56010 Federal Register / Vol. 76, No. 175 / Friday, September 9, 2011 / Proposed Rules 

ENVIRONMENTAL PROTECTION 

AGENCY 

40 CFR Part 98 

[EPA–HQ–OAR–2011–0512; FRL–9456–4] 

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. 

DATES: Comments. Comments must be 

received on or before October 11, 2011, 

unless a public hearing is held, in 

which case comments must be received 

on or before October 24, 2011. 

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 

September 16, 2011. If requested, the 

hearing will be conducted on September 

26, 2011, in the Washington, DC area. 

EPA will publish further information 

about the hearing in the Federal 

Register 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. 

E-mail: 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. 

• 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 e-mail. 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 e-mail comment directly 

to EPA without going through http:// 

www.regulations.gov your e-mail 

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 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; e-mail address: 

GHGReportingRule@epa.gov. For 

technical questions, please see the 

Greenhouse Gas Reporting Program Web 

site http://www.epa.gov/climatechange/ 

emissions/ghgrulemaking.html. 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.html. Alternatively, you 

may contact Carole Cook at 202–343– 

9263. 

SUPPLEMENTARY INFORMATION: 

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.html. 

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, e-mail address: 

GHGReportingRule@epa.gov. 

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: 

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Federal Register / Vol. 76, No. 175 / Friday, September 9, 2011 / Proposed Rules 56011 

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. 

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 

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 

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? 

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 Low-Income 

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 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 

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56012 Federal Register / Vol. 76, No. 175 / Friday, September 9, 2011 / Proposed Rules 

(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) 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 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-custody-transfer 

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. 

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. 

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. 

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TABLE 2—PETITIONS FOR RECONSIDERATION—Continued 

Petitioner and date of letter Issue raised for reconsideration Is this issue addressed in this action? 

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. 

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 

proposedEPA 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. 

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. 

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56014 Federal Register / Vol. 76, No. 175 / Friday, September 9, 2011 / Proposed Rules 

TABLE 2—PETITIONS FOR RECONSIDERATION—Continued 

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 CFR 

§ 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. 

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.’ Thisis not helpful 

and gives industry no clarity regarding 

which compressor stations are required to 

report’’.

Yes. 

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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TABLE 2—PETITIONS FOR RECONSIDERATION—Continued 

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. 

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. 

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. 

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56016 Federal Register / Vol. 76, No. 175 / Friday, September 9, 2011 / Proposed Rules 

TABLE 2—PETITIONS FOR RECONSIDERATION—Continued 

Petitioner and date of letter Issue raised for reconsideration Is this issue addressed in this action? 

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 which was not included in the proposal’’.

No. 

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. 

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. 

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TABLE 2—PETITIONS FOR RECONSIDERATION—Continued 

Petitioner and date of letter Issue raised for reconsideration Is this issue addressed in this action? 

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 

high-bleed, continuous low-bleed, 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. 

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. 

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 basinlevel 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. 

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56018 Federal Register / Vol. 76, No. 175 / Friday, September 9, 2011 / Proposed Rules 

TABLE 2—PETITIONS FOR RECONSIDERATION—Continued 

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). 

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. 

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). 

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Federal Register / Vol. 76, No. 175 / Friday, September 9, 2011 / Proposed Rules 56019 

TABLE 2—PETITIONS FOR RECONSIDERATION—Continued 

Petitioner and date of letter Issue raised for reconsideration Is this issue addressed in this action? 

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. 

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. 

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’’) 

and 76 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 

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 

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56020 Federal Register / Vol. 76, No. 175 / Friday, September 9, 2011 / Proposed Rules 

1 74 FR 16448 (April 10, 2009) and 74 FR 56260 

(October 30, 2009). 

2EPA 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. 

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. 

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 legal authority, 

see the preambles to the proposed and 

2009 final part 981.1

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. 

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 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 2012,2

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 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 for the 2011 reporting 

year, but apply them to the sub-basin 

categories based on BAMM. 

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Federal Register / Vol. 76, No. 175 / Friday, September 9, 2011 / Proposed Rules 56021 

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. 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 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. 

• 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 

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 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. 

