80554 Federal Register / Vol. 76, No. 247 / Friday, December 23, 2011 / Rules and Regulations 

ENVIRONMENTAL PROTECTION 

AGENCY 

40 CFR Part 98 

[EPA–HQ–OAR–2011–0512; FRL–9501–9] 

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, 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 Av., 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. NW., 

Washington, DC 20460; telephone 

number: (202) 343–9263; fax number: 

(202) 343–2342; email address: 

GHGReportingRule@epa.gov. For 

technical information and 

implementation materials, please go to 

the Web site 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 Web site at http:// 

www.epa.gov/climatechange/emissions/ 

ghgrulemaking.html. 

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 

486210 Pipeline transportation of natural gas. 

Petroleum and Natural Gas Systems .......................................................................... 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 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 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 


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Court) by February 21, 2012. 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 

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 

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 

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 

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 Low-Income 

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—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, 


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80556 Federal Register / Vol. 76, No. 247 / Friday, December 23, 2011 / Rules and Regulations 

1 76 FR 56010 (September 9, 2011). 

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 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 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 information 

generally on the various actions related 

to treatment of data that may be 

considered CBI, please see the GHG 

Reporting Program Web site 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 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 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 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 


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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 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 

sub-basins applicable to their facility as 

a best available monitoring method 

(BAMM). The use of a field-level 

measurement as a BAMM for a subbasin 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 

sub-basin 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 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 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 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 

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 


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Category of the Greenhouse Gas 

Reporting Rule: EPA’s Response to 

Public Comments’’ and 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, W–4, W–5, W–6, and 

W–7 to adjust for 60ß standard 

temperature and 14.7 psia pressure. 

The final amendments are organized 

following the different sections of the 

subpart W regulatory text 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 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 nonmethane gases from produced natural 

gas, or separation of NGLs into one or 

more component mixtures. 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 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 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 ‘‘meteringregulating 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 


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harmonizing change, we are also adding 

a definition for the term ‘‘meteringregulating 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 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 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 ‘‘noncustody 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 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 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 8,760 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 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 8,760 hours for reporters to use as a 

default option. EPA is removing the 

subscript ‘‘s,’’ since mass emissions do 

not need to be reported at standard 

conditions. 


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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 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 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 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 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 subbasins, 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 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 sub-basin category. Finally 

EPA clarified in 40 CFR 98.233 

(f)(1)(i)(C) that a new producing subbasin 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’’ 


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were removed along with a summation 

sign to clarify that emissions are 

calculated for 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 subbasin 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 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 subbasin. 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 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 subbasin 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 subbasin 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 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 welltype 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 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 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 


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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 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) 

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 

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 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 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 

sub-basin level for improperly 

functioning dump valves. This 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 


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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 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 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 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 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. 

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 degrees Fahrenheit and 14.7 psia; 

therefore, in Equation W–25, 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 degrees Fahrenheit and 14.7 psia; 

therefore, in Equation W–29, 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 stations at custody transfer’’ and 

replace with the term ‘‘transmissiondistribution 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 


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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 transmissiondistribution transfer stations over a 

multiple year period, not exceeding five 

years. For more information on the 

comments received and EPA’s response 

to 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). 

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 ‘‘meter/ 

regulator runs’’ at all ‘‘meteringregulating 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 meteringregulation 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 meteringregulating stations in Equation W–32 is 

based on ‘‘transmission-distribution 

transfer stations’’ 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 

redundancy. Next, EPA has changed 

standard condition to 60 degrees 

Fahrenheit and 14.7 psia; therefore, in 

Equations W–33 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 subbasin category or facility, depending on 

the emission source, instead of the 

actual most recent gas composition 

based on available analysis in a subbasin entity. 

Next, we are amending 40 CFR 

98.233(u)(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 that only 

fractionate liquid streams would 

determine their gas compositions. 


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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. 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 ri. 

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 Masss,CO2, 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 

Masss,CO2 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. 

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 subbasin 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 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. 

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. 

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 part 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 options, such as the use of a bucket 

truck. EPA still requires the use of 


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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. 

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 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. 

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. 

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 

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 ‘‘metering-regulating’’ and 

by clarifying that the collection of all 

distribution pipelines and meteringregulating 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 

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 declination tracking in 


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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 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 pressure of 

one well from the same sub-basin 

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 subbasin 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 

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. 

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 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 

revising the entries for ‘‘Leaker 

Emission Factors—TransmissionDistribution 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, 


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2011 proposal, which proposed five 

pressure ranges, four bounded ranges 

between 0–200 psig and one unbounded 

range above 200 psig, for this source. 

Commenters also requested clarification 

as to whether the proposed pressure 

ranges would apply across the subbasin, 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 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 subbasin. 

Please refer to the Pressure Analysis 

document in EPA–HQ–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. 

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 subbasins in 40 CFR 98.236(e), 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 sub-basin 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, 

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 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 


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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 

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 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, changeouts 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 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 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. 

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 

Transmission-Distribution Transfer 

Station docket memo in docket #EPA– 

HQ–OAR–2011–0512. 

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 transmissiondistribution transfer station leaking 

component counts to calculate 

emissions. In accordance with the 


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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 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. Therefore, EPA decided 

not to exclude remote stations. In this 

action, EPA is finalizing an option for 

transmission-distribution 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 

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 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 floodlighting, 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 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. 

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 


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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 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 

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 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 

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 sub-basin 

category. Commenters requested that an 

oil formation type be added to the subbasin category definition. 

