6560.50

ENVIRONMENTAL PROTECTION AGENCY

40 CFR Part 98

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

RIN 2060-AR09

Mandatory Reporting of Greenhouse Gases: Technical 

Revisions to the Electronics Manufacturing and the 

Petroleum and Natural Gas Systems Categories of the 

Greenhouse Gas Reporting Rule 

AGENCY: Environmental Protection Agency (EPA).

ACTION: Proposed Rule. 

SUMMARY: This action proposes technical revisions to the 

electronics manufacturing and the petroleum and natural gas 

systems source categories of the greenhouse gas reporting 

rule. Proposed changes include providing clarification on 

existing requirements, increasing flexibility for certain 

calculation methods, amending data reporting requirements 

clarifying terms and definitions, and technical 

corrections. In addition, the Environmental Protection 

Agency is proposing to amend the definition of heat 

transfer fluids in subpart I to include more fluorocarbons

used as heat transfer fluids in the electronics 

manufacturing industry. 
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DATES: Comments. Comments must be received on or before 

[INSERT THE DATE, 30 DAYS AFTER PUBLICATION OF THIS 

PROPOSED RULE IN THE FEDERAL REGISTER], unless a public 

hearing is held, in which case comments must be received on 

or before [INSERT THE DATE 45 DAYS AFTER PUBLICATION OF 

THIS PROPOSED RULE IN THE FEDERAL REGISTER]. 

Public Hearing. A public hearing will be held if 

requested. To request a hearing, please contact the person 

listed in the following FOR FURTHER INFORMATION CONTACT 

section by [INSERT DATE 7 DAYS AFTER DATE OF PUBLICATION OF 

THIS PROPOSED RULE IN THE FEDERAL REGISTER]. If requested, 

the hearing will be conducted on [INSERT DATE 15 DAYS AFTER 

DATE OF PUBLICATION OF THIS PROPOSED RULE IN THE FEDERAL 

REGISTER], in the Washington, DC area. EPA will provide 

further information about the hearing on its webpage if a 

hearing is requested.

ADDRESSES: You may submit your comments, identified by 

Docket ID No. EPA-HQ-OAR-2011-0512 by any of the following 

methods:

 Federal eRulemaking Portal: 

http://www.regulations.gov. Follow the online 

instructions for submitting comments.

Email: GHG_Reporting_Rule_Oil_And_Natural_Gas@epa.gov. 

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

subject line of the message.

 Fax: (202) 566–9744.
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 Mail: Environmental Protection Agency, EPA Docket 

Center (EPA/DC), Mail Code 28221T, Attention Docket ID 

No. EPA-HQ-OAR–2011-0512, 1200 Pennsylvania Avenue, 

NW., Washington, DC 20460.

 Hand/Courier Delivery: EPA Docket Center, Public 

Reading Room, EPA West Building, Room 3334, Attention 

Docket ID No. EPA-HQ-OAR–2011-0512, 1301 Constitution 

Avenue, NW., Washington, DC 20004. Such deliveries 

are only accepted during the docket’s normal hours of 

operation, and special arrangements should be made for 

deliveries of boxed information.

Instructions: Direct your comments to Docket ID No. 

EPA-HQ-OAR-2011-0512, Mandatory Reporting of Greenhouse 

Gases: Petroleum and Natural Gas Systems. EPA's policy is 

that all comments received will be included in the public 

docket without change and may be made available online at 

http://www.regulations.gov, including any personal 

information provided, unless the comment includes 

information claimed to be confidential business information 

(CBI) or other information whose disclosure is restricted 

by statute. Do not submit information that you consider to 

be CBI or otherwise protected through 

http://www.regulations.gov or email. The 

http://www.regulations.gov web site is an “anonymous 

access” system, which means EPA will not know your identity 

or contact information unless you provide it in the body of 

your comment. If you send an email comment directly to EPA 

without going through http://www.regulations.gov your email 
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address will be automatically captured and included as part 

of the comment that is placed in the public docket and made 

available on the Internet. If you submit an electronic 

comment, EPA recommends that you include your name and 

other contact information in the body of your comment and 

with any disk or CD-ROM you submit. If EPA cannot read 

your comment due to technical difficulties and cannot 

contact you for clarification, EPA may not be able to 

consider your comment. Electronic files should avoid the 

use of special characters, any form of encryption, and be 

free of any defects or viruses.

Docket: All documents in the docket are listed in the 

http://www.regulations.gov index. Although listed in the 

index, some information is not publicly available, e.g., 

CBI or other information whose disclosure is restricted by 

statute. Certain other material, such as copyrighted 

material, will be publicly available for viewing at the EPA 

Docket Center. Publicly available docket materials are 

available either electronically in 

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

Docket Center, EPA/DC, EPA West Building, Room 3334, 1301 

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

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

through Friday, excluding legal holidays. The telephone 
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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 questions, please 

see the Greenhouse Gas Reporting Program website 

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

ml. To submit a question, select Rule Help Center, 

followed by Contact Us. To obtain information about the 

public hearing or to register to speak at the public 

hearing, please go to 

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

ml. Alternatively, you may contact Carole Cook at 202–343–

9263.

Worldwide Web (WWW). In addition to being available 

in the docket, an electronic copy of today's proposal will 

also be available through the WWW. Following the 

Administrator's signature, a copy of this action will be 

posted on EPA's greenhouse gas reporting rule Web site at 

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

ml.
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Additional information on submitting comments. To 

expedite review of your comments by Agency staff, you are 

encouraged to send a separate copy of your comments, in 

addition to the copy you submit to the official docket, to 

Carole Cook, U.S. EPA, Office of Atmospheric Programs, 

Climate Change Division, Mail Code 6207-J, Washington, DC 

20460, telephone (202) 343-9263, email address: 

GHGReportingRule@epa.gov. 

SUPPLEMENTARY INFORMATION:

Regulated Entities. The Administrator determined that 

this action is subject to the provisions of Clean Air Act 

(CAA) section 307(d). If finalized, these amended 

regulations could affect owners or operators of petroleum 

and natural gas systems and certain electronic 

manufacturers. Regulated categories and 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

Petroleum and 

Natural Gas 

Systems

486210 Pipeline transportation of 

natural gas.

221210 Natural gas distribution 

facilities.

211 Extractors of crude petroleum 

and natural gas.

211112 Natural gas liquid extraction 

facilities.

Electronics 

Manufacturing

334111 Microcomputers manufacturing 

facilities.
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Source 

Category NAICS Examples of affected facilities

334413 Semiconductor, photovoltaic 

(solid-state) device 

manufacturing facilities.

334419 Liquid Crystal Display (LCD) 

unit screens manufacturing 

facilities.

334419 Micro-electro-mechanical systems 

(MEMS) manufacturing 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. 

Although Table 1 of this preamble lists the types of 

facilities of which EPA is aware that could be potentially 

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, 40 CFR part 98 subpart I 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. 

Acronyms and Abbreviations. The following acronyms 

and abbreviations are used in this document.

AGA American Gas Association

API American Petroleum Institute
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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

HTF heat transfer fluid

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
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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

NF3 nitrogen trifluoride

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

SF6 sulfur hexafluoride

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. How is this preamble organized?

B. Background on the Proposed Action

C. Legal Authority

D. How would these amendments apply to 2012 reports?
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II. Technical Corrections and Other Amendments

A. Subpart A – General Provisions

B. Subpart I – Electronics Manufacturing

C. Subpart W – Petroleum and Natural Gas Systems

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 LowIncome Populations

I. Background

A. How is this preamble organized?

The first section of this preamble contains the basic 

background information about the origin of these proposed 

rule amendments and request for public comment. This 

section also discusses EPA’s use of legal authority under 

the CAA to collect data on GHGs. 

The second section of this preamble describes in 

detail the changes that are being proposed to correct 

technical errors or to address implementation issues 

identified by EPA and others. This section also presents 
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EPA’s rationale for the proposed changes and identifies 

issues on which EPA is particularly interested in receiving 

public comments.

Finally, the last (third) section discusses the 

various statutory and executive order requirements 

applicable to this proposed rulemaking.

B. Background on the Proposed Action

EPA published Subpart I: Electronics Manufacturing of 

the Greenhouse Gas Reporting Program (GHGRP) on December 1, 

2010 (75 FR 74774). Subpart I of the GHGRP requires 

monitoring and reporting of GHG emissions from electronics 

manufacturing. Electronics manufacturing facilities 

covered by subpart I are those that have emissions equal to 

or greater than 25,000 mtCO2e. 

Following the publication of subpart I in the Federal 

Register, 3M Company (3M) sought reconsideration of the 

final rule requirements for reporting fluorinated heat 

transfer fluids (HTFs). In this action EPA, is proposing 

amendments to the provisions in subpart I related to 

calculating and reporting fluorinated HTFs to reflect the 

Agency’s intent to cover all fluorocarbons (except for 

ozone depleting substances regulated under EPA’s 

Stratospheric Protection Regulations at 40 CFR Part 82) 
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that can enter the atmosphere under the conditions in which 

HTFs are used in the electronics manufacturing industry. 

EPA published Subpart W: Petroleum and Natural Gas 

Systems of the Greenhouse Gas Reporting Rule on November 

30, 2010(75 FR 74458). Subpart W of the GHGRP, which 

applies to facilities in specific segments of the petroleum 

and natural gas industry that emit GHGs greater than or 

equal to 25,000 mtCO2e per year, covers approximately 85 

percent of GHG emissions – including vented, equipment 

leak, and combustion emissions - from facilities in 

specific segments of the petroleum and natural gas 

industry. 

Following the publication of subpart W in the Federal 

Register, several industry groups requested reconsideration 

of several provisions in the final rule. Part of the 

proposed amendments in this action are in response to those 

requests for reconsideration . Today we are granting 

reconsideration of, and requesting comment on, those issues 

raised in the petitions listed in Table 2 where indicated 

in such Table that the issue is addressed in this action. 

While we do not necessarily agree that each of those 

identified issues meet the criteria for reconsideration, we 

nonetheless believe that they do raise important 

implementation issues and are thus granting reconsideration 
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of those issues and proposing concomitant revisions to the 

rule. At this time we are not granting reconsideration of 

other issues raised in those petitions where indicated in 

the following table that they are not being addressed in 

this action but will consider those issues at a later time.

Table 2: Petitions for Reconsideration

Petitioner 

and Date of 

Letter

Issue Raised for 

Reconsideration

Is this issue 

addressed in this 

action?

American 

Gas 

Association 

by letter 

dated March 

2, 2011

Non custody transfer city 

gate station terminology. 

AGA asserted that 

“[s]everal provisions in 

the Subpart W rule and 

preamble seem to imply 

that a ‘non-custodytransfer city gate 

station’ will always have 

a meter.”

Yes.

Custody transfer city 

gate station terminology. 

AGA asserted that the 

term “custody transfer 

city gate station” in 

subpart W was unclear and

needed clarification. 

Yes.

Use of GTI emission 

factors. AGA requested 

reconsideration of the 

emissions factors for 

Local Distribution 

Companies in the final 

rule. 

Partially.
14 of 209

Petitioner 

and Date of 

Letter

Issue Raised for 

Reconsideration

Is this issue 

addressed in this 

action?

New emission factor 

formulas are confusing or 

contain math errors that 

vastly inflate emission 

estimates. AGA asserted 

that the “[t]he new 

emissions factor 

equations W-30, W-31 and 

W-32 in the final rule 

are confusing. Since 

these formulas were not 

included in the proposed 

rule, AGA did not have an 

opportunity to comment on 

them.” 

Yes.

New electronic reporting 

form is not yet available 

for comment or testing. 

AGA asserted that 

“[s]takeholders should be 

given the opportunity to 

comment and to have 

access to the reporting 

software to perform trial 

runs. 

No. This is being

addressed in a 

separate package. 

EPA should exclude small 

internal combustion 

sources, not just 

external combustion. AGA 

asserted that “EPA should 

revise the final rule to 

provide a de minimis 

exemption for small 

internal and external 

combustion sources at 

underground storage 

facilities.” Also “AGA 

request reconsideration 

of this new exclusion for 

small combustion sources 

and revision to include 

both small internal and 

external combustion 

sources...” 

Yes.
15 of 209

Petitioner 

and Date of 

Letter

Issue Raised for 

Reconsideration

Is this issue 

addressed in this 

action?

AGA asserted that “[t]he 

rule contains conflicting 

provisions regarding 

whether emissions from 

dehydrator units at 

underground storage 

facilities should or 

should not be reported.”

No. 

AGA asserted that “EPA 

did not provide rational 

explanation for using 

outdated inaccurate 

emission factors rather 

than modern updated 

emission factors.”

Yes. 

AGA asserted that 

“[d]efinition of 

‘facility’ is overbroad 

and confusing.” The 

facility definition 

referred to here is found 

in 40 CFR 98.238.

No.

AGA asserted that “It was 

arbitrary and capricious 

for EPA to create a 

subpart W reporting 

regulation for a null set 

– LNG storage facilities 

will not exceed the 

25,000 ton per year 

threshold.”

No.

AGA asserted that “It was 

arbitrary and capricious 

for EPA to create a 

subpart W reporting 

regulation for LNG import 

and export facilities –

which have only minimal 

methane leaks.”

No.
16 of 209

Petitioner 

and Date of 

Letter

Issue Raised for 

Reconsideration

Is this issue 

addressed in this 

action?

Chesapeake 

Energy / 

American 

Exploration 

and 

Production 

Council by 

Letter 

Dated 

January 31, 

2011

Measurement of Emissions. 

CEC/AXPC asserted that 

“EPA proposed to require 

costly measurement and 

reporting of emissions 

from hundreds of 

thousands of sources. 

Commenters asked EPA to 

adopt a reasonable 

threshold for 

measurement, so that 

emissions could still be 

accounted for, but in a 

cost-effective way. 

Commenters recommended 

using the API Compendium 

for that purpose.”

No.

De minimis emissions from 

portable equipment. 

CEC/AXPC asserted that 

“[t]he final rule 

likewise fails to 

adequately support 

requiring the reporting 

of de minimis emissions 

from portable equipment 

as EPA proposed...EPA 

asserts a truism that all 

emissions contribute to 

sector emissions 

overall.”

Yes.

Designated Representative. 

CEC/AXPC requested 

reconsideration of the 

designated representative 

provisions in the final 

rule.

Yes.
17 of 209

Petitioner 

and Date of 

Letter

Issue Raised for 

Reconsideration

Is this issue 

addressed in this 

action?

Dump Valves. CEC/AXPC 

asserts that “[t]he 

requirement to measure 

and report emissions from 

dump valves associated 

with onshore production 

storage tanks...is a new 

and unreasonable ongoing 

monitoring and record 

keeping burden...”

No.

Best Available Monitoring 

Methods.

No. This is being 

addressed in a 

separate action (76 

FR 37300). 

Emissions Manifolded to 

Common Vents. CEC/AXPC 

asserted that the final 

provisions for 

centrifugal compressor 

monitoring “[n]ot only 

expands the rule to cover 

equipment that was not 

identified in the 

proposed rule, but it is 

also inconsistent and 

creates ambiguity for 

covered sources regarding 

what is required.” 

No.

Compressor Monitoring. 

CEC/AXPC asserts that 

“[t]he final rule imposes 

a new obligation to 

monitor and report that 

would require major 

piping modifications and 

that would unduly 

threaten worker safety.”

No.
18 of 209

Petitioner 

and Date of 

Letter

Issue Raised for 

Reconsideration

Is this issue 

addressed in this 

action?

Excluding Boosting 

Stations. CEC/AXPC 

asserted that “[t]he 

final rule fails to 

distinguish between a 

boosting station, which 

is exempt, and an 

‘onshore natural gas 

transmission compression 

facility’ which must 

report under the rule.”

Yes.

Onshore Natural Gas 

Transmission Compression 

Industry Segment 

Definition. CEC/AXPC 

asserted that “[a]s 

presently drafted, the 

unclear and inconsistent 

final provisions render 

the rule arbitrary and 

capricious and contrary 

to law.” And “The term 

‘onshore natural gas 

transmission compression’

means a stationary 

combination of 

compressors that move 

natural gas at elevated 

pressure from production 

fields or natural gas 

processing facilities in 

transmission pipelines or 

into storage. 40 C.F.R. 

§98.230(a)(4). A 

transmission compressor 

station can include 

equipment to separate 

liquids or dehydrate 

natural gas Id. However, 

according to the final 

rule this source category 

does not include 

gathering lines and 

boosting stations.”

Yes.
19 of 209

Petitioner 

and Date of 

Letter

Issue Raised for 

Reconsideration

Is this issue 

addressed in this 

action?

Onshore Natural Gas 

Processing Industry Segment 

Definition. CEC/AXPC 

asserted that “[a]s 

presently drafted, the 

unclear and inconsistent 

final provisions render 

the rule arbitrary and 

capricious and contrary 

to law.” CEC/AXPC further

stated concerns with the 

definition for onshore 

natural gas processing 

industry segment 

definition and where the 

segment differs from 

onshore natural gas 

transmission industry 

segment, and from 

gathering lines and 

boosting stations. 

Yes.

Gathering Lines and 

Boosting Stations. 

CEC/AXPC asserted that 

“EPA noted that the 

‘final rule does not 

require reporting of 

emissions from [the] 

gathering and boosting 

segment of the industry.’ 

This...is not helpful and 

gives industry no clarity 

regarding which 

compressor stations are 

required to report.” 

Yes.
20 of 209

Petitioner 

and Date of 

Letter

Issue Raised for 

Reconsideration

Is this issue 

addressed in this 

action?

Mapping Wells to Fields. 

CEC/AXPC asserted that 

“EPA has not clarified 

how reporting entities 

are supposed to map wells 

to a particular ‘field.’” 

Also, CEC/AXPC asserted 

that “[w]ithout 

sufficient clarity 

regarding what wells are 

in a particular field, it 

is difficult for covered 

sources to know with 

certainty what gas 

composition is considered 

representative for each 

well.”

Yes.

Definition of Facility for 

Onshore Petroleum and 

Natural Gas Production. 

CEC/AXPC asserted that 

the “EPA has not provided 

a reasoned explanation 

for why a term other than 

‘facility’ cannot be 

adopted for Subpart w 

(such as ‘Reporting 

Area’) in order to avoid 

unintended confusion and 

inaccuracies in 

reporting.”

No.

Pipeline Quality Natural 

Gas. CEC/AXPC asserted 

that “[t]here is not a 

clear and unambiguous 

definition in the final 

rule for ‘pipeline 

quality’ natural gas.”

Yes.
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Petitioner 

and Date of 

Letter

Issue Raised for 

Reconsideration

Is this issue 

addressed in this 

action?

Producing Horizon/formation 

definition. CEC/AXPC 

asserted that “[t]here is 

not a clear and 

unambiguous definition 

provided in the final 

rule for the term 

‘producing 

horizon/formation.’”

Yes.

Well testing venting and 

flaring clarification. 

CEC/AXPC asserted that 

“[t]he final rule is 

unclear regarding the 

requirement to report 

emissions from well 

testing venting and 

flaring.”

Yes.

Associated Gas Venting and 

Flaring. CEC/AXPC 

asserted that “40 CFR 

98.233(m) imposes a 

requirement to report 

emissions from associated 

gas venting and flaring 

not in conjunction with 

well testing. While this 

regulation references 40 

CFR 98.233(l), that 

definition is unclear. 

Therefore industry is 

left without clarity 

regarding what emissions 

are included in 

‘associated gas venting 

and flaring not in 

conjunction with well 

testing.’” 

No.
22 of 209

Petitioner 

and Date of 

Letter

Issue Raised for 

Reconsideration

Is this issue 

addressed in this 

action?

Pneumatic Devices. 

CEC/AXPC asserted that 

“EPA has not given 

sufficient consideration 

to the burden imposed by 

requiring that the bleed 

rate of each device be 

determined in order to 

count and classify the 

devices.”

Yes.

Blowdown Vent Stacks. 

CEC/AXPC asserted that 

“[t]he sources that are 

required to report 

emissions from blowdown 

vent stacks are not 

clear.”

Yes.

American 

Petroleum 

Institute by 

Letter Dated 

January 31, 

2011. 

Best Available Monitoring 

Methods.

No. This is being 

addressed in a 

separate action (76 

FR 37300). 

Exclusion for ‘small’ 

internal combustion sources 

is needed. API asserted 

that “EPA should extend the 

exclusion for small 

external combustion sources 

to small internal 

combustion sources.”

Yes.

Stuck dump valves to 

separators/tanks in onshore 

production operations. API 

asserted that “[t]he new 

requirement to report 

emissions from stuck dump 

valves requires reporters 

to check all dump valves on 

a well site... These 

requirements represent an 

administrative burden for 

reports that was not 

contemplated in the 

proposed rule.”

No. 
23 of 209

Petitioner 

and Date of 

Letter

Issue Raised for 

Reconsideration

Is this issue 

addressed in this 

action?

Reporting requirements for 

centrifugal and 

reciprocating compressor 

venting at onshore natural 

gas processing facilities. 

API requested EPA to 

reconsider an asserted 

expansion of reporting 

requirements for 

centrifugal and 

reciprocating compressor 

venting at onshore natural 

gas processing facilities. 

No.

Requirements for flare 

stack emission associated 

with onshore oil and gas 

production. API asserted 

that “[e]missions from 

flare stacks associated 

with onshore oil and gas 

production were not 

included in the Petroleum 

and Natural Gas production 

industry segment in the 

proposed rule...the inclusion 

of emissions from flare 

stacks associated with 

onshore oil and gas 

production is duplicative, 

burdensome, and a potential 

source of reporting 

inaccuracies.”

Yes. 

Reporting requirements for 

all venting and flaring 

activities in the 

production source category. 

API asserts that “EPA’s 

expansion of the reporting 

obligations in 98.233(m) to 

include upset or 

maintenance gas from 

producing wells imposes 

additional and extensive 

burdens on regulated 

parties wich was not 

included in the proposal.”

No. 
24 of 209

Petitioner 

and Date of 

Letter

Issue Raised for 

Reconsideration

Is this issue 

addressed in this 

action?

Use of gas composition 

based on available sample 

analysis for reporters 

without continuous gas 

composition analyzer. API 

asserts that “EPA should 

resolve the ambiguity 

created by the current 

language.”

Yes.

Portable combustion 

equipment that cannot move 

on roadways under its own 

power and drive train that 

is stationed at a wellhead 

for less than 30 days in a 

reporting year. API 

asserts that “[t]he final

rule requires reporters to 

account for this equipment, 

despite the fact that it is 

on site for an extremely 

short period of time....it is 

unrealistic to expect 

reporters to measure 

emissions from every piece 

of portable combustion 

equipment that is only 

onsite for a matter of 

days.”

Yes.

Separate calculations for 

Subsonic and supersonic 

flow when both happen 

during a single completion. 