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56022 Federal Register / Vol. 76, No. 175 / Friday, September 9, 2011 / Proposed Rules 

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 

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., 

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 

petroleum and natural gas production 

segment from a ‘‘field’’ level, to a subbasin 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 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 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 

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) 

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Federal Register / Vol. 76, No. 175 / Friday, September 9, 2011 / Proposed Rules 56023 

3For 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–OAR–2008–0508.) 

4HTFs 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.) 

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, 

tertiary amine or aminoether, any 

perfluoropolyether, and any 

hydrofluoropolyether.’’ As EPA stated 

in the preamble to the final rule, ‘‘This 

modification ensures that non-volatile 

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 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 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

(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. 

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 

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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. 

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 

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., 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-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 massbalances 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 nonHTF 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 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 

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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 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 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. 

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 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 field-level 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 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 ‘‘fieldlevel’’ 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 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 

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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 

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 sub-basin 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 field-level 

approach. 

The foundation of the proposed subbasin approach is defining a sub-basin 

category through the use of a county 

level designation and the distinction of 

the type of hydrocarbon formation. The 

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 subbasin 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 subbasin 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 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 

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. 

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. 

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 

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industry segment includes that 

equipment that is ‘‘on a single well-pad 

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 wellpad 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 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 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 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. 

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 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) rateregulated 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 

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production fields or gas processing 

plants, but also move natural gas 

coming from other transmission 

compressors. In 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 ‘‘meterregulating 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 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 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 

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 ‘‘meter-regulator’’ 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’’ and replacing the term ‘‘noncustody 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 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 

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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. 

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. 

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. 

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 

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 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. 

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 

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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 ‘‘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 

sub-basin 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 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 (Subbasin Category for Onshore Petroleum 

and Natural Gas Production), that 

reporting should be for each well tubing 

diameter grouping and pressure 

grouping within each sub-basin 

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). 

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 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 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. 

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 

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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. 

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. 

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 

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. 

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 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 

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 

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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, 

pentane-plus 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 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 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

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 ‘‘meter-regulating’’ is a term 

that we are proposing to define in 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 transmissiondistribution 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 meteringregulating 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 the 

Administrator. For natural gas 

distribution facilities at transmissiondistribution 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–HQ–OAR–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 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 

‘‘non-custody transfer city-gate’’ with 

above grade ‘‘metering-regulating 

station’’ for the reason stated above in 

this preamble. We are also clarifying 

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that the count in 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 W–31 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 wellpad 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 ‘‘meteringregulating stations’’ in place of ‘‘city 

gate’’ and to clarify that the emission 

factor for meter/regulator runs at all 

metering-regulating stations in equation 

W–32 is based on 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 ‘‘metering-regulation 

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 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 ‘‘sub-basin 

category’’ for the reasons outlined in 

Section II.C. of this preamble (Sub-Basin 

Category Reporting for Onshore 

Petroleum and Natural Gas Production). 

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 

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 combustion-related 

emissions and when they must use the 

methods in 40 CFR 98.233(z) to 

calculate combustion-related emissions. 

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 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 

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5Response to Comments Document: Subpart W— 

Petroleum and Natural Gas Systems, part 2, page 28. 

Comment Number: EPA–HQ–OAR–2009–0923– 

1039–23. 

potential equipment threshold for noncompressor internal combustion 

engines, EPA collected and reviewed 

data on the size ranges of 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 combustionrelated emissions at compressors should 

not be excluded from reporting, 

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 rule,5 EPA 

did not intend to require retention of a 

video 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 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 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. 

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 ‘‘noncustody 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 

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characteristics to characterize other 

emissions sources across different subbasins.’’ 

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 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 wellpad. The association with a single wellpad 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 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 gasliquid 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 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 

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 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 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 

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56036 Federal Register / Vol. 76, No. 175 / Friday, September 9, 2011 / Proposed Rules 

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 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. 

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 

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 

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 (RFA) 

The Regulatory Flexibility Act (RFA) 

generally requires an agency to prepare 

a regulatory flexibility analysis of any 

rule subject to notice and comment 

rulemaking requirements under the 

Administrative Procedure Act or any 

other statute unless the agency certifies 

that the rule will not have a significant 

economic impact on a substantial 

number of small entities. Small entities 

include small businesses, small 

organizations, and small governmental 

jurisdictions. 