Response: EPA agrees with the 

commenters and has added oil 

formation type to the definition of subbasin 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, since these were in 

conflict with the definition of sub-basin 

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 sub-basin 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 


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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 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 

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 

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-forprofit 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 

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 

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 

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 


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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 

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 

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 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. 

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 

Low-Income 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 

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. 

List of Subjects in 40 CFR Part 98 

Environmental protection, 

Administrative practice and procedure, 

Greenhouse gases, Suppliers, Reporting 

and recordkeeping requirements. 

Dated: December 2, 2011. 

Lisa P. Jackson, 

Administrator. 

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, as defined in § 98.238 of this 

part. 

■ 3. Section 98.6 is amended by revising 

the definitions of ‘‘Continuous bleed’’ 

and ‘‘Intermittent bleed pneumatic 

devices’’ to read as follows: 

§ 98.6 Definitions. 

* * * * * 

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 


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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: 

§ 98.230 Definition of the source category. 

(a) * * * 

(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 non-selfpropelled 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

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. 

(3) 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 dioxide 

removal, fractionation of NGLs, or the 

capture of CO2 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. 

(4) 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 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: 

§ 98.232 GHGs to report. 

(a) You must report CO2, CH4, and 

N2O emissions from each industry 

segment specified in paragraph (b) 

through (i) of this section, CO2, CH4, and 

N2O 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 N2O 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, natural gas dehydrators, 

natural gas compressors, electrical 

generators, steam boilers, and process 

heaters. 

(d) For onshore natural gas 

processing, report CO2, CH4, and N2O 

emissions from the following sources: 

* * * * * 

(e) For onshore natural gas 

transmission compression, report CO2, 

CH4, and N2O 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 N2O emissions from the following 

sources: 

* * * * * 

(h) LNG import and export 

equipment, report CO2, CH4, and N2O 

emissions from the following sources: 

* * * * * 

(i) For natural gas distribution, report 

CO2, CH4, and N2O emissions from the 

following sources: 

(1) Meters, regulators, and associated 

equipment at above grade transmissiondistribution transfer stations, including 

equipment leaks from connectors, block 

valves, control valves, pressure relief 

valves, orifice meters, regulators, and 

open ended lines. 

(2) Equipment leaks from vaults at 

below grade transmission-distribution 

transfer stations. 


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(3) Meters, regulators, and associated 

equipment at above grade meteringregulating 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 N2O 

emissions from stationary fuel 

combustion sources following the 

methods in § 98.233(z) 

(j) [Reserved] 

(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 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’’ 

in Equation W–3. 

■ f. Revising paragraph (d)(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’’, ‘‘Count’’, and 

‘‘1000’’ in Equation W–5. 

■ j. Revising the first sentence of 

paragraph (e)(5) introductory text. 

■ 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; removing Equation 

W–11 and its definitions, adding 

Equations W–11A, W–11B, W–11C and 

their definitions, and revising W–12 and 

its definitions. 

■ 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). 

■ 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’’ and ‘‘Count’’, and adding the 

definition of ‘‘1,000’’. 

■ gg. In paragraph (j)(8), revising 

Equation W–16, revising the definition 

of ‘‘En’’, removing the definition of ‘‘Et’’, 

and adding the definition of ‘‘8,760’’. 

■ 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), 

republishing Equations W–19 and W–20 

and 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’’ in Equation W–24. 

■ oo. In paragraph (o)(7), revising the 

definition of ‘‘EFi’’ in Equation W–25. 

■ pp. In paragraph (p)(7)(i) introductory 

text, revising the definition of ‘‘MTm’’ in 

Equation W–28. 

■ qq. In paragraph (p)(9), revising the 

definition of ‘‘EFi’’ in Equation W–29. 

■ rr. Revising paragraph (q) introductory 

text. 

■ ss. Revising paragraph (q)(8). 

■ tt. Revising paragraph (r) introductory 

text and the definitions in Equation W– 

31. 

■ 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’’ in 

Equation W–33. 

■ ww. Revising paragraph (t)(2) and the 

parameters ‘‘Ts’’ and ‘‘Ps’’ in Equation 

W–34. 

■ xx. Adding paragraph (t)(3). 

■ 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 ‘‘ri’’ in Equation W–36. 

■ aaa. In paragraph (w)(3), revising 

Equation W–37 and the definitions of 

parameters ‘‘Massc,i’’ and ‘‘GHGi’’. 

■ bbb. In paragraph (x)(2), revising 

Equation W–38 and the definitions of 

parameter ‘‘Masss,CO2’’. 

■ ccc. Revising paragraph (z) 

introductory text, 

(z)(1),(z)(2)introductory text, 

(z)(2)(i),(z(2)(ii), (z)(2)(iii), 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. 

■ eee. In newly redesignated paragraph 

(z)(2)(vi), revising Equation W–40, 

removing the definition for N2O, 

revising the definition of ‘‘HHV’’, and 

adding the definitions ‘‘GWP’’ and 

‘‘Mass,N2O’’. 

■ fff. Adding paragraph (z)(4). 

The revisions read as follows: 

§ 98.233 Calculating GHG emissions. 

(a) * * * 

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. 


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Countt = 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. 

EFt = Population emission factors for natural 

gas pneumatic device venting listed in 

Tables W–1A, W–3, and W–4 of this 

subpart for onshore petroleum and 

natural gas production, onshore natural 

gas transmission compression, and 

underground natural gas storage 

facilities, respectively. 

GHGi = For onshore petroleum and natural 

gas production facilities, concentration 

of 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. 

Convi = Conversion from standard cubic feet 

to metric tons CO2e; 0.000403 for CH4, 

and 0.00005262 for CO2. 

