10 percent CH4 plus CO2

* * * * * 

by weight do not need to be reported. Tubing systems equal 

to or less than one half inch diameter are exempt from the 

requirements of paragraph (r) of this section and do not 

need to be reported. Calculate emissions from all sources 

listed in this paragraph using Equation W-31 of this 

section. 
Page 163 of 212 

This document is a prepublication version, signed by EPA Administrator Lisa P. Jackson on 

December 2, 2011. We have taken steps to ensure the accuracy of this version, but it is not the 

official version.

Es,i

Count

 = Annual volumetric GHG emissions at standard 

conditions from each component type in cubic 

feet. 

s

EF = Population emission factor for the specific 

component type, as listed in Table W-1A and 

Tables W-3 through Table W-7 of this subpart. 

Use appropriate population emission factor for 

operations in Eastern and Western U.S., 

according to Table W-1D of this subpart. EF for 

meter/regulator runs at above grade meteringregulating stations is determined in Equation W32 of this section. 

 = Total number of this type of emission source at 

the facility. For onshore petroleum and natural 

gas production, average component counts are 

provided by major equipment piece in Tables W-1B 

and Table W-1C of this subpart. Use average 

component counts as appropriate for operations 

in Eastern and Western U.S., according to Table 

W-1D of this subpart. Underground natural gas 

storage shall count the components listed for 

population emission factors in Table W-4. LNG 

Storage shall count the number of vapor recovery 

compressors. LNG import and export shall count 

the number of vapor recovery compressors. 

Natural gas distribution shall count the 

meter/regulator runs as described in paragraph 

(r)(6) of this section. 

GHGi = For onshore petroleum and natural gas production 

facilities, concentration of GHGi, CH4 or CO2, in 

produced natural gas as defined in paragraph 

(u)(2) of this section; for onshore natural gas 

transmission compression and underground natural 

gas storage, GHGi equals 0.975 for CH4 and 1.1 ×

10-2 for CO2; for LNG storage and LNG import and 

export equipment, GHGi equals 1 for CH4 and 0 for 

CO2; and for natural gas distribution, GHGi

equals 1 for CH4 and 1.1×10-2 CO2

T

. 

s

* * * * * 

 = Average estimated time that each component type 

associated with the equipment leak emission was 

operational in the calendar year, in hours, 

using engineering estimate based on best 

available data. 
Page 164 of 212 

This document is a prepublication version, signed by EPA Administrator Lisa P. Jackson on 

December 2, 2011. We have taken steps to ensure the accuracy of this version, but it is not the 

official version.

(2) * * * 

(i) * * * 

(A) Count all major equipment listed in Table W-1B 

and Table W-1C of this subpart. For meters/piping, use one 

meters/piping per well-pad. 

* * * * * 

(6) * * * 

(i) Below grade metering-regulating stations; 

distribution mains; and distribution services, shall use 

the appropriate default population emission factors listed 

in Table W-7 of this subpart. Below grade T-D transfer 

stations shall use the emission factor for below grade 

metering-regulating stations. 

(ii) Emissions from all above grade meteringregulating stations (including above grade TD transfer 

stations) shall be calculated by applying the emission 

factor calculated in Equation W-32 and the total count of 

meter/regulator runs at all above grade metering-regulating 

stations (inclusive of TD transfer stations) to Equation W31. The facility wide emission factor in Equation W-32 

will be calculated by using the total volumetric GHG 

emissions at standard conditions for all equipment leak 

sources calculated in Equation W-30B in paragraph (q)(8) of 

this section and the count of meter/regulator runs located 
Page 165 of 212 

This document is a prepublication version, signed by EPA Administrator Lisa P. Jackson on 

December 2, 2011. We have taken steps to ensure the accuracy of this version, but it is not the 

official version.

at above grade transmission-distribution transfer stations 

that were monitored over the years that constitute one 

complete cycle as per (q)(8)(i) of this section. A meter 

on a regulator run is considered one meter or regulator 

run. Reporters that do not have above grade T-D transfer 

stations shall report a count of above grade meteringregulating stations only and do not have to comply with 

§98.236(c)(16)(xix). 

Count

E

EF ,is ÷ 8760 = (Eq. W-32) 

Where: 

EF = Facility emission factor for a meter/regulator 

run per component type at above grade meteringregulating for GHGi

E

 in cubic feet per 

meter/regulator run per hour. 

s,i = Annual volumetric GHG i emissions, CO2 or CH4

Count = Total number of meter/regulator runs at all TD 

transfer stations that were monitored over the 

years that constitute one complete cycle as per 

(q)(8)(i) of this section. 

 at 

standard condition from each component type at 

all above grade TD transfer stations, from 

Equation W-30B. 

8760 = Conversion to hourly emissions 

* * * * * 

(t) Volumetric emissions. Calculate volumetric 

emissions at standard conditions as specified in paragraphs 

(t)(1) or (2) of this section, with actual pressure and 
Page 166 of 212 

This document is a prepublication version, signed by EPA Administrator Lisa P. Jackson on 

December 2, 2011. We have taken steps to ensure the accuracy of this version, but it is not the 

official version.

temperature determined by engineering estimates based on 

best available data unless otherwise specified. 

(1) Calculate natural gas volumetric emissions at 

standard conditions using actual natural gas emission 

temperature and pressure, and Equation W-33 of this 

section. 

* * * * * 

Ts = Temperature at standard conditions (60o

* * * * * 

F). 

Ps

* * * * * 

 = Absolute pressure at standard conditions (14.7 

psia). 

(2) Calculate GHG volumetric emissions at standard 

conditions using actual GHG emissions temperature and 

pressure, and Equation W-34 of this section. 

* * * * * 

Ts = Temperature at standard conditions (60o

* * * * * 

F). 

Ps

* * * * * 

 = Absolute pressure at standard conditions (14.7 

psia). 
Page 167 of 212 

This document is a prepublication version, signed by EPA Administrator Lisa P. Jackson on 

December 2, 2011. We have taken steps to ensure the accuracy of this version, but it is not the 

official version.

(3) Reporters using 68°F for standard temperature may 

use the ratio 519.67/527.67 to convert volumetric emissions 

from 68°F to 60°F. 

(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. 

(2) For Equation W-35 of this section, the mole 

fraction, Mi

(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 an annual average of 

these values for determining the mole fraction. If you do 

not have a continuous gas composition analyzer, then you 

must use an annual average gas composition based on your 

most recent available analysis of the sub-basin category or 

facility, as applicable to the emission source. 

, shall be the annual average mole fraction for 

each sub-basin category or facility, as specified in 

paragraphs (u)(2)(i) through (vii) of this section. 
Page 168 of 212 

This document is a prepublication version, signed by EPA Administrator Lisa P. Jackson on 

December 2, 2011. We have taken steps to ensure the accuracy of this version, but it is not the 

official version.

(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. For onshore natural gas processing plants that 

solely fractionate a liquid stream, use the GHG mole 

percent in feed natural gas liquid for all streams. 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 the 

onshore natural gas transmission compression industry 

segment. You may use a default 95 percent methane and 1 

percent carbon dioxide fraction for GHG mole fraction in 

natural gas. 

(iv) GHG mole fraction in natural gas stored in the 

underground natural gas storage industry segment. You may 

use a default 95 percent methane and 1 percent carbon 

dioxide fraction for GHG mole fraction in natural gas. 
Page 169 of 212 

This document is a prepublication version, signed by EPA Administrator Lisa P. Jackson on 

December 2, 2011. We have taken steps to ensure the accuracy of this version, but it is not the 

official version.

(v) GHG mole fraction in natural gas stored in the 

LNG storage industry segment. You may use a default 95 

percent methane and 1 percent carbon dioxide fraction for 

GHG mole fraction in natural gas. 

(vi) GHG mole fraction in natural gas stored in the 

LNG import and export industry segment. For export 

facilities that receive gas from transmission pipelines, 

you may use a default 95 percent methane and 1 percent 

carbon dioxide fraction for GHG mole fraction in natural 

gas. 