For purposes of assessing the impacts 

of this 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-forprofit 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 

entities, since the primary purpose of 

the regulatory flexibility analyses is to 

identify and address regulatory 

alternatives ‘‘which minimize any 

significant economic impact of the rule 

on small entities’’ 5 U.S.C. 603 and 604. 

Thus, an agency may certify that a rule 

will not have a significant economic 

impact on a substantial number of small 

entities if the rule relieves regulatory 

burden, or otherwise has a positive 

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Federal Register / Vol. 76, No. 175 / Friday, September 9, 2011 / Proposed Rules 56037 

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 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 

(UMRA) 

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 

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 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 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. 

J. Executive Order 12898: Federal 

Actions To Address Environmental 

Justice in Minority Populations and 

Low-Income Populations 

Executive Order 12898 (59 FR 7629, 

February 16, 1994) establishes federal 

executive policy on environmental 

justice. Its main provision directs 

federal agencies, to the greatest extent 

practicable and permitted by law, to 

make environmental justice part of their 

mission by identifying and addressing, 

as appropriate, disproportionately high 

and adverse human health or 

environmental effects of their programs, 

policies, and activities on minority 

populations and low-income 

populations in the United States. 

EPA has determined that this 

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. 

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56038 Federal Register / Vol. 76, No. 175 / Friday, September 9, 2011 / Proposed Rules 

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: August 19, 2011. 

Lisa P. Jackson, 

Administrator. 

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. 

* * * * * 

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) * * * 

(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 

I–16 to read as follows. 

§ 98.93 Calculating GHG Emissions. 

* * * * * 

(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 this 

subpart, for each fluorinated heat 

transfer fluid used. 

* * * * * 

10. Section 98.98 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: 

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). 

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Federal Register / Vol. 76, No. 175 / Friday, September 9, 2011 / Proposed Rules 56039 

Subpart W—[Amended] 

12. Section 98.230 is amended by 

revising paragraphs (a)(2) through (a)(4), 

and (a)(8) to read as follows: 

§ 98.230 Definition of the source category. 

(a) * * * 

(2) Onshore petroleum and natural 

gas production. Onshore petroleum and 

natural gas production means all 

equipment on a single well-pad or 

associated with a single well-pad 

(including but not limited to 

compressors, generators, dehydrators, 

storage vessels, and portable non-selfpropelled equipment which includes 

well drilling and completion 

equipment, workover equipment, 

gravity separation equipment, auxiliary 

non-transportation-related equipment, 

and leased, rented or contracted 

equipment) used in the production, 

extraction, recovery, lifting, 

stabilization, separation or treating of 

petroleum and/or natural gas (including 

condensate). This equipment also 

includes associated storage or 

measurement vessels and all enhanced 

oil recovery (EOR) operations using CO2

or natural gas injection, and all 

petroleum and natural gas production 

equipment located on islands, artificial 

islands, or structures connected by a 

causeway to land, an island, or an 

artificial island. 

(3) Onshore natural gas processing. 

Natural gas processing means the 

separation of natural gas liquids (NGLs) 

or non-methane gases from produced 

natural gas, or the separation of NGLs 

into one or more component mixtures. 

Separation includes one or more of the 

following: Forced extraction of natural 

gas liquids, sulfur and carbon dioxide 

removal, fractionation of NGLs, or the 

capture of CO2 separated from natural 

gas streams. This segment also includes 

all residue gas compression equipment 

owned or operated by the natural gas 

processing plant. This industry segment 

includes processing plants that 

fractionate gas liquids, and processing 

plants that do not fractionate gas liquids 

but have an annual average throughput 

of 25 MMscf per day or greater. 

(4) Onshore natural gas transmission 

compression. Onshore natural gas 

transmission compression means any 

stationary combination of compressors 

that move natural gas from production 

fields, natural gas processing plants, or 

other transmission compressors through 

transmission pipelines to natural gas 

distribution pipelines, LNG storage 

facilities, or into underground storage. 