Tt = 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) * * * 

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, 

in produced natural gas as defined in 

paragraph (u)(2)(i) of this section. 

Convi = 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 sieve or 

other absorbents and adsorbents), 

calculate emissions for CO2 only (not 

CH4) 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. 

(1) 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 N2O emissions is not required as 

part of the Tier 4 requirements for 

AGRs. 

(2) 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 W–4A. If outlet gas flow 

rate is known, use Equation W–4B. 

Where: 

Ea, CO2 = Annual volumetric CO2 emissions 

at actual conditions, in cubic feet per 

year. 

Vin = 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. 

Vout = 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. 

VolI = Volume fraction of CO2 content in 

natural gas into the AGR unit as 

determined in paragraph (d)(7) of this 

section. 

Volo = 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 

N2O emissions using any of the 


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calculation methodologies described in 

paragraph (e) of this section. 

(1) Calculation Methodology 1. 

Calculate annual mass emissions from 

dehydrator vents with annual average 

daily throughput greater than or equal to 

0.4 million standard cubic feet per day 

using a software program, such as 

AspenTech HYSYS® or GRI–GLYCalc, 

that uses the Peng-Robinson 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 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 at 60 °F and 14.7 

psia. 

Count = Total number of glycol dehydrators 

with throughput less than 0.4 million 

standard cubic feet per day. 

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 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. 

Where: 

Ea,n = 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. 

h = Total number of wells of the same tubing 

diameter group and pressure group 

combination in a sub-basin. 

p = Wells 1 through h of the same tubing 

diameter group and pressure group 

combination in a sub-basin. 

Tp = 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. 

FRp = 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 subbasin category, an average flow rate is 

calculated beginning in the first year of 

production. 

* * * * * 

(2) Calculation Methodology 2. 

Calculate the total emissions for well 

venting for liquids unloading using 

Equation W–8 of this section. 

Where: 

Es,n = Annual natural gas emissions at 

standard conditions, in cubic feet/year. 

W = Total number of wells with well venting 

for liquids unloading for each sub-basin. 

0.37×10¥3 = {3.14 (pi)/4}/{14.7*144} (psia 

converted to pounds per square feet). 

CDp = Casing internal diameter for each well, 

p, in inches. 

WDp = 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. 

SPp = 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). 

Vp = Number of vents per year per well, p. 

SFRp = 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. 

HRp,q = Hours that each well, p, was left open 

to the atmosphere during unloading, q. 


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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 is equal to 1. 

(3) * * * 

Where: 

Es,n = Annual natural gas emissions at 

standard conditions, in cubic feet/year. 

W = Total number of wells with well venting 

for liquids unloading for each sub-basin. 

0.37×10¥3 = {3.14 (pi)/4}/{14.7*144} (psia 

converted to pounds per square feet). 

TDp = Tubing internal diameter for each well, 

p, in inches. 

WDp = Tubing depth to plunger bumper for 

each well, p, in feet. 

SPp = Flow-line pressure for each well, p, in 

pounds per square inch absolute (psia), 

using engineering estimate based on best 

available data. 

Vp = Number of vents per year for each well, 

p. 

SFRp = 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. 

HRp,q = Hours that each well, p, was left open 

to the atmosphere during each 

unloading, q. 

0.5 = Hours for average well to blowdown 

tubing volume at flow-line pressure. 

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. 

(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 sub-basin 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. 

Where: 

Es,n = 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. 

W = Total number of wells completed or 

worked over using hydraulic fracturing 

in a sub-basin and well type (horizontal 

vs. vertical) combination. 

Tp = 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. 

FRM = Ratio of backflow during well 

completions and workovers from 

hydraulic fracturing to 30-day 

production rate from Equation W–12. 

PRp = 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. 

EnFp = 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 is 0. 

SGp = 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 is 0. 

FVp = 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 

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 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 W–10A, for each 

calculated horizontal well completion 


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and each calculated vertical well 

completion in each gas producing subbasin 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: 

Where: 

FR = Average flow rate in cubic feet per hour, 

under subsonic flow conditions. 

A = Cross sectional area of orifice (m2). 

P1 = Upstream pressure (psia). 

Tu = Upstream temperature (degrees Kelvin). 

P2 = Downstream pressure (psia). 

3430 = Constant with units of m 2/(sec 2 * K). 

1.27*10 5 = Conversion from m 3/second to 

ft 3/hour. 

Where: 

FR = Average flow rate in cubic feet per hour, 

under sonic flow conditions. 

A = Cross sectional area of orifice (m 2). 

Tu = Upstream temperature (degrees Kelvin). 

187.08 = Constant with units of m 2/(sec 2 * 

K). 

1.27*10 5 = Conversion from m 3/second to 

ft 3/hour. 

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. 

Where: 

FRM = Ratio of backflow rate during well 

completions and workovers from 

hydraulic fracturing to 30-day 

production rate. 

FRp = 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. 

PRp = First 30-day production rate in 

standard cubic feet per hour for each 

well p that was measured in the subbasin and well type combination. 

W = Number of wells completed or worked 

over using hydraulic fracturing in a subbasin and well type formation. 

(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 subbasin 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 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: 


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Where: 

Es,n = Annual natural gas emissions in 

standard cubic feet from a gas well 

venting during well completions and 

workovers without hydraulic fracturing. 

Nwo = 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. 

EFwo = Emission Factor for non-hydraulic 

fracture well workover venting in 

standard cubic feet per workover. EFwo = 

3114 standard cubic feet natural gas per 

well workover without hydraulic 

fracturing. 

p = Well completions 1 through f in a subbasin. 

f = Total number of well completions without 

hydraulic fracturing in a sub-basin 

category. 