API asserted that “[t]he 

proposed rule did not 

include a requirement that 

well completions have 

separate calculations for

subsonic and supersonic 

flow when both occur during 

a single completion. The 

final rule adds this 

requirement, which is not 

technically possible.” 

Yes.
25 of 209

Petitioner 

and Date of 

Letter

Issue Raised for 

Reconsideration

Is this issue 

addressed in this 

action?

Flow meter requirements. 

API asserts that “[t]he 

final rule adds a 

requirement at 40 CFR 

98.234(b) that all flow 

meters, composition 

analyzers and pressure 

gauges be operated and 

calibrated according to the 

procedures in Section 

98.3(i) of the MRR...API is 

concerned about the 

potential unintended 

consequence following the 

addition of stationary 

source combustion equipment 

at a well pad at new 40 CFR 

98.232(C)(22), which 

required compliance with 40 

CFR 98.233(z)(2)(1).” 

Yes.

Emission factors for 

continuous high-bleed, 

continuous low-bleed, and 

intermittent bleed 

pneumatic devices. API 

asserted that “[a]lthough 

EPA has provided emission 

factors in Table W-1A that 

apply to continuous highbleed, continuous lowbleed, and intermittent 

bleed pneumatic devices, 

EPA has not provided 

guidance on how to classify 

pneumatic devices according 

to these three categories.”

Yes.

Definitions to Industry 

Categories. API asserted 

that the “[a]ltered final 

rule creates ambiguity as 

to whether certain 

facilities are included in 

the production category, 

excluded as gathering or 

booster stations, or 

included under the gas 

processing category.” 

Yes. 
26 of 209

Petitioner 

and Date of 

Letter

Issue Raised for 

Reconsideration

Is this issue 

addressed in this 

action?

Number of plunger lifts and 

average casing diameter in 

inches. API asserted that 

“[t]he final rule adds 40 

CFR 98.236(c)(5) 

requirements to report the 

number of plunger lifts and 

average casing diameter in 

inches by field. The 

difficulty with these 

additions is not with the 

requirement for counting 

plunger lifts and noting 

casing diameter, but that 

reporting must take place 

at the field level.” 

Yes. 

Floating Production Storage 

and Offloading Equipment. 

API asserted that “[t]he 

proposed rule did not 

include floating production 

storage and offloading 

equipment in the definition 

of offshore petroleum and 

natural gas production. 

API questions the need for 

this addition at 40 CFR 

98.230(a)(1).” 

No.

Basin level reporting for 

onshore petroleum and 

natural gas production. 

API asserted that “[t]his 

broad definition of onshore 

production facility is 

impractical. Subpart W 

imposes reporting 

requirements on over 22,000 

entities operating hundreds 

of thousands of wells and 

millions of pieces of 

equipment scattered over 

hundreds of thousands of 

square miles.” 

Yes.
27 of 209

Petitioner 

and Date of 

Letter

Issue Raised for 

Reconsideration

Is this issue 

addressed in this 

action?

Field level reporting for 

onshore petroleum and 

natural gas production. 

API asserts that “[t]his 

level of reporting is 

problematic when applied to 

new requirements of the 

final rule. For the same 

reasons, it remains 

problematic when applied to 

those requirements in the 

proposed rule that remain 

in the final rule.”

Yes. 

Designated Representative 

of Subpart W Facility. API 

asserted that “[t]he new 

basin-level facility 

definition for onshore 

petroleum and natural gas 

production systems adopted 

in Subpart W adds 

unreasonable complexity to 

several of the existing 

administrative requirements 

for the designated 

representative set forth in 

40 CFR 98.4” 

Yes. 
28 of 209

Petitioner 

and Date of 

Letter

Issue Raised for 

Reconsideration

Is this issue 

addressed in this 

action?

Reporting of GHG emissions 

from leased, rented, or 

contracted activities. API 

asserts that “[t]hese 

requirements create 

significant complications. 

A single well pad may be 

owned by one entity, 

operated by another entity, 

lease portable equipment 

from a third entity, and 

have that portable 

equipment operated by yet 

another entity. The rule 

places the burden of 

reporting entirely on the 

owner of the well or the 

holders of the operating 

permit and makes the 

designated representatives 

legally responsible for the 

accuracy of the emissions 

data provided by third 

parties.”

Partially.

Threshold for “small” size 

units that are exempt from 

consideration. API asserts 

that “[t]he final rule’s 

threshold of 0.4 MMscf per 

day for dehydrator 

calculations using software 

and individual reporting is 

too low.” 

No.

Gas 

Processors 

Association 

by Letter 

Dates 

February 11, 

2011

Best Available Monitoring 

Methods. GPA asserted that 

“[s]ubpart W’s best 

available monitoring method 

provisions do not provide 

reporting entities with 

adequate time to ensure 

compliance with the final 

rule.”

No, this is being 

addressed in a 

separate action (76 

FR 37300).
29 of 209

Petitioner 

and Date of 

Letter

Issue Raised for 

Reconsideration

Is this issue 

addressed in this 

action?

Compressor venting 

monitoring requirements. 

GPA asserted that 

“[c]urrent compressor 

venting monitoring 

requirements are overly 

burdensome and present 

significant safety and 

operational process 

concerns to reporting 

entities.”

No. 

Use of the terms “gathering 

lines” and “booster 

stations” not being defined 

in final rule. GPA 

asserted that “[t]he terms 

‘gathering lines’ and 

‘booster stations’ are not 

defined in the final rule, 

nor is sufficient detail 

provided regarding the 

definition of ‘gas 

processing facility.’” GPA 

further asserted that 

“[a]bsent such definitions 

and clarifications, there 

will be substantial 

confusion as to which 

facilities are required to 

report emissions data.” 

Yes. 

Facility definition for 

onshore petroleum and 

natural gas production. 

GPA asserted “[t]he 

definition of a facility in 

Subpart W differs from the 

definition of a facility 

provided in all other 

applicable regulations 

under the Clean Air Act. 

This inconsistency will 

create unnecessary 

confusion among related 

programs and is not 

necessary or justified.”

No. 
30 of 209

Petitioner 

and Date of 

Letter

Issue Raised for 

Reconsideration

Is this issue 

addressed in this 

action?

Southwest 

Gas 

Corporation 

by Letter 

Dated 

January 31, 

2011

Terms in Subpart W. 

Southwest Gas Corporation 

asserted that “[t]he 

USEPA’s final rule fails to 

provide clear definitions 

that can be used uniformly 

throughout the natural gas 

distribution industry.” 

Yes.

Errors in Calculations. 

Southwest Gas Corporation 

asserted that the USEPA 

published errors in 

equations in 40 CFR 98.233, 

namely equation W-32. 

Yes.

Interstate 

Natural Gas 

Association 

of America 

Best Available Monitoring 

Methods. 

No, this is being 

addressed in a 

separate action (76 

FR 37300).

Technical Provisions in 

Subpart W. INGAA asserted 

that “[n]umerous technical 

elements of Subpart W 

remain unclear, confusing, 

overly complicated or 

conflicting.” 

Partially.

INGAA petitioned EPA to 

reconsider the default gas 

compositions and requested 

the use of separate default 

gas compositions for 

methane and CO2 for vented 

and fugitive emissions for 

the natural gas 

transmission compression 

and storage segments. 

Yes.

INGAA petitioned EPA to 

reconsider minor 

clarifications to 40 CFR 

98.233(t), (u), and (v) for 

clarity

Yes.
31 of 209

Petitioner 

and Date of 

Letter

Issue Raised for 

Reconsideration

Is this issue 

addressed in this 

action?

INGAA requested EPA to 

reconsider the provisions 

in the final rule for 

determining the type of 

pneumatic device at a 

facility. INGAA requested 

EPA to consider the option 

of using engineering 

estimates to determine the 

type of pneumatic devices.

Yes.

INGAA requested EPA to 

reconsider the provisions 

in the rule related to

blowdown vent stacks and 

requested a 

reconsideration of those 

provisions. 

Yes.

INGAA requested EPA to 

reconsider the provisions 

in the rule for emissions 

from blowdown vent stacks

and to include an 

additional equation to 

allow facilities who 

currently track emissions 

by equipment type to submit 

emission to EPA in that 

manner.

Yes.

INGAA requested that EPA to 

reconsider provisions 

related to flaring.

Yes.

INGAA requested that EPA 

reconsider provisions for 

monitoring emissions from 

centrifugal and 

reciprocating compressors 

and to consider including 

clarifications to rule 

text. 

No.

INGAA requested EPA to 

reconsider provisions 

related to monitoring and 

QA/QC requirements 

including provisions for 

the alternative work 

practice. 

Yes.
32 of 209

Petitioner 

and Date of 

Letter

Issue Raised for 

Reconsideration

Is this issue 

addressed in this 

action?

INGAA requested EPA to 

reconsider missing data 

provisions and broaden 

access.

No.

INGAA requested EPA to 

reconsider provisions as 

stated in 40 CFR 98.236 and 

requested several 

clarifications to final 

text. 

Partially. 

The proposed amendments in this action include 

technical corrections and clarifications to ensure that the 

2010 final rule is implemented as intended. Amendments to 

subparts I and W are also being proposed in other actions. 

Please see 76 FR 47392 (Herein referred to as the 

“technical corrections rule”) and76 FR 37300. This 

proposal complements these proposed rules and is not 

intended to duplicate or replace those proposed amendments. 

In limited cases, an amendment to subpart W was proposed in 

the technical corrections rule and we are proposing to 

amend it further in this action. Additional proposed 

amendments were determined to be necessary to address 

questions and issues raised by stakeholders since 

development of the proposal of the technical corrections 

rule. Where amendments have been made to the same 

paragraph in this action and in the technical corrections 

rule, the proposal below provides the complete proposed 
33 of 209

amendatory language for how EPA proposes to amend the 

provision. We are seeking public comment only on the 

issues specifically identified in this proposal for the 

identified subparts. We will not respond to any comments 

addressing other aspects of Part 98 or any other related 

rulemakings. 

EPA promulgated confidentiality determinations for 

certain data elements required to be reported under Part 98 

and finalized amendments to the Special Rules Governing 

Certain Information Obtained Under the Clean Air Act, which 

authorizes 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, May 26, 2011 hereinafter 

referred to as the “May 26, 2011 Final CBI Rule”). That 

notice addressed reporting of data elements in 34 subparts 

that were determined not to be inputs to emission equations 

and therefore were not proposed to have their reporting 

deadline deferred. 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 and July 20, 

2010 supplemental CBI proposal. 
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EPA is planning to address the confidentiality 

determinations for the data elements in subpart W in a 

separate action. EPA plans to issue and finalize the 

confidentiality determinations for subpart W prior to the 

2012 reporting deadline. 

C. Legal Authority

EPA is proposing these rule amendments under its 

existing CAA authority, specifically authorities provided 

in section 114 of the CAA. 

As stated in the preamble to the 2009 Final Greenhouse 

Gas Reporting Rule (Part 98) (74 FR 56260, October 30, 

2009), CAA section 114 provides EPA broad authority to 

require the information proposed to be gathered by this 

rule because such data would inform and are relevant to 

EPA’s carrying out a wide variety of CAA provisions. As 

discussed in the preamble to the initial proposed rule (74 

FR 16448, April 10, 2009), section 114(a)(1) of the CAA 

authorizes the Administrator to require emissions sources, 

persons subject to the CAA, manufacturers of control or 

process equipment, or 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 EPA’s 
35 of 209

legal authority, see the preambles to the proposed and 2009 

final Part 981. 

D. How Would These Amendments Apply to 2012 Reports?

EPA is planning to address the comments on these 

proposed amendments and publish the final amendments before 

the end of 2011. Therefore, for subpart W, reporters would 

be expected to calculate emissions and other relevant data 

for the reports that are submitted in 2012 using part 98, 

as amended by this rule, as finalized. We have determined 

that it is feasible for the sources to implement these 

changes for the 2011 reporting year since the proposed 

revisions primarily provide additional clarifications or 

flexibility regarding the existing regulatory requirements, 

generally do not affect the type of information that must 

be collected, and do not substantially affect how emissions 

are calculated. 

For amendments being proposed today to subpart I, EPA 

is requesting comment on whether to require electronics 

manufacturing facilities to estimate and report 2011 

emissions in 2012 for HTFs that would be newly included in 

the scope of subpart I if today’s proposed rule amendments 

were finalized. 

 

1 74 FR 16448 (April 10, 2009) and 74 FR 56260 (October 30, 2009).
36 of 209

For facilities subject to the provisions in 40 CFR 

part 98 – subpart W, many proposed revisions simply provide 

additional information and clarity on existing 

requirements. For instance, we are proposing to amend 40 

CFR 98.1(c)(1) to clarify that for onshore petroleum and 

natural gas facilities, the references in 40 CFR 98.4 that 

apply to owner(s) and operator(s) refer to the onshore 

petroleum and natural gas production owner or operator, as 

defined in 40 CFR 98.238. Therefore, we are proposing to 

explicitly make this clarification in 40 CFR 98.1 (Purpose 

and Scope). The proposed amendment does not change the 

burden of the 2010 final rule, and in fact, EPA believes 

that it alleviates concerns expressed by industry that the 

designated representative provisions are overly burdensome. 

Some of the proposed amendments for subpart W provide 

greater flexibility or simplified calculation methods for 

certain facilities. For example, we are proposing to amend 

40 CFR 98.233(i) to provide an additional option to 

calculate GHG emissions from blowdown vent stacks. 

Specifically, we are proposing to allow reporters the 

option of tracking blowdowns by each occurrence for the 

same blowdown volume, consistent with current practice at 

some facilities, whereas in the final rule, reporters were 
37 of 209

required to track total blowdown vent emissions from all 

occurrences for the same blowdown volume in a year. 

Further, some proposed amendments for subpart W are to 

the data reporting requirements to provide additional 

clarity on which GHG emissions have to be reported and at 

which level of aggregation. For example, in 40 CFR 98.236 

EPA is proposing to clarify where “vented” emissions should 

be reported separately from “flared” emissions and that 

reporting of CH4, CO2, and N2O emissions should be reported 

individually for each source type in CO2e. We have 

concluded that amendments such as these could be 

implemented for the reports submitted to EPA in 2012 

because the proposed changes are, with one exception, 

consistent with the calculation methodologies already in 

part 98 and the owners or operators are not required to 

actually report until March 20122, several months after we 

expect this proposal to be finalized. 

The one exception where both the underlying 

calculation requirements and reporting requirements in 

subpart W are proposed to be changed is related to the 

requirements for field level reporting for four emissions 

sources in the onshore petroleum and natural gas production 

 

2 EPA has proposed to extend the 2012 reporting deadline for source categories first 

required to begin data collection in 2011 from March 31, 2012 to September 28, 2012. 

Please see the technical corrections rule previously referenced. 
38 of 209

segment. As described further in Section II.C of this 

preamble, we are proposing to amend the calculation and 

reporting requirements for well completions and well 

workovers, well venting for liquids unloading, and storage 

tanks to require calculations and reporting to be 

undertaken at the county level and by geologic formation 

(by formation type). 

EPA believes that the proposed amendments for subpart 

W can still be implemented for the 2011 reporting year for 

a couple of reasons. First, these amendments are being 

proposed based on industry concern about associating wells 

with a particular “field” given possible ambiguity 

surrounding EIA field designations. While EPA maintains 

its belief that reporting by the field is a viable and 

workable option, however, EPA does acknowledge that 

counties are readily identifiable, and provide clear 

geographic boundaries. AS a result, implementation of this 

alternative method should be straightforward for 

facilities. Second, if facilities are concerned about 

their ability to implement these provisions for the 2011 

reporting year, they may use best available monitoring 

methods (BAMM) pursuant to 40 CFR 98.234(f). In the event 

that facilities have already taken a measurement at the 

field level, they could still use those same measurements 
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for the 2011 reporting year, but apply them to the subbasin categories based on BAMM. 

Other amendments to subpart W are proposed to address 

issues identified as a result of working with the affected 

facilities during rule implementation. These proposed 

revisions provide additional flexibility to the sources, or 

reduce the reporting burden. For example, the 2010 final 

rule required leak detection for emissions from dump valves 

in transportation storage tanks, and if a leak is detected, 

measurement of the quantity of emissions would be required. 

However, industry raised questions as to whether a facility 

could forgo leak detection and directly measure the 

emissions from leaking dump valves under the natural gas 

transmission industry segment. This action provides this 

additional flexibility, because it reduces burden without 

compromising the quality of the data reported to EPA. 

We are also proposing corrections to terms and 

definitions in certain equations in subpart W. For 

example, we are proposing to amend the calculation for 

estimating CO2 emissions from acid gas removal vents in 

Equation W-4. Although the existing equation is 

appropriate when the amount of CO2 in gas is relatively low, 

such as 1 percent, the error rate in the estimate increases 

significantly as the amount of CO2 in gas increases. 
40 of 209

Therefore, EPA is proposing a new equation, which uses the 

exact same input parameters and thus will not result in any 

additional burden to reporters, but will improve the 

quality of the information submitted to EPA. These 

clarifications do not result in additional requirements; 

therefore, we have concluded that reporters can follow part 

98, as amended, in submitting their first reports to EPA in 

2012.

Finally, we are proposing other technical corrections

in subpart W that have no impact on a facility’s data 

collection efforts in 2011. For example, we are proposing 

to correct cross references in equations and change 

incorrect use of the term “facility” in the definition of 

the source category.

In summary, these proposed amendments to subpart W

generally would not require any additional monitoring or 

information collection above what is already included in 

Part 98. Therefore, we expect that sources can use the 

same information that they have been collecting under the 

current version of Part 98 to calculate and report GHG 

emissions for 2011 and submit reports in 2012 under Part 

98, as amended by this action. 

We seek comment on whether it is appropriate to 

implement these amendments and incorporate the requirements 
41 of 209

in the data reported to EPA by March 31, 2012. Further, we 

seek comment on whether there are specific provisions in 

subpart W for which this timeline may not be feasible or 

appropriate due to the nature of the proposed changes or 

the way in which data have been collected thus far in 2011. 

We request that commenters provide specific examples of how 

the proposed implementation schedule would or would not 

work. 

II. Technical Corrections and Other Amendments

Following promulgation of the 2010 final subpart I and 

subpart W, EPA has identified errors in the regulatory 

language that we are now proposing to correct. These 

issues were identified as a result of working with affected 

industries to implement rules. We have also identified 

certain rule provisions that should be amended to provide 

greater clarity. For additional background information on 

the questions raised, please refer to the Technical Support 

Document for this proposed rulemaking available in the 

docket to this rulemaking (EPA–HQ–OAR–2011-0512). 

The amendments we are now proposing include the 

following types of changes: 

 Changes to correct cross references within the 

subparts.
42 of 209

 Additional information to allow reporters to better or 

more fully understand compliance obligations in a 

specific provision.

 Corrections to terms and definitions in certain 

equations.

 Corrections to data reporting requirements so that 

they more closely conform to the information used to 

perform emission calculations.

 Other amendments related to certain issues identified 

as a result of working with the affected sources 

during rule implementation and outreach.

We are seeking public comment only on the issues 

specifically identified in this notice for the identified 

subparts. We will not respond to any comments addressing 

other aspects of Part 98 or any other related rulemakings.

A. Subpart A – General Provisions 

Designated Representative. Two industry associations 

raised concerns about the provisions related to 

determination of the designated representative in the 

context of how the subpart A definition would affect 

subpart W reporters. Through a letter dated January 31, 

2011, the American Petroleum Institute (API) encouraged 

EPA to reconsider the implications on owners and operators 

in the onshore petroleum and natural gas production segment 

in the context of the provisions in 40 CFR 98.4. 

Specifically, API was concerned that given the definition 

of “facility” for onshore petroleum and natural gas 

production, coupled with the relatively complex ownership 
43 of 209

structures in the industry (as compared to other subparts 

covered under part 98), EPA should modify several 

requirements in 40 CFR 98.4(authorization and 

responsibilities of the designated representative). API 

encouraged EPA to eliminate the requirement of notifying 

co-owners of the designated representative selection (40 

CFR 98.4(i)(4)(iv)), eliminate the requirement for listing 

of co-owners as part of the certificate of representation 

(40 CFR 98.4(i)(3), and eliminate the requirement for new 

certificates of representation following ownership changes 

(40 CFR 98.4(h)). 

Similar concerns were expressed in a letter from 

Chesapeake Energy Corporation (CEC) and the American 

Exploration & Production Council (AXPC) dated January 31, 

2011. CEC/AXPC was also concerned that the current 

operational reality in the onshore petroleum and natural 

gas industry would make it difficult for a designated 

representative to make the certifications required in 40 

CFR 98.4(i)(4). Specifically, CEC/AXPC was concerned about 

attesting to the fact that the designated representative 

was selected by an agreement binding on the owners and 

operators of the facility, that all owners and operators 

are fully bound by representations of the designated 

representative, that the owners and operators of the 
44 of 209

facility would be bound by any order issued to the 

designated representative by the administrator or a court, 

and that the designated representative has given written 

notice of their selection and of the agreement by which the 

designated was selected by the owner and operator of the 

facility. 

EPA maintains, as described in the October 2009 final 

rule (74 FR 56357), that the high level of public interest 

in the data collected under this rule, as well as its 

importance to future policy, warrants establishment, by 

rule pursuant to CAA sections 114, 208, and 301(a)(1), of a 

high standard for data quality and consistency and a high 

level of accountability for reported data, which will help 

ensure that the data quality and consistency standard is 

met. The designated representative is the primary point of 

contact between the owner or operator and the EPA. 

Therefore, it is important that EPA knows who the 

designated representative is, and that the designated 

representative has made the necessary certification 

statements. 

EPA recognizes that the onshore petroleum and natural 

gas industry has a different organizational structure and 

operational realities than other industries subject to Part 

98. As such, in the 2010 final rule for subpart W (75 FR 
45 of 209

74512), EPA specifically defined who is an onshore 

petroleum and natural gas production owner or operator. 

Under 40 CFR 98.238, onshore petroleum and natural gas 

production owner or operator means “the person or entity 

who holds the permit to operate petroleum and natural gas 

wells on the drilling permit or an operating permit where 

no drilling permit is issued, which operates an onshore 

petroleum and/or natural gas production facility (as 

described in 40 CFR 98.230(a)(2). Where petroleum and 

natural gas wells operate without a drilling or operating 

permit, the person or entity that pays the state or federal 

business income taxes is considered the owner or operator.” 

It was EPA’s intent that this definition of owner and 

operator apply not only in subpart W, but also in subpart A 

for the obligations of Subpart W “owners and operators” 

(e.g., those related to identifying the designated 

representative and requirement for who must be included on 

the Certificate of Representation (COR)). 

EPA acknowledges that the final subpart W rule is not 

clear, and it could be interpreted that all “owners” and

all “operators”, as defined in 40 CFR 98.6, are required to 

identify the designated representative for the facility and 

be held accountable for all requirements under 40 CFR 98.4. 