In addition, a transmission compressor 

station includes equipment for liquids 

separation, and tanks for the storage of 

water and hydrocarbon liquids. Residue 

(sales) gas compression that is part of 

onshore natural gas processing plants 

are included in the onshore natural gas 

processing segment and are excluded 

from this segment. 

* * * * * 

(8) Natural gas distribution. Natural 

gas distribution means the distribution 

pipelines and metering and regulating 

equipment at metering-regulating 

stations that are operated by a Local 

Distribution Company (LDC) within a 

single state that is regulated as a 

separate operating company by a public 

utility commission or that is operated as 

an independent municipally-owned 

distribution system. This segment also 

excludes customer meters and 

regulators, infrastructure, and pipelines 

(both interstate and intrastate) 

delivering natural gas directly to major 

industrial users and farm taps upstream 

of the local distribution company inlet. 

* * * * * 

13. Section 98.232 is amended by: 

a. Revising paragraph (c) introductory 

text and paragraph (c)(22). 

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 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: 

* * * * * 

(i) For natural gas distribution, report 

CO2, CH4, and N2O emissions from the 

following sources: 

(1) Meters, regulators, and associated 

equipment at above grade transmissiondistribution transfer stations, including 

equipment leaks from connectors, block 

valves, control valves, pressure relief 

valves, orifice meters, regulators, and 

open ended lines. 

(2) Equipment leaks from vaults at 

below grade transmission-distribution 

transfer stations. 

(3) Meters, regulators, and associated 

equipment at above grade meteringregulating 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 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 

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56040 Federal Register / Vol. 76, No. 175 / Friday, September 9, 2011 / Proposed Rules 

‘‘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 ‘‘a’’ 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). 

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 introductory texts for 

paragraphs (g)(1) and (g)(1)(i). 

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

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

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

paragraph (g)(1)(ii) introductory text; 

redesignating Equation W–11 as 

Equation W–11A and Equation W–12 as 

Equation W–11B respectively; and 

adding 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 introductory texts for 

paragraphs (g)(3) and (g)(5). 

v. In paragraph (h), revising paragraph 

(h) introductory text and 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 

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. 

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 introductory texts for 

paragraphs (t), (t)(1), and (t)(2). 

kk. Revising paragraph (u) 

introductory text and paragraph (u)(2). 

ll. In paragraph (v), revising paragraph 

(v) introductory text and the definitions 

of ‘‘Masss,i’’, ‘‘Es,i’’, and ‘‘ri’’ in Equation 

W–36. 

mm. Revising introductory texts for 

paragraphs (z), (z)(1), (z)(2), (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) * * * 

* * * * * 

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) * * * 

* * * * * 

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. 

* * * * * 

(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 


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Federal Register / Vol. 76, No. 175 / Friday, September 9, 2011 / Proposed Rules 56041 

may elect to install a CO2 concentration 

monitor and a volumetric flow rate 

monitor that comply with all of the 

requirements specified for the Tier 4 

Calculation Methodology in subpart C of 

this part (General Stationary Fuel 

Combustion). The calculation and 

reporting of CH4 and N2O emissions is 

not required as part of the Tier 4 

requirements for AGRs. 

* * * * * 

(3) * * * 

* * * * * 

(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. 

* * * * * 

(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 sub-basin category), where gas wells 

are vented to the atmosphere to expel 

liquids accumulated in the tubing, a 

recording flow meter shall be installed 

on the vent line used to vent gas from 

the well (e.g., on the vent line off the 

wellhead separator or atmospheric 

storage tank) according to methods set 

forth in § 98.234(b). Calculate emissions 

from well venting for liquids unloading 

using Equation W–7 of this section. 

* * * * * 

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 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 subbasin category, an average flow rate is 

calculated beginning in the first year of 

production. 

(2) * * * 

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) * * * 

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). 


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56042 Federal Register / Vol. 76, No. 175 / Friday, September 9, 2011 / Proposed Rules 

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) * * * 

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 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 

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 greater than or equal to 2, 

then flow is sonic; otherwise, flow is 

subsonic: 

Where: 

FR = Average flow rate in cubic feet per hour, 

under subsonic flow conditions. 