Vp = 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. 

Tp = Time each well completion without 

hydraulic fracturing, p, was venting in 

hours during the year. 

(1) Volumetric emissions for both CH4

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 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. 

Where: 

ES,N = 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 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 

(60°F). 

Ta = Temperature at actual conditions in the 

unique physical volume (°F). 

Ps = Absolute pressure at standard conditions 

(14.7 psia). 

Pa = Absolute pressure at actual conditions 

in the unique physical volume (psia). 

Where: 

Es,n = Annual natural gas venting emissions 

at standard conditions from blowdowns 

in cubic feet. 

p = Individual occurrence of blowdown for 

the same unique physical volume. 

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 

(60°F). 

Ta = Temperature at actual conditions in the 

unique physical volume (°F) for each 

blowdown ‘‘p’’. 

Ps = Absolute pressure at standard conditions 

(14.7 psia). 

Pa,b,p = Absolute pressure at actual conditions 

in the unique physical volume (psia) at 

the beginning of the blowdown ‘‘p’’. 

Pa,e,p = 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 nonGHG gases. 

(4) Calculate both CH4 and CO2

volumetric and mass emissions using 

calculations in paragraph (u) and (v) of 

this section. 

(j) * * * 

(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 


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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 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 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. 

(3) 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 emissions 

by either of the methods in paragraph 

(j)(3) of this section: 

(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 and gas from the subbasin 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) * * * 

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 at 60 °F and 14.7 psia. 

Count = Total number of separators or wells 

with throughput less than 10 barrels per 

day. 

1,000 = Conversion to cubic feet 

* * * * * 

(8) * * * 

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 annual emissions 

from compressor scrubber dump valve 

leakage as follows: 

(1) Monitor the tank vapor vent stack 

annually for emissions using an optical 

gas imaging instrument according to 

methods set forth in § 98.234(a)(1) or by 

directly measuring the tank vent using 

a flow meter 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). 

(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. 

(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. 


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Where: 

Ea,n = Annual volumetric natural gas 

emissions from well(s) testing in cubic 

feet under actual conditions. 

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. 

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) * * * 

(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) * * * 

Where: 

Ea,n = Annual volumetric natural gas 

emissions, at the facility level, from 

associated gas venting under actual 

conditions, in cubic feet. 

GORp,q = Gas to oil ratio, for well p in subbasin q, in cubic feet of gas per barrel of 

oil; oil here refers to hydrocarbon liquids 

produced of all API gravities. 

Vp,q = 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. 

x = Total number of wells in sub-basin that 

vent or flare associated gas. 

y = Total number of sub-basins in a basin that 

contain wells that vent or flare 

associated gas. 

* * * * * 

(n) * * * 

(2) * * * 

(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 

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. 

(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) * * * 

* * * * * 

(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, 

in these equations. 

(o) * * * 

(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 × 107

standard cubic feet per year per 

compressor for CH4 and 5.30 × 105

thousand standard cubic feet per year 

per compressor for CO2 at 60 °F and 14.7 

psia. 

* * * * * 


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(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 × 

103 standard cubic feet per year per 

compressor for CH4 and 5.27 × 102

standard cubic feet per year per 

compressor for CO2 at 60 °F and 14.7 

psia. 

* * * * * 

(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). 

Where: 

Es,i = 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. 

x = Total number of each component type. 

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. 

Tp = 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. 

t = Calendar year of reporting. 

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 W–30B 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 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 transmissiondistribution 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 transmissiondistribution transfer stations and all 

metering-regulating stations that do 

meet the definition of transmissiondistribution transfer stations are not 

required to perform component leak 

detection under this section. 

(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. 

* * * * * 

Es,i = Annual volumetric GHG emissions at 

standard conditions from each 

component type in cubic feet. 

Counts = 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 


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meter/regulator runs as described in 

paragraph (r)(6) of this section. 

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 metering-regulating stations 

is determined in Equation W–32 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. 

Ts = 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. 

* * * * * 

(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 

metering-regulating 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 W–31. 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 at above grade transmissiondistribution 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). 

Where: 

EF = Facility emission factor for a meter/ 

regulator run per component type at 

above grade metering-regulating for GHGi

in cubic feet per meter/regulator run per 

hour. 

Es,i = Annual volumetric GHG i emissions, 

CO2 or CH4 at standard condition from 

each component type at all above grade 

TD transfer stations, from Equation W– 

30B. 

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. 

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 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 

(60 °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 

(60 °F). 

* * * * * 

Ps = Absolute pressure at standard conditions 

(14.7 psia). 

* * * * * 

(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, 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. 

(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. 

(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. 

(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 


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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. 

Where: 

Massi = GHGi (either CH4, CO2, or N2O) mass 

emissions in metric tons CO2e. 

Es,i = GHGi (either CH4, CO2, or N2O) 

volumetric emissions at standard 

conditions, in cubic feet. 

ri = 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) * * * 

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) * * * 

Where: 

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 N2O 

combustion-related emissions from 

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 Btu 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 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 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: 


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Where: 

ECO2 = Contribution of annual CO2 emissions 

from portable or stationary fuel 

combustion sources in cubic feet, under 

actual conditions. 

Va = Volume of gas sent to combustion unit 

in cubic feet, during the year. 

YCO2 = Concentration of CO2 constituent in 

gas sent to combustion unit. 

Ea,CH4 = Contribution of annual CH4

emissions from portable or stationary 

fuel combustion sources in cubic feet, 

under actual conditions. 

h = 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. 