EPA never intended that 4,000 owners and operators, e.g., 
46 of 209

would have to be listed on the COR, an example provided by 

API in their Petition for Reconsideration. Rather, EPA 

intended that for onshore petroleum and natural gas 

facilities, the references in 40 CFR 98.4 that apply to 

owner(s) and operator(s) refer to the onshore petroleum and 

natural gas production operator, as defined in 40 CFR 

98.238. Therefore, we are proposing to explicitly make 

this clarification in 40 CFR 98.1 (Purpose and Scope). 

Definitions: We are proposing amendments to the 

definition of continuous bleed pneumatic device in 40 CFR 

98.6 to clarify that continuous bleed devices supply gas to 

process control devices; these are not necessarily 

measurement devices, as suggested by the 2010 final rule.

Similarly, we are proposing to amend the definition of 

an intermittent bleed pneumatic device to clarify that 

these devices automatically maintain the process conditions 

and that the devices discharge all or a portion of the full 

volume of the actuator intermittently. 

Incorporation by Reference (IBR). Finally we are also 

proposing to amend 40 CFR 98.7 (What standardized methods 

are incorporated by reference into this part?) to remove 

paragraph 40 CFR 98.7(q). As elaborated further below, we 

are proposing to change the calculation and reporting 

requirements for specific equipment in the onshore 
47 of 209

petroleum and natural gas production segment from a “field” 

level, to a sub-basin category. Consistent with this 

proposed amendment, there is no longer a need to 

incorporate the Energy Information Administration (EIA) Oil 

and Gas Field Code Master List, 2008. 

B. Subpart I – Electronics Manufacturing

In this action, EPA is proposing to amend the 

provisions contained within subpart I to calculate and 

report emissions from fluorinated GHGs used as HTFs. 

First, EPA is proposing to amend the definition of HTFs in 

40 CFR 98.98, to include all fluorocarbons used as HTFs in 

the electronics manufacturing industry. The definition of 

HTFs incorporates the term “fluorinated GHGs” as defined in 

the general provisions of the greenhouse gas reporting rule 

(subpart A) at 40 CFR 98.6. The definition of “fluorinated 

greenhouse gas” in subpart A excludes “substances with 

vapor pressures of less than 1 mm of Hg absolute at 25 

degrees C.” EPA is proposing to specify that the vapor 

pressure cutoff clause in the subpart A definition of 

fluorinated GHGs does not apply to fluorinated HTFs in 

subpart I. As a result, emissions of fluorinated HTFs with 

vapor pressures of less than 1 mm of Hg absolute at 25 

degrees C would no longer be excluded from reporting under 

subpart I. Second, also in the definition of HTFs, EPA is 
48 of 209

proposing to add the phrase “but not limited to” before 

listing examples of fluorinated HTFs to ensure that 

potential future alternatives are covered. Third, EPA is 

proposing to remove the last sentence in the definition 

(“Electronics manufacturers may also use these same 

fluorinated chemicals to clean substrate surfaces or other 

parts”) and move the concept of using HTFs to clean 

substrate surfaces or other parts to the first sentence. 

Fourth, EPA is proposing minor revisions throughout the 

subpart I regulatory text to clarify the use of the terms 

fluorinated GHGs and fluorinated HTFs (e.g., referring to 

fluorinated HTFs rather than fluorinated GHGs used as 

HTFs). And last, in 40 CFR 98.92(a)(5), under GHGs to 

report, EPA is proposing to revise the clause “fluorinated 

GHG emitted from heat transfer use” to read “emissions of 

fluorinated heat transfer fluids.” 

EPA published Subpart I: Electronics Manufacturing of 

Part 98 on December 1, 2010 (75 FR 74774). This subpart 

requires monitoring and reporting of GHG emissions from 

electronics manufacturing. Included in the December 1, 

2010 final rule are provisions that require electronics 

manufacturing facilities to calculate and report emissions 

from the use of fluorinated HTFs. Pursuant to 40 CFR 

98.93(h), electronics manufacturing facilities must 
49 of 209

calculate HTF emissions using a mass balance approach based 

on: the beginning and end of year inventories; acquisitions 

and disbursements of HTFs; and the nameplate capacities of 

newly installed and removed equipment containing HTFs. For 

purposes of subpart I, HTFs are defined as the following: 

“fluorinated GHGs used for temperature control, device 

testing, and soldering in certain types of electronic 

manufacturing production processes. HTFs used in the 

electronics sector include perfluoropolyethers, 

perfluoroalkanes, perfluoroethers, tertiary 

perfluoroamines, and perfluorocyclic ethers. Electronics 

manufacturers may also use these same fluorinated chemicals 

to clean substrate surfaces and other parts” (40 CFR 

98.98). 

The definition of HTFs in subpart I includes the term 

“fluorinated greenhouse gases” (fluorinated GHGs), which is 

defined in Subpart A: General Provisions (40 CFR 98.6). 

EPA initially proposed a definition of fluorinated GHGs in 

the April 2009 proposed rule for Part 98 (74 FR 16448) as 

follows: “Fluorinated GHG means sulfur hexafluoride (SF6), 

nitrogen trifluoride (NF3), and any fluorocarbon except for 

controlled substances as defined at 40 CFR part 82, subpart 

A. In addition to (SF6) and NF3, “fluorinated GHG” includes 

but is not limited to any hydrofluorocarbon, any 
50 of 209

perfluorocarbon, any fully fluorinated linear, branched or 

cyclic alkane, ether, tertiary amine or aminoether, any 

perfluoropolyether, and any hydrofluoropolyether.” 

EPA received numerous comments on the definition, 

particularly in regards to Subpart OO-Suppliers of 

Industrial GHGs. For example, some commenters argued that 

the proposed definition of fluorinated GHGs was too broad 

because it would include nonvolatile materials that could 

not be emitted to the atmosphere. More specifically, one 

commenter suggested establishing a lower vapor pressure 

limit for fluorinated GHGs (heat transfer fluids) of 400 Pa 

(0.004 bar, or three mm Hg absolute) at 25 C.3 

In response to comments, in the 2009 final Part 98 

(74 FR 56260), EPA finalized the following definition of 

fluorinated GHG: “Fluorinated GHG means sulfur hexafluoride 

(SF6), nitrogen trifluoride (NF3), and any fluorocarbon 

except for controlled substances as defined at 40 CFR part 

82, subpart A and substances with vapor pressures of less 

than 1 mm of Hg absolute at 25 degrees C. With these 

exceptions, “fluorinated GHG” includes but is not limited 

to any hydrofluorocarbon, any perfluorocarbon, any fully 

fluorinated linear, branched or cyclic alkane, ether, 

 

3 For more information on comments and responses, please see the preamble to the final 

rule Mandatory Reporting of Greenhouse Gases (74 FFR 56348), and the Response to Public 

Comment on Subpart OO (“Mandatory Greenhouse Gas Reporting Rule: EPA’s Response to Public 

Comments, Subpart OO: Suppliers of Industrial GHGs” available in docket, EPA-HQ-OAR2008-0508.) 
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tertiary amine or aminoether, any perfluoropolyether, and 

any hydrofluoropolyether.” As EPA stated in the preamble 

to the final rule, “This modification ensures that nonvolatile fluorocarbons such as fluoropolymers are excluded 

from reporting requirements, while requiring reporting of 

fluorocarbons (as well as SF6 and NF3) that could reasonably 

be expected to be emitted to the atmosphere” (74 FR 56348, 

October 30, 2009). 

EPA proposed the subpart I definition for HTFs, which 

included the term “fluorinated GHG,” in an April 12, 2010 

Federal Register notice (75 FR 18652). In a December 1, 

2010 final rule “Mandatory Reporting of Greenhouse Gases: 

Additional Sources of Fluorinated GHGs” (75 FR 74775), EPA 

finalized a definition for HTFs that was substantially 

similar to the definition in the April 2010 proposed rule. 

Following publication of the final rule, 3M Company 

(3M) sought reconsideration of the reporting requirements 

for fluorinated GHGs used as HTFs under subpart I. 

Specifically, in its Petition for Reconsideration dated 

January 28, 2011 (available in docket EPA-HQ-OAR-2009-

0927), 3M stated that “...as currently written the reporting 

requirements for heat transfer fluids will exclude a 

significant portion of fluorinated GHGs used as heat 

transfer fluids. Thus, the GHG emissions associated with 
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heat transfer fluids will not be accurately reported under 

the rule.” Further, 3M stated, “By tying the reporting 

requirements for heat transfer fluids to the definition of 

a fluorinated GHG under §98.6 in Subpart A, the scope of 

Subpart I’s reporting requirements are limited to those 

heat transfer fluids that have vapor pressures of >1 mmHg 

at 25 degrees C. Although 3M understands the reasons 

behind the vapor pressure threshold in the general 

definition of a fluorinated GHG, the same rationale should 

not apply to heat transfer fluids. Heat transfer fluids 

are used at elevated temperatures and pressures, and as a 

result the vapor pressure of these materials at 1 mm Hg 

absolute T 25 degrees C is not predicative of emissions. 

Heat transfer fluids are used through a broad range of 

boiling points and are routinely lost from systems 

primarily through mechanical leaks but also from 

evaporative loss. Once emitted from a system, the fate of 

heat transfer fluids is primarily the atmosphere.” 

In addition to the concern that the rule will result 

in “dramatic under reporting of heat transfer fluid use and 

emissions,” 3M also raised the concern that “although all 

the heat transfer fluids that have relatively low global 

warming potentials will be required to be reported as GHGs, 

a substantial percentage of heat transfer fluids that have 
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global warming potentials in the range of 10,000 times that 

of CO2 will be exempt from reporting requirements.” 

Consequently, 3M argued, “the rule will likely lead to a 

migration toward use of exempt compounds and an increase in 

GHG emissions from the sector.”

To address the problem, 3M suggested that subpart I 

should be amended to specify that for reporting 

requirements under subpart I, the vapor pressure cutoff in 

the general definition of fluorinated GHG does not apply to 

HTFs. 

In finalizing the HTF provisions in subpart I, EPA did 

not intend to exclude a significant portion of fluorocarbon 

HTFs that can enter the atmosphere; any such exclusion was 

inadvertent. Given the high temperatures in which HTFs may 

be used, EPA believes that such fluids are able to enter 

the atmosphere even when their vapor pressures at 25 

degrees C (77 degrees F) are low. This is because the 

vapor pressures of substances increase as their 

temperatures increase, and HTFs with low vapor pressures 

are likely to be used in high-temperature applications.4 

 

4 HTFs are selected for particular applications based on their viscosities within 

operating temperature ranges and/or their boiling points. For example, for liquid phase 

applications (e.g., some cooling applications) HTFs are selected that have boiling points 

above the operating temperature range and low viscosities at the lower operating 

temperatures. As temperature decreases, viscosity increases. Low viscosities are more 

desirable because they will provide good heat transfer and will be easily pumped. For 

higher temperature applications, such as vapor phase soldering, HTFs with low vapor 

pressures—at room temperature (high boiling points) are generally selected. (See, e.g., 

“Fluorochemicals in Heat Transfer Applications: Frequently Asked Questions,” 3M, 

available in the docket for this rulemaking.)
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(Vapor pressure is an indicator of the rapidity with which 

a substance evaporates.) For example, an HTF with a vapor 

pressure of about 0.2 mm Hg at 25 degrees C might be used 

at a temperature of 140 degrees C for heat transfer 

applications, where it may have a vapor pressure of over 80 

mm Hg. Similarly, an HTF with a vapor pressure of about 

0.1 mm Hg at 25 degrees C might be used for vapor phase 

soldering at a temperature above its boiling point. Under 

these conditions, all of the material is in the vapor 

phase. Supporting technical information is available in 

the docket (EPA-HQ-OAR-2011-0512). 

EPA understands that at any particular temperature, an 

HTF with a low vapor pressure at 25 degrees C is likely to 

evaporate more slowly than an HTF with a higher vapor 

pressure at 25 degrees C. Nevertheless, if the temperature 

is high, evaporation will occur. 

EPA views data on emissions of HTFs as an important 

component in improving future efforts to characterize GHG 

emissions from the electronics manufacturing sector. EPA 

believes that the changes being proposed today will ensure 

that all fluorinated HTFs used in electronics manufacturing 

are appropriately monitored and reported under subpart I. 

 
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In this action, EPA is proposing that the definition 

of HTFs in subpart I be revised to read as follows: 

“Fluorinated heat transfer fluids means fluorinated GHGs 

used for temperature control, device testing, cleaning 

substrate surfaces and other parts, and soldering in 

certain types of electronics manufacturing production 

processes. For fluorinated heat transfer fluids under this 

subpart I, the lower vapor pressure limit of 1 mm of Hg in 

absolute at 25 degrees C in the definition of “fluorinated 

greenhouse gas” in 40 CFR 98.6 shall not apply. 

Fluorinated heat transfer fluids used in the electronics 

manufacturing sector include, but are not limited to, 

perfluoropolyethers, perfluoroalkanes, perfluoroethers, 

tertiary perfluoroamines, and perfluorocyclic ethers.” 

The effect of making the vapor pressure cut-off 

portion of the definition of fluorinated GHGs inapplicable 

to fluorinated HTFs under subpart I would be to subject 

emissions from fluorinated HTFs that have vapor pressures 

less than one mm of Hg absolute at 25 degrees C to the 

reporting requirements. Consequently, EPA would receive 

valuable emissions information on the full range of 

volatile fluorinated HTFs used in electronics 

manufacturing. 
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The purpose of the Mandatory Reporting Rule is to 

collect accurate facility-specific GHG emissions data for 

use in developing future GHG policies and programs. For 

this reason, EPA believes that the definition of HTFs being 

proposed today is prudent and appropriate because it will 

provide EPA with comprehensive information on emissions of 

fluorinated HTFs. Considering the simple mass balance 

methodology required for reporting emissions of fluorinated 

HTFs in subpart I, the potential value of this information 

justifies a comprehensive definition. If some HTFs (or 

HTFs in some currently included applications) are found to 

have very low emission rates, this information will itself 

be valuable for informing future GHG policies. However, 

given that HTFs are capable of entering the atmosphere at 

the temperatures where they are used, any conclusion that 

the emissions of some HTFs are low must be supported by 

actual measurements. 

EPA considered including a modified vapor pressure 

limit in the proposed definition of HTF. One approach we 

considered was to adopt a vapor pressure limit associated 

with a particular temperature higher than 25 degrees C. 

The goal of such a limit would be to require reporting of 

those HTFs that may readily enter the vapor phase in their 

current and potential future applications. However, we 
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believe that today’s proposed, application-based definition 

achieves this goal more simply and effectively than would a 

definition that includes a vapor pressure limit associated 

with a particular temperature higher than 25 degrees C. 

First, given the breadth of conditions under which HTFs are 

used currently in the electronics industry, as well as the 

rapidity of technological change within this industry, it 

would be difficult to specify an appropriate upper-limit

temperature to which to link the vapor pressure. Some 

applications occur at very high temperatures, and those 

temperatures could conceivably rise in the future. Second, 

such a limit, if not linked to particular HTF applications,

could include fluorinated chemicals that are used 

exclusively in low-temperature applications where they 

would not quickly enter the atmosphere if released, such as 

certain lubricants or oils. Third, the major application 

of HTFs is for process cooling. In this application, as 

discussed above, HTFs with lower vapor pressures at a 

particular temperature are likely to be used at higher 

temperatures. This is a systematic relationship that 

almost guarantees that the HTF will be capable of 

volatilizing at the temperature of use. Similar 

relationships are likely to hold in other applications 

where viscosity or boiling point is a concern, e.g., 
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thermal shock testing. Finally, other applications, such 

as substrate cleaning or vapor phase soldering, occur when 

the material is in the vapor phase. Any upper-bound 

temperature linked to a vapor pressure would have to fall

above the temperatures where vapor phase soldering occurs. 

The proposed definition achieves the same goal much more 

directly by including the applications “soldering,” 

“temperature control,” “device testing,” and “cleaning 

substrate surfaces.”

Another approach we considered was to require 

reporting only of HTFs that achieve a particular vapor 

pressure (e.g., 1 mm Hg absolute) at their maximum 

temperature of use, where the maximum temperature of use 

could vary from facility to facility or even application to 

application within a facility. This approach would 

explicitly focus monitoring and reporting on those HTFs and 

applications where volatilization could occur. However, 

because the coverage of particular chemicals would depend 

on their maximum temperature of use within a particular 

facility or application, this approach would be 

significantly more difficult to implement and enforce than 

the proposed, application-based definition. Facilities 

would be required to investigate the temperatures at which 

each HTF is used and to distinguish between low- and high-
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temperature applications of the same HTF in developing 

emissions estimates. The proposed approach, in contrast, 

would clearly define the applicability of the rule and 

would enable facilities (and EPA) to rely on facility-wide 

mass-balances to estimate emissions of particular 

chemicals. 

EPA does not intend for its definition of HTFs to 

include greases or lubricants such as those used in vacuum 

pump applications because such applications do not 

typically occur at temperatures at which the lubricants 

would volatilize. EPA does not believe that the current or 

proposed definitions include such lubricants. However, EPA 

requests comment on whether the definition should be 

amended to explicitly exclude lubrication or other 

applications. To address situations in which a particular 

chemical may be used in both HTF and non-HTF applications, 

EPA also requests comment on whether we should give 

reporters flexibility to report under 40 CFR 98.93(h) 

either a chemical’s emissions from all applications or its 

emissions from only the applications included in the HTF 

definition. This would give facilities the option to avoid 

maintaining a separate supply of the chemical for purposes 

of tracking HTF emissions, as would otherwise be required 

for the mass-balance calculation. Emissions from the non-
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HTF applications would presumably make up a small fraction 

of the total.

The narrow exception to the vapor pressure cutoff 

would only apply to fluorinated HTFs used in the 

electronics manufacturing industry; EPA continues to 

believe that the vapor pressure cutoff is appropriate to 

maintain in the definition of fluorinated GHG in 40 CFR 82 

subpart A (e.g., for purposes of the industrial gas supply 

provisions at subpart OO). EPA is not aware of other 

fluorocarbon applications in which the vapor pressure of 

the fluorocarbon falls below 1 millimeter of Hg at 25 

degrees C but typically rises significantly above it at the 

temperature of use. 

In addition, EPA is also proposing four other minor 

amendments to the regulatory text related to fluorinated 

HTFs. First, in the definition of HTF (40 CFR 98.98), EPA 

is proposing to add the phrase “but not limited to” before 

listing examples of fluorinated HTFs. Electronics 

manufacturing is an innovative and quickly evolving 

industry in which new chemicals are frequently adopted. 

EPA is proposing this change to ensure that potential 

future alternatives are covered. Second, also in the 

definition of HTFs (40 CFR 98.98), EPA is proposing to 

delete the last sentence (“Electronics manufacturers may 
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also use these same fluorinated chemicals to clean 

substrate surfaces or other parts”) and move the concept of 

cleaning substrates surfaces or other parts to the first 

sentence. EPA is proposing this change to improve 

readability of the definition. Third, EPA is proposing 

minor revisions throughout the subpart I regulatory text to 

clarify the use of the terms fluorinated GHGs and 

fluorinated HTFs (e.g., referring to fluorinated HTFs 

rather than fluorinated GHGs used as HTFs). For example, 

in instances where EPA used the term “fluorinated GHG used 

as heat transfer fluids,” EPA is proposing to use 

“fluorinated heat transfer fluids.” Where EPA refers to 

HTFs, EPA does not intend the full definition of 

fluorinated GHGs (as defined in subpart A) to apply. And 

last, in 40 CFR 98.92(a)(5), under GHGs to report, EPA is 

proposing to revise the clause “fluorinated GHG emitted 

from heat transfer use” to read “emissions of fluorinated 

heat transfer fluids.” EPA is proposing this change to 

clarify that emissions of fluorinated HTFs, not just 

fluorinated GHGs, are required to be reported under subpart 

I. In addition, EPA is proposing the change to clarify the 

Agency’s intention that emissions from HTFs can occur 

through all phases of the equipment’s lifetime, including 

installation, use, servicing, and disposal. Under subpart 
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I, all of those emissions of HTFs should be calculated and 

reported. 

EPA does not anticipate an increase in burden 

resulting from these proposed changes because this action 

is clarifying the intent of the requirements finalized in 

subpart I. In finalizing the reporting requirements for 

fluorinated HTFs, EPA did not intend to exclude 

fluorocarbons that can enter the atmosphere under the 

conditions in which HTFs are used in the electronics 

manufacturing industry. EPA’s burden estimates were based 

on reporting of all fluorinated HTFs; therefore, the 

clarification of intent does not impose additional burden 

on reporters.

EPA requests comment on the proposed amendments to the 

HTF provisions of subpart I. In particular, EPA requests 

comment whether the proposed definition effectively 

captures fluorinated HTFs used in electronics manufacturing 

(i.e., whether any type of fluorinated HTFs other than 

those included in the proposed definition are currently 

being used or are anticipated to be used in the future for 

electronics manufacturing). EPA also requests comment on 

whether any other conforming changes need to be made. 

EPA plans to address the comments on these proposed 

amendments and publish the final amendments to subpart I 
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before the end of 2011. Therefore, EPA requests comment on 

whether to require electronics manufacturing facilities to 

estimate and report 2011 emissions in 2012 of the HTFs that 

would be newly included in the scope of subpart I if 

today’s proposed rule were finalized. Specifically, EPA 

requests comment on whether information collected as part 

of routine business practices, such as records of HTF 

stocks, disbursements, and acquisitions, could be used to 

estimate 2011 emissions to be reported in 2012. If it is 

not feasible to estimate HTF emissions in 2011 for 

substances that are currently excluded from reporting using 

information collected as part of routine business 

practices, EPA requests detailed information illustrating 

why it is not feasible. 

C. Subpart W – Petroleum and Natural Gas Systems 

EPA is proposing several technical clarifications and 

amendments to subpart W to address issues raised during the 

first year of promulgation of the rule in response to 

petitions submitted to EPA for reconsideration, as well as 

clarifications to specified provisions in the rule to 

ensure consistency with subpart W, and across all subparts, 

where appropriate. In addition, several technical 

corrections are proposed to clarify provisions that were 

either erroneous or unclear to reporters. 
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The following section describes EPA’s proposed 

amendments. We first discuss the proposed amendments 

related to field-level reporting in the onshore petroleum

and natural gas production section, since this proposed 

amendment affects multiple emissions sources (well 

completions, well workovers, well venting for liquids 

unloading, and onshore storage tanks) and also affects many 

sections of the rule (e.g., calculation, monitoring and 

quality assurance/quality control (QA/QC), and the data 

reporting requirements). Following the discussion for 

onshore production, we discuss the proposed amendments to 

the Definition of the Source Category (40 CFR 98.230), 

GHG’s to Report (40 CFR 98.232), Calculating GHG Emissions 

(40 CFR 98.233), Monitoring and QA/QC Requirements (40 CFR 

98.234), Data Reporting Requirements (40 CFR 98.236) and 

Records to be Retained (40 CFR 98.237) under subpart W.