(vii) GHG mole fraction in local distribution 

pipeline natural gas that passes through the facility for 

natural gas distribution facilities. You may use a default 

95 percent methane and 1 percent carbon dioxide fraction 

for GHG mole fraction in natural gas. 

(v) GHG mass emissions. Calculate GHG mass emissions 

in carbon dioxide equivalent by converting the GHG 

volumetric emissions at standard conditions into mass 

emissions using Equation W-36 of this section. 

3

, 10*** − = EMass ρ iisi GWP (Eq. W-36) 

Where: 

Massi = GHGi (either CH4 , CO2, or N2O) mass emissions in 

metric tons CO2

E

e. 

s,i = GHGi (either CH4, CO2, or N2O) volumetric 

emissions at standard conditions, in cubic feet. 
Page 170 of 212 

This document is a prepublication version, signed by EPA Administrator Lisa P. Jackson on 

December 2, 2011. We have taken steps to ensure the accuracy of this version, but it is not the 

official version.

 = Density of GHGi. Use 0.0526 kg/ft3

 for CO2 and 

N2O, and 0.0422 kg/ft3 for CH4

* * * * * 

 at 60°F and 14.7 

psia. 

(w)* * * 

(3) * * * 

3

2 2 10**** −

CO = RVNMass cv GHGCO (Eq. W-37) 

Where: 

MassCO2 =

* * * * * 

Annual EOR injection gas venting emissions in 

metric tons from blowdowns. 

GHGCO2 = Mass fraction of CO2

* * * * * 

 in critical phase injection 

gas. 

(x)* * * 

(2) * * * 

MassCO2 = Shl * Vhl

Where: 

(Eq. W-38) 

MassCO2 = Annual CO2 emissions from CO2

* * * * * 

 retained in 

hydrocarbon liquids produced through EOR 

operations beyond tankage, in metric tons. 

(z) Onshore petroleum and natural gas production and 

natural gas distribution combustion emissions. Calculate 

CO2, CH4, and N2

ρ i

O combustion-related emissions from 
Page 171 of 212 

This document is a prepublication version, signed by EPA Administrator Lisa P. Jackson on 

December 2, 2011. We have taken steps to ensure the accuracy of this version, but it is not the 

official version.

stationary or portable equipment, except as specified in 

paragraph (z)(3) and(z)(4) of this section, as follows: 

(1) If a fuel combusted in the stationary or portable 

equipment is listed in Table C–1 of subpart C of this part, 

or is a blend containing one or more fuels listed in 

Table C–1, calculate emissions according to (z)(1)(i). If 

the fuel combusted is natural gas and is of pipeline 

quality specification and has a minimum high heat value of 

950 Btu per standard cubic foot, use the calculation 

methodology described in (z)(1)(i) and you may use the 

emission factor provided for natural gas as listed in Table 

C-1. If the fuel is natural gas, and is not pipeline 

quality or has a high heat value of less than 950 But per 

standard cubic feet, calculate emissions according to 

(z)(2). If the fuel is field gas, process vent gas, or a 

blend containing field gas or process vent gas, calculate 

emissions according to (z)(2). 

(i) For fuels listed in Table C-1 or a blend 

containing one or more fuels listed in Table C-1, calculate 

CO2, CH4, and N2O emissions according to any Tier listed in 

subpart C of this part. You must follow all applicable 

calculation requirements for that tier listed in 98.33, any 

monitoring or QA/QC requirements listed for that tier in 
Page 172 of 212 

This document is a prepublication version, signed by EPA Administrator Lisa P. Jackson on 

December 2, 2011. We have taken steps to ensure the accuracy of this version, but it is not the 

official version.

98.34, any missing data procedures specified in 98.35, and 

any recordkeeping requirements specified in 98.37. 

(ii) Emissions from fuel combusted in stationary or 

portable equipment at onshore natural gas and petroleum 

production facilities and at natural gas distribution 

facilities will be reported according to the requirements 

specified in 98.236(c)(19) and not according to the 

reporting requirements specified in subpart C of this part. 

(2) For fuel combustion units that combust field gas, 

process vent gas, a blend containing field gas or process 

vent gas, or natural gas that is not of pipeline quality or 

that has a high heat value of less than 950 Btu per 

standard cubic feet, calculate combustion emissions as 

follows: 

(i) You may use company records to determine the 

volume of fuel combusted in the unit during the reporting 

year. 

(ii) If you have a continuous gas composition 

analyzer on fuel to the combustion unit, you must use these 

compositions for determining the concentration of gas 

hydrocarbon constituent in the flow of gas to the unit. If 

you do not have a continuous gas composition analyzer on 

gas to the combustion unit, you must use the appropriate 

gas compositions for each stream of hydrocarbons going to 
Page 173 of 212 

This document is a prepublication version, signed by EPA Administrator Lisa P. Jackson on 

December 2, 2011. We have taken steps to ensure the accuracy of this version, but it is not the 

official version.

the combustion unit as specified in the applicable 

paragraph in (u)(2) of this section. 

(iii) Calculate GHG volumetric emissions at actual 

conditions using Equations W-39A and W-39B of this section: 

∑=

= +

5

1

2, 2 ***)*(

j

a CO a YVE CO η RYV jja (Eq. W-39A) 

( ) a CH 4, VE a −= η *1* YCH 4 (Eq. W-39B) 

Where: 

Eco2 = Contribution of annual CO2

V

 emissions from 

portable or stationary fuel combustion sources 

in cubic feet, under actual conditions. 

a

Y

 = Volume of gas sent to combustion unit in cubic 

feet, during the year. 

CO2 = Concentration of CO2

E

 constituent in gas sent 

to combustion unit. 

a,CH4 = Contribution of annual CH4

η = Fraction of gas combusted for portable and 

stationary equipment determined using 

engineering estimation. For internal 

combustion devices, a default of 0.995 can be 

used. 

 emissions from 

portable or stationary fuel combustion sources 

in cubic feet, under actual conditions. 

Yj 

R

 = Concentration of gas hydrocarbon constituents 

j (such as methane, ethane, propane, butane, 

and pentanes plus) in gas sent to combustion 

unit. 

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, in gas sent to combustion unit. 
Page 174 of 212 

This document is a prepublication version, signed by EPA Administrator Lisa P. Jackson on 

December 2, 2011. We have taken steps to ensure the accuracy of this version, but it is not the 

official version.

YCH4

 * * * * * 

 = Concentration of methane constituent in gas 

sent to combustion unit. 

(vi) Calculate N2

Mass ON ( ) HHVFuel EF ×××××= GWP −3

2 101

O mass emissions using Equation W–40 

of this section. 

 (Eq. W-40)

Where: 

MassN2O = Annual N2

* * * * * 

O emissions from the combustion of a 

particular type of fuel (metric tons CO2e). 

HHV = For the high heat value for field gas or process 

vent gas, use 1.235 x 10-3

* * * * * 

 mmBtu/scf for HHV. 

GWP = Global warming potential, as listed in Table A-1 

of subpart A of this part. 

 (3) External fuel combustion sources with a rated 

heat capacity equal to or less than 5 mmBtu/hr do not need 

to report combustion emissions or include these emissions 

for threshold determination in §98.231(a). You must report 

the type and number of each external fuel combustion unit. 

(4) Internal fuel combustion sources, not 

compressor-drivers, with a rated heat capacity equal to or 

less than 1 mmBtu/hr (or the equivalent of 130 horsepower), 

do not need to report combustion emissions or include these 

emissions for threshold determination in §98.231(a). You 
Page 175 of 212 

This document is a prepublication version, signed by EPA Administrator Lisa P. Jackson on 

December 2, 2011. We have taken steps to ensure the accuracy of this version, but it is not the 

official version.

must report the type and number of each internal fuel 

combustion unit. 

7. Section 98.234 is amended by: 

a. Revising paragraphs (a)(1), (a)(2), and (a)(5). 

b. Removing and reserving paragraph (a)(4). 

c. Revising paragraph (c) introductory text and 

paragraph (d)(3). 

d. Revising Equation W-41 of paragraph (e). 

e. Adding new paragraph (g). 