Yj = Concentration of gas hydrocarbon 

constituents j (such as methane, ethane, 

propane, butane, and pentanes plus) in 

gas sent to combustion unit. 

Rj = Number of carbon atoms in the gas 

hydrocarbon constituent j; 1 for methane, 

2 for ethane, 3 for propane, 4 for butane, 

and 5 for pentanes plus, in gas sent to 

combustion unit. 

YCH4 = Concentration of methane constituent 

in gas sent to combustion unit. 

* * * * * 

(vi) Calculate N2O mass emissions 

using Equation W–40 of this section. 

Where: 

MassN2O = Annual N2O 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 × 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 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 

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. 

* * * * * 

(5) Acoustic leak detection device. 

Use the acoustic leak detection device to 

detect through-valve leakage. When 

using the acoustic leak detection device 

to quantify the through-valve leakage, 

you must use the instrument 

manufacturer’s calculation methods to 

quantify the through-valve leak. When 

using the acoustic leak detection device, 

if a leak of 3.1 scf per hour or greater 

is calculated, a leak is detected. In 

addition, you must operate the acoustic 

leak detection device to monitor the 

source valves required by this subpart in 

accordance with the instrument 

manufacturer’s operating parameters. 

Acoustic 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 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) * * * 


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Where: 

p = Absolute pressure. 

R = Universal gas constant. 

T = Absolute temperature. 

Vm = Molar volume. 

Where: 

w = Acentric factor of the species. 

Tc = Critical temperature. 

Pc = 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). 

■ h. Revising paragraphs (c)(6) 

introductory text, and (c)(6)(i). 

■ i. Revising paragraph (c)(6)(ii)(B), 

(c)(6)(ii)(D) and adding paragraph 

(c)(6)(ii)(E). 

■ j. Revising paragraph (c)(7). 

■ k. Revising paragraphs (c)(8)(i) 

introductory text and (c)(8)(i)(J); and 

adding paragraphs (c)(8)(i)(K) and 

(c)(8)(i)(L). 

■ l. 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). 

■ m. Revising paragraphs (c)(8)(iii) 

introductory text and (c)(8)(iii)(F); and 

adding paragraphs (c)(8)(iii)(G) and 

(c)(8)(iii)(H). 

■ n. Adding paragraph (c)(8)(iv)(B). 

■ o. Revising paragraphs (c)(9) 

introductory text and (c)(9)(i) ; and 

adding paragraphs (c)(9)(ii) (c)(9)(iii). 

■ p. Revising paragraphs (c)(10) 

introductory text and (c)(10)(iv); and 

adding paragraph (c)(10)(v). 

■ q. Revising paragraph (c)(11) 

introductory text and (c)(11)(iii); and 

adding paragraph (c)(11)(iv). 

■ r. Revising paragraph (c)(12)(vi) and 

adding paragraphs (c)(12)(vii) through 

(c)(12)(xi). 

■ s. Revising paragraphs (c)(15) 

introductory text, (c)(15)(i)(A), 

(c)(15)(i)(B) and (c)(15)(i)(C). 

■ t. Revising paragraphs (c)(15)(ii)(A) 

through (c)(15)(ii)(C). 

■ u. Revising paragraph (c)(16). 

■ v. Revising paragraph (c)(17)(v). 

■ w. Revising paragraphs (c)(18) 

introductory text and paragraph 

(c)(18)(iii). 

■ x. Revising paragraphs (c)(19)(iii), 

(c)(19)(v), (c)(19)(vi), and (c)(19)(vii). 

■ y. Adding paragraph (e). 

The revisions read as follows: 

§ 98.236 Data Reporting Requirements. 

* * * * * 

(a) Report annual emissions in metric 

tons of CO2e 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 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 CO2e 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. 

(1) * * * 

(iv) Report annual CO2 and CH4

emissions at the facility level, expressed 

in metric tons CO2e for each gas, for 

each of the following pieces of 

equipment: high bleed pneumatic 

devices; intermittent bleed pneumatic 

devices; low bleed pneumatic devices. 

(2) * * * 

(ii) Report annual CO2 and CH4

emissions at the facility level, expressed 

in metric tons CO2e for each gas, for all 

natural gas driven pneumatic pumps 

combined. 

(3) * * * 

(ii) For Calculation Methodology 1 

and Calculation Methodology 2 of 

§ 98.233(d), annual average fraction of 

CO2 content in the vent from the acid 

gas removal unit (refer to § 98.233(d)(6)). 


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(iii) For Calculation Methodology 3 of 

§ 98.233(d), annual average volume 

fraction of CO2 content of natural gas 

into and out of the acid gas removal unit 

(refer to § 98.233(d)(7) and (d)(8)). 

(iv) Report the annual quantity of 

CO2, expressed in metric tons CO2e, that 

was recovered from the AGR unit and 

transferred outside the facility, under 

subpart PP of this part. 

(v) Report annual CO2 emissions for 

the AGR unit, expressed in metric tons 

CO2e. 

(vi) For the onshore natural gas 

processing industry segment only, 

report a unique name or ID number for 

the AGR unit. 

(vii) An indication of which 

calculation methodology was used for 

the AGR. 

(4) * * * 

(i) * * * 

(H) Concentration of CH4 and CO2 in 

wet natural gas. 

* * * * * 

(J) For each glycol dehydrator, report 

annual CO2 and CH4 emissions that 

resulted from venting gas directly to the 

atmosphere, expressed in metric tons 

CO2e for each gas. 

(K) For each glycol dehydrator, report 

annual CO2, CH4, and N2O emissions 

that resulted from flaring process gas 

from the dehydrator, expressed in 

metric tons CO2e for each gas. 