Sub-basin Category for Onshore Petroleum and Natural 

Gas Production. EPA has received several requests to 

reconsider the use of a field-level measurement plan for 

emission sources (mainly monitoring of GHGs from well 

unloading, well completions, and well workovers) that 

require one measurement per field as designated by the U.S. 

Energy Information Administration (EIA) Field Code Master 

List (FCML). Onshore petroleum and natural gas production 
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reporters have expressed concerns over the use of this 

field designation and proposed that a sub-basin category be 

assigned instead of a field designation to take 

measurements. Specifically, petitioners indicated that EPA 

has not clarified how reporting entities are supposed to 

map wells to a particular field. They contested that there 

are no coordinates provided in the EIA FCML 2008. They 

also suggested there is no formal way to designate 

appropriate field names and the rule does not have a 

mechanism to deal with wells that are not in a recognized 

field in the EIA Master List. Mapping wells to the proper 

field is central to compliance with the rule, they assert, 

because the rule requires aggregation of information by 

field for the different emissions sources. To address 

these concerns, industry petitioned EPA to replace the 

field-level approach with a “sub-basin category” approach. 

In general, EPA continues to believe that the fieldlevel designation is workable, although perhaps not the 

only means of obtaining representative emissions estimates. 

EPA has determined that the EIA field codes are developed 

using field names that operators provide and agree on with 

States, which is finally provided by the States to the EIA. 

Therefore, EPA believes that operators can determine the 

EIA field they are in using the EIA field codes. EPA also 
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agrees that the 2010 final rule did not state a clear 

mechanism to address wells in fields that were not included 

in the EIA FCML. However, EPA has determined that this is 

not an acute problem. EPA has analyzed the EIA FCML for 

several years and found that the changes in the database 

from year to year are not significant. For example, there 

were only 30 changes in field definitions between 2007 and 

2008 of the total 64,454 fields in the database. Similar 

numbers result from comparing 2006 with 2007 (170 changes 

in field definition of a total 63,873 fields in the 

database) and comparing 2006 with 2005 (44 changes in field 

definition of a total 63,356 fields in the database). The 

changes include both the revision of some field names as 

well as new additions.

In this action we are proposing an alternative 

approach to replace “field-level” with “sub-basin 

categories.” EPA considered, but is not proposing at this 

time modifications to the current field level reporting 

method that would address the outstanding concerns raised 

by industry. Specifically, EPA considered an amendment 

that would allow reporters to use a temporary field name 

when submitting reports to EPA in instances where a well 

does not fall within a designated EIA field code. This 

alternative approach would include a provision for 
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reporters to report a preliminary field name where a field 

has not been formally designated by the State and as such 

may not yet be included in the EIA FCML. These preliminary 

fields entered by the reporter would be annotated in the 

final report to EPA and would be flagged in the data system 

for further follow up to determine the final field name 

designated by the State. Because States operate on 

different schedules for which final determinations are made 

on field designation requests, reporters would be required 

to certify with official documentation submitted to EPA 

upon each reporting period on the status of their field 

designation request. Under this alternate approach, for 

field designations that are made prior to the next 

reporting date, reporters should confirm the field 

designation with official documentation during the next 

submission of their emission report to EPA. This proposed 

method would address concerns raised by industry about 

fields not yet included in the EIA FCML. 

In addition, EPA is considering but did not propose a 

provision that would delineate how reporters would 

determine appropriate field names for wells for which the 

designated field is unknown due to unclear location or 

coordinates of the well. Under such a provision, reporters 

would determine the EIA FCML field for a given well by 
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determining the well coordinates and follow the procedures 

outlined in the 2008 EIA FCML or most approximate year’s 

documentation that accompanies the EIA FCML field list 

which outlines the method for matching up well coordinates 

with field names. Although EPA is proposing an alternative 

means to calculate and report emissions based on a subbasin category, we are seeking comment on this approach to 

modify the current field-level calculation and reporting 

requirements for utilizing the EIA FCML for sampling. 

Although EPA maintains that the current field level 

calculation and reporting requirements are feasible and 

provide representative emissions estimates (with an 

amendment to clarify how to address non-designated fields), 

EPA is proposing an alternative sub-basin approach that we 

believe also achieves an appropriate level of 

representativeness. Please see Economic Impact Analysis 

Memorandum in Docket ID EPA-HQ-OAR-2001-0512. This 

proposed sub-basin category classification would provide 

similar quality data as the EIA FCML designation but 

believes will also address some of the questions and 

concerns regarding current implementation of the fieldlevel approach. 

The foundation of the proposed sub-basin approach is 

defining a sub-basin category through the use of a county 
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level designation and the distinction of the type of 

hydrocarbon formation. The various hydrocarbon formations 

can be grouped into four categories: conventional, coal bed 

methane, tight formations, and shale. 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). 

With this basic formulation of sub-basin category, EPA 

has determined that it is necessary to provide a second 

level of classification to get a representative emissions 

profile of emissions sources. For example, the emissions 

from well completions or hydraulic fracturing can vary by 

several multiples within the same producing formation 

because of different fracture zones and fracture extent. 

Similarly, well liquids unloading emissions can vary widely 

because of different well dimensions and liquid 

accumulation. EPA further notes that the activity of 

emissions sources are highly concentrated within certain 

counties and formation types. For example, of the 3,143 
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counties in the United States, there are only 54 counties 

that had any form of well completion in year 2010. In such 

a case, where 25,000 well completions are concentrated in 

54 counties, a single measurement from a sub-basin 

category, may not be sufficiently representative. 

Therefore, to obtain a sufficient number of data 

points to be able to characterize the variability in the 

emissions profile, EPA is proposing a measurement plan that 

uses some operational criteria to generate more than one 

sample per sub-basin category for specific emissions 

sources. Specifically, EPA is proposing the use of 

pressure ranges for liquids unloading measurements, because 

the volume of gas released during an unloading is related 

to the wellhead pressure. For example, reporters would 

take one measurement per pressure range within a sub-basin 

category. An example of pressure ranges is 0-25 psig, >25-

60 psig, >60-110 psig, >110-200 psig, and 200 psig and 

above. These pressure ranges were developed based on an 

analysis that reviewed well data from the HPDI© database 

which determined the optimal pressure ranges that also 

minimize variability of a single data point as a 

representation of that pressure range. For more 

information on this analysis, please see the Technical 
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Support Document for this proposed rulemaking in the 

docket. 

The rationale for applying these pressure ranges is 

that wells generally have more liquids unloading problems 

when they are flowing at low pressures and lower 

velocities. Hence, it is reasonable to provide more ranges 

in the lower pressure spectrum. EPA expects to see few 

wells over 200 psig that necessitate liquids unloading to 

atmospheric pressure. For well completions and workovers, 

EPA is proposing to divide the population of wells between 

vertical and horizontal wells, as defined in proposed 

amended 40 CFR 98.238, and then using a graduated number of 

measurements per number of wells completed or worked over 

in these categories. For example, one measurement per 25 

wells with hydraulic fracture, two measurements per 50 

wells with hydraulic fracture, three measurements per 100 

wells with hydraulic fracture, and four measurements per 

200 or more wells with hydraulic fracture. EPA understands 

that there are many operational factors that impact the 

magnitude of emissions from well hydraulic fracture 

completions and workovers and therefore is proposing more 

than one measurement where there is a larger number of 

wells in the sub-basin category. 
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Source Category Definitions. In general, we are 

proposing several amendments to the source category 

definitions to clarify the boundaries between the different 

industry segments. The proposed amendments below seek 

merely to clarify coverage in the rule and were not 

intended to change who is required to report within and 

across the industry segments.

Onshore Petroleum and Natural Gas Production. We are 

proposing 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). EPA received feedback from reporters on the 

finalized definition for the onshore production industry 

segment on November 30, 2010 (see 75 FR 74489) requesting 

clarification on the term “associated with a well-pad.” 

Specifically, reporters requested clarification on what the 

term “associated with a well-pad” meant in the context of 

the boundaries of the onshore production industry segment. 

Reporters stated that there is unclear demarcation between 

equipment that are considered part of the onshore 

production industry segment and equipment that are 

considered part of the onshore natural gas processing 

industry segment. 
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To address concerns on the meaning of ”associated with 

a well-pad”, EPA is first proposing to revise the term 

itself to state that the onshore production industry 

segment includes that equipment that is “on a single wellpad or associated with a single well-pad.” EPA has 

determined that equipment located on a single well-pad is 

considered part of the onshore production industry segment 

irrespective of the hydrocarbon streams that it is 

handling. For example, a separator located on a well-pad

that handles hydrocarbon streams from multiple well-pads 

would be considered to be part of the onshore production 

industry segment, i.e. equipment that is not located on a 

well-pad would be considered to be associated with a wellpad. Also, hydrocarbon streams from multiple wellheads 

located on a single well-pad is considered to be a single 

hydrocarbon stream from that well-pad. 

In addition, EPA is proposing to clarify in the 

onshore production industry segment definition that 

dehydrators that are on a single well-pad or associated 

with a single well-pad are included as types of equipment 

that is considered part of this segment. Following 

promulgation of subpart W in November 2010, EPA received 

several questions from the reporting community requesting 

clarification on whether or not dehydrators associated with 
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a single well-pad would be a part of the industry segment. 

It was EPA’s intent that these dehydrators that are on a 

well-pad or associated with a single well-pad be considered 

part of the onshore production industry segment. EPA also 

received similar requests for clarification on whether or 

not storage vessels, not necessarily the entire storage 

facility, were also considered part of the onshore 

production industry segment. To address these concerns, 

EPA is proposing to clarify in the definition that both 

dehydrators and storage vessels are included in the 

equipment list that are considered part of the onshore 

production industry segment. Finally, EPA proposes to 

clarify that Enhanced Oil Recovery (EOR) that use either CO2

or natural gas are a part of the source category. The 

equipment located on a well-pad is part of the onshore 

production industry segment irrespective of the hydrocarbon 

streams located on a well-pad.

Onshore Natural Gas Processing. EPA is proposing 

several clarifications to the onshore natural gas 

processing industry segment definition in 40 CFR 

98.230(a)(3). By letter dated January 31, 2011, the Gas 

Processors Association (GPA), CEC/AXPC, and API, all 

expressed concerns with overlap between the onshore 

production, onshore natural gas processing, and onshore 
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natural gas transmission industry segments. API stated 

that “The definitions of the industry categories ‘onshore 

oil and gas production’ and ‘natural gas processing’ do not 

provide a clear line between onshore oil and gas 

production, gas gathering/collection and booster stations, 

and natural gas processing facilities.” The letter stated 

“API is particularly concerned that the final rule could be 

interpreted to include gathering and boosting stations in 

the processing sector, despite EPA’s stated intent to 

exclude gathering and boosting stations from coverage at 

this time.” Industry raised concerns that boosting 

stations would be covered under the finalized natural gas 

processing industry segment definition because they 

typically have processes that require removal of liquids 

for operation of specific equipment that boost gas 

pressure. For example, scrubbers are used upstream of 

compressors to take out any liquids for optimal operation 

of the compression equipment. However, the presence of 

scrubbers in and of itself should not result in the 

facility being defined as a processing facility. 

To address the concerns with boundaries between 

industry segments, we are proposing several revisions to 

clarify our intent. First we are proposing to strike the 

term “and recovers” from the first sentence in order to 
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more clearly characterize the unique activities performed 

at the processing plant. Processing plants extract heavy 

hydrocarbons and non hydrocarbon gases from the gaseous 

phase of an inlet feed to the plant. By inclusion of the 

term “recovers” in the industry segment definition, the 

natural gas processing plant definition may have been 

incorrectly interpreted to bring in other types of 

processes that were not intended to be covered. 

We are also proposing to clarify that this industry 

segment includes one or a combination of the following 

three processes: separation of natural gas liquids (NGLs) 

from natural gas, separation of non-methane gases from 

produced natural gas, or separation of NGLs into one or 

more component mixtures. This proposed revision would 

clarify that the natural gas processing industry segment 

differs from what typically happens at boosting stations in 

that natural gas processing plants typically perform one or 

more of these processes, whereas boosting stations do not. 

We are also proposing a clarification on what 

separation means by stating 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.
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We are proposing to strike the term “this industry 

segment does not include reporting of emissions from 

gathering lines and boosting stations” because the edits 

proposed above clarify what “onshore natural gas 

processing” means and therefore it is unnecessary to 

discuss that which is excluded. Further, if we had decided 

to maintain the “gathering lines and boosting” stations in 

the rule, EPA would have to propose and finalize a 

definition of the term “gathering line and boosting” 

station, which EPA has previously noted we intend to 

consider in a future rulemaking (75 FR 74468). 

Finally we are proposing to strike the term “facility” 

and replace it with the term “plant” as “facility” has a 

specific definition in 40 CFR 98.6 that was not intended 

here. A natural gas processing plant may be located at a 

facility that also contains other source categories covered 

by 40 CFR Part 98. 

Onshore Natural Gas Transmission Compression. EPA is 

proposing several clarifications to the onshore natural gas 

transmission compression industry segment definition in 40 

CFR 98.230(a)(4). As noted earlier, by letter dated 

January 31, 2011, API, CEC/AXPC, and GPA raised their 

concerns that the boundaries between the onshore 

production, onshore natural gas processing, and onshore 
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natural gas transmission compression industry segment 

boundaries were unclear based on the provisions in the 

November 30, 2010 final rule. 

First, we are proposing to strike the term “at 

elevated pressure” because it was not clear what “elevated 

pressure” meant. For example, elevated with respect to 

what baseline? Based on questions received on the 

definition for transmission compressor stations, we have 

proposed to clearly define transmission pipelines using a 

widely accepted designation for what is a transmission 

pipeline, avoiding the need to retain the language of 

“elevated pressure”. We are proposing to define in 40 CFR 

98.238 that a transmission pipeline means 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 the Natural Gas Act. 

Next, we are proposing to clarify the end points 

between which a natural gas transmission compression 

facility would move natural gas. Specifically, we are 

proposing to explicitly state 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 
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addition, we are proposing to explicitly state that natural 

gas transmission compression facilities may move natural 

gas into not only distribution pipelines, but also into 

liquefied natural gas storage or into underground storage. 

We are also proposing to strike the term “natural gas 

dehydration” from the industry segment definition because 

this term does not represent a unique characteristic to 

facilities with natural gas transmission compression. We 

believe that deleting this term from the definition of the 

natural gas transmission compression industry segment, will 

result in this industry segment definition being more 

representative and accurate. Finally, as described above 

under onshore natural gas processing, we are proposing to 

strike the reference to “gathering lines and boosting

stations” and “facility.” 

Natural Gas Distribution. EPA is proposing several 

amendments to the natural gas distribution industry segment 

definition to further clarify its intent. First, we are 

proposing in 40 CFR 98.230(a)(8) to eliminate the term 

“city gate station” and add the term “meter-regulating 

station”. The term “city gate”, was used in the 2010 final 

rule because it was believed to be widely used throughout 

the natural gas distribution industry. However, since 

publication, we have learned that the term can have several 
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meanings and the interpretation of what is a “city gate” 

station may vary among potential reporters. By letter 

dated March 2, 2011 from the American Gas Association, it 

was stated that “[t]he term `city gate ́ is widely used in

the industry, but unfortunately it means different things 

to different companies. It can mean the place where an LDC 

takes custody of natural gas from the upstream supplier 

(either directly from a producer or from an interstate 

pipeline company). The term `city gate ́ is also used by 

some to refer to the place where natural gas is conveyed 

into a lower pressure distribution system for a town or 

city – either directly from the upstream supplier (producer 

or interstate pipeline) or from the LDC’s own intrastate 

high pressure transmission pipelines. Some companies do 

not use the term `city gate ́ to refer to the situation 

where natural gas goes from the company’s own transmission 

pipes to one of its distribution systems. Instead, these 

companies may use other terms such as `district regulator ́ 

or `metering and regulating stations ́, or `M&R ́ equipment, 

and these terms also can have varying meanings.” 

Further, subpart A provides a definition for “city 

gate”, which was intended to apply to subpart NN and is 

based on financial custody transfer. Whereas the 

connotation of the term city gate as defined in subpart A 
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works sufficiently for subpart NN, it has created confusion 

for subpart W and does not clearly identify the types of 

facilities EPA intended to cover. The amendments that EPA 

is proposing are designed to more clearly portray EPA’s 

intent using language readily understandable to industry. 

First, we are proposing to strike the parenthetical 

term “(not interstate transmission pipelines or intrastate 

transmission pipelines).” The parenthetical was deemed 

unnecessary because EPA is proposing to add 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). Next, we are proposing to replace 

the term “city gate” with “meter-regulating” station. 

Because of the wide range of views in industry on the 

meaning of the term “city gate” EPA is proposing to remove 

the term “city gate” from subpart W and replace it with a 

term that reflects the types of activities occurring at the 

stations of interest. Specifically, we are proposing to 

add a definition for the term “meter-regulating station” in 

40 CFR 98.238 to mean, “An 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 
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taps”. With this change, EPA intends to clarify a key 

concept in the natural gas distribution segment definition, 

but does not intend to change who is actually covered by 

the rule’s requirements. 

EPA is proposing to strike the terms “excluding 

customer meters” and “physically deliver natural gas to end 

users” because the proposed definition for “meterregulator” stations already addresses this exclusion. 

Finally, we are proposing to clarify in the industry 

segment definition that we are only seeking for LDCs that 

are within a single state, consistent with the definition 

for LDCs in subpart NN. 

Greenhouse Gases to Report. We are proposing several 

amendments to the subpart W provisions on the greenhouse 

gases that must be reported. 

We are proposing to amend 40 CFR 98.232(c) to clarify 

that the equipment listed in 98.232(c)(1) thru (22) are for 

equipment on a single well-pad or associated with a single 

well-pad in order to make the language consistent with the 

proposed changes to the onshore production industry segment 

definition in 40 CFR 98.230(a)(2) described above. 

We are proposing to amend 40 CFR 98.232(i) by 

replacing the term “custody transfer city gate station” 

with the term “transmission-distribution transfer station”
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and replacing the term “non-custody transfer station” with 

the term “metering-regulating station.” EPA is proposing 

this amendment to clarify that the sources covered be 

consistent with the proposed terms for the natural gas 

distribution industry segment in 40 CFR 98.230(a)(8). We 

are also proposing to amend the source types by removing 

the text “Customer meters are excluded.” The exclusion is 

already covered in both the industry segment definition and 

in the definition of “metering-regulating station” provided 

in 40 CFR 98.238 and does not provide added clarity in this 

context. Next, we are proposing to strike 40 CFR 98.232(j) 

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. In addition 

to the proposal to strike 40 CFR 98.232(j), we are 

proposing to revise the introductory sentences to 40 CFR 

98.232(e), (f), (g), (h) and (i) to clarify that N2O 

emissions, which are the primary GHG emission from flaring, 

are also required to be reported under these industry 

segments. This proposed amendment also clarifies that 

flare emissions must only be calculated where “flare 

stacks” are either specifically identified in a specific 
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industry segment (e.g., onshore natural gas processing) or 

where an emissions source that is covered in an industry 

segment is routed to a flare (e.g., centrifugal compressors 

under onshore natural gas transmission). 

Finally, we are proposing to further clarify in 40 CFR 

98.232(k) that the onshore production and natural gas 

distribution industry segments are to report their 

combustion emissions under 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 

proposing several clarifications, corrections, and 

amendments throughout 40 CFR 98.233. 

Natural Gas Pneumatic Device Venting. 

EPA is proposing to revise Equation W-1 in 40 CFR 

98.233(a) by adding 40 CFR 98.233(a)(3) that allows the 

type of pneumatic devices to be determined using 

engineering estimation based on best available information. 

The proposed amendment for pneumatic devices was in 

response to questions received about how to determine 

whether a pneumatic device is high bleed or low bleed and 

the unanticipated burden for industry if they would have to 

measure the bleed rate of all pneumatic devices in order to 

determine how to characterize each pneumatic device. 
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EPA is also proposing to amend Equation W-1, to 

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

hours the devices were operational. Previously, this 

equation assumed that all natural gas pneumatic devices 

were operational all year, which would overestimate the 

emissions where the pneumatic devices operate less than a 

full year. Overall, we are proposing these amendments to 

Equation W-1 to more accurately reflect operating 

conditions for natural gas pneumatic device venting. 

Furthermore, EPA is clarifying in the definition for “GHGi” 

that compositions in 40 CFR 98.233(u) may be used for the 

onshore petroleum and natural gas production, onshore 

natural gas transmission compression, and underground 

natural gas storage industry segments. 

In addition, with respect to the pneumatic device 

venting category, we are proposing in 40 CFR 

98.236(c)(1)(iv) to clarify that emissions should be 

reported collectively for all high bleed pneumatic devices, 

then separately for all intermittent bleed pneumatic 

devices, and separately for all low bleed pneumatic 

devices. The 2010 final rule stated merely “report 

emissions collectively”. The proposed amendment is 

consistent with how data are collected and emissions 

calculated. 
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Natural Gas Driven Pneumatic Pump Venting. 

We are proposing to amend Equation W-2 in 40 CFR 

98.233(c), which is used for calculating GHG emissions from 

natural gas pneumatic pump venting, to include a parameter 

“T” that estimates the total amount of hours the pumps were 

operational. Previously, this equation assumed that all 

natural gas pneumatic pumps were operational all year, 

which would overestimate the emissions where the pneumatic 

devices operate less than a full year. We are proposing 

this amendment to Equation W-2 to more accurately reflect 

operating conditions for natural gas pneumatic pump 

venting. 

Acid Gas Removal Vents. We are proposing to amend the 

calculation for estimating CO2 emissions from acid gas 

removal vents in Equation W-4 in 40 CFR 98.233(d). EPA 

notes that the equation in the 2010 final rule is an 

approximation and works well when the amount of CO2 in gas 

is relatively low, such as 1 percent. However, the error 

rate in the estimate increases significantly as the amount 

of CO2 in gas increases. Therefore, EPA is proposing a new 

equation, which uses the exact same input parameters and 

thus will not result in any additional burden to reporters, 

but will improve the quality of the information submitted 

to EPA. 
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We are also proposing to amend 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 the subpart C: Stationary 

Combustion Tier 4 calculation requirement for Acid Gas 

Removal vents and to make the requirements consistent in 

subpart W where use of CEMS is required.

In 40 CFR 98.236(c)(3) we are proposing to clarify 

that reporting of CO2 content should reflect the annual 

average of the measurements undertaken in 40 CFR 98.233(d). 

The 2010 final rule was not clear on whether or not to 

aggregate the measurements, and if so, how. 

Dehydrator Vents. EPA is proposing several amendments 

to the provisions in 40 CFR 98.233(e) for calculating GHGs 

from dehydrator vents. First, we are proposing to clarify 

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) introductory language. The 

final rule explicitly stated that natural gas was the gas 

considered to be the stripping gas. We are proposing this 

amendment to more accurately reflect operating conditions 
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for glycol dehydrators in which gases other than natural 

gas are used as stripping gases. 