A = Cross sectional area of orifice (m2). 

P1 = Upstream pressure (psia). 

Tu = Upstream temperature (degrees Kelvin). 

P2 = Downstream pressure (psia). 

3430 = Constant with units of m2/(sec2 * K). 

1.27*105 = Conversion from m3/second to 

ft3/hour. 

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 m2/(sec2 * K). 

1.27*105 = Conversion from m3/second to 

ft3/hour. 


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Where: 

R = Pressure ratio 

P1 = Pressure upstream of the restriction 

orifice in pounds per square inch 

absolute. 

P2 = Pressure downstream of the restriction 

orifice in pounds per square inch 

absolute. 

(iii) The emissions to 30-day production 

ratio is calculated using Equation W–12 of 

this section. 

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 subbasin and well type combination. 

W = Number of wells completed or worked 

over using hydraulic fracturing in a subbasin 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 subbasin and well type combination for the 

total number of hours of venting of each 

of these wells. 

(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). 

* * * * * 

(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 shutdowns or to 

take equipment out of service for 

maintenance (excluding depressurizing 

to a flare, over-pressure relief, operating 

pressure control venting and blowdown 

of non-GHG gases; desiccant dehydrator 

blowdown venting before reloading is 

covered in paragraph (e)(5) of this 

section) as follows: 

(1) Calculate the 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. 

Where: 

* * * * * 

Vv = Total volume of blowndown equipment 

chambers (including pipelines, 

compressors and vessels) between 

isolation valves in cubic feet. 

* * * * * 


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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 (°F). 

Ta = Temperature at actual conditions in the 

blowdown equipment chamber (°F) 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. 

* * * * * 

(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 subbasin category and assume all of the CH4

and CO2 in both oil and gas are emitted 

from the tank. 

* * * * * 

(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 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 

de-methanizer overhead or dew point 

control for onshore natural gas 

processing facilities. For onshore 

natural gas processing plants that solely 

fractionate a liquid stream, use the GHG 

mole percent in feed natural gas liquid 

for all streams. 

(iii) For any applicable industry 

segment, when the stream going to the 

flare is a hydrocarbon product stream, 

such as methane, ethane, propane, 

butane, pentane-plus and mixed light 

hydrocarbons, then you may use a 

representative composition from the 

source for the stream determined by 

engineering calculation based on 

process knowledge and best available 

data. 

* * * * * 

(n) * * * 

* * * * * 

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 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. 


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(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. 

* * * * * 

(q) * * * 

* * * * * 

* * * * * 

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. 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 transmissiondistribution 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 transmissiondistribution transfer stations and 

metering-regulating stations that do not 

meet the definition of transmissiondistribution 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 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 metering-regulating 

stations is determined in Equation W–32 

of this section. 

GHGi = For onshore petroleum and natural 

gas production facilities, concentration of 

GHGi, CH4 or CO2, in produced natural gas; 

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. 

* * * * * 

(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 

metering-regulating stations (including 

above grade TD transfer stations) shall 

be calculated by applying the emission 

factor calculated in Equation W–32 and 

the total count of meter/regulator runs at 

all above grade metering-regulating 

stations (inclusive of TD transfer 

stations) to Equation W–31. The facility 

wide emission factor in Equation W–32 

will be calculated by using the total 

volumetric GHG emissions at standard 

conditions for all equipment leak 

sources calculated in paragraph (q)(8) of 

this section and the count of meter/ 

regulator runs located at above grade 

transmission-distribution transfer 

stations. 

Where: 

EFi = Facility emission factor for a meter/ 

regulator run at above grade meteringregulating for GHGi in cubic feet per 

meter/regulator run per hour. 

Es,i = Annual volumetric GHG i emissions, 

CO2 or CH4 at standard condition from 

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 


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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 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 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. 

(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. 

ri = 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: 

(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. 

(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. 