* * * * * 

§98.234 Monitoring and QA/QC requirements.

(a) * * * 

(1) Optical gas imaging instrument. Use an optical 

gas imaging instrument for equipment leak detection in 

accordance with 40 CFR part 60, subpart A, §60.18 of the 

Alternative work practice for monitoring equipment leaks, 

§60.18(i)(1)(i); §60.18(i)(2)(i) except that the monitoring 

frequency shall be annual using the detection sensitivity 

level of 60 grams per hour as stated in 40 CFR Part 60, 

subpart A, Table 1: Detection Sensitivity Levels; 

§60.18(i)(2)(ii) and (iii) except the gas chosen shall be 

methane, and §60.18(i)(2)(iv) and (v); §60.18(i)(3); 

§60.18(i)(4)(i) and (v); including the requirements for 

daily instrument checks and distances, and excluding 
Page 176 of 212 

This document is a prepublication version, signed by EPA Administrator Lisa P. Jackson on 

December 2, 2011. We have taken steps to ensure the accuracy of this version, but it is not the 

official version.

requirements for video records. 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. 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. Unless using methods 

in paragraph (a)(2) of this section, an optical gas imaging 

instrument must be used for all source types that are 

inaccessible and cannot be monitored without elevating the 

monitoring personnel more than 2 meters above a support 

surface. 

(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) or (a)(2) of this section to monitor 

inaccessible equipment leaks or vented emissions. 
Page 177 of 212 

This document is a prepublication version, signed by EPA Administrator Lisa P. Jackson on 

December 2, 2011. We have taken steps to ensure the accuracy of this version, but it is not the 

official version.

(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 throughvalve 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 stethoscope 

type devices designed to detect through valve leakage when 

put in contact with the valve body and 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. 

 (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 the bag is safe to handle. The bag 

opening must be of sufficient size that the entire emission 
Page 178 of 212 

This document is a prepublication version, signed by EPA Administrator Lisa P. Jackson on 

December 2, 2011. We have taken steps to ensure the accuracy of this version, but it is not the 

official version.

can be tightly encompassed for measurement till the bag is 

completely filled. 

* * * * * 

(d) * * * 

(3) Estimate natural gas volumetric emissions at 

standard conditions using calculations in §98.233(t). 

Estimate CH4 and CO2

* * * * * 

 volumetric and mass emissions from 

volumetric natural gas emissions using the calculations in 

§98.233(u) and (v). 

(e) * * * 

2 2 2bVV b

a

bV

RT

p

m m m −+ − − = α

(Eq. W-41) 

Where: 

p = Absolute pressure. 

R = Universal gas constant. 

T = Absolute temperature. 

Vm

a = 

 = Molar volume. 

c

c

p

TR 22 45724.0

b = c

c

p

7780.0 RT

α = ( )

2

2 126992.054226.137464.01 































++ − − Tc

T

ω ω

Where: 
Page 179 of 212 

This document is a prepublication version, signed by EPA Administrator Lisa P. Jackson on 

December 2, 2011. We have taken steps to ensure the accuracy of this version, but it is not the 

official version.

ω = Acentric factor of the species. 

Tc

P

 = Critical temperature. 

c

* * * * * 

 = Critical pressure. 

 (g) For the purposes of fulfilling requirements in 40 

CFR 98.233(f) and (g) which require measurements to be 

taken every other year beginning in the first year of data 

collection, reporters have the option of taking the first 

measurement in 2012 to satisfy the requirements for the 

2011 – 2012 data collection cycle. 

8. Section 98.236 is amended by: 

a. Revising paragraphs (a) introductory text and 

(a)(8). 

b. Revising paragraph (b). 

c. Revising paragraphs (c) introductory text, 

(c)(1)(iv), (c)(2)(ii), and (c)(3)(ii) through (c)(3)(v); 

and adding paragraphs (c)(3)(vi) and (vii). 

d. Revising paragraphs (c)(4)(i)(H) and 

(C)(4)(i)(J); and adding paragraphs (c)(4)(i)(K), and 

(c)(4)(i)(L). 

e. Revising paragraphs (c)(4)(ii)(B) and 

(c)(4)(ii)(C); and adding paragraph (c)(4)(ii)(D). 

f. Revising paragraph (c)(4)(iii)(B). 

g. Revising paragraph (c)(5). 
Page 180 of 212 

This document is a prepublication version, signed by EPA Administrator Lisa P. Jackson on 

December 2, 2011. We have taken steps to ensure the accuracy of this version, but it is not the 

official version.

h.

i. Revising paragraphs (c)(6) introductory text, and 

(c)(6)(i).. 

j. Revising paragraph (c)(6)(ii)(B), (c)(6)(ii)(D) 

and adding paragraph (c)(6)(ii)(E). 

k. Revising paragraph (c)(7). 

l. Revising paragraphs (c)(8)(i) introductory text 

and (c)(8)(i)(J); and adding paragraphs (c)(8)(i)(K) and 

(c)(8)(i)(L). 

m. Revising paragraphs (c)(8)(ii) introductory text, 

(c)(8)(ii)(D), and (c)(8)(ii)(G); and adding paragraphs 

(c)(8)(ii)(H) and (c)(8)(ii)(I). 

n. Revising paragraphs (c)(8)(iii) introductory text 

and (c)(8)(iii)(F); and adding paragraphs (c)(8)(iii)(G) 

and (c)(8)(iii)(H). 

o. Adding paragraph (c)(8)(iv)(B). 

p. Revising paragraphs (c)(9) introductory text, 

(c)(9)(i) and (c)(9)(ii); and adding paragraph (c)(9)(iii). 

q. Revising paragraphs (c)(10) introductory text and 

(c)(10)(iv); and adding paragraph (c)(10)(v). 

r. Revising paragraph (c)(11) introductory text and 

(c)(11)(iii); and adding paragraph (c)(11)(iv). 

s. Revising paragraph (c)(12)(vi) and adding 

paragraphs (c)(12)(vii) through (c)(12)(xi). 
Page 181 of 212 

This document is a prepublication version, signed by EPA Administrator Lisa P. Jackson on 

December 2, 2011. We have taken steps to ensure the accuracy of this version, but it is not the 

official version.

t. Revising paragraphs (c)(15) introductory text, 

(c)(15)(i)(A), (c)(15)(i)(B) and (c)(15)(i)(C). 

u. Revising paragraphs (c)(15)(ii)(A) through 

(c)(15)(ii)(C). 

v. Revising paragraph (c)(16). 

w. Revising paragraph (c)(17)(v). 

x. Revising paragraphs (c)(18) introductory text and 

paragraph (c)(18)(iii). 

y. Revising paragraphs (c)(19)(iii), (c)(19)(v), 

(c)(19)(vi), and (c)(19)(vii). 

z. Adding paragraph (e). 

The revisions read as follows: 

* * * * * 

§98.236 Data Reporting Requirements.

(a) Report annual emissions in metric tons of CO2

* * * * * 

e for 

each GHG separately for each of the industry segments 

listed in paragraphs (a)(1) through (8) of this section. 

(8) Natural gas distribution. 

(b) For offshore petroleum and natural gas 

production, report emissions of CH4, CO2, and N2O as 

applicable to the source type (in metric tons CO2e per year 

at standard conditions) individually for all of the 
Page 182 of 212 

This document is a prepublication version, signed by EPA Administrator Lisa P. Jackson on 

December 2, 2011. We have taken steps to ensure the accuracy of this version, but it is not the 

official version.

emissions source types listed in the most recent BOEMRE 

study. 

(c) Report the information listed in this paragraph 

for each applicable source type in metric tons of CO2

(1) * * * 

e for 

each GHG. If a facility operates under more than one 

industry segment, each piece of equipment should be 

reported under the unit’s respective majority use segment. 

When a source type listed under this paragraph routes gas 

to flare, separately report the emissions that were vented 

directly to the atmosphere without flaring, and the 

emissions that resulted from flaring the gas. Both the 

vented and flared emissions will be reported under the 

respective source type and not under the flare source type. 