We are also proposing to amend 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). In addition, we are 

proposing to clarify that only for dehydrators that use 

desiccant should GHG volumetric and mass emissions be 

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

We are proposing this amendment to account for calculation 

methodology 1 and 2, 40 CFR 98.233(e)(1) – (e)(3), that

calculates total GHGi volumetric emissions in standard cubic 

feet and will only need conversion to GHG mass emissions 

using 40 CFR 98.233(v). 

With respect to the data reporting requirements, we 

are proposing to clarify the requirement to report vented 

and flared emissions individually. In the 2010 final rule, 

EPA intended that vented emissions be reported as one 

value, and flared emissions as a separate value. However, 

because these were entered in the same sub-paragraph, 40 

CFR 98.236(c)(4)(i)(J), there was some ambiguity as to the 

aggregation for reporting. Therefore, EPA is proposing to 

create separate reporting requirements for vented and 
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flared emissions. A similar amendment is proposed for 40 

CFR 98.236(c)(4)(ii)(D).

Also for dehydrators, EPA is proposing to clarify that 

in specifying whether any vent gas controls have been used, 

the owners or operators should report which vent gas 

controls were used. 

Well Venting for Liquids Unloadings. First, we are 

proposing to revise 40 CFR 98.233(f) methodology 1, 

methodology 2, and methodology 3 such that sampling would 

be done in a sub-basin category as opposed to the field 

level as described earlier in Section II.C. of this 

preamble (Sub-basin Category for Onshore Petroleum and 

Natural Gas Production). 

In the technical corrections rule, EPA proposed 

several technical corrections to the provisions in 40 CFR 

98.233(f) including corrections to Equation W-8, W-9, and 

their respective definitions. In today’s action, we are 

proposing additional revisions to Equations W-8 and W-9 and 

their respective definitions. Because both proposed 

actions affect the same paragraph of the rule, for clarity 

the part 98 amendatory language at the end of this preamble 

contain the full set of revisions from both proposed 

actions. The changes proposed today are explained below in 

this preamble. 
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First we are proposing to revise Equation W-8 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 

proposed revision from actual conditions to standard 

conditions was made to be more uniform in approach to 

calculate emissions. The parameters in Equation W-8 have 

been made applicable to each venting instance, q, and for 

each well, p, in a pressure grouping and sub-basin 

category. These changes are notational amendments that 

correct the summation operation. Next, we are proposing to 

amend the definition for “SFR” which is the average sales 

flowrate to state that the average sales flow rate of gas 

is to be obtained at standard conditions, and also that 

Equation W-33 may be used to convert the sales flow rate 

from actual to standard conditions. In addition, the 

definition for parameter WDwp has been clarified to mean the 

distance between the lowest packer to the bottom of the 

well. We are also proposing to remove 40 CFR 

98.233(f)(2)(i) to remove redundancy with 40 CFR 

98.233(f)(4). As stated previously, we are proposing to 

amend Equation W-9 in the same manner as Equation W-8: by 

revising the definition for “Ea,n” to accurately state that 

the definition should result in standard conditions, thus 
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“Es,n”, and by revising the definition for SFR to state that 

the average sales flow rate is to be calculated at standard 

conditions using Equation W-33; and the parameters, where 

applicable, have been made applicable to each venting 

event, q for each well, p, in a pressure grouping and subbasin category to correct the summation. Finally, we are 

proposing to amend Equation W-8 and W-9 to account for a 

change in aggregation from field level to sub-basin 

category for reporting. 

For Calculation Method 1, where a representative 

measurement is taken from one well unloading and then 

applied to all other wells of a similar type, EPA is 

defining the categorization of “similar types” by five 

pressure ranges and three tubing diameters. The pressure 

ranges 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. The relevancy of these pressure ranges and 

tubing diameter ranges is that liquids unloading venting is 
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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. 

Finally, in the data reporting requirements in 40 CFR 

98.236(c)(5), we are proposing to make a harmonizing 

change, consistent with the amendments described above in 

(Sub-basin Category for Onshore Petroleum and Natural Gas 

Production), that reporting should be for each well tubing 

diameter grouping and pressure grouping within each subbasin category. 

Gas Well Venting During Completions and Workovers from 

Hydraulic Fracturing. We are proposing several amendments 

to 40 CFR 98.233(g) to account for the proposed change in 

aggregation from field level to sub-basin category for 

taking measurements. For example, we are replacing the 

term “field” with “sub-basin and well type combination” in 

the definitions and clarifying that the GHG emissions are 

determined for each sub-basin and well type combination. 

For further discussion on the proposed changes from field 

level calculations and reporting to sub-basin category, 

please refer to Section II.C of this preamble (Sub-basin 

Category for Onshore Petroleum and Natural Gas Production).
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We are also proposing to revise equation W-10 by 

including a provision to account for the time period in 

which we believe normal production of a well would be 

established. In this action, we are revising equation W-10 

by defining a parameter, FRM, which would represent the 

ratio of emissions (FRP) to the average 30 day production 

from the well immediately following hydraulic fracturing

(PRp). The emissions, FRp, which in the final rule as the 

average flow rate in cubic feet per hour converted to 

standard conditions, are calculated using W-11A and W-11B. 

FRM is calculated using the newly assigned Equation W-12. 

We believe that this proposed revision will more accurately 

represent the production flow from a well immediately 

following a well or completion using hydraulic fracturing 

and will more accurately represent when a completion or 

workover ends and when normal production begins. Finally, 

in Equation W-10, EPA is proposing to add 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. This amendment corrects the 

summation operator to make it mathematically accurate. 

 EPA also added Equation W-11C, which allows 

reporters to determine whether the well flow rate of gas 
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during venting to the atmosphere or a flare (i.e. FRWp), is 

sonic or sub-sonic flow. Thus, reporters can determine 

whether to use Equation W-11A, which is for sub-sonic flow, 

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

We are also proposing several minor edits to 40 CFR 

98.233(g)(3) and 40 CFR 98.233(g)(5) to clarify that all 

requirements in 40 CFR 98.233(g) apply to gas well venting 

during completions and workovers from hydraulic fracturing, 

consistent with the emission source name of “Gas well 

venting during completions and workovers from hydraulic 

fracturing”. 

In 40 CFR 98.233(g)(3) we are also proposing to delete 

the reference to how to calculate the volume of recovered 

completion or workover gas. The first sentence in that 

paragraph is already clear that company records may be 

used, therefore the second sentence does not provide any 

additional information and is duplicative.

We are proposing several harmonizing changes to the 

data reporting requirements for this emissions source. We 

are proposing to indicate that reporting is required for 

each “sub-basin category” and well type (horizontal or 

vertical). We are also proposing to clarify that reporting 

of reduced emissions completions for both well completions 

and workovers is required. Although this information is 
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required to be collected for both well completions and well 

workovers, EPA inadvertently omitted the reporting 

requirement for reduced emissions completions for well 

workovers. 

Also in 40 CFR 98.236, we are proposing to clarify 

that reporters are only required to count the number of 

workovers that flare or vent gas to the atmosphere. There 

is no reporting requirement for workovers that do not flare 

or vent gas.

Gas Well Venting During Completions and Workovers 

Without Hydraulic Fracturing. In this section we are 

proposing to strike the term “well workovers not involving 

hydraulic fracturing” from the introductory text in 

paragraph (h) because it was repetitive. 

Second we are proposing to replace the term “field” 

used in the definition for the parameter “Nwo” and “f” for 

the same reasons stated in Section II.C. of this preamble 

(Sub-basin Category for Onshore Petroleum and Natural Gas 

Production).

Finally, EPA is proposing to amend the summation 

operator in Equation W-13 to make it mathematically 

accurate. This includes making specific parameters in 

Equation W-13 applicable to each well completion, p.
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Blowdown Vent Stacks. In a previous action we proposed 

amendments to the introductory sentences to 40 CFR 

98.233(i). In this action, based on additional questions 

received during implementation of subpart W, we are 

proposing to further clarify the types of blowdowns that 

EPA intended to cover. First, we are proposing to delete 

“to atmosphere” because not every blowdown will result in 

the blowdown chamber being brought to atmospheric pressure. 

Operators often release only part of the gas in the 

blowdown chamber and maintain it at low pressure. It was 

always EPA’s intent to cover these types of “blowdowns” and 

thus we are proposing to delete “to atmosphere”. Further 

we are clarifying that we only intend to cover the types of 

blowdowns typically tracked by operators for planned 

maintenance or emergency shutdowns. EPA had earlier 

proposed to exclude emergency shutdowns in a previous 

action. However, EPA has since been informed that 

operators track emergency shutdowns already. Therefore, 

EPA is proposing to require emergency shutdowns to be 

reported. In addition, we did not intend to capture 

blowdowns that are not typically tracked by operators, such 

as pressure release valve releases designed to keep 

equipment under safe operating mode. 
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EPA has also considered other factors that could 

impact emissions from blowdowns, for example 

compressibility. We have considered accounting for gas 

compressibility but have not proposed this because we 

believe that the effort in adjusting for a compressibility 

factor outweighs the benefits in terms of increased 

accuracy. EPA seeks comments on why such an allowance 

should be provided and how to standardize this option so 

that those who choose to use it all do so in the same way.

Also in this action, we are proposing to revise the 

numbering of Equation W-14b and include an additional 

Equation, W-14b that will take into account that a chamber 

may not be blown down to atmospheric pressure, and will 

allow facilities the option of tracking blowdowns by each 

occurrence by blowdown volume. It has come to EPA’s 

attention that some facilities may log blowdowns at a 

facility by individual blowdown occurrence. To enable 

facilities to retain their current tracking system, we are 

proposing to add an option for calculating blowdown 

emissions by equipment type. This option for tracking 

blowdowns would not impact data quality. Harmonizing 

changes in 40 CFR 98.236(c)(7) are being proposed to 

account for these amendments. 
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Lastly, we are proposing to include a default 

composition for the natural gas transmission industry 

segment, and for the LNG storage and underground storage 

segments. EPA received feedback from industry that a 

default composition of 95 percent methane and 1 percent CO2

was a representative breakdown of the gas composition at 

these types of facilities while limiting burden and should 

be acceptable. EPA agrees that a default composition of 95 

percent methane and 1 percent CO2 is appropriate because the 

composition of natural gas is monitored by transmission 

compression companies and regulated by FERC. 

Onshore Production Storage Tanks. EPA is proposing to 

replace 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 

“sub-basin category” consistent with the proposed 

amendments described in Section II.C, (Sub-basin Category 

for Onshore Petroleum and Natural Gas Production), of this 

preamble. We are also proposing to clarify this level of 

reporting in the data reporting requirements in 40 CFR 

98.236(c)(8). 

Also in the data reporting requirements, we are 

proposing to clarify the reporting requirement in 40 CFR 

98.236(c)(8)(i), 98.236(c)(8)(ii) and 98.236(c)(8)(iii) 

that reporters must report vented, flared, and recovered 
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emissions individually for Calculation Methodology 1 and 2. 

This is consistent with the calculation requirements. 

Transmission Storage Tanks. We are proposing to 

revise 40 CFR 98.233(k) to include an additional provision 

such that reporters would now have the option of directly 

measuring the transmission storage tanks while bypassing an 

initial screening with the optical gas imaging instrument. 

EPA received feedback from industry that some owners and 

operators would prefer to simply measure the tank annually 

without having to be required to screen the tank vapors 

with a camera first. We agree that allowing facilities to 

directly measure the emissions, without first requiring 

leak detection, does not compromise data quality, but could 

enable facilities to meet the requirements of the rule with 

lower burden. Therefore, in this action, EPA is proposing 

to allow operators to either screen their tanks first by 

using the optical gas imaging instrument for 5 continuous

minutes and if a leak is detected, measure the leak 

according to the provisions in 40 CFR 98.234 consistent 

with the 2010 final rule, or measure the tank vent vapors 

for 5 minutes using either a flow meter, calibrated bag, or 

high volume sampler according to the provisions outlined in 

40 CFR 98.234. 
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Finally, with respect to the data reporting 

requirements in 40 CFR 98.236(c)(9), as described further 

above, we are proposing to clarify the separate reporting 

requirements for vented and flared emissions.

Well Testing Venting and Flaring. EPA is proposing 

In amendments to the data reporting requirements in 40 

CFR 98.236(c)(10). Specifically, we are proposing to add a 

reporting requirement for the emissions of the flaring gas 

collectively. This is consistent with other proposed 

clarifications to report flared emissions separately. 

EPA is considering, and has not proposed, using the 

production rate to estimate volume of emission from gas 

wells that produce dry gas. EPA is soliciting comments on 

this suggested provision for gas wells. 

EPA has received several requests to exclude the well 

testing venting and flaring emissions source from the rule. 

Industry has informed EPA that this source has very little, 

if any, emissions because the well testing is almost 

exclusively performed in a closed system using a “test 

separator”, which industry has stated would result in zero 

emissions. 

EPA has reviewed this request and in general, EPA 

continues to believe that well testing venting and flaring 

is a relevant source in the onshore petroleum and natural 
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gas production industry segment. In addition, EPA has 

determined that during well testing, some states allow 

companies to flare sour gas for a maximum of 72 or 144 

hours. EPA has concluded that this approach would result 

in emissions from this source that should be reported under 

this rule. If, however, for some reason reporters do not 

have any emissions from this source (for e.g., states do 

not allow venting or flaring from well testing), they would 

report zero emissions. 

Thus, EPA is retaining well testing venting and 

flaring in the rule. However, EPA is seeking comment on 

how to reduce or eliminate burden in cases where companies 

verify that zero emissions are associated with this 

potential source, such as when a closed loop system is 

employed.

Associated Gas Venting and Flaring. EPA is proposing 

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

the term “sub-basin category” for the same reasons outlined 

in Section II.C. (Sub-basin Category for Onshore Petroleum 

and Natural Gas Production)of this preamble. 

Flare Stack Emissions. We are proposing two 

amendments in 40 CFR 98.233(n)(2) to clarify how to 

determine gas compositions for hydrocarbon streams going to 

flare. First, we are proposing to amend 40 CFR 
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98.233(n)(2)(ii) to clarify that reporters must use the GHG 

mole percent in feed natural gas for all streams for 

onshore natural gas processing plants that solely 

fractionate a liquid stream. EPA is proposing this 

amendment to address lack of clarity in the final 

provisions which did not explicitly state how natural gas 

processing plants which only fractionate liquid streams 

would determine their gas compositions. We are also 

proposing to clarify in 40 CFR 98.233(n)(2)(iii) that 

methane, in addition to ethane, propane, butane, pentaneplus and mixed light hydrocarbons, should be accounted for 

when the stream going to the flare is a hydrocarbon product 

stream. This proposed technical correction, to add 

methane, ensures that the paragraph 40 CFR 

98.233(n)(2)(iii) is consistent with the equation. 

In addition, we are proposing to clarify the summation 

operator in W-21 to make it mathematically correct. We are 

also clarifying that source types in 40 CFR 98.233 that 

send emissions to a flare must determine volumetric flow 

rate, parameter “Va”, in Equation W-19 through W-20, at 

actual conditions. 

We are also proposing to clarify that the volume of 

gas sent to the flare should be calculated in actual 

conditions. This is consistent with other proposed changes 
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throughout this revision that clarify the use of actual 

versus standard conditions.

In addition, we are proposing to allow facilities the 

option to use a continuous emissions monitoring system 

(CEMS) to estimate GHG emissions from flares. EPA received 

questions as to why CEMS were allowed for use for AGR 

vents, for example, but not for flares. We did not intend 

to unnecessarily limit the measurement options for flares, 

and therefore are proposing to add the option to use CEMS. 

The proposed text clarifies that the use of CEMS is 

required if a CO2 concentration monitor and volumetric flow 

rate monitor are installed and that optionally a user may 

install a CO2 concentration monitor and volumetric flow rate 

monitor to be eligible to use the Tier 4 methodology. When 

CEMS are used to calculate emissions for flare stacks the 

use of equations W-19 to W-21 would no longer apply. With 

the relatively high quantity of unburned methane in the 

emissions from flares, EPA has identified that it is not 

appropriate to use the CH4 calculation methodology in 

subpart C as most flared gases will not be fuels listed in 

Table C-1 of subpart C. EPA is seeking comment on what form 

an equation should take that would calculate CH4 and N2O for 

flares that are monitored by CEMS. One option is to 

calculate the CH4 by multiplying the concentration of CO2
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measured by the CEMS by the fraction of CH4 that was not 

combusted as determined by flare efficiency.

In the data reporting requirements in 40 CFR 

98.236(c)(12) we are proposing to add reporting 

requirements consistent with the calculation requirements 

in Equations W-19 through W-21. Specifically, we are 

proposing to add reporting of uncombusted CH4, combusted and 

uncombusted CO2 and combustion-related N2O emissions. The 

proposed amendments ensure consistency across the 

calculation, monitoring and reporting requirements. 

Centrifugal Compressor Venting. Consistent with other 

clarifications throughout this proposed rule, we are 

proposing to clarify in the definition for the term MTm in 

Equation W-24 that flow measurements should be determined 

in standard cubic feet per hour. 

Leak Detection and Leaker Emission Factors. 

We are proposing to revise 40 CFR 98.233(q)(8) to 

remove the term “city gate stations at custody transfer”

and replace with “transmission-distribution transfer 

stations” for the reasons described earlier in Section 

II.C of this preamble. We are also proposing to remove the 

term “meters and regulators” and replace with above ground 

“metering-regulating stations”. The term “meterregulating” is a term that we are proposing to define in 
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this action, as described earlier in Section II.C of this 

preamble. 

The revisions to terminology for natural gas 

distribution facilities have been proposed to clearly 

identify who is covered under the distribution segment of 

subpart W, and the sources for which leak detection and 

measurement are required and those sources for which an 

emission factor can be used. Based on feedback received 

from industry, there may be concerns that the emission 

factors developed at the transmission-distribution transfer 

stations are not representative of emissions at other above 

ground metering-regulating stations. Although we are not 

proposing changes to the approach for applying emission 

factors to above ground metering-regulating stations in 

this action, we are seeking comment on alternative 

approaches, or data that may be used, for determining 

emissions factors for above ground metering-regulating 

stations. Based on comments received, EPA may consider 

future amendments to the rule. 

In a separate action, (76 FR 37300) EPA is proposing 

to expand the final BAMM provisions to cover all facilities 

subject to subpart W, and allow reporters the option to use 

best available monitoring methods (BAMM) for all of 2011 

without being required to submit a request for approval to 
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the Administrator. For natural gas distribution facilities 

at transmission-distribution transfer stations, this would 

allow facilities to estimate the number of equipment leaks

and the equipment sources themselves using BAMM as provided 

in the rule, along with the total time the component was 

found leaking and operational, as outlined in Equation W—

30. This emission factor could then be used for other 

above ground metering-regulating stations within the 

facility boundary. 

EPA is proposing to clarify the summation operator in 

W-30 to make it mathematically correct. This clarification 

includes amending x to be the total number of each 

equipment leak source and adding Tp, which is the total time 

the component p was found leaking and operational. We are 

proposing to revise the parameter GHGi. For industry 

segments listed in 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 (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 (See 

Technical Support Document Memo (TSD)in Docket ID EPA-HQOAR-2011-0512 for further details).

Next we are proposing two amendments in 40 CFR 

98.236(c)(15). We are proposing to amend the reporting 
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requirements in 40 CFR 98.236(c)(15)(i)(C) to clarify that 

owners or operators must report CH4 emissions collectively 

by equipment type and CO2 emissions collectively by 

equipment type. The calculation methodologies in 40 CFR 

98.233(q), as finalized in the rule, require reporters to 

calculate CH4 emissions and CO2 emissions separately per 

source with equipment leaks. We are proposing this 

amendment to clarify that applicable reporters must report 

the CH4 emissions collectively by equipment type and CO2

emissions collectively by equipment type. We are also 

proposing to correct the reporting requirement in 40 CFR 

98.236(c)(15)(ii)(A) to not include onshore natural gas 

processing. This source category is not required to use 

population emission factors. This amendment is associated 

with the amendment to Equation W-31 in 40 CFR 98.233(r) 

discussed in Calculating Greenhouse Gas Emissions.

Population Count and Emission Factors. We are 

proposing several amendments in 40 CFR 98.233(r). First we 

are proposing to amend the population emission factor 

definition in equation W-31 by replacing the term “noncustody transfer city-gate” with above grade “meteringregulating station” for the reason stated above in this 

preamble. We are also clarifying that the count in 
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equation W-31 applies to the number of “meter/regulator 

runs” at all “metering-regulating stations” combined. 

We are also proposing to amend the term “count” in W31 as follows to elaborate and clarify how each industry 

segment should count the total number of 

equipment/components. In that same equation, we are also 

proposing to revise the definition for GHGi by referring to 

40 CFR 98.233(u) and deleting the composition specified for 

each industry segment. 

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

to explicitly state how meters and piping are to be 

counted. Table 1-B of the 2010 final rule was developed 

using activity data from the 1996 EPA/Gas Research 

Institute Study (1996 EPA/GRI Study), Methane Emissions 

from the U.S. Natural Gas Industry. For all major 

equipment that are not specifically listed, the 1996 

EPA/GRI Study categorized all components at a well-pad

under the meters/piping category. Therefore, owners or 

operators should use one count of meters/piping per wellpad. 

Further, consistent with proposed amendments described 

above, EPA is proposing to amend 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 
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meter/regulator runs at all metering-regulating stations in 

equation W-32 is based on leak detection performed at 

“transmission-distribution transfer stations”. EPA is also 

amending 40 CFR 98.233(r)(6)(i) to clarify that below grade 

meters and regulators apply to below grade “meteringregulation stations”.

Lastly, we are proposing revisions to equation W-32 

that include revisions to the definitions for EF, Es,i, and 

“Count” again to clarify the terminology change away from 

“custody transfer” to above ground “metering-regulating” 

stations. We are also proposing the inclusion of a 

conversion factor to convert to hourly emissions. 

Consequently, we are proposing to amend the conversion in 

Equation W-32 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. 

In addition to the proposed calculation amendments 

described above, we are also proposing to replace the term 

“field” with “sub-basin category” in the reporting for 
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onshore production, consistent with the proposed change to 

sub-basin calculation and reporting. 

Volumetric Emissions. We are proposing to amend 40 

CFR 98.233(t) to clarify that reporters should use actual 

temperature and pressure and adjust to standard conditions. 

The phrase “by converting actual temperature and pressure 

of natural gas emissions to standard temperature and 

pressure of natural gas” was deleted because it is 

redundant.

GHG Volumetric Emissions. We are proposing to amend 

40 CFR 98.233(u) to include 95 percent methane/1 percent CO2

default gas composition for the natural gas transmissions 

industry segment, along with the LNG storage and 

underground storage industry segments. Again, as described 

above, EPA agrees that a default composition of 95 percent 

methane and 1 percent CO2 is appropriate because the 

composition of natural gas is monitored consistently and 

regulated by FERC. 