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 

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sensitivity level of 60 grams per hour as 

stated in 40 CFR part 60, subpart A, 

Table 1: Detection Sensitivity Levels; 

§ 60.18(i)(2)(ii) and (iii) except the gas 

chosen shall be methane, and 

§ 60.18(i)(2)(iv) and (v); § 60.18(i)(3); 

§ 60.18(i)(4)(i) and (v); including the 

requirements for daily instrument 

checks and distances, and excluding 

requirements for video records. Any 

emissions detected by the optical gas 

imaging instrument is a leak unless 

screened with Method 21 (40 CFR part 

60, appendix A–7) monitoring, in which 

case 10,000 ppm or greater is designated 

a leak. In addition, you must operate the 

optical gas imaging instrument to image 

the source types required by this 

subpart in accordance with the 

instrument manufacturer’s operating 

parameters. An optical gas imaging 

instrument must be used for all source 

types that are inaccessible and cannot 

be monitored without elevating the 

monitoring personnel more than 2 

meters above a support surface. 

(2) Method 21. Use the equipment 

leak detection methods in 40 CFR part 

60, appendix A–7, Method 21. If using 

Method 21 monitoring, if an instrument 

reading of 10,000 ppm or greater is 

measured, a leak is detected. 

Inaccessible emissions sources, as 

defined in 40 CFR part 60, are not 

exempt from this subpart. Owners or 

operators must use alternative leak 

detection devices as described in 

paragraph (a)(1) or (a)(2) of this section 

to monitor inaccessible equipment leaks 

or vented emissions. 

* * * * * 

(5) Acoustic leak detection device. 

Use the acoustic leak detection device to 

detect through-valve leakage. When 

using the acoustic leak detection device 

to quantify the through-valve leakage, 

you must use the instrument 

manufacturer’s calculation methods to 

quantify the through-valve leak. When 

using the acoustic leak detection device, 

if a leak of 3.1 scf per hour or greater 

is calculated, a leak is detected. In 

addition, you must operate the acoustic 

leak detection device to monitor the 

source valves required by this subpart in 

accordance with the instrument 

manufacturer’s operating parameters. 

Acoustic stethoscope type devices 

designed to detect through valve leakage 

when put in contact with the valve body 

and that provide an audible leak signal 

but do not calculate a leak rate can be 

used to identify non-leakers with 

subsequent measurement required to 

calculate the rate if through-valve 

leakage is identified. Leaks are reported 

if a leak rate of 3.1 scf per hour or 

greater is measured. 

* * * * * 

(c) Use calibrated bags (also known as 

vent bags) only where the emissions are 

at near-atmospheric pressures and 

below the maximum temperature 

specified by the vent bag manufacturer 

such that the bag is safe to handle. The 

bag 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 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). 

j. Revising paragraphs (c)(7)(i) and 

(c)(7)(ii); and adding paragraph 

(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). 

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. 

(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. 

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(2) * * * 

(ii) Report annual CO2 and CH4

emissions at the facility level, expressed 

in metric tons CO2e for each gas, for all 

natural gas driven pneumatic pumps 

combined. 

(3) * * * 

(ii) For Calculation Methodology 1 

and Calculation Methodology 2 of 

§ 98.233(d), annual average fraction of 

CO2 content in the vent from the acid 

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

(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 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 

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). 

* * * * * 

(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) * * * 

(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 subbasin category, unless otherwise 

specified: 

* * * * * 

(J) Annual CO2 and CH4 emissions 

that resulted from venting gas to the 

atmosphere, expressed in metric tons 

CO2e for each gas, for 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). 

(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). 

(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 

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Federal Register / Vol. 76, No. 175 / Friday, September 9, 2011 / Proposed Rules 56049 

Calculation Methodology 3 and 4 of 

§ 98.233(j). 

(iii) For wellhead gas-liquid 

separators and wells with throughput 

less than 10 barrels per day, using 

Calculation Methodology 5 of § 98.233(j) 

Equation W–15 of § 98.233, report the 

following: 

* * * * * 

(F) Annual CO2 and CH4 emissions 

that resulted from venting gas to the 

atmosphere, expressed in metric tons 

CO2e for each gas, at the sub-basin level 

for Calculation Methodology 5 of 

§ 98.233(j). 

(G) Annual CO2 and CH4 gas 

quantities that were recovered, 

expressed in metric tons CO2e for each 

gas, at the sub-basin level for 

Calculation Methodology 5 of 

§ 98.233(j). 