(iv) Report annual CO2 and CH4 emissions at the 

facility level, expressed in metric tons CO2

(2) * * * 

e for each gas, 

for each of the following pieces of equipment: high bleed 

pneumatic devices; intermittent bleed pneumatic devices; 

low bleed pneumatic devices. 

(ii) Report annual CO2 and CH4 emissions at the 

facility level, expressed in metric tons CO2

(3) * * * 

e for each gas, 

for all natural gas driven pneumatic pumps combined. 
Page 183 of 212 

This document is a prepublication version, signed by EPA Administrator Lisa P. Jackson on 

December 2, 2011. We have taken steps to ensure the accuracy of this version, but it is not the 

official version.

(ii) For Calculation Methodology 1 and Calculation 

Methodology 2 of §98.233(d), annual average fraction of CO2

(iii) For Calculation Methodology 3 of §98.233(d), 

annual average volume fraction of CO

content in the vent from the acid gas removal unit (refer 

to §98.233(d)(6)). 

2

(iv) Report the annual quantity of CO

 content of natural gas 

into and out of the acid gas removal unit (refer to 

§98.233(d)(7) and (d)(8)). 

2, expressed in 

metric tons CO2

(v) Report annual CO

e, that was recovered from the AGR unit and 

transferred outside the facility, under subpart PP of this 

part. 

2 emissions for the AGR unit, 

expressed in metric tons CO2

(vi) For the onshore natural gas processing industry 

segment only, report a unique name or ID number for the AGR 

unit. 

e. 

(vii) An indication of which calculation methodology 

was used for the AGR. 

(4) * * * 

(i) * * * 

(H) Concentration of CH4 and CO2 

* * * * * 

in wet natural gas. 
Page 184 of 212 

This document is a prepublication version, signed by EPA Administrator Lisa P. Jackson on 

December 2, 2011. We have taken steps to ensure the accuracy of this version, but it is not the 

official version.

(J) For each glycol dehydrator, report annual CO2 and 

CH4 emissions that resulted from venting gas directly to the 

atmosphere, expressed in metric tons CO2

(K) For each glycol dehydrator, report annual CO

e for each gas. 

2, 

CH4, and N2O emissions that resulted from flaring process 

gas from the dehydrator, expressed in metric tons CO2

(L) For the onshore natural gas processing industry 

segment only, report a unique name or ID number for glycol 

dehydrator. 

e for 

each gas. 

(ii) * * * 

* * * * * 

(B) Which vent gas controls are used (refer to 

§98.233(e)(3) and (e)(4)). 

(C) Report annual CO2 and CH4 emissions at the 

facility level that resulted from venting gas directly to 

the atmosphere, expressed in metric tons CO2

(D) Report annual CO

e for each gas, 

combined for all glycol dehydrators with annual average 

daily throughput of less than 0.4 MMscfd. 

2, CH4, and N2O emissions at the 

facility level that resulted from the flaring of process 

gas, expressed in metric tons CO2e for each gas, combined 

for all glycol dehydrators with annual average daily 

throughput of less than 0.4 MMscfd. 
Page 185 of 212 

This document is a prepublication version, signed by EPA Administrator Lisa P. Jackson on 

December 2, 2011. We have taken steps to ensure the accuracy of this version, but it is not the 

official version.

(iii) * * * 

* * * * * 

(B) Report annual CO2 and CH4 emissions at the 

facility level, expressed in metric tons CO2

(5) For well venting for liquids unloading, report 

the following: 

e for each gas, 

for all absorbent desiccant dehydrators combined. 

(i) For Calculation Methodology 1 (refer to Equation 

W-7 of §98.233), report the following for each tubing 

diameter group and pressure group combination within each 

sub-basin category: 

(A) Count of wells vented to the atmosphere for 

liquids unloading. 

(B) Count of plunger lifts. Whether the selected well 

from the tubing diameter and pressure group combination had 

a plunger lift (yes/no). 

(C) Cumulative number of unloadings vented to the 

atmosphere. 

(D) Average flow rate of the measured well venting in 

cubic feet per hour (refer to §98.233(f)(1)(i)(A)). 

(E) Internal casing diameter or internal tubing 

diameter in inches, where applicable, and well depth of 

each well, in feet, selected to represent emissions in 

that tubing size and pressure combination. 
Page 186 of 212 

This document is a prepublication version, signed by EPA Administrator Lisa P. Jackson on 

December 2, 2011. We have taken steps to ensure the accuracy of this version, but it is not the 

official version.

(F) Casing pressure, in psia, of each well selected 

to represent emissions in that tubing size group and 

pressure group combination that does not have a plunger 

lift. 

(G) Tubing pressure, in psia, of each well selected 

to represent emissions in a tubing size group and pressure 

group combination that has a plunger lift. 

(H) Report annual CO2 and CH4 emissions, expressed in 

metric tons CO2

(ii) For Calculation Methodologies 2 and 3 (refer to 

Equation W-8 and W-9 of §98.233), report the following for 

each sub-basin category: 

e for each gas. 

(A) Count of wells vented to the atmosphere for 

liquids unloading. 

(B) Count of plunger lifts. 

(C) Cumulative number of unloadings vented to the 

atmosphere. 

(D) Average internal casing diameter, in inches, of 

each well, where applicable. 

 (E) Report annual CO2 and CH4 emissions, 

expressed in metric tons CO2

(6) For well completions and workovers, report the 

following for each sub-basin category: 

e for each GHG gas. 
Page 187 of 212 

This document is a prepublication version, signed by EPA Administrator Lisa P. Jackson on 

December 2, 2011. We have taken steps to ensure the accuracy of this version, but it is not the 

official version.

(i) For gas well completions and workovers with 

hydraulic fracturing by sub-basin and well type (horizontal 

or vertical) combination (refer to Equation W-10A and W-10B 

of §98.233), report the following: 

 

(A) Total count of completions in calendar year. 

(B) When using Equation W-10A, measured flow rate of 

backflow during well completion in standard cubic feet per 

hour. 

(C) Total count of workovers in calendar year that 

flare gas or vent gas to the atmosphere. 

(D) When using Equation W-10A, measured flow rate of 

backflow during well workover in standard cubic feet per 

hour. 

(E) When using Equation W-10A, total number of days 

of backflow from all wells during completions. 

(F) When using Equation W-10A, total number of days 

of backflow from all wells during workovers. 

(G) Report number of completions employing purposely 

designed equipment that separates natural gas from the 

backflow and the amount of natural gas, in standard cubic 

feet, recovered using engineering estimate based on best 

available. 
Page 188 of 212 

This document is a prepublication version, signed by EPA Administrator Lisa P. Jackson on 

December 2, 2011. We have taken steps to ensure the accuracy of this version, but it is not the 

official version.

(H) Report number of workovers employing purposely 

designed equipment that separates natural gas from the 

backflow and the amount of natural gas, in standard cubic 

feet, recovered using engineering estimate based on best 

available data. 

(I) Annual CO2 and CH4 emissions that resulted from 

venting gas directly to the atmosphere, expressed in metric 

tons CO2

(J) Annual CO

e for each gas. 

2, CH4, and N2O emissions that resulted 

from flares, expressed in metric tons CO2

 * * * * * 

e for each gas. 

(ii) * * * 

* * * * * 

(B) Total count of workovers in calendar year that 

flare gas or vent gas to the atmosphere. 

* * * * * 

(D) Annual CO2 and CH4 emissions that resulted from 

venting gas directly to the atmosphere, expressed in metric 

tons CO2

(E) Annual CO

e for each gas. 

2, CH4, and N2O emissions that resulted 

from flares, expressed in metric tons CO2

(7) For blowdown vent stack emission source, (refer 

to Equation W-14A and Equation W-14B of §98.233), report 

the following: 

e for each gas. 
Page 189 of 212 

This document is a prepublication version, signed by EPA Administrator Lisa P. Jackson on 

December 2, 2011. We have taken steps to ensure the accuracy of this version, but it is not the 

official version.