We are also proposing to strike the reference to the 

term “field” in 40 CFR 98.233(u) and replace with “subbasin category” for the reasons outlined in Section II.C. 

of this preamble (Sub-Basin Category Reporting for Onshore 

Petroleum and Natural Gas Production). 
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We are also proposing to clarify that the GHG mole 

fraction that is determined without using a continuous gas 

analyzer may be determined using an annual average instead 

of the most recent gas composition based on available 

analysis in a sub-basin entity. 

GHG Mass Emissions. We are proposing to clarify in 

the definitions to the equation W-36 that the equation 

applies to N2O emissions as well. N2O emissions are 

calculated from stationary combustion and flares, and the 

proposed edit is necessary to convert the mass emissions of 

N2O to carbon dioxide equivalents of gas. EOR injection

pump blowdown. We are proposing to clarify in the equation 

that only CO2 emissions are calculated. The variables 

Massc,i has been changed to Massc,CO2, and GHGi has been 

changed to GHGCO2.

Onshore Production and Distribution Combustion 

Emissions. In a previous action, EPA proposed several 

revisions to 40 CFR 98.233(z) including corrections to 

Equations W-39 and 40. In this action, we are proposing 

additional amendments to clarify when owners or operators 

of onshore production and distribution facilities must use 

the methods in 40 CFR subpart C to calculate combustionrelated emissions and when they must use the methods in 40 

CFR 98.233(z) to calculate combustion-related emissions. 
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We are proposing to clarify that facilities using subpart C 

to calculate emissions are not limited to the use of tier 

1, but rather may use any tier. Regardless of the tier 

used, the facility must follow the corresponding 

calculation, monitoring and reporting requirements of that 

tier. 

We are also proposing to amend the requirements for 

units combusting field gas or process vent gas. The 2010 

final rule required the use of a continuous flow meter, if 

present. Use of a continuous flow meter would have 

necessitated calibration requirements per 40 CFR 98.3(i). 

These calibration requirements were disproportionately 

burdensome for these relatively small disperse units, 

particularly given that facilities that currently do not 

have a flow meter in place could use company records. In 

this action, we are proposing to amend the requirements to 

allow the use of company records for this equipment. 

Onshore Production and Distribution Equipment 

Threshold for Internal Combustion Equipment. In letters 

dating January 31, 2011 and March 5, 2011 from API and AGA, 

respectively EPA received petitions to reconsider an 

exemption for internal combustion engines similar to that 

which was in the final subpart W rule (75 FR 74458, 

November 30, 2010) for external combustion engines. These 
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requests from the onshore petroleum and natural gas 

production and natural gas distribution reporters were to 

provide respite for reporting of emissions from internal 

combustion equipment that are brought in temporarily for 

maintenance and construction. Some reporters have 

requested complete exemption such that combustion equipment 

that fall below a specific threshold would be exempt from 

reporting. 

EPA considered, but decided not to propose an 

exemption for reporting for internal combustion engines. 

EPA decided not to propose amendments because data 

currently are not available to sufficiently characterize 

these upstream emissions. For example, the volume of fuel 

consumed, especially at wellhead natural gas compressors, 

is not being monitored and only limited data, voluntarily 

reported, are available through the Energy Information 

Administration. 

Although EPA has decided not to propose a threshold 

due to lack of availability of a comprehensive data source 

from which to develop policy, we acknowledge that there is 

potentially small internal combustion equipment outside of 

compressors. In considering a potential equipment 

threshold for non-compressor internal combustion engines, 

EPA collected and reviewed data on the size ranges of 
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small, portable internal combustion engines that may be 

brought to a wellhead for periodic maintenance and 

construction. Such equipment would include, for example, 

electric generators for arc welding, electric generators 

powering portable flood-lighting, and electrical generators 

or gasoline engines powering air compressors (for sand 

blasting or pneumatic tools). For lighting, the industrial 

generators were almost exclusively below 12 horsepower 

(hp), with the highest found being 13.9 hp. For welding 

machines, we assumed that they 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. EPA determined that 130 horsepower (double the 

largest size found) would exclude virtually all small

portable or stationary internal combustion engines, but is 

much smaller than the 5 mmBtu/hour exclusion for external 

combustion sources and equates to about 1 mmBtu/hour. EPA 

is seeking comments on whether a 1 mmBtu/ hour equipment 

threshold for internal combustion engines that are not 

driven by natural gas is reasonable. We also seek comment 

on EPA’s position that combustion-related emissions at 

compressors should not be excluded from reporting, 
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regardless of size and where EPA can find reliable 

estimates of natural gas consumption.

EPA is proposing to clarify the summation operator in 

Equation W-39 to make it mathematically correct. In 

addition, EPA is proposing to clarify in Equation W-40 that 

N2O mass emissions are calculated by changing the parameter 

N2O to Masss,N2O.

In specific, EPA is soliciting comments as to why 

emissions from specific internal combustion related 

equipment should not be reported including the size of the 

equipment that should be excluded along with supporting 

data. 

Monitoring and QA/QC Requirements. We are proposing 

several amendments to the monitoring and QA/QC requirements 

in 40 CFR 98.234. 

First, we are proposing to amend the language in 40 

CFR 98.234(a)(1) by first 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. We are also proposing to state explicitly that 

video recordings are not required under subpart W. As 

noted in the Response to Comments to the 2010 final rule5, 

EPA did not intend to require retention of a video 

 

5 Response to Comments Document: Subpart W – Petroleum and Natural Gas Systems, Part 2, 

page 28. Comment Number: EPA-HQ-OAR-2009-0923-1039-23. 
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recording of the leak detection using optical gas imaging 

instruments for reporting to EPA under subpart W of the 

greenhouse gas reporting rule. However, some of the 

references to the Alternate Work Practice suggested that 

EPA intended that facilities retain these records onsite. 

Next, we are proposing to amend the language in 40 CFR 

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

may be used to monitor inaccessible emissions sources. 

This amendment increases flexibility in monitoring 

requirements and reduces the burden on the industry, 

without compromising data quality. 

Further, based on questions raised by industry, we are 

proposing to amend 40 CFR 98.234(a)(5) by revising the 

acoustic leak detection device provisions to use a 

different model of acoustic detector, one that does not 

have a through-valve leakage correlation, thereby allowing 

leakage to be measured by other methods if a leak is found. 

However, EPA is proposing to clarify that not all types of 

acoustic detectors are allowed. In particular the “gun” 

type instrument that is aimed at the equipment from a 

distance to detect the acoustic signal of leakage is not an 

allowable instrument. This type cannot distinguish between 

external leakage to the atmosphere from internal, throughvalve leakage, which is the objective for specifying this 
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device. EPA is proposing to further specify 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, may be 

used.

We are also proposing editorial revisions in 40 CFR 

98.234(c) for calibrated bagging to specify that those 

using the calibrated bag for sampling, must ensure that the 

emissions must be at a temperature below that which the bag 

manufacturer specifies for safe handling. 

Data Reporting Requirements. We are proposing several 

amendments and clarifications throughout 40 CFR 98.236 in 

order to address questions received about how data should 

be reported. Many of the data reporting requirements were 

lacking clarity with respect to the level of reporting. 

Based on the questions received, as well as EPA’s 

experience gained in developing the electronic GHG 

reporting tool (e-GGRT), which provided EPA a better 

understanding of the clarity necessary in the data 

reporting requirements, EPA is proposing the following 

changes.

In cases where technical amendments were already 

proposed for individual emissions sources above, EPA has 

described the corresponding proposed amendments to the 
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reporting requirements along with the technical amendments. 

This section outlines any remaining proposed amendments to 

the data reporting requirements not already described 

above.

First we are proposing to clarify the data reporting 

requirements for offshore petroleum and natural gas 

production facilities in 40 CFR 98.236(b). Specifically, 

the 2010 final rule was not clear in terms of which gases 

were required to be reported and the data elements for 

reporting. Consistent with the calculation requirements, 

we are proposing to clarify that facilities containing the 

offshore petroleum and natural gas production segment would 

be required to 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 the emissions 

source types listed in the most recent BOEMRE study. 

Next, in the introductory paragraph for 40 CFR 

98.236(c) we are proposing to clarify that vented emissions 

should be reported separately from flared emissions. We 

have specified which source types require separate 

calculation of flared emissions, but EPA is taking comment 

on whether any source types that have process gas routed to 

flares were excluded from having specific reporting 

requirements established for flares. 
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We are proposing to make changes to the data reporting 

requirements for local distribution companies, consistent 

with the proposed amendments to 40 CFR 98.230(a)(8). 

Specifically, we are proposing to replace “custody 

transfer” with “transmission-distribution transfer” station 

and replace “non-custody transfer” with “above ground 

metering-regulating station.” In addition, we are 

proposing to require the reporting of counts and emissions 

of both above grade and below grade stations for each of 

metering-regulating stations and “transmission-distribution 

transfer stations”.

Finally, EPA seeks some basic information on average 

API gravity of the hydrocarbon liquids produced, gas to oil 

ratio, and low pressure separator pressure per sub-basin 

entity. It is EPA’s understanding that his information is 

already known to reporters. EPA will use these facility 

sub-basin characteristics to characterize other emissions 

sources across different sub-basins.”

Records that must be retained. EPA is proposing to 

add the following recordkeeping requirement: “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.” While EPA believes this 
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requirement is already included in 40 CFR 98.3(g)(2)(i) 

where the records for “The GHG emissions calculations and 

methods used” requirement is made, EPA believes that adding 

this statement to the recordkeeping requirements in subpart 

W will provide facilities with further clarity on the 

records they are required to keep. This clarification is 

intended to make clear that stating company records, 

engineering estimation, or best available information were 

used is not enough to satisfy the requirement in 40 CFR 

98.3(g)(2)(i). This requirement is intended to parallel a 

similar requirement for subpart C specified in 40 CFR 

98.34(f) and referenced in 40 CFR 98.37.

Definitions. We are proposing to amend, and in some 

cases, add definitions to 40 CFR 98.238 to further clarify 

rule requirements.

Associated With a Single Well-Pad. We are proposing 

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

to clearly demarcate the boundary of onshore production. 

EPA proposes that the association be defined by the 

hydrocarbon stream from a 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, where the point of combination 

is located off that single well-pad. In addition, we are 
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stating that this definition does not include storage and 

condensate tanks that are located downstream of the point 

of combination. For gas contained in crude oil or 

condensate flowing under pressure off a single well-pad to 

a gas-liquid separator or tank, or comingled with flow from 

other well-pads, 40 CFR 98.233(j) requires reporting of the 

gas content that may be released from the oil or condensate

in an atmospheric pressure fixed roof storage tank. We 

have determined that the conditions of the pressurized oil 

or condensate (i.e. gravity, pressure, temperature, flow 

rate) are commonly known by the well owner/operator, and 

the amount of gas that may be released from the oil or 

condensate with a pressure reduction can be determined most 

appropriately by the well owner/operator. 

Distribution Pipeline. EPA is proposing to include a 

definition for distribution pipelines to add clarity on its 

intent on coverage for the natural gas distribution 

industry segment. We are proposing to use a widely 

accepted definition for distribution pipelines, 

specifically, those designated as such by the Pipeline and 

Hazardous Material Safety Administration (PHMSA).

Facility With Respect to Natural Gas Distribution. 

EPA is proposing to revise the definition for natural gas 

distribution by replacing the term “metering stations, and 
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regulating” with the term “metering-regulating”. EPA is 

proposing to include a definition for the term above ground 

“metering-regulating station” to clarify where leak 

detection and monitoring is required in the 2010 final 

rule. 

Farm Taps. EPA is proposing to revise the definition 

for farm taps in 40 CFR 98.238 by striking the unnecessary 

phrase “The gas may or may not be metered, but always does 

not pass through a city gate station.”

Flare. We are proposing to add a definition of flare 

specific for subpart W to address questions received during 

implementation about what constitutes a flare. The 

proposed definition clarifies that a flare may be either at 

ground level or elevated and uses an open or enclosed flame 

to combust waste gases without energy recovery. This 

definition for subpart W is intended to be inclusive of 

devices that combust waste gases without energy recovery. 

This broad, all-inclusive definition for Subpart W is 

necessitated by the wide variety of waste gas combustion 

devices that are or may be used in the different segments 

of Subpart W, all for the same purpose and having the same 

effect of combustion emissions of hydrocarbon gases.

Forced Extraction of Natural Gas Liquids. We are 

proposing to add a definition for forced extraction to 
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restrict it to specific processes. EPA determined that it 

was necessary to develop this more precise definition 

because many industry questions pointed to the confusion 

between processing plants, gas gathering stations and 

wellheads, where similar equipment and processes are 

conducted as at some, but not all, processing plants that 

EPA determined should be subject to this rule. Those 

similar processes. These processes in and of themselves do 

not make a facility a “processing plant.” Furthermore, the 

Oil & Gas Journal annual survey of gas processing plants is 

primarily focused on those that fractionate, leaving out 

known, large gas plants that separate NGLs or condition 

gas, but do not fractionate, and are clearly not gathering 

booster stations. The key principle that EPA is attempting 

to clarify through this definition is the separation of 

heavier hydrocarbons in the vapor phase of natural gas 

delivered to a plant, excluding the simple gravity 

separation of liquids entrained in the gas. This principle 

is “forced extraction”, as defined here. 

Horizontal Well. With the change from field level 

reporting to sub-basin category, EPA is proposing to add a 

distinction for calculating emissions from horizontal wells 

and vertical wells. We are proposing to define horizontal 

well to mean a well bore that has a planned deviation from 
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primarily vertical to a primarily horizontal inclination or 

declination tracking in parallel with and through the 

target formation.

Sub-Basin Category. With the change from field level 

reporting to sub-basin category, EPA is proposing to add a 

definition for sub-basin category to mean 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 four formation types: conventional with >0.1 

millidarcy permeability, and unconventional with ≤0.1 

millidarcy permeability shale, coal seam, and other tight 

reservoir rock, all of which are unconventional with ≤0.1 

millidarcy permeability . Unconventional wells producing 

from formations categorized in two or more types are 

considered shale for a combination of “shale and coal”, 

“shale and other tight”, or “shale, coal and other tight”; 

and are considered as coal for combinations of “coal and 

other tight". 

Transmission-Distribution (TD) transfer station. EPA 

is proposing to add a definition for Transmission 

Distribution (TD) transfer station to define what was 

previously termed “custody transfer” in the final rule. It 

was not EPA’s intent for the term “custody transfer” to be 
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defined in the context of ownership of gas transfer. EPA 

believes the new definition may be universally applied to 

designate which “metering-regulating stations” are 

classified as “transmission-distribution transfer 

stations”. All covered stations in the distribution 

segment will be collectively referred to as “meteringregulation stations” but the subset that require leak 

detection are “transmission-distribution transfer 

stations.” EPA was notified of concerns from industry that 

defining a transmission distribution transfer station 

without a threshold would include numerous small TD 

transfer stations that would otherwise not have been 

required to perform leak surveys. EPA has not included any 

thresholds in the proposal but we are taking comment on 

what an appropriate threshold would be to exclude these 

smaller transfer stations. Such a threshold should exempt 

stations with low throughputs or low emissions. Any 

threshold should be readily verifiable and be readily 

applied to all stations. Potential options for a threshold 

include using the inlet pressure, the design or actual flow 

rate of the station, or other parameters directly related 

to the emissions from the station. Any suggested changes 

should include a discussion of how many stations would be 

exempted from leak detection and how many would still 
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require leak detection. Such an exemption would not 

preclude a station from reporting, it would only mean that 

leak detection is not required at that station. The 

stations that fall below the select threshold would still 

be included for evaluation against the 25,000mtCO2e 

threshold through the application of an emissions factor. 

Natural gas distribution facilities that do not have any TD 

transfer stations above the threshold, would use a factor 

to determine their emissions and compare those emissions 

against the 25,000 mtCO2e threshold. 

Transmission Pipeline. We are proposing to add a 

definition for transmission pipeline. 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. We propose to use 

this existing mechanism to clearly demarcate transmission 

pipelines from distribution and gathering pipelines. 

Finally, we believe that equipment located on designated 

transmission pipelines that are subject to monitoring under 

subpart W are easily identifiable by facility owners or 

operators. 
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Tubing Systems. Based on a question received in the 

early phases of implementation, we are proposing to clarify 

that the exclusion for piping equal to or less than one 

half inch diameter applies to the nominal pipe size (NPS). 

Vertical Well. With the change from field level 

reporting to sub-basin category, EPA is proposing to add a 

distinction for calculating emissions from horizontal wells 

and vertical wells. EPA proposes that a 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. We are proposing to 

clarify 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). If well testing 

is conducted immediately after well completion or workover 

we are proposing to clarify that it is considered part of 

the well completion or workover.

III. Statutory and Executive Order Review
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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 proposes to simplify the existing 

reporting methodologies in subpart W and clarify monitoring 

methodologies and data reporting requirements. In many 

cases, the proposed amendments to the reporting 

requirements could potentially reduce the reporting burden 

by making the reporting requirements conform more closely 

to current industry practices. In addition, while the 

proposed modification to one of the monitoring 

methodologies is not expected to increase compliance cost, 

it would require the reporting of information not contained 

in the information collection requirements to 40 CFR 98 

subpart W. Therefore, the proposed 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 
129 of 209

Information Collection Request (ICR) document has been 

assigned EPA ICR number 2376.03. 

The proposed amendments to subpart I would carry out 

the Agency’s intent to require reporting of emissions of 

all fluorocarbons used as heat transfer fluids in the 

electronics manufacturing industry. This was the intent of 

the subpart I reporting requirements for HTFs finalized in 

December 2010 (75 FR 74774), and this intent was reflected 

in the Information Collection Request (ICR) prepared during 

that rulemaking. Thus, the proposed amendments will not 

increase EPA or industry burden beyond that estimated in 

the ICR.

The Office of Management and Budget (OMB) has 

previously approved the information collection requirements 

contained in the existing regulations, 40 CFR 98 subpart W 

(75 FR 74458), and 40 CFR part 98 subpart I (75 FR 74774), 

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. 

C. Regulatory Flexibility Act

The Regulatory Flexibility Act (RFA) generally 

requires an agency to prepare a regulatory flexibility 
130 of 209

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 proposed 

rule on small entities, small entity is defined as: (1) a 

small business as defined by the Small Business 

Administration’s (SBA)regulations at 13 CFR 121.201; (2) a 

small governmental jurisdiction that is a government of a 

city, county, town, school district or special district 

with a population of less than 50,000; and (3) a small 

organization that is any not-for-profit enterprise which is 

independently owned and operated and is not dominant in its 

field. 

After considering the economic impacts of today’s 

proposed rule 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 
131 of 209

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 USC 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. 

This action includes proposed amendments to provisions 

in those rules that could result in reduced burden on 

reporters. In some cases, EPA is proposing to increase 

flexibility in the selection of methods use for calculating 

GHG’s, and is also proposing to revise certain methods that 

may result in greater conformance to current industry 

practices. In addition, in this action, EPA is proposing 

to revise specific provisions to provide clarity on what is 

to be reported. Further, in this action, EPA is also 

proposing amendments to clarify the Agency’s intent. These 

proposed revisions could overall reduce burden on reporters 

while maintaining the data quality of the information being 

reported to EPA. As part of the process of finalization of

the subpart W and subpart I rules, EPA undertook specific 

steps to evaluate the effect of those final rules on small 
132 of 209

entities. Based on the proposed amendments to the subpart W 

and subpart I provisions, burden will stay the same or 

decrease, therefore EPA’s determination finding of no 

significant economic impact on a substantial number of 

small entities has not changed. 

D. Unfunded Mandates Reform Act

The proposed 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 proposed rule amendments are not subject to the 

requirements of section 202 and 205 of the UMRA. This rule 

is also not subject to the requirements of section 203 of 

UMRA because it contains no regulatory requirements that 

might significantly or uniquely affect small governments. 

This action is also not subject to the requirements of 

section 203 of UMRA because it contains no regulatory 

requirements that might significantly or uniquely affect 

small governments. Further, the proposed amendments will 

not impose any new requirements that are not currently 

required for 40 CFR part 98, and the rule amendments would 

not unfairly apply to small governments. 

E. Executive Order 13132: Federalism
133 of 209

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 proposed 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.

In the spirit of Executive Order 13132, and consistent 

with EPA policy to promote communications between EPA and 

State and local governments, EPA specifically solicits 

comment on this proposed action from State and local 

officials.

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 and subpart 

I, EPA undertook the necessary steps to determine the 

impact of those rules on tribal entities and provided 
134 of 209

supporting documentation demonstrating the results of the 

Agency’s analyses. The proposed rule amendments in this 

action do not impose any significant changes to the current 

reporting requirements contained in 40 CFR part 98 subpart 

W and 40 CFR part 98 subpart I. And in several cases, the 

proposed 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 tribal officials during the 

development of the original actions. A summary of the 

concerns raised during the 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). EPA specifically solicits additional comment on 

this proposed action from tribal officials.

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 
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action is not subject to Executive Order 13045 because it 

does not establish an environmental standard intended to 

mitigate health or safety risks.

H. Executive Order 13211: Actions that Significantly 

Affect Energy Supply, Distribution, or Use

This action is not subject to Executive Order 13211 

(66 FR 28355, May 22, 2001), because it is not a 

significant regulatory action under Executive Order 12866.

I. National Technology Transfer and Advancement Act

Section 12(d) of the National Technology Transfer and 

Advancement Act of 1995 (NTTAA), Public Law No. 104-113, 

12(d) (15 U.S.C. 272 note) directs EPA to use voluntary 

consensus standards in its regulatory activities unless to 

do so would be inconsistent with applicable law or 

otherwise impractical. Voluntary consensus standards are 

technical standards (e.g., materials specifications, test 

methods, sampling procedures, and business practices) that 

are developed or adopted by voluntary consensus standards 

bodies. NTTAA directs EPA to provide Congress, through 

OMB, explanations when the Agency decides not to use 

available and applicable voluntary consensus standards. 

This proposed rulemaking does not involve technical 

standards. Therefore, EPA is not considering the use of 

any voluntary consensus standards.
136 of 209

J. Executive Order 12898: Federal Actions to Address 

Environmental Justice in Minority Populations and LowIncome Populations

Executive Order 12898 (59 FR 7629, February 16, 1994) 

establishes federal executive policy on environmental 

justice. Its main provision directs federal agencies, to 

the greatest extent practicable and permitted by law, to 

make environmental justice part of their mission by 

identifying and addressing, as appropriate, 

disproportionately high and adverse human health or 

environmental effects of their programs, policies, and 

activities on minority populations and low-income 

populations in the United States. 