(L) For the onshore natural gas 

processing industry segment only, 

report a unique name or ID number for 

glycol dehydrator. 

(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 

CO2e for each gas, combined for all 

glycol dehydrators with annual average 

daily throughput of less than 0.4 

MMscfd. 

(D) Report annual CO2, 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. 

(iii) * * * 

(B) Report annual CO2 and CH4

emissions at the facility level, expressed 

in metric tons CO2e for each gas, for all 

absorbent desiccant dehydrators 

combined. 

(5) For well venting for liquids 

unloading, report the following: 

(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. 

(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 

CO2e for each gas. 

(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: 

(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 

CO2e for each GHG gas. 

(6) For well completions and 

workovers, report the following for each 

sub-basin category: 

(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. 

(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 CO2e for each gas. 

(J) Annual CO2, CH4, and N2O 

emissions that resulted from flares, 

expressed in metric tons CO2e 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 CO2e for each gas. 

(E) Annual CO2, CH4, and N2O 

emissions that resulted from flares, 

expressed in metric tons CO2e for each 

gas. 

(7) For blowdown vent stack emission 

source, (refer to Equation W–14A and 

Equation W–14B of § 98.233), report the 

following: 

(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 CO2e 

for each gas. 

(C) A unique name or ID number for 

the unique physical volume. 

(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 CO2e for each gas. 


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(8) * * * 

(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 subbasin category, unless otherwise 

specified: 

* * * * * 

(J) Annual CO2 and CH4 emissions 

that resulted from venting gas to the 

atmosphere, expressed in metric tons 

CO2e for each gas, for all wellhead gasliquid 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). 

(K) Annual CO2 and CH4 gas 

quantities that were recovered, 

expressed in metric tons CO2e 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). 

(L) Annual CO2, CH4, and N2O 

emissions that resulted from flaring gas, 

expressed in metric tons CO2e 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). 

(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: 

* * * * * 

(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 

CO2e for each gas, at the sub-basin level 

for Calculation Methodology 3 or 4 of 

§ 98.233(j). 

(H) Annual CO2 and CH4 gas 

quantities that were recovered, 

expressed in metric tons CO2e for each 

gas, at the sub-basin level for 

Calculation Methodology 3 or 4 of 

§ 98.233(j). 

(I) Annual CO2, CH4, and N2O 

emissions that resulted from flaring gas, 

expressed in metric tons CO2e for each 

gas, at the sub-basin level for 

Calculation Methodology 3 and 4 of 

§ 98.233(j). 

(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: 

* * * * * 

(F) Annual CO2 and CH4 emissions 

that resulted from venting gas to the 

atmosphere, expressed in metric tons 

CO2e 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 CO2e for each 

gas, at the sub-basin level for 

Calculation Methodology 5 of 

§ 98.233(j). 

(H) Annual CO2, CH4, and N2O 

emissions that resulted from flaring gas, 

expressed in metric tons CO2e for each 

gas, at the sub-basin level for 

Calculation Methodology 5 of 

§ 98.233(j). 

(iv) * * * 

(B) Annual CO2 and CH4 emissions 

that resulted from venting gas to the 

atmosphere, expressed in metric tons 

CO2e for each gas, at the sub-basin level 

for improperly functioning dump 

valves. 

(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: 

(i) For each vent stack, report annual 

CO2 and CH4 emissions that resulted 

from venting gas directly to the 

atmosphere, expressed in metric tons 

CO2e for each gas. 

(ii) For each transmission storage 

tank, report annual CO2, CH4, and N2O 

emissions that resulted from flaring 

process gas from the transmission 

storage tank, expressed in metric tons 

CO2e for each gas. 

(iii) A unique name or ID number for 

the vent stack monitored according to 

40 CFR 98.233(k). 

(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 CO2e for each gas, 

emissions from well testing venting. 

(v) Report annual CO2, CH4, and N2O 

emissions at the facility level, expressed 

in metric tons CO2e for each gas, 

emissions from well testing flaring. 

(11) For associated natural gas venting 

and flaring (refer to Equation W–18 of 

§ 98.233), report the following for each 

basin: 

* * * * * 

(iii) Report annual CO2 and CH4

emissions at the facility level, expressed 

in metric tons CO2e for each gas, 

emissions from associated natural gas 

venting. 

(iv) Report annual CO2, CH4, and N2O 

emissions at the facility level, expressed 

in metric tons CO2e for each gas, 

emissions from associated natural gas 

flaring. 

(12) * * * 

(vi) Report uncombusted CH4

emissions, in metric tons CO2e (refer to 

Equation W–19 of § 98.233). 

(vii) Report uncombusted CO2

emissions, in metric tons CO2e (refer to 

Equation W–20 of § 98.233). 

(viii) Report combusted CO2

emissions, in metric tons CO2e (refer to 

Equation W–21 of § 98.233). 

(ix) Report N2O emissions, in metric 

tons CO2e. 

(x) For the natural gas processing 

industry segment, a unique name or ID 

number for the flare stack. 

(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. 

(B) For onshore natural gas 

processing, range of concentrations of 

CH4 and CO2 (refer to Equation W–30 of 

§ 98.233). 

(C) Annual CO2 and CH4 emissions, in 

metric tons CO2e for each gas (refer to 

parameter GHGi in Equation W–30 of 

§ 98.233), by component type. 

(ii) * * * 

(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 CO2e for each gas (refer to 

Equation W–31 of § 98.233), by 

component type. 