(i) For each unique physical volume that is blown 

down more than once during the calendar year, report the 

following: 

(A) Total number of blowdowns for each unique 

physical volume in the calendar year. 

(B) Annual CO2 and CH4 emissions, for each unique 

physical blowdown volume, expressed in metric tons CO2

(C) A unique name or ID number for the unique 

physical volume. 

e for 

each gas. 

(ii) For all unique volumes that are blown down once 

during the calendar year, report the following: 

(A) Total number of blowdowns for all unique physical 

volumes in the calendar year. 

(B) Annual CO2 and CH4 emissions from all unique 

physical volumes as an aggregate per facility, expressed in 

metric tons CO2

(8) * * * 

e for each gas. 

(i) For wellhead gas-liquid separator with oil 

throughput greater than or equal to 10 barrels per day, 

using Calculation Methodology 1 and 2 of §98.233(j), report 

the following by sub-basin category, unless otherwise 

specified: 
Page 190 of 212 

This document is a prepublication version, signed by EPA Administrator Lisa P. Jackson on 

December 2, 2011. We have taken steps to ensure the accuracy of this version, but it is not the 

official version.

* * * * * 

(J) Annual CO2 and CH4 emissions that resulted from 

venting gas to the atmosphere, expressed in metric tons CO2

(K) Annual CO

e 

for each gas, for all wellhead gas-liquid separators or 

storage tanks using Calculation Methodology 1, and for all 

wellhead gas-liquid separators or storage tanks using 

Calculation Methodology 2 of §98.233(j). 

2 and CH4 gas quantities that were 

recovered, expressed in metric tons CO2

(L) Annual CO

e for each gas, for 

all wellhead gas-liquid separators or storage tanks using 

Calculation Methodology 1, and for all wellhead gas-liquid 

separators or storage tanks using Calculation Methodology 2 

of §98.233(j). 

2, CH4, and N2O emissions that resulted 

from flaring gas, expressed in metric tons CO2

(ii) For wells with oil production greater than or 

equal to 10 barrels per day, using Calculation Methodology 

3 and 4 of §98.233(j), report the following by sub-basin 

category: 

e for each 

gas, for all wellhead gas-liquid separators or storage 

tanks using Calculation Methodology 1 , and for all 

wellhead gas-liquid separators or storage tanks using 

Calculation Methodology 2 of §98.233(j). 

* * * * * 
Page 191 of 212 

This document is a prepublication version, signed by EPA Administrator Lisa P. Jackson on 

December 2, 2011. We have taken steps to ensure the accuracy of this version, but it is not the 

official version.

(D) Sales oil API gravity range for wells in 

(c)(8)(ii)(B) and (c)(8)(ii)(C) of this section, in 

degrees. 

* * * * * 

(G) Annual CO2 and CH4 emissions that resulted from 

venting gas to the atmosphere, expressed in metric tons CO2

(H) Annual CO

e 

for each gas, at the sub-basin level for Calculation 

Methodology 3 or 4 of §98.233(j). 

2 and CH4 gas quantities that were 

recovered, expressed in metric tons CO2

(I) Annual CO

e for each gas, at 

the sub-basin level for Calculation Methodology 3 or 4 of 

§98.233(j). 

2, CH4, and N2O emissions that resulted 

from flaring gas, expressed in metric tons CO2

(iii) For wellhead gas-liquid separators and wells 

with throughput less than 10 barrels per day, using 

Calculation Methodology 5 of §98.233(j) Equation W-15 of 

§98.233, report the following: 

e for each 

gas, at the sub-basin level for Calculation Methodology 3 

and 4 of §98.233(j). 

* * * * * 

(F) Annual CO2 and CH4 emissions that resulted from 

venting gas to the atmosphere, expressed in metric tons CO2e 
Page 192 of 212 

This document is a prepublication version, signed by EPA Administrator Lisa P. Jackson on 

December 2, 2011. We have taken steps to ensure the accuracy of this version, but it is not the 

official version.

for each gas, at the sub-basin level for Calculation 

Methodology 5 of §98.233(j). 

(G) Annual CO2 and CH4 gas quantities that were 

recovered, expressed in metric tons CO2

(H) Annual CO

e for each gas, at 

the sub-basin level for Calculation Methodology 5 of 

§98.233(j). 

2, CH4, and N2O emissions that resulted 

from flaring gas, expressed in metric tons CO2

(iv) * * * 

e for each 

gas, at the sub-basin level for Calculation Methodology 5 

of §98.233(j). 

(B) Annual CO2 and CH4 emissions that resulted from 

venting gas to the atmosphere, expressed in metric tons CO2

(9) For transmission tank emissions identified 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: 

e 

for each gas, at the sub-basin level for improperly 

functioning dump valves. 

(i) For each vent stack, report annual CO2 and CH4

emissions that resulted from venting gas directly to the 

atmosphere, expressed in metric tons CO2

(ii) For each transmission storage tank, report 

annual CO

e for each gas. 

2, CH4, and N2O emissions that resulted from 
Page 193 of 212 

This document is a prepublication version, signed by EPA Administrator Lisa P. Jackson on 

December 2, 2011. We have taken steps to ensure the accuracy of this version, but it is not the 

official version.

flaring process gas from the transmission storage tank, 

expressed in metric tons CO2

(iii) A unique name or ID number for the vent stack 

monitored according to 40 CFR 98.233(k). 

e for each gas. 

(10) For well testing venting and flaring (refer to 

Equation W-17A or W-17B of §98.233), report the following: 

* * * * * 

(iv) Report annual CO2 and CH4 emissions at the 

facility level, expressed in metric tons CO2

(v) Report annual CO

e for each gas, 

emissions from well testing venting. 

2, CH4, and N2O emissions at the 

facility level, expressed in metric tons CO2

(11) For associated natural gas venting and flaring 

(refer to Equation W-18 of §98.233), report the following 

for each basin: 

e for each gas, 

emissions from well testing flaring. 

* * * * * 

(iii) Report annual CO2 and CH4 emissions at the 

facility level, expressed in metric tons CO2

(iv) Report annual CO

e for each gas, 

emissions from associated natural gas venting. 

2, CH4, and N2O emissions at the 

facility level, expressed in metric tons CO2

(12) * * * 

e for each gas, 

emissions from associated natural gas flaring. 
Page 194 of 212 

This document is a prepublication version, signed by EPA Administrator Lisa P. Jackson on 

December 2, 2011. We have taken steps to ensure the accuracy of this version, but it is not the 

official version.

(vi) Report uncombusted CH4 emissions, in metric tons 

CO2

(vii) Report uncombusted CO

e (refer to Equation W-19 of §98.233). 

2 emissions, in metric tons 

CO2

(viii) Report combusted CO

e (refer to Equation W-20 of §98.233). 

2 emissions, in metric tons 

CO2

(ix) Report N

e (refer to Equation W-21 of §98.233). 

2O emissions, in metric tons CO2

(x) For the natural gas processing industry segment, 

a unique name or ID number for the flare stack. 

e. 

(xi) In the case that a CEMS is used to measure CO2

emissions for the flare stack, indicate that a CEMS was 

used in the annual report and report the combusted CO2 and 

uncombusted CO2

* * * * * 

 as a combined number. 

(15) For each component type (major equipment type 

for onshore production) that uses emission factors for 

estimating emissions (refer to §98.233(q) and (r)) 

(i) * * * 

(A) Total count of leaks found in each complete 

survey listed by date of survey and each component type 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. 
Page 195 of 212 

This document is a prepublication version, signed by EPA Administrator Lisa P. Jackson on 

December 2, 2011. We have taken steps to ensure the accuracy of this version, but it is not the 

official version.

(B) For onshore natural gas processing, range of 

concentrations of CH4 and CO2

(C) Annual CO

 (refer to Equation W-30 of 

§98.233). 

2 and CH4 emissions, in metric tons CO2e 

for each gas (refer to parameter GHGi

(ii) * * * 

 in Equation W-30 of 

§98.233), by component type. 