EPA has determined that this proposed rule 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.
Mandatory Reporting of Greenhouse Gases: Technical 

Revisions to Subpart I: Electronics Manufacturing and 

Subpart W: Petroleum and Natural Gas Systems of the 

Greenhouse Gas Reporting Rule

137 of 209

List of Subjects in 40 CFR Part 98

Environmental protection, Administrative practice and 

procedure, Greenhouse gases, Incorporation by reference, 

Suppliers, Reporting and recordkeeping requirements.

Dated:

Lisa P. Jackson, 

Administrator.
Page 138 of 209

For the reasons stated in the preamble, title 40, 

chapter I, of the Code of Federal Regulations is proposed 

to be 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 for “Continuous bleed” and “Intermittent bleed 

pneumatic devices” to read as follows:

§98.6 Definitions.

* * * * *
Page 139 of 209

Continuous bleed means a continuous flow of pneumatic 

supply gas to the process control device (e.g., level 

control, temperature control, pressure control) where the 

supply gas pressure is modulated by the process condition, 

and then flows to the valve controller where the signal is 

compared with the process set-point to adjust gas pressure 

in the valve actuator.

* * * * *

Intermittent bleed pneumatic devices mean automated 

flow control devices powered by pressurized natural gas and 

used for automatically maintaining a process condition such 

as liquid level, pressure, delta-pressure, and temperature. 

These are snap-acting or throttling devices that discharge 

all or a portion of the full volume of the actuator 

intermittently when control action is necessary, but do not 

bleed continuously.

* * * * *

4. Section 98.7 is amended by removing paragraph (q).

Subpart I—[Amended]

5. Section 98.90 is amended by revising paragraph 

(a)(5) to read as follows:

§98.90 Definition of the source category.

(a) * * *
Page 140 of 209

(5) Any electronics manufacturing production process 

in which fluorinated heat transfer fluids are used to cool 

process equipment, to control temperature during device 

testing, to clean substrate surfaces and other parts, and 

for soldering (e.g., vapor phase reflow).

6. Section 98.92 is amended by revising paragraph (a) 

introductory text and paragraph (a)(5) to read as follows:

§98.92 GHGs to report.

(a) You must report emissions of fluorinated GHGs (as 

defined in §98.6), N2O, and fluorinated heat transfer fluids 

(as defined in §98.98). The fluorinated GHGs and 

fluorinated heat transfer fluids that are emitted from 

electronics manufacturing production processes include, but 

are not limited to, those listed in Table I–2 to this 

subpart. You must individually report, as appropriate:

* * * * *

(5) Emissions of fluorinated heat transfer fluids.

* * * * *

7. Section 98.93 is amended by revising paragraph (h) 

introductory text and the definition of “EHi” in Equation I16 to read as follows.

§98.93 Calculating GHG Emissions.

* * * * *
Page 141 of 209

(h) If you use fluorinated heat transfer fluids, you 

must report the annual emissions of fluorinated heat 

transfer fluids using the mass balance approach described 

in Equation I-16 of this subpart.

* * * * *

EHi = Emissions of fluorinated heat transfer fluids i, 

(metric tons/year).

* * * * *

8. Section 98.94 is amended by revising paragraph (h) 

introductory text to read as follows:

§98.94 Monitoring and QA/QC requirements.

* * * * *

(h) You must adhere to the QA/QC procedures of this 

paragraph (h) when calculating annual gas consumption for 

each fluorinated GHG and N2O used at your facility and 

emissions from the use of fluorinated heat transfer fluids.

* * * * *

9. Section 98.96 is amended by revising paragraph (r) 

to read as follows:

§98.96 Data Reporting requirements

* * * * *

(r) For heat transfer fluid emissions, inputs to the 

heat transfer fluid mass balance equation, Equation I–16 of 
Page 142 of 209

this subpart, for each fluorinated heat transfer fluid 

used. 

* * * * *

10. Section 98.98 is amended by removing the 

definition of “Heat transfer fluids” and adding the 

definition of “Fluorinated heat transfer fluids” in 

alphabetical order to read as follows:

§98.98 Definitions.

* * * * *

Fluorinated heat transfer fluids means fluorinated 

GHGs used for temperature control, device testing, cleaning 

substrate surfaces and other parts, and soldering in 

certain types of electronics manufacturing production 

processes. For fluorinated heat transfer fluids under this 

subpart I, the lower vapor pressure limit of 1 mm of Hg in 

absolute at 25 degrees C in the definition of Fluorinated 

greenhouse gas in 40 CFR 98.6 shall not apply. Fluorinated 

heat transfer fluids used in the electronics manufacturing 

sector include, but are not limited to, 

perfluoropolyethers, perfluoroalkanes, perfluoroethers, 

tertiary perfluoroamines, and perfluorocyclic ethers. 

* * * * *

11. Table I–2 to Subpart I is amended by revising the 

title and the second column heading to read as follows:
Page 143 of 209

Table I-2 to Subpart I of Part 98—Examples of Fluorinated 

GHGs and Fluorinated Heat Transfer Fluids Used by the 

Electronics Industry 

Product Type Fluorinated GHGs and Fluorinated Heat 

Transfer Fluids Used During Manufacture

Electronics CF4, C2F6, C3F8, c-C4F8, c-C4F8O, C4F6, C5F8, 

CHF3, CH2F2, NF3, SF6, and HTFs(CF3-(O-CF(CF3)-

CF2)n-(O-CF2)m-O-CF3, CnF2n+2, CnF2n+1(O)CmF2m+1, 

CnF2nO, (CnF2n+1)3N)

Subpart W—[Amended]

12. Section 98.230 is amended by revising paragraphs 

(a)(2), (a)(3), (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 nonself-propelled equipment which includes well drilling and 

completion equipment, workover equipment, gravity 

separation equipment, auxiliary non-transportation-related 

equipment, and leased, rented or contracted equipment) used 

in the production, extraction, recovery, lifting, 

stabilization, separation or treating of petroleum and/or 

natural gas (including condensate). This equipment also 

includes associated storage or measurement vessels and all 

enhanced oil recovery (EOR) operations using CO2 or natural 
Page 144 of 209

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 
Page 145 of 209

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.

* * * * *

13. Section 98.232 is amended by: 

a. Revising paragraph (c) introductory text and 

paragraph (c)(22).
Page 146 of 209

b. Revising paragraph (e) introductory text.

c. Revising paragraph (f) introductory text. 

d. Revising paragraph (g) introductory text.

e. Revising paragraph (h) introductory text.

f. Revising paragraph (i) introductory text and

paragraph (i)(1).

g. Redesignating paragraphs (i)(2) through (i)(6) as 

paragraphs (i)(3) through (i)(7), respectively.

h. Revising newly designated paragraphs (i)(3) and 

(i)(4).

i. Adding new paragraph (i)(2).

j. Removing and reserving paragraph (j).

k. Revising paragraph (k).

The revisions read as follows: 

§98.232 GHGs to report.

* * * * *

(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 
Page 147 of 209

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.

* * * * *

(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: 

* * * * *
Page 148 of 209

(i) For natural gas distribution, report CO2, CH4, and 

N2O emissions from the following sources: 

(1) Meters, regulators, and associated equipment at 

above grade transmission-distribution 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.

(3) Meters, regulators, and associated equipment at 

above grade metering-regulating station.

(4) Equipment leaks from vaults at below grade 

metering-regulating stations.

* * * * *

(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 
Page 149 of 209

facilities must report stationary combustion emissions as 

specified in paragraph (i) of this section. 

14. Section 98.233 is amended by: 

a. In paragraph (a), revising Equation W-1 and the 

definitions of “Count” and “GHGi” in Equation W-1; and 

adding the definition of “T” in Equation W-1.

b. Adding paragraph (a)(3). 

c. In paragraph (c), revising Equation W-2 and the 

definition of “GHGi”; and adding the definition of “T” in 

Equation W-2.

d. Revising paragraphs (d) introductory text and 

(d)(1). 

e. In paragraph (d)(3), revising Equation W-4 and 

removing the definition of “α” in Equation W-4.

f. Revising paragraph (e)(1)(vii). 

g. Revising the definition of “1000” in Equation W-5 

of paragraph (e)(2). 

h. Revising paragraph (e)(6).

i. Revising paragraphs (f) introductory text, (f)(1) 

introductory text, and the definitions of Equation W-7 in 

paragraph (f)(1).

j. Revising paragraphs (f)(1)(i)(A) through 

(f)(1)(i)(C). 
Page 150 of 209

k. In paragraph (f)(2), revising Equation W-8 and 

the definitions of Equation W-8.

l. Removing paragraphs (f)(2)(i) and (f)(2)(ii). 

m. In paragraph (f)(3), revising Equation W-9 and 

the definitions of Equation W-9.

n. Removing paragraphs (f)(3)(i) and (f)(3)(ii). 

o. In paragraph (g), revising Equation W-10 and the 

definitions of Equation W-10.

p. Revising paragraphs (g)(1) introductory text and 

(g)(1)(i) introductory text. 

q. Removing paragraphs (g)(1)(i)(A) through 

(g)(1)(i)(D).

r. In paragraph (g)(1)(ii), revising the paragraph 

(g)(1)(ii) introductory text; redesignating Equation W-11 

as Equation W-11A and redesignating Equation W-12 as 

Equation W-11B; and adding Equation W-11C.

s. Redesignating paragraphs (g)(1)(ii)(A) through 

(g)(1)(ii)(B) as paragraphs (g)(1)(iii) through (g)(1)(v)

and revising new paragraphs (g)(1)(iii) through (g)(1)(v).

t. Removing paragraph (g)(1)(ii)(D). 

u. Revising paragraph (g)(3) introductory text and 

paragraph (g)(5) introductory text.
Page 151 of 209

v. In paragraph (h), revising the paragraph (h) 

introductory text and the revising the definitions of “Nwo”, 

“f”, “Vp” and “Tp” in Equation W-13.

w. Revising paragraph (i) introductory text and 

paragraphs (i)(1) and (i)(2).

x. In paragraph (i)(3), revising the paragraph 

(i)(3) introductory text; redesignating Equation W-14 as 

Equation W-14A; revising the definition of “N” in newly 

redesignated Equation W-14A; and adding Equation W-14B. 

y. Revising paragraph (i)(5).

z. Revising paragraph (j)(1)(vii)(B), 

(j)(1)(vii)(C), and (j)(3)(i).

aa. Revising paragraphs (k)(1) and (k)(2)(i).

bb. Revising paragraph (m)(1).

cc. Revising paragraph (n)(2)(ii) and (n)(2)(iii), 

and in paragraph (n)(4), revising equation W-21 and the 

definition for “Yj”.

dd. Redesignating paragraph (n)(9) as paragraph 

(n)(10) and adding new paragraphs (n)(9) and (n)(11). 

ee. In paragraph (o)(6), revising the definition of 

“MTm” in Equation W-24.

ff. In paragraph (p)(7)(i), revising the definition 

of “MTm” in Equation W-28.
Page 152 of 209

gg. In paragraph (q), revising equation W-30 and the 

definitions for “x”, “EF”, “GHGi”, “Tp”, and revising 

paragraph (q)(8).

hh. In paragraph (r), revising the definitions of 

“Counts”, “EFs”, and “GHGi” in Equation W-31. 

ii. Revising paragraphs (r)(2)(i)(A), (r)(6)(i), 

(r)(6)(ii) introductory text, Equation W-32, and the 

definitions of Equation W-32. 

jj. Revising paragraphs (t) introductory text, (t)(1) 

introductory text, and (t)(2) introductory text. 

kk. Revising paragraph (u) introductory text and 

paragraph (u)(2).

ll. In paragraph (v), revising the paragraph (v) 

introductory text and the definitions of “Masss,i”, “Es,i”, 

and “i” in Equation W-36. 

mm. Revising paragraphs (z) introductory text, (z)(1) 

introductory text, (z)(2) introductory text, (z)(2)(i), and 

(z)(2)(ii).

nn. Adding paragraphs (z)(1)(i) and (z)(1)(ii).

The revisions read as follows: 

§98.233 Calculating GHG emissions.

(a) * * *

Masss,i  Count * EF * GHGi*Convi* T (Eq. W-1)

* * * * *
Page 153 of 209

Count = Total number of continuous high bleed, continuous 

low bleed, or intermittent bleed natural gas 

pneumatic devices of each type as determined in 

paragraph (a)(1) and (a)(2) of this section. 

* * * * *

GHGi = For onshore petroleum and natural gas production 

facilities, onshore natural gas transmission 

compression, and underground natural gas storage, 

concentration of GHGi, CH4, or CO2, in natural gas 

as defined in paragraph (u)(2)(i) of this 

section.

* * * * *

T = Total number of hours in the operating year the 

devices were operational.

* * * * *

(3) For all industry segments, determine the type of 

pneumatic device using engineering estimates based on best 

available information.

* * * * *

(c) * * *

Masss,i  Count * EF * GHGi*Convi* T (Eq. W-2)

* * * * *

GHGi = Concentration of GHGi, CH4, or CO2, in produced 

natural gas as defined in paragraph (u)(2)(i) of 

this section.

* * * * *

T = Total number of hours in the operating year the 

pumps were operational.

* * * * *
Page 154 of 209

(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). 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 
Page 155 of 209

reporting of CH4 and N2O emissions is not required as part 

of the Tier 4 requirements for AGRs.

* * * * *

(3) * * *

 

  I O

I O

a CO Vol Vol

Vol Vol

V

E  











 

 *

1

, 2 (Eq. W-4)

* * * * *

(e) * * *

(1) * * *

(vii) Use of stripping gas.

* * * * *

(2) 

* * * * *

1000 = Conversion of EFi in thousand standard cubic feet 

to cubic feet.

* * * * *

(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.

* * * * *
Page 156 of 209

(f) Well venting for liquids unloadings. Calculate 

CO2 and CH4 emissions from well venting for liquids 

unloading using one of the calculation methodologies 

described in paragraphs (f)(1), (f)(2), or (f)(3) of this 

section.

(1) Calculation Methodology 1. For one well of each 

unique well tubing diameter grouping and pressure grouping 

in each sub-basin category (see §98.238 for the definitions 

of tubing diameter grouping, pressure grouping, and subbasin 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.

* * * * *

Ea,n = Annual natural gas emissions for wells of the 

same tubing diameter grouping and pressure 

grouping at actual conditions in cubic feet. 

Th,t = Cumulative amount of time in hours of venting 

from all wells of the same tubing diameter 

grouping p and pressure grouping q during the 

year.

FRh,t = Average flow rate in cubic feet per hour of a 

measured well venting for the duration of the 
Page 157 of 209

liquids unloading, under actual conditions as 

determined in paragraph (f)(1)(i) of this 

section.

h = Total number of different tubing diameter 

groupings.

p = Tubing diameter grouping 1 through h.

t = Total number of pressure groupings.

q = Pressure grouping 1 through t.

* * * * *

(i) * * *

(A) The average flow rate per hour of venting is 

calculated for each unique tubing diameter grouping and 

pressure grouping 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 grouping that have the same 

tubing diameter grouping, for the number of hours of 

venting these wells.

(C) A new average flow rate is calculated every other 

calendar year for each reporting sub-basin category 

starting the first calendar year of data collection. For a 

new producing sub-basin category, an average flow rate is 

calculated beginning in the first year of production.

(2) * * *
Page 158 of 209

       

 



















         

W

p

V

q

s n p p p p q q p q p

p

E V CD WD SP SFR HR Z

1 1

, ,

3 2

,

0.37 10 1.0 (Eq. W-8)

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 at the facility.

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

pounds per square feet).

CDP = Casing diameter for each well, p, in inches.

WDP = Well depth from the lowest packer to the bottom 

of the well, in feet.

SPP = Shut-in pressure for each well, p, in pounds 

per square inch atmosphere (psia).

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

SFRP = Average sales flow rate of gas well, p, at 

standard conditions in cubic feet per hour. 

Use Equation W-33 to calculate the sales flow 

rate at standard conditions.

HRQ,PW = Hours that each well,p , was left open to the 

atmosphere during unloading, q. 

1.0 = Hours for average well to blowdown casing 

volume at shut-in pressure.

ZQ,P = If HRQ,P is less than 1.0 then ZQ,P is equal to 

0. If HRQ,P is greater than or equal to 1.0 

then ZQ,P is equal to 1.

(3) * * *

       

 















         

W

p

V

q

s n p p p p q q p q p

p

E V TD WD SP SFR HR Z

1 1

, ,

3 2

,

0.37 10 0.5 (Eq. W-9)

Where:

Es,n = Annual natural gas emissions at standard 

conditions, in cubic feet/year. 
Page 159 of 209

W = Total number of wells with well venting for 

liquids unloading at the facility. 

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

pounds per square feet).

TDP = Tubing diameter for each well, p,in inches.

WDP = Tubing depth to plunger bumper for each well, p, 

in feet.

SPP = Sales line pressure for each well, p, in pounds 

per square inch atmospheric (psia).

VP = Number of vents per year for each well, p.

SFRP = Average sales flow rate of each gas well, p, at 

standard conditions in cubic feet per hour. 

Use Equation W-33 to calculate the sales flow 

rate at standard conditions.

HRQ,P = 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 sales line pressure.

ZQ,P = If HRQ,P is less than 0.5 then ZQ,P is equal to 0. 

If HRQ,P is greater than or equal to 0.5 then 

ZQ,P is equal to 1.

* * * * *

(g) * * *

 



    

W

p

Es n Tp FRM PRp EnFp SGp

1

, (Eq. W-10)

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 combination. 

Tp = Cumulative amount of time in hours of each well 

(p) completion or workover venting in a sub-basin 
Page 160 of 209

and well type combination during the reporting 

year.

FRM = Venting to 30-day production ratio 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 EnF is 0. If 

injected gas is CO2, then EnF is 0.

SGp = Volume of natural gas in cubic feet at standard 

conditions that was recovered into a sales 

pipeline for well p as per paragraph (g)(3) of 

this section. If no gas was recovered for sales, 

SG is 0.

W = Total number of wells completed or worked over 

using hydraulic fracturing in a sub-basin and 

well type combination.

(1) The average flow rate for gas well venting to the 

atmosphere or to a flare during well completions and 

workovers from hydraulic fracturing shall be determined 

using measurement(s) from either of the calculation 

methodologies described in this paragraph (g)(1) of this 

section. The number of measurements shall be determined as 

follows: One measurement for less than or equal to 25 

completions/workovers; two measurements for 26 to 50 

completions/workovers; three measurements for 51 to 100 

completions/workovers; four measurements for 101 to 250 
Page 161 of 209

completions/workovers; and five measurements for greater 

than 250 completions/workovers.

(i) Calculation Methodology 1. For well 

completion(s) in each gas producing sub-basin category and 

well type (horizontal or vertical) combination and for one 

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 if used, to measure the 

backflow venting according to methods set forth in 

§98.234(b). 

(ii) Calculation Methodology 2. For one horizontal 

well completion and one vertical well completion in each 

gas producing sub-basin category and for one well 

horizontal workover and one 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 intermittent well flow rate of gas during 

venting to the atmosphere or a flare. Calculate emissions 

using Equation W-11A of this section for subsonic flow or 

Equation W-11B of this section for sonic flow. Use 

Equation W-11C of this section to determine whether flow is 

sonic or subsonic. If the value of R in Equation W-11C is 
Page 162 of 209

greater than or equal to 2, then flow is sonic; otherwise, 

flow is subsonic:

































 















 

1.758

1

2

1.515

1

5 2

1.27 10 * * 3430 * *

P

P

P

P

FR A Tu

(Eq. W-11A)

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 m2/(sec2 * K).

1.27*105 = Conversion from m3/second to ft3/hour.

FR A 08 *Tu 1.27 10 * * 187.

5

  (Eq. W-11B)

Where:

FR = Average flow rate in cubic feet per hour, under 

sonic flow conditions.

A = Cross sectional area of orifice (m2).

Tu = Upstream temperature (degrees Kelvin).

187.08 = Constant with units of m

2/(sec2 * K).

1.27*105 = Conversion from m3/second to ft3/hour.

2

1

P

R  P

(Eq. W-11C)

Where:

R = Pressure ratio

P1 = Pressure upstream of the restriction orifice in 

pounds per square inch absolute.
Page 163 of 209

P2 = Pressure downstream of the restriction orifice in 

pounds per square inch absolute.

(iii) The emissions to 30-day production ratio is 

calculated using Equation W-12 of this section. 









 W

p

p

W

p

p

PR

FR

FRM

1

1

(Eq. W-12)

Where:

FRM = Emissions to 30-day production ratio.

FRp = Measured flow rate from Calculation Methodology 1 

or estimated 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.

PRp = First 30-day production rate in standard cubic

feet per hour for each well p that was measured 

in the sub-basin and well type combination.

W = Number of wells completed or worked over using 

hydraulic fracturing in a sub-basin and well type 

formation.

(iv) The flow rates for horizontal and vertical wells 

are applied to all horizontal and vertical well completions 

in the gas producing sub-basin and well type combination 

and to all horizontal and vertical well workovers, 

respectively, in the gas producing sub-basin and well type 

combination for the total number of hours of venting of 

each of these wells. 
Page 164 of 209

(v) 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. 

(2) The volume of CO2 or N2 injected into the well 

reservoir during energized hydraulic fractures will be 

measured using an appropriate meter as described in 

§98.234(b) or using receipts of gas purchases that are used 

for the energized fracture job. 

(i) Calculate gas volume at standard conditions using 

calculations in paragraph (t) of this section.

(ii) [Reserved]

(3) The volume of recovered completion or workover 

gas sent to a sales line will be measured using existing 

company records. If data does not exist on sales gas, then 

an appropriate meter as described in §98.234(b) may be 

used.

* * * * *

(5) Determine if the well completion or workover from 

hydraulic fracturing recovered gas with purpose designed 

equipment that separates saleable gas from the backflow, 

and sent this gas to a sales line (e.g., reduced emissions 

completions or workovers).
Page 165 of 209

* * * * *

(h) Gas well venting during completions and workovers 

without hydraulic fracturing. Calculate CH4, CO2 and N2O 

(when flared) emissions from each gas well venting during 

well completions and workovers not involving hydraulic 

fracturing using Equation W-13 of this section:

* * * * *

Nwo = Number of workovers per sub-basin not involving 

hydraulic fracturing in the reporting year.

f = Total number of well completions without 

hydraulic fracturing in a sub-basin category.

Vp = Average daily gas production rate in 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 sales 

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.* *

* * *

(i) Blowdown vent stacks. Calculate CO2 and CH4

blowdown vent stack emissions from depressurizing equipment 

to reduce system pressure for planned or emergency 
Page 166 of 209

shutdowns or to take equipment out of service for 

maintenance (excluding depressurizing to a flare, overpressure 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 total 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 total 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 type (including but not limited to compressors, 

vessels, pipelines, headers, fractionators, and tanks). 

Physical volumes smaller than 50 standard cubic feet are 

exempt from reporting under paragraph (i) of this section.

(3) Calculate the total annual venting emissions for 

each equipment type using either Equation W-14A or W-14B of 

this section. 