(H) Annual CO2, CH4, and N2O 

emissions that resulted from flaring gas, 

expressed in metric tons CO2e for each 

gas, at the sub-basin level for 

Calculation Methodology 5 of 

§ 98.233(j). 

(iv) * * * 

(B) Annual CO2 and CH4 emissions 

that resulted from venting gas to the 

atmosphere, expressed in metric tons 

CO2e for each gas, at the sub-basin level 

for improperly functioning dump 

valves. 

(9) * * * 

(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. 

(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) * * * 

(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. 

(iii) Number of above grade meteringregulating stations (this count will 

include above grade T–D transfer 

stations). 

(iv) Number of below grade meteringregulating 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 meteringregulating 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. 

(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 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, and 

average low pressure separator pressure 

for each sub-basin 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, 

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56050 Federal Register / Vol. 76, No. 175 / Friday, September 9, 2011 / Proposed Rules 

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’’, 

‘‘Metering-regulating station’’, ‘‘Pressure 

groupings’’, ‘‘Sub-basin category’’, 

‘‘Transmission-distribution transfer 

station’’, ‘‘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 CFR 192.3. 

* * * * * 

Facility with respect to natural gas 

distribution for purposes of reporting 

under this subpart and for the 

corresponding subpart A requirements 

means the collection of all distribution 

pipelines and metering-regulating 

stations that are operated by a Local 

Distribution Company (LDC) within a 

single state that is regulated as a 

separate operating company by a public 

utility commission or that are operated 

as an independent municipally-owned 

distribution system. 

Facility with respect to onshore 

petroleum and natural gas production 

for purposes of reporting under this 

subpart and for the corresponding 

subpart A requirements means all 

petroleum or natural gas equipment on 

a 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). 

* * * * * 

Flare, for the purposes of subpart W, 

means a combustion device, whether at 

ground level or elevated, that uses an 

open or closed flame to combust waste 

gases without energy recovery. 

* * * * * 

Forced extraction of natural gas 

liquids means removal of ethane or 

higher carbon number hydrocarbons 

existing in the vapor phase in natural 

gas, by removing ethane or heavier 

hydrocarbons derived from natural gas 

into natural gas liquids by means of a 

forced extraction process. Forced 

extraction processes include but are not 

limited to refrigeration, absorption (lean 

oil), cryogenic expander, and 

combinations of these processes. Forced 

extraction does not include in and of 

itself; natural gas dehydration, or the 

collection or gravity separation of water 

or hydrocarbon liquids from natural gas 

at ambient temperature or heated above 

ambient temperatures, or the 

condensation of water or hydrocarbon 

liquids through passive reduction in 

pressure or temperature, or portable 

dewpoint suppression skids. 

* * * * * 

Horizontal well means a well bore that 

has a planned deviation from primarily 

vertical to a primarily horizontal 

inclination or declination tracking in 

parallel with and through the target 

formation. 

* * * * * 

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 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 CFR 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 meterregulating station where a local 

distribution company takes part or all of 

the natural gas from a transmission 

pipeline and puts it into a distribution 

pipeline. 

Transmission pipeline means a 

Federal Energy Regulatory Commission 

rate-regulated Interstate pipeline, a state 

rate-regulated Intrastate pipeline, or a 

pipeline that falls under the ‘‘Hinshaw 

Exemption’’ as referenced in section 1(c) 

of the Natural Gas Act, 15 U.S.C. 717– 

717(w)(1994). 

Tubing diameter 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 

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Federal Register / Vol. 76, No. 175 / Friday, September 9, 2011 / Proposed Rules 56051 

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 Gate 1 Stations Components, Gas 

Service,’’ ‘‘Population Emission 

Factors—Below Grade M&R2

Components, Gas Service 3,’’ 

‘‘Population Emission Factors— 

Distribution Mains, Gas Service 4,’’ and 

‘‘Population Emission Factors— 

Distribution Services, Gas Service 5.’’ 

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

*******

1Excluding customer meters. 

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

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

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

[FR Doc. 2011–21725 Filed 9–8–11; 8:45 am] 

BILLING CODE 6560–50–P 

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