(16) For local distribution companies, 

report the following: 

(i) Total number of above grade T–D 

transfer stations in the facility. 


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(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. 

(xv) Number of plastic distribution 

services. 

(xvi) Number of copper distribution 

services. 

(xvii) Annual CO2 and CH4 emissions, 

in metric tons CO2e for each gas, from 

all above grade T–D transfer stations 

combined. 

(xviii) Annual CO2 and CH4

emissions, in metric tons CO2e for each 

gas, from all below grade T–D transfer 

stations combined. 

(xix) Annual CO2 and CH4 emissions, 

in metric tons CO2e for each gas, from 

all above grade metering-regulating 

stations (including T–D transfer 

stations) combined. 

(xx) Annual CO2 and CH4 emissions, 

in metric tons CO2e for each gas, from 

all below grade metering-regulating 

stations (including T–D transfer 

stations) combined. 

(xxi) Annual CO2 and CH4 emissions, 

in metric tons CO2e for each gas, from 

all distribution mains combined. 

(xxii) Annual CO2 and CH4 emissions, 

in metric tons CO2e for each gas, from 

all distribution services combined. 

(17) * * * 

(v) For each EOR pump, report annual 

CO2 and CH4 emissions, expressed in 

metric tons CO2e for each gas. 

(18) For EOR hydrocarbon liquids 

dissolved CO2 for each sub-basin 

category (refer to Equation W–38 of 

§ 98.233), report the following: 

* * * * * 

(iii) Report annual CO2 emissions at 

the sub-basin level, expressed in metric 

tons CO2e. 

(19) * * * 

(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 CO2e for each 

gas, by type of unit. 

* * * * * 

(v) Cumulative number of internal 

fuel combustion units, not compressordrivers, 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 CO2e for each 

gas, by type of unit. 

(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 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 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’’, ‘‘Subbasin category’’, ‘‘Transmissiondistribution transfer station’’, ‘‘Tubing 

diameter groups’’, ‘‘Tubing systems’’, 

‘‘Vertical well’’, and ‘‘Well testing 

venting and flaring’’. 

■ 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 CFR 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 (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). 

* * * * * 

Flare, for the purposes of subpart W, 

means a combustion device, whether at 

ground level or elevated, that uses an 


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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. 

* * * * * 

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-totubing 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 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 meteringregulating 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 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 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. 

■ 11. Table W–1A to Subpart W of Part 

98 is revised to read as follows: 

TABLE A–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 Service 1

Valve ....................................................................................................................................................................................... 0.640 

Connector ............................................................................................................................................................................... 0.083 

Open-ended Line .................................................................................................................................................................... 1.46 

Pressure Relief Valve ............................................................................................................................................................. 0.97 

Low Continuous Bleed Pneumatic Device Vents 2 ................................................................................................................ 1.39 

High Continuous Bleed Pneumatic Device Vents 2 ................................................................................................................ 37.3 

Intermittent Bleed Pneumatic Device Vents 2 ........................................................................................................................ 13.5 

Pneumatic Pumps 3 ................................................................................................................................................................ 10.3 


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TABLE A–1A OF SUBPART W—DEFAULT WHOLE GAS EMISSION FACTORS FOR ONSHORE PETROLEUM AND NATURAL GAS

PRODUCTION—Continued 

Onshore petroleum and natural gas production 

Emission factor 

(scf/hour/ 

component) 

Population Emission Factors—All Components, Light Crude Service 4

Valve ....................................................................................................................................................................................... 0.04 

Flange ..................................................................................................................................................................................... 0.002 

Connector ............................................................................................................................................................................... 0.005 

Open-ended Line .................................................................................................................................................................... 0.04 

Pump ...................................................................................................................................................................................... 0.01 

Other 5 ..................................................................................................................................................................................... 0.23 

Population Emission Factors—All Components, Heavy Crude Service 6

Valve ....................................................................................................................................................................................... 0.0004 

Flange ..................................................................................................................................................................................... 0.0007 

Connector (other) ................................................................................................................................................................... 0.0002 

Open-ended Line .................................................................................................................................................................... 0.004 

Other 5 ..................................................................................................................................................................................... 0.002 

Western U.S. 

Population Emission Factors—All Components, Gas Service 1

Valve ....................................................................................................................................................................................... 2.903 

Connector ............................................................................................................................................................................... 0.396 

Open-ended Line .................................................................................................................................................................... 0.748 

Pressure Relief Valve ............................................................................................................................................................. 4.631 

Low Continuous Bleed Pneumatic Device Vents 2 ................................................................................................................ 1.77 

High Continuous Bleed Pneumatic Device Vents 2 ................................................................................................................ 47.4 

Intermittent Bleed Pneumatic Device Vents 2 ........................................................................................................................ 17.1 

Pneumatic Pumps 3 ................................................................................................................................................................ 10.3 

Population Emission Factors—All Components, Light Crude Service 4

Valve ....................................................................................................................................................................................... 0.04 

Flange ..................................................................................................................................................................................... 0.002 

Connector ............................................................................................................................................................................... 0.005 

Open-ended Line .................................................................................................................................................................... 0.04 

Pump ...................................................................................................................................................................................... 0.01 

Other 5 ..................................................................................................................................................................................... 0.23 

Population Emission Factors—All Components, Heavy Crude Service 6

Valve ....................................................................................................................................................................................... 0.0004 

Flange ..................................................................................................................................................................................... 0.0007 

Connector (other) ................................................................................................................................................................... 0.0002 

Open-ended Line .................................................................................................................................................................... 0.004 

Other 5 ..................................................................................................................................................................................... 0.002 

1For multi-phase flow that includes gas, use the gas service emissions factors. 