 

 





































 V C

T P

T P

E N V v

a s

s a

s n v

*

459.67

459.67 * , (Eq. W-14A)

Where:
Page 167 of 209

* * * * *

Vv = Total volume of blowdown equipment chambers 

(including pipelines, compressors and vessels) 

between isolation valves in cubic feet.

* * * * *

  

   

































 



N

p a s

s a s p a e p

s n v

T P

T P P

E V

1

, , , ,

,

459.67

459.67

(Eq. W-14B)

Where:

Es,n = Annual natural gas venting emissions at standard 

conditions from blowdowns in cubic feet.

N = Number of repetitive blowdowns for each unique 

volume in calendar year.

Vv = Total volume of blowdown equipment chamber 

(including pipelines, compressors and vessels) 

between isolation valves in cubic feet for each 

blowdown “i.”

C = Purge factor that is 1 if the equipment is not 

purged or zero if the equipment is purged using 

non-GHG gases.

Ts = Temperature at standard conditions (oF).

Ta = Temperature at actual conditions in the blowdown 

equipment chamber (oF) for each blowdown “i”.

Ps = Absolute pressure at standard conditions (psia).

Pa,s,p = Absolute pressure at actual conditions in the 

blowdown equipment chamber (psia) at the start of 

the blowdown “p”.

Pa,e,p = Absolute pressure at actual conditions in the 

blowdown equipment chamber (psia) at the end of 

the blowdown “p”; 0 if blowdown volume is purged 

using non-GHG gases.

* * * * *
Page 168 of 209

(5) Calculate total annual venting emissions for all 

blowdown vent stacks by adding all standard volumetric and 

mass emissions determined using Equations W-14A or W-14B 

and paragraph (i)(4) of this section.

(j) * * *

(1) * * *

(vii) * * *

(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. 

* * * * *

(3) * * *

(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 sub-basin category and assume all of the 

CH4 and CO2 in both oil and gas are emitted from the tank.

* * * * *
Page 169 of 209

(k) * * *

(1) Monitor the tank vapor vent stack annually for 

emissions using an optical gas imaging instrument according 

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

measuring the tank vent using a flow meter, calibrated bag, 

or high volume sampler according to methods in §98.234(b) 

through (d) for a duration of 5 minutes. Or you may 

annually monitor leakage through compressor scrubber dump 

valve(s) into the tank using an acoustic leak detection 

device according to methods set forth in §98.234(a)(5).

(2) * * *

(i) Use a meter, such as a turbine meter, calibrated 

bag, or high flow sampler to estimate tank vapor volumes 

according to methods set forth in §98.234(b) through (d). 

If you do not have a continuous flow measurement device, 

you may install a flow measuring device on the tank vapor 

vent stack. If the vent is directly measured for five 

minutes under paragraph §98.233(k)(1) of this section to 

detect continuous leakage, this serves as the measurement.

(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 
Page 170 of 209

from a cluster of wells in the same sub-basin category 

shall be used.

* * * * *

(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 demethanizer overhead or dew point control for onshore 

natural gas processing facilities. For onshore natural gas 

processing plants that solely fractionate a liquid stream, 

use the GHG mole percent in feed natural gas liquid for all 

streams.

(iii) For any applicable industry segment, when the 

stream going to the flare is a hydrocarbon product stream, 

such as methane, ethane, propane, butane, pentane-plus and 

mixed light hydrocarbons, then you may use a representative 

composition from the source for the stream determined by 

engineering calculation based on process knowledge and best 

available data.

* * * * *
Page 171 of 209

(n) * * *

   





5

1

, 2

* * *

J

a CO Va Yj Rj E combusted 

 

(Eq. W-21)

* * * * *

Yj = Mole fraction of gas hydrocarbon constituents j 

(such as methane, ethane, propane, butane, and 

pentanes-plus)

* * * * *

(9) If you operate and maintain a CEMS that has both 

a CO2 concentration monitor and volumetric flow rate 

monitor, you must calculate CO2 emissions for the flare 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). 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 
Page 172 of 209

Methodology in subpart C of this part (General Stationary 

Fuel Combustion). 

(10) The flare emissions determined under paragraph 

(n) of this section must be corrected for flare emissions 

calculated and reported under other paragraphs of this 

section to avoid double counting of these emissions. 

(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.

* * * * *

(p) * * *

(7) * * *

(i) * * *

* * * * *

MTm = Meter readings from all reciprocating compressor 

vents in each and mode, m, in standard cubic feet 

per hour.
Page 173 of 209

* * * * *

(q) * * *

* * * * *

 





x

p

Es i GHGi EF Tp

1

, * *

(Eq. W-30)

* * * * *

x = Total number of each equipment leak source.

* * * * *

GHGi = For onshore natural gas processing facilities, 

concentration of GHGi, CH4 or CO2, in the total 

hydrocarbon of the feed natural gas; 98.230(a)(4) 

and (a)(5),GHGi equals 0.974 for CH4 and 1.0 × 10-2

for CO2; for facilities listed in §98.230(a)(6) 

and (a)(7), GHGi equals 1 for CH4 and 0 for CO2;

and for facilities listed in §98.230(a)(8), 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 or the beginning of the calendar year. 
Page 174 of 209

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.

* * * * *

(8) Natural gas distribution facilities for above 

grade transmission-distribution transfer stations, shall 

use the appropriate default leaker emission factors listed 

in Table W-7 of this subpart for equipment leak detected 

from connectors, block valves, control valves, pressure 

relief valves, orifice meters, regulators, and open ended 

lines. Leak detection at natural gas distribution 

facilities is only required at above grade stations that 

qualify as transmission-distribution transfer stations. 

Below grade transmission-distribution transfer stations and 

metering-regulating stations that do not meet the 

definition of transmission-distribution transfer stations 

are not required to perform component leak detection under 

this section.

(r) * * *

* * * * *

Counts = Total number of this type of emission source at 

the facility. For onshore petroleum and natural 

gas production, average component counts are 
Page 175 of 209

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 

respective component for each emission factor as 

described in paragraph (r)(6) of this section.

EFs = Population emission factor for the specific 

source, as listed in Table W-1A and Tables W-3 

through Table W-7 of this subpart. Use 

appropriate population emission factor for 

operations in Eastern and Western U.S., 

according to Table W-1D of this subpart. EF for

meter/regulator runs at above grade meteringregulating stations is determined in Equation W32 of this section. 

GHGi = For onshore petroleum and natural gas production 

facilities, concentration of GHGi, CH4 or CO2, in 

produced natural gas; for other facilities 

listed in §98.230(a)(4) and (a)(5),GHGi equals 

0.952 for CH4 and 1.0 × 10-2 for CO2; for 

facilities listed in §98.230(a)(6) and (a)(7), 

GHGi equals 1 for CH4 and 0 for CO2; and for 

facilities listed in §98.230(a)(8), GHGi equals 1 

for CH4 and 1.1×10-2 CO2.

* * * * *

(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. 

* * * * *
Page 176 of 209

(6) * * *

(i) Below grade metering-regulating stations 

(including below grade T-D transfer stations); distribution 

mains; and distribution services, shall use the appropriate 

default population emission factors listed in Table W-7 of 

this subpart. 

(ii) Emissions from all above grade meteringregulating stations (including above grade TD transfer 

stations) shall be calculated by applying the emission 

factor calculated in Equation W-32 and the total count of 

meter/regulator runs at all above grade metering-regulating 

stations (inclusive of TD transfer stations) to Equation W31. The facility wide emission factor in Equation W-32 

will be calculated by using the total volumetric GHG 

emissions at standard conditions for all equipment leak 

sources calculated in paragraph (q)(8) of this section and 

the count of meter/regulator runs located at above grade 

transmission-distribution transfer stations.

Count

E

EF s i

8760 , 

  (Eq. W-32)

Where:

EFi = Facility emission factor for a meter/regulator 

run at above grade metering-regulating for GHGi in 

cubic feet per meter/regulator run per hour.
Page 177 of 209

Es,i = Annual volumetric GHG i emissions, CO2 or CH4 at 

standard condition from all equipment leak 

sources at all above grade TD transfer stations, 

from paragraph (q) of this section.

Count = Total number of meter/regulator runs at all TD

transfer stations.

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.

* * * * *

(2) Calculate GHG volumetric emissions at standard 

conditions using actual GHG emissions temperature and 

pressure, and Equation W-34 of this section.

* * * * *

(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 
Page 178 of 209

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 

available analyses in each of the sub-basin categories.

(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 
Page 179 of 209

have a continuous gas composition analyzer on feed natural 

gas, you must use these values for determining the mole 

fraction. If you do not have a continuous gas composition 

analyzer, then annual samples must be taken according to 

methods set forth in §98.234(b).

(iii) GHG mole fraction in transmission pipeline 

natural gas that passes through the facility for onshore 

natural gas transmission compression facilities. 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 

underground natural gas storage facilities. 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 LNG 

storage facilities. 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 LNG 

import and export facilities. For export facilities that 

receive gas from transmission pipelines, you may use a 

default 95 percent methane and 1 percent carbon dioxide 

fraction for GHG mole fraction in natural gas. 
Page 180 of 209

(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 at standard conditions by 

converting the GHG volumetric emissions at standard 

conditions into mass emissions using Equation W-36 of this 

section.

* * * * *

Masss,i = GHG i (either CH4 , CO2, or N2O) mass emissions at 

standard conditions in metric tons CO2e. 

Es,i = GHG i (either CH4, CO2, or N2O) volumetric 

emissions at standard conditions, in cubic feet.

 i = Density of GHG i. Use 0.0520 kg/ft3 for CO2 and 

N2O, and 0.0190 kg/ft3 for CH4 at 68°F and 14.7 

psia or 0.0530 kg/ft3 for CO2 and N2O, and 0.0193 

kg/ft3 for CH4 at 60°F and 14.7 psia .

* * * * *

(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) of this section, as follows:
Page 181 of 209

(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 is natural gas and is of pipeline quality 

specification and has a minimum high heat value of 950 Btu 

per standard cubic foot, use the calculation methodology 

described in (z)(1)(i) and you may use the emission factor 

provided for natural gas as listed in Table C-1. If the 

fuel is natural gas, and is not pipeline quality or has a 

high heat value of less than 950 But per standard cubic 

feet, calculate emissions according to (z)(2). If the fuel 

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

gas or process vent gas, calculate emissions according to 

(z)(2).

(i) For fuels listed in Table C-1 or a blend 

containing one 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. 
Page 182 of 209

(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 paragraph (u)(2)(i) of 

this section.
Page 183 of 209

15. 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). 

§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 
Page 184 of 209

optical gas imaging instrument to image the source types 

required by this subpart in accordance with the instrument 

manufacturer’s operating parameters. 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 throughvalve leak. When using the acoustic leak detection device, 

if a leak of 3.1 scf per hour or greater is calculated, a 
Page 185 of 209

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 

must be of sufficient size that the entire emissions volume 

can be encompassed for measurement.

* * * * *

(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 
Page 186 of 209

volumetric natural gas emissions using the calculations in 

§98.233(u) and (v).

16. 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 paragraphs (c)(5) introductory text, 

(c)(5)(iii), and (c)(5)(vi); and adding paragraph 

(c)(5)(vii).

h. Revising paragraphs (c)(6) introductory text, 

(c)(6)(i) introductory text, (c)(6)(i)(B), (c)(6)(i)(D), 

(c)(6)(i)(G), and (c)(6)(i)(H); and adding paragraph 

(c)(6)(ii)(I).

i. Revising paragraphs (c)(6)(ii)(B) and 

(c)(6)(ii)(D); and adding paragraph (c)(6)(ii)(E).
Page 187 of 209

j. Revising paragraphs (c)(7)(i) and (c)(7)(ii); and 

adding paragraphs (c)(7)(iii).

k. Revising paragraphs (c)(8)(i) introductory text 

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

through (c)(8)(i)(M).

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)(i) and (c)(9)(ii); and 

adding paragraph (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)(i)(B) and 

(c)(15)(i)(C). 

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

(c)(15)(ii)(C). 
Page 188 of 209

u. Revising paragraphs (c)(16)(i) through 

(c)(16)(iv), (c)(16)(vi), and (c)(16)(xv).

v. Removing and reserving paragraph (c)(16)(v).

w. Adding paragraphs (c)(16)(xvi) through 

(c)(16)(xx).

x. Revising paragraph (c)(17)(v) and adding 

paragraph (c)(17)(vi).

y. Revising paragraph (c)(18) introductory text and 

paragraph (c)(18)(iii). 

z. Revising paragraph (c)(19)(iii) and (c)(19)(vi).

aa. Adding paragraph (e). 

The revisions read as follows:

§98.236 Data Reporting Requirements .

* * * * *

(a) Report annual emissions 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 the emissions 

source types listed in the most recent BOEMRE study. 
Page 189 of 209

(c) Report the information listed in this paragraph 

for each applicable source type. If a facility operates 

under more than one industry segment, each piece of 

equipment should be reported under its 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
Page 190 of 209

content in the vent from the acid gas removal unit (refer 

to §98.233(d)(6)).

(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.

(v) Report annual CO2 emissions for the AGR unit, 

expressed in metric tons CO2e.

(vi) 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 
Page 191 of 209

gas from the dehydrator, expressed in metric tons CO2e for 

each gas.

(L) A unique name or ID number for the 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 a 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 a 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 (refer to 

Equations W-7, W-8 and W-9 of §98.233), report the 
Page 192 of 209

following by each well tubing diameter grouping and 

pressure grouping within each sub-basin category:

* * * * *

(iii) Cumulative number of unloadings vented to the 

atmosphere.

* * * * *

(vi) Report annual CO2 and CH4 emissions, expressed in 

metric tons CO2e for each gas, for each tubing diameter and 

pressure grouping within each sub-basin category.

(vii) When using Calculation Methodology 1, casing 

diameter, depth and pressure of each well selected to 

represent emissions in that tubing size and pressure 

combination (refer to Equation W-7 of §98.233).

(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-10 of 

§98.233):

* * * * * 

(B) Average flow rate of the measured well completion 

venting in cubic feet per hour (refer to Equation W-12 of 

§98.233).

* * * * * 
Page 193 of 209

(D) Average flow rate of the measured well workover 

venting in cubic feet per hour (refer to Equation W-12 of 

§98.233).

* * * * * 

(G) Report number of completions and number of 

workovers employing reduced emissions completions and 

engineering estimate based on best available data of the 

amount of gas recovered to sales.

(H) Annual CO2 and CH4 emissions that resulted from 

venting gas directly to the atmosphere, expressed in metric 

tons CO2e for each gas.

(I) Annual CO2, CH4, and N2O emissions that resulted 

from flares, expressed in metric tons CO2e for each gas.

* * * * * 

(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) * * *
Page 194 of 209

(i) Total number of blowdowns per unique volume type 

in calendar year. 

(ii) Annual CO2 and CH4 emissions, expressed in metric 

tons CO2e for each gas, for each unique volume type, at each 

blowdown stack.

(iii) A unique name or ID number for the blowdown 

vent stack.

(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 sub-basin 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 each wellhead gas-liquid separator or 

storage tank using Calculation Methodology 1 or 2 of 

§98.233(j).

(K) Annual CO2 and CH4 gas quantities that were 

recovered, expressed in metric tons CO2e for each gas, for 

each wellhead gas-liquid separator or storage tank using 

Calculation Methodology 1 or 2 of §98.233(j).
Page 195 of 209

(L) Annual CO2, CH4, and N2O emissions that resulted 

from flaring gas, expressed in metric tons CO2e for each 

gas, for each wellhead gas-liquid separator or storage tank

using Calculation Methodology 1 or 2 of §98.233(j).

(M) A unique name or ID number for each wellhead gas 

liquid separator or storage tank.

(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).
Page 196 of 209

(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 
Page 197 of 209

for each gas, at the sub-basin level for improperly 

functioning dump valves.

(9) * * *

(i) For each transmission storage tank, 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 transmission 

storage tank. 

(10) For well testing venting and flaring (refer to 

Equation W-17 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.
Page 198 of 209

(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) 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) * * *
Page 199 of 209

(i) * * *

(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 Equation W-30 of §98.233), by 

equipment type.

(ii) * * *

(A) For source categories §98.230(a)(4), (a)(5), 

(a)(6), (a)(7), and (a)(8), total count for each type of 

leak source in Tables W-2, W-3, W-4, W-5, and W-6 of this 

subpart for which there is a population emission factor, 

listed by major heading and component type.

(B) For onshore production (refer to §98.230

paragraph (a)(2)), total count for each type of major 

equipment in Table W-1B and Table W-1C of this subpart, by 

sub-basin category.

(C) Annual CO2 and CH4 emissions, in metric tons CO2e 

for each gas (refer to Equation W-31 of §98.233), by 

equipment type.

(16) * * *

(i) Number of above grade T-D transfer stations.

(ii) Number of below grade T-D transfer stations.
Page 200 of 209

(iii) Number of above grade metering-regulating

stations (this count will include above grade T-D transfer 

stations).

(iv) Number of below grade metering-regulating 

stations (this count will include below grade T-D transfer 

stations).

(v) [Reserved]

(vi) Above grade metering-regulating station leak 

factor (refer to Equation W-32 of §98.233).

* * * * *

(xv) Annual CO2 and CH4 emissions, in metric tons CO2e 

for each gas, from all above grade T-D transfer stations 

combined. 

(xvi) Annual CO2 and CH4 emissions, in metric tons 

CO2e for each gas, from all below grade T-D transfer 

stations combined. 

(xvii) 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.

(xviii) 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.

(xix) Annual CO2 and CH4 emissions, in metric tons 

CO2e for each gas, from all distribution mains combined.
Page 201 of 209

(xx) 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.

(vi) A unique name or ID for the EOR pump.

(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 at 

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.

* * * * * 

(vi) Report annual CO2, CH4, and N2O emissions from 

internal combustion units, expressed in metric tons CO2e for 

each gas, by type of unit. 

* * * * *

(e) For onshore petroleum and natural gas production, 

report the average API gravity, average gas to oil ratio, 
Page 202 of 209

and average low pressure separator pressure for each subbasin category.

17. 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.

18. 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”, ”Natural gas”, “Meteringregulating station”, “Pressure groupings”, “Sub-basin 

category”, “Transmission-distribution transfer station”, 
Page 203 of 209

“Tubing diameter groupings”, “Tubing systems”, “Vertical 

well”, and “Well testing venting and flaring”.

c. Removing the definition of “Field”.

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. This does not include storage and condensate 

tanks that are located downstream of the point of 

combination. 

* * * * *

Distribution pipeline means a pipeline that is 

designated as such by the Pipeline and Hazardous Material 

Safety Administration (PHMSA) 49 C.F.R. §192.3.

* * * * *

Facility with respect to natural gas distribution for 

purposes of reporting under this subpart and for the 

corresponding subpart A requirements means the collection 

of all distribution pipelines and metering-regulating 
Page 204 of 209

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 well-pad or 

associated with a well-pad and CO2 EOR operations that are 

under common ownership or common control including leased, 

rented, or contracted activities by an onshore petroleum 

and natural gas production owner or operator and that are 

located in a single hydrocarbon basin as defined in 

§98.238. Where a person or entity owns or operates more 

than one well in a basin, then all onshore petroleum and 

natural gas production equipment associated with all wells 

that the person or entity owns or operates in the basin 

would be considered one facility.

Farm Taps are pressure regulation stations that 

deliver gas directly from transmission pipelines to 

generally rural customers. In some cases a nearby LDC may 

handle the billing of the gas to the customer(s). 

* * * * *
Page 205 of 209

Flare, for the purposes of subpart W, means a 

combustion device, whether at ground level or elevated, 

that uses an open or closed flame to combust waste gases 

without energy recovery. 

* * * * *

Forced extraction of natural gas liquids means removal 

of ethane or higher carbon number hydrocarbons existing in 

the vapor phase in natural gas, by removing ethane or 

heavier hydrocarbons derived from natural gas into natural 

gas liquids by means of a forced extraction process. 

Forced extraction processes include but are not limited to 

refrigeration, absorption (lean oil), cryogenic expander, 

and combinations of these processes. Forced extraction 

does not include in and of itself; natural gas dehydration, 

or the collection or gravity separation of water or 

hydrocarbon liquids from natural gas at ambient temperature 

or heated above ambient temperatures, or the condensation 

of water or hydrocarbon liquids through passive reduction 

in pressure or temperature, or portable dewpoint 

suppression skids. 

* * * * *

Horizontal well means a well bore that has a planned 

deviation from primarily vertical to a primarily horizontal 
Page 206 of 209

inclination or declination tracking in parallel with and 

through the target formation.

* * * * *

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. 

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. 

* * * * *

Pressure groupings 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.

* * * * *

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 
Page 207 of 209

the boundaries of an individual county and subsurface 

completion in one or more of each of the following four 

formation types as designated by 18 C.F.R. 270.305: 

conventional with >0.1 millidarcy permeability, and 

unconventional with ≤0.1 millidarcy permeability. 

Unconventional formation types are either shale, coal seam, 

or other tight reservoir rock. Wells producing from more 

than one unconventional formation type shall be classified 

into only one type based on the formation with the most 

contribution to production as determined by engineering 

knowledge. Unconventional wells producing in two or more 

formation types of “shale and coal seam”, “shale and other 

tight”, or “shale, coal seam, and other tight”; are 

considered shale. In addition, unconventional wells 

producing in “coal seam and other tight" formations are 

considered coal.

Transmission-distribution (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 means a Federal Energy 

Regulatory Commission rate-regulated Interstate pipeline, a 

state rate-regulated Intrastate pipeline, or a pipeline 
Page 208 of 209

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 groupings are defined as follows: 

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 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 (i.e., the well testing) through a choke 

(an orifice restriction). If well testing is conducted 

immediately after well completion or workover, then it is 

considered part of well completion or workover.

19. Table W-7 to subpart W is amended by:

a. Revising the entries for “Leaker Emission Factors—

Above Grade M&R at City Gate1 Stations Components, Gas 
Page 209 of 209

Service,” “Population Emission Factors - Below Grade M&R2

Components, Gas Service3,” “Population Emission Factors -

Distribution Mains, Gas Service4,” and “Population Emission 

Factors - Distribution Services, Gas Service5.”

b. Removing Footnote 1.

c. Redesignating Footnotes 2, 3, 4, and 5 as 

Footnotes 1, 2, 3, and 4.

The revisions read as follows:

* * * * * * *

Leaker Emission Factors – Transmission-distribution Transfer Station1

Components, Gas Service

* * * * * * *

Population Emission Factors - Below Grade Metering-Regulating station1

Components, Gas Service2

* * * * * * *

Population Emission Factors - Distribution Mains, Gas Service3

* * * * * * *

Population Emission Factors - Distribution Services, Gas Service4

* * * * * * *

1 Excluding customer meters.

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

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

4 Emission Factor is in units of “scf/hour/number of services.”