(A) For source categories §98.230(a)(4), (a)(5), 

(a)(6), (a)(7), and (a)(8), total count for each component 

type 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 

facility. 

(C) Annual CO2 and CH4 emissions, in metric tons CO2

(16) For local distribution companies, report the 

following: 

e 

for each gas (refer to Equation W-31 of §98.233), by 

component type. 

(i) Total number of above grade T-D transfer stations 

in the facility. 
Page 196 of 212 

This document is a prepublication version, signed by EPA Administrator Lisa P. Jackson on 

December 2, 2011. We have taken steps to ensure the accuracy of this version, but it is not the 

official version.

(ii) Number of years over which all T-D transfer 

stations will be monitored at least once. 

(iii) Number of T-D stations monitored in calendar 

year. 

(iv) Total number of below grade T-D transfer 

stations in the facility. 

(v) Total number of above grade metering-regulating 

stations (this count will include above grade T-D transfer 

stations) in the facility. 

(vi) Total number of below grade metering-regulating 

stations (this count will include below grade T-D transfer 

stations) in the facility. 

(vii) [Reserved] 

(viii) Leak factor for meter/regulator run developed 

in Equation W-32 of §98.233. 

(ix) Number of miles of unprotected steel distribution 

mains. 

(x) Number of miles of protected steel distribution 

mains. 

(xi) Number of miles of plastic distribution mains. 

(xii) Number of miles of cast iron distribution mains. 

(xiii) Number of unprotected steel distribution 

services. 

(xiv) Number of protected steel distribution services. 
Page 197 of 212 

This document is a prepublication version, signed by EPA Administrator Lisa P. Jackson on 

December 2, 2011. We have taken steps to ensure the accuracy of this version, but it is not the 

official version.

(xv) Number of plastic distribution services. 

(xvi) Number of copper distribution services. 

(xvii) Annual CO2 and CH4 emissions, in metric tons 

CO2

(xviii) Annual CO

e for each gas, from all above grade T-D transfer 

stations combined. 

2 and CH4 emissions, in metric tons 

CO2

(xix) Annual CO

e for each gas, from all below grade T-D transfer 

stations combined. 

2 and CH4 emissions, in metric tons 

CO2

(xx) Annual CO

e for each gas, from all above grade metering-regulating 

stations (including T-D transfer stations) combined. 

2 and CH4 emissions, in metric tons CO2

(xxi) Annual CO

e 

for each gas, from all below grade metering-regulating 

stations (including T-D transfer stations) combined. 

2 and CH4 emissions, in metric tons 

CO2

(xxii) Annual CO

e for each gas, from all distribution mains combined. 

2 and CH4 emissions, in metric tons 

CO2

(17) * * * 

e for each gas, from all distribution services combined. 

(v) For each EOR pump, report annual CO2 and CH4

emissions, expressed in metric tons CO2

(18) For EOR hydrocarbon liquids dissolved CO

e for each gas. 

2 for 

each sub-basin category (refer to Equation W-38 of 

§98.233), report the following: 
Page 198 of 212 

This document is a prepublication version, signed by EPA Administrator Lisa P. Jackson on 

December 2, 2011. We have taken steps to ensure the accuracy of this version, but it is not the 

official version.

* * * * * 

(iii) Report annual CO2 emissions at the sub-basin 

level, expressed in metric tons CO2

(19) * * * 

e. 

(iii) Report annual CO2, CH4, and N2O emissions from 

external fuel combustion units with a rated heat capacity 

larger than 5 mmBtu/hr, expressed in metric tons CO2

* * * * * 

e for 

each gas, by type of unit. 

(v) Cumulative number of internal fuel combustion 

units, not compressor-drivers, with a rated heat capacity 

equal to or less than 1 mmBtu/hr or 130 horsepower, by type 

of unit. 

(vi) Report annual CO2, CH4, and N2O emissions from 

internal combustion units greater than 1mmBtu/hr, expressed 

in metric tons CO2

(vii) Cumulative volume of fuel combusted in internal 

combustion units with a rated heat capacity larger than 1 

mmBtu/hr or 130 horsepower, by fuel type. 

e for each gas, by type of unit. 

* * * * * 

(e) For onshore petroleum and natural gas production, 

report the best available estimate of API gravity, best 

available estimate of gas to oil ratio, and best available 
Page 199 of 212 

This document is a prepublication version, signed by EPA Administrator Lisa P. Jackson on 

December 2, 2011. We have taken steps to ensure the accuracy of this version, but it is not the 

official version.

estimate of average low pressure separator pressure for 

each oil sub-basin category. 

9. Section 98.237 is amended by adding paragraph (e) 

to read as follows: 

* * * * * 

§98.237 Records that must be retained.

 (e) The records required under §98.3(g)(2)(i) shall 

include an explanation of how company records, engineering 

estimation, or best available information are used to 

calculate each applicable parameter under this subpart. 

10. Section 98.238 is amended by: 

a. Revising the definitions of “Facility with respect 

to natural gas distribution for purposes of this subpart 

and subpart A”, “Facility with respect to onshore petroleum 

and natural gas production for purposes of this subpart and 

for subpart A”, “Farm Taps”, and “Transmission pipeline”. 

b. Adding definitions of “Associated with a single 

well-pad”, “Distribution pipeline”, “Flare”, “Forced 

extraction”, “Horizontal well”, “Meter/regulator run”, 

“Metering-regulating station”, ”Natural gas”, “Pressure 

groups”, “Sub-basin category”, “Transmission-distribution 

transfer station”, “Tubing diameter groups”, “Tubing 

systems”, “Vertical well”, and “Well testing venting and 

flaring”. 
Page 200 of 212 

This document is a prepublication version, signed by EPA Administrator Lisa P. Jackson on 

December 2, 2011. We have taken steps to ensure the accuracy of this version, but it is not the 

official version.

c. Removing the definitions of “Gas well” and “Oil 

well”. 

The revisions read as follows: 

* * * * * 

§98.238 Definitions.

Associated with a single well-pad

* * * * * 

 means associated 

with the hydrocarbon stream as produced from one or more 

wells located on that single well-pad. The association 

ends where the stream from a single well-pad is combined 

with streams from one or more additional single well-pads, 

where the point of combination is located off that single 

well-pad. Onshore production storage tanks on or associated 

with a single well-pad are considered a part of the 

onshore production facility. 

Distribution pipeline

* * * * * 

 means a pipeline that is 

designated as such by the Pipeline and Hazardous Material 

Safety Administration (PHMSA) 49 C.F.R. §192.3. 

Facility with respect to natural gas distribution for 

purposes of reporting under this subpart and for the 

corresponding subpart A requirements means the collection 

of all distribution pipelines and metering-regulating 

stations that are operated by a Local Distribution Company 
Page 201 of 212 

This document is a prepublication version, signed by EPA Administrator Lisa P. Jackson on 

December 2, 2011. We have taken steps to ensure the accuracy of this version, but it is not the 

official version.

(LDC) within a single state that is regulated as a separate 

operating company by a public utility commission or that 

are operated as an independent municipally-owned 

distribution system. 

Facility with respect to onshore petroleum and natural 

gas production for purposes of reporting under this subpart 

and for the corresponding subpart A requirements means all 

petroleum or natural gas equipment on a single well-pad or 

associated with a single well-pad and CO2 EOR operations 

that are under common ownership or common control including 

leased, rented, or contracted activities by an onshore 

petroleum and natural gas production owner or operator and 

that are located in a single hydrocarbon basin as defined 

in §98.238. Where a person or entity owns or operates more 

than one well in a basin, then all onshore petroleum and 

natural gas production equipment associated with all wells 

that the person or entity owns or operates in the basin 

would be considered one facility. 

Farm Taps 

* * * * * 

are pressure regulation stations that 

deliver gas directly from transmission pipelines to 

generally rural customers. In some cases a nearby LDC may 

handle the billing of the gas to the customer(s). 
Page 202 of 212 

This document is a prepublication version, signed by EPA Administrator Lisa P. Jackson on 

December 2, 2011. We have taken steps to ensure the accuracy of this version, but it is not the 

official version.