2Emission Factor is in units of ‘‘scf/hour/device.’’ 

3Emission 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. 6 Hydrocarbon liquids less than 20°API are considered ‘‘heavy crude.’’ 

■ 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 1 ..................................................................................................................................................................................... 14.84 

Connector ............................................................................................................................................................................... 5.59 

Open-Ended Line ................................................................................................................................................................... 17.27 


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TABLE W–2 OF SUBPART W—DEFAULT TOTAL HYDROCARBON EMISSION FACTORS FOR ONSHORE NATURAL GAS

PROCESSING—Continued 

Onshore natural gas processing plants 

Emission factor 

(scf/hour/ 

component) 

Pressure Relief Valve ............................................................................................................................................................. 39.66 

Meter ....................................................................................................................................................................................... 19.33 

Leaker Emission Factors—Non-Compressor Components, Gas Service 

Valve 1 ..................................................................................................................................................................................... 6.42 

Connector ............................................................................................................................................................................... 5.71 

Open-Ended Line ................................................................................................................................................................... 11.27 

Pressure Relief Valve ............................................................................................................................................................. 2.01 

Meter ....................................................................................................................................................................................... 2.93 

1Valves 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 1 ..................................................................................................................................................................................... 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 1 ..................................................................................................................................................................................... 6.42 

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 Vents 2 ................................................................................................................ 1.37 

High Continuous Bleed Pneumatic Device Vents 2 ................................................................................................................ 18.20 

Intermittent Bleed Pneumatic Device Vents 2 ........................................................................................................................ 2.35 

1Valves include control valves, block valves and regulator valves. 

2Emission 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 1 ................................................................................................................................................................................... 14 .84 

Connector ............................................................................................................................................................................. 5 .59 

Open-Ended Line ................................................................................................................................................................. 17 .27 

Pressure Relief Valve ........................................................................................................................................................... 39 .66 

Meter ..................................................................................................................................................................................... 19 .33 


sroberts on DSK5SPTVN1PROD with RULES
80594 Federal Register / Vol. 76, No. 247 / Friday, December 23, 2011 / Rules and Regulations 

TABLE W–4 OF SUBPART W—DEFAULT TOTAL HYDROCARBON EMISSION FACTORS FOR UNDERGROUND NATURAL GAS

STORAGE—Continued 

Underground natural gas storage 

Emission factor 

(scf/hour/ 

component) 

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 Vents 2 .............................................................................................................. 1 .37 

High Continuous Bleed Pneumatic Device Vents 2 .............................................................................................................. 18 .20 

Intermittent Bleed Pneumatic Device Vents 2 ...................................................................................................................... 2 .35 

1Valves include control valves, block valves and regulator valves. 

2Emission 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 ..................................................................................................................................................................................... 1.77 

Population Emission Factors—LNG Storage Compressor, Gas Service 

Vapor Recovery Compressor ................................................................................................................................................. 4.17 

1 ‘‘Other’’ equipment type should be applied for any equipment type other than connectors, pumps, or valves. 

2Emission Factor is in units of ‘‘scf/hour/device.’’ 

■ 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/ 

component) 

Leaker Emission Factors—LNG Terminals Components, LNG Service 

Valve ....................................................................................................................................................................................... 1.19 

Pump Seal .............................................................................................................................................................................. 4.00 

Connector ............................................................................................................................................................................... 0.34 

Other 1 ..................................................................................................................................................................................... 1.77 

Population Emission Factors—LNG Terminals Compressor, Gas Service 

Vapor Recovery Compressor 2 ............................................................................................................................................... 4.17 

1 ‘‘Other’’ equipment type should be applied for any equipment type other than connectors, pumps, or valves. 

2Emission Factors is in units of ‘‘scf/hour/compressor.’’ 

■ 17. Table W–7 to subpart W of Part 98 

is revised to read as follows: 


sroberts on DSK5SPTVN1PROD with RULES
Federal Register / Vol. 76, No. 247 / Friday, December 23, 2011 / Rules and Regulations 80595 

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 Station 1 Components, Gas Service 

Connector ............................................................................................................................................................................. 1 .69 

Block Valve ........................................................................................................................................................................... 0 .557 

Control Valve ........................................................................................................................................................................ 9 .34 

Pressure Relief Valve ........................................................................................................................................................... 0 .27 

Orifice Meter ......................................................................................................................................................................... 0 .212 

Regulator .............................................................................................................................................................................. 0 .772 

Open-ended Line .................................................................................................................................................................. 26 .131 

Population Emission Factors—Below Grade Metering-Regulating station 1 Components, Gas Service 2

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 Service 3

Unprotected Steel ................................................................................................................................................................. 12 .58 

Protected Steel ..................................................................................................................................................................... 0 .35 

Plastic ................................................................................................................................................................................... 1 .13 

Cast Iron ............................................................................................................................................................................... 27 .25 

Population Emission Factors—Distribution Services, Gas Service 4

Unprotected Steel ................................................................................................................................................................. 0 .19 

Protected Steel ..................................................................................................................................................................... 0 .02 

Plastic ................................................................................................................................................................................... 0 .001 

Copper .................................................................................................................................................................................. 0 .03 

1Excluding customer meters. 

2Emission Factor is in units of ‘‘scf/hour/station.’’ 

3Emission Factor is in units of ‘‘scf/hour/mile.’’ 

4Emission Factor is in units of ‘‘scf/hour/number of services.’’ 

[FR Doc. 2011–31532 Filed 12–22–11; 8:45 am] 

BILLING CODE 6560–50–P 


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