Flare

* * * * * 

, for the purposes of subpart W, means a 

combustion device, whether at ground level or elevated, 

that uses an open or closed flame to combust waste gases 

without energy recovery. 

Forced extraction of natural gas liquids means removal 

of ethane or higher carbon number hydrocarbons existing in 

the vapor phase in natural gas, by removing ethane or 

heavier hydrocarbons derived from natural gas into natural 

gas liquids by means of a forced extraction process. 

Forced extraction processes include but are not limited to 

refrigeration, absorption (lean oil), cryogenic expander, 

and combinations of these processes. Forced extraction 

does not include in and of itself; natural gas dehydration, 

or the collection or gravity separation of water or 

hydrocarbon liquids from natural gas at ambient temperature 

or heated above ambient temperatures, or the condensation 

of water or hydrocarbon liquids through passive reduction 

in pressure or temperature, or portable dewpoint 

suppression skids. 

Horizontal well means a well bore that has a planned 

deviation from primarily vertical to a primarily horizontal 

inclination or declination tracking in parallel with and 

through the target formation. 
Page 203 of 212 

This document is a prepublication version, signed by EPA Administrator Lisa P. Jackson on 

December 2, 2011. We have taken steps to ensure the accuracy of this version, but it is not the 

official version.

* * * * * 

Meter/regulator run means a series of components used 

in regulating pressure or metering natural gas flow or 

both. 

Metering-regulating station means a station that 

meters the flowrate, regulates the pressure, or both, of 

natural gas in a natural gas distribution facility. This 

does not include customer meters, customer regulators, or 

farm taps. 

Natural gas

* * * * * 

 means a naturally occurring mixture or 

process derivative of hydrocarbon and non-hydrocarbon gases 

found in geologic formations beneath the earth’s surface, 

of which its constituents include, but are not limited to, 

methane, heavier hydrocarbons and carbon dioxide. Natural 

gas may be field quality, pipeline quality, or process gas. 

Pressure groups as applicable to each sub-basin are 

defined as follows: less than or equal to 25 psig; greater 

than 25 psig and less than or equal to 60 psig; greater 

than 60 psig and less than or equal to 110 psig; greater 

than 110 psig and less than or equal to 200 psig; and 

greater than 200 psig. The pressure in the context of 

pressure groups is either the well shut-in pressure; well 

casing pressure; or you may use the casing-to-tubing 
Page 204 of 212 

This document is a prepublication version, signed by EPA Administrator Lisa P. Jackson on 

December 2, 2011. We have taken steps to ensure the accuracy of this version, but it is not the 

official version.

pressure of one well from the same sub-basin multiplied by 

the tubing pressure for each well in the sub-basin. 

* * * * * 

Sub-basin category, for onshore natural gas 

production, means a subdivision of a basin into the unique 

combination of wells with the surface coordinates within 

the boundaries of an individual county and subsurface 

completion in one or more of each of the following five 

formation types: oil, high permeability gas, shale gas, 

coal seam, or other tight reservoir rock. The distinction 

between high permeability gas and tight gas reservoirs 

shall be designated as follows: high permeability gas 

reservoirs with >0.1 millidarcy permeability, and tight gas 

reservoirs with ≤0.1 millidarcy permeability. Permeability 

for a reservoir type shall be determined by engineering 

estimate. Wells that produce from high permeability gas, 

shale gas, coal seam, or other tight reservoir rock are 

considered gas wells; gas wells producing from more than 

one of these formation types shall be classified into only 

one type based on the formation with the most contribution 

to production as determined by engineering knowledge. All 

wells that produce hydrocarbon liquids and do not meet the 

definition of a gas well in this sub-basin category 

definition are considered to be in the oil formation. All 
Page 205 of 212 

This document is a prepublication version, signed by EPA Administrator Lisa P. Jackson on 

December 2, 2011. We have taken steps to ensure the accuracy of this version, but it is not the 

official version.

emission sources that handle condensate from gas wells in 

high permeability gas, shale gas, or tight reservoir rock 

formations are considered to be in the formation that the 

gas well belongs to and not in the oil formation. 

Transmission-distribution (T-D) transfer station means 

a metering-regulating station where a local distribution 

company takes part or all of the natural gas from a 

transmission pipeline and puts it into a distribution 

pipeline. 

Transmission pipeline means a Federal Energy 

Regulatory Commission rate-regulated Interstate pipeline, a 

state rate-regulated Intrastate pipeline, or a pipeline 

that falls under the “Hinshaw Exemption” as referenced in 

section 1(c) of the Natural Gas Act, 15 U.S.C. 717-717 

(w)(1994) . 

Tubing diameter groups are defined as follows: outer 

diameter less than or equal to 1 inch; outer diameter 

greater than 1 inch and less than 2.375 inch; and outer 

diameter greater than or equal to 2.375 inch. 

Tubing systems

* * * * * 

 means piping equal to or less than one 

half inch diameter as per nominal pipe size. 

Vertical well means a well bore that is primarily 

vertical but has some unintentional deviation or one or 
Page 206 of 212 

This document is a prepublication version, signed by EPA Administrator Lisa P. Jackson on 

December 2, 2011. We have taken steps to ensure the accuracy of this version, but it is not the 

official version.

more intentional deviations to enter one or more subsurface 

targets that are off-set horizontally from the surface 

location, intercepting the targets either vertically or at 

an angle. 

Well testing venting and flaring

11. Table W-1A to Subpart W of Part 98 is revised to 

read as follows: 

 means venting and/or 

flaring of natural gas at the time the production rate of a 

well is determined for regulatory, commercial, or technical 

purposes. If well testing is conducted immediately after 

well completion or workover, then it is considered part of 

well completion or workover. 

TABLE W-1A OF SUBPART W–DEFAULT WHOLE GAS EMISSION FACTORS 

FOR ONSHORE PETROLEUM AND NATURAL GAS PRODUCTION 

Onshore petroleum and natural gas production

Emission Factor 

(scf/hour/component)

Eastern U.S.

Population Emission Factors - All Components, Gas Service1

Valve 0.640

Connector 0.083

Open-ended Line 1.46

Pressure Relief Valve 0.97

Low Continuous Bleed Pneumatic Device Vents2 1.39

High Continuous Bleed Pneumatic Device Vents2 37.3

Intermittent Bleed Pneumatic Device Vents2 13.5

Pneumatic Pumps3 10.3

Population Emission Factors - All Components, Light Crude Service4

Valve 0.04

Flange 0.002

Connector 0.005

Open-ended Line 0.04
Page 207 of 212 

This document is a prepublication version, signed by EPA Administrator Lisa P. Jackson on 

December 2, 2011. We have taken steps to ensure the accuracy of this version, but it is not the 

official version.

Pump 0.01

Other5 0.23

Population Emission Factors - All Components, Heavy Crude Service6

Valve 0.0004

Flange 0.0007

Connector (other) 0.0002

Open-ended Line 0.004

Other5 0.002

Western U.S.

Population Emission Factors - All Components, Gas Service1

Valve 2.903

Connector 0.396

Open-ended Line 0.748

Pressure Relief Valve 4.631

Low Continuous Bleed Pneumatic Device Vents2 1.77

High Continuous Bleed Pneumatic Device Vents2 47.4

Intermittent Bleed Pneumatic Device Vents2 17.1

Pneumatic Pumps3 10.3

Population Emission Factors - All Components, Light Crude Service4

Valve 0.04

Flange 0.002

Connector 0.005

Open-ended Line 0.04

Pump 0.01

Other5 0.23

Population Emission Factors - All Components, Heavy Crude Service6

Valve 0.0004

Flange 0.0007

Connector (other) 0.0002

Open-ended Line 0.004

Other5 0.002 1 For multi-phase flow that includes gas, use the gas service 

emissions factors

2 Emission Factor is in units of "scf/hour/device"

3 Emission Factor is in units of "scf/hour/pump" 4 Hydrocarbon liquids greater than or equal to 20 ̊API are considered 

"light crude"

5 ”Others” category includes instruments, loading arms, pressure 

relief valves, stuffing boxes, compressor seals, dump lever arms, and 

vents.
Page 208 of 212 

This document is a prepublication version, signed by EPA Administrator Lisa P. Jackson on 

December 2, 2011. We have taken steps to ensure the accuracy of this version, but it is not the 

official version.

12. Table W-2 of Subpart W of Part 98 is revised to 

read as follows: 

TABLE W-2 OF SUBPART W–DEFAULT TOTAL HYDROCARBON EMISSION 

FACTORS FOR ONSHORE NATURAL GAS PROCESSING 

Onshore natural gas processing plants

Emission Factor 

(scf/hour/component)

Leaker Emission Factors - Compressor Components, Gas Service

Valve 14.84

Connector 5.59

Open-Ended Line 17.27

Pressure Relief Valve 39.66

Meter 19.33

Leaker Emission Factors – Non-Compressor Components, Gas Service

Valve 6.42

Connector 5.71

Open-Ended Line 11.27

Pressure Relief Valve 2.01

Meter 2.93

1 Valves include control valves, block valves and regulator valves.

 13. Table W-3 to Subpart W of Part 98 is revised to 

read as follows: 

TABLE W-3 OF SUBPART W–DEFAULT TOTAL HYDROCARBON EMISSION 

FACTORS FOR ONSHORE NATURAL GAS TRANSMISSION COMPRESSION 

Onshore natural gas transmission compression Emission Factor 

(scf/hour/component)

Leaker Emission Factors - Compressor Components, Gas Service

Valve 14.84

Connector 5.59

Open-Ended Line 17.27

Pressure Relief Valve 39.66

Meter 19.33

Leaker Emission Factors – Non-Compressor Components, Gas Service

Valve 6.42

6 Hydrocarbon liquids less than 20 ̊API are considered "heavy crude"
Page 209 of 212 

This document is a prepublication version, signed by EPA Administrator Lisa P. Jackson on 

December 2, 2011. We have taken steps to ensure the accuracy of this version, but it is not the 

official version.

Connector 5.71

Open-Ended Line 11.27

Pressure Relief Valve 2.01

Meter 2.93

Population Emission Factors – Gas Service

Low Continuous Bleed Pneumatic Device 

Vents2 

1.37

High Continuous Bleed Pneumatic Device 

Vents2

18.20

Intermittent Bleed Pneumatic Device Vents2

2.35 1 Valves include control valves, block valves and regulator valves.

2 Emission Factor is in units of "scf/hour/device"

14. Table W-4 to Subpart W of Part 98 is revised to read as 

follows: 

TABLE W-4 OF SUBPART W–DEFAULT TOTAL HYDROCARBON EMISSION 

FACTORS FOR UNDERGROUND NATURAL GAS STORAGE 

Underground natural gas storage

Emission Factor 

(scf/hour/component

)

Leaker Emission Factors - Storage Station, Gas Service

Valve 14.84

Connector 5.59

Open-Ended Line 17.27

Pressure Relief Valve 39.66

Meter 19.33

Population Emission Factors - Storage Wellheads, Gas Service

Connector 0.01

Valve 0.1

Pressure Relief Valve 0.17

Open Ended Line 0.03

* * * * * * *

Population Emission Factors - Other Components, Gas Service

Low Continuous Bleed Pneumatic Device Vents2

1.37

High Continuous Bleed Pneumatic Device 18.20
Page 210 of 212 

This document is a prepublication version, signed by EPA Administrator Lisa P. Jackson on 

December 2, 2011. We have taken steps to ensure the accuracy of this version, but it is not the 

official version.

Underground natural gas storage

Emission Factor 

(scf/hour/component

)

Leaker Emission Factors - Storage Station, Gas Service

Vents2

Intermittent Bleed Pneumatic Device Vents2

2.35 1 Valves include control valves, block valves and regulator valves.

2 Emission Factor is in units of "scf/hour/device"

15. Table W-5 to Subpart W of Part 98 is revised to read as 

follows: 

TABLE W-5 OF SUBPART W–DEFAULT METHANE EMISSION FACTORS FOR 

LIQUEFIED NATURAL GAS (LNG) STORAGE

LNG Storage Emission Factor 

(scf/hour/component)

Leaker Emission Factors – LNG Storage Components, LNG Service

Valve 1.19

Pump Seal 4.00

Connector 0.34

Other 1.77

Population Emission Factors – LNG Storage Compressor, Gas Service

Vapor Recovery Compressor 4.17 1

2 Emission Factor is in units of "scf/hour/device"

"other" equipment type should be applied for any equipment type 

other than connectors, pumps, or valves.

16. Table W-6 to Subpart W of Part 98 is revised to read 

as follows: 

TABLE W-6 OF SUBPART W–DEFAULT METHANE EMISSION FACTORS 

FOR LNG IMPORT AND EXPORT EQUIPMENT 

LNG import and export equipment

Emission Factor 

(scf/hour/compon

ent)

Leaker Emission Factors - LNG Terminals Components, LNG Service

Valve 1.19

Pump Seal 4.00

Connector 0.34
Page 211 of 212 

This document is a prepublication version, signed by EPA Administrator Lisa P. Jackson on 

December 2, 2011. We have taken steps to ensure the accuracy of this version, but it is not the 

official version.

Underground natural gas storage

Emission Factor 

(scf/hour/component

)

Leaker Emission Factors - Storage Station, Gas Service

Other 1.77 1

Population Emission Factors - LNG Terminals Compressor, Gas Service

Vapor Recovery Compressor 4.17 2 

1 "other" equipment type should be applied for any equipment type 

other than connectors, pumps, or valves.

2 Emission Factors is in units of "scf/hour/compressor”.

17. Table W-7 to subpart W of Part 98 is revised to 

read as follows: 

a. Revising the entries for “Leaker Emission Factors—

Above Grade M&R at City Gate Stations Components, Gas 

Service,” “Population Emission Factors - Below Grade M&R 

Components, Gas Service,” “Population Emission Factors - 

Distribution Mains, Gas Service,” and “Population Emission 

Factors - Distribution Services, Gas Service.” 

b. Removing Footnote 1. 

c. Redesignating Footnotes 2, 3, 4, and 5 as 

Footnotes 1, 2, 3, and 4. 

The revisions read as follows: 

TABLE W-7 OF SUBPART W–DEFAULT METHANE EMISSION FACTORS FOR 

NATURAL GAS DISTRIBUTION 

Natural gas distribution

Emission Factor 

(scf/hour/component

)

Leaker Emission Factors – Transmission-distribution Transfer Station1

Components, Gas Service

Connector 1.69

Block Valve 0.557

Control Valve 9.34
Page 212 of 212 

This document is a prepublication version, signed by EPA Administrator Lisa P. Jackson on 

December 2, 2011. We have taken steps to ensure the accuracy of this version, but it is not the 

official version.

Natural gas distribution

Emission Factor 

(scf/hour/component

)

Pressure Relief Valve 0.27

Orifice Meter 0.212

Regulator 0.772

Open-ended Line 26.131

Population Emission Factors -– Below Grade Metering-Regulating station1

Components, Gas Service2

Below Grade M&R Station, Inlet Pressure > 300 

psig 1.30

Below Grade M&R Station, Inlet Pressure 100 to 

300 psig 0.20

Below Grade M&R Station, Inlet Pressure < 100 

psig 0.10

Population Emission Factors - Distribution Mains, Gas Service3

Unprotected Steel 12.58

Protected Steel 0.35

Plastic 1.13

Cast Iron 27.25

Population Emission Factors - Distribution Services, Gas Service4

Unprotected Steel 0.19

Protected Steel 0.02

Plastic 0.001

Copper 0.03 1 Excluding customer meters. 2 Emission Factor is in units of "scf/hour/station." 3 Emission Factor is in units of "scf/hour/mile." 4 Emission Factor is in units of “scf/hour/number of services.”