6560.50 

ENVIRONMENTAL PROTECTION AGENCY 

40 CFR Part 98 

[EPA-HQ-OAR-2008-0508; FRL-] 

RIN 2060-A079 

Mandatory Reporting of Greenhouse Gases 

AGENCY: Environmental Protection Agency (EPA). 

ACTION: Proposed Rule. 

SUMMARY: EPA is proposing a supplemental rule to require 

reporting of greenhouse gas (GHG) emissions from petroleum 

and natural gas systems. Specifically, the proposed 

supplemental rulemaking would require emissions reporting 

from the following industry segments: onshore petroleum and 

natural gas production, offshore petroleum and natural gas 

production, natural gas processing, natural gas 

transmission compressor stations, underground natural gas 

storage, liquefied natural gas (LNG) storage, LNG import 

and export terminals, and distribution. The proposed 

supplemental rulemaking does not require control of GHGs, 

rather it requires only that sources above certain 

threshold levels monitor and report emissions. 
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DATES: Comments must be received on or before [INSERT THE 

DATE XX DAYS AFTER PUBLICATION IN THE FEDERAL REGISTER]. 

There will be [insert number of hearings] public hearings. 

One hearing will be on [insert date] in [insert location] 

and will begin at [insert time] local time and end at 

[insert time] local time. The second hearing will be on 

[insert date] in [insert location] and will begin at 

[insert time] local time. 

ADDRESSES: You may submit your comments, identified 

by docket [insert docket number and/or RIN number[insert 

RIN number]] by any of the following methods: 

• Federal eRulemaking Portal: 

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

for submitting comments. 

• E-mail: a-and-r-Docket@epa.gov. Include [docket 

number and/or RIN number]in the subject line of the 

message. 

• Fax: (202) 566–1741. 

• Mail: Environmental Protection Agency, EPA Docket 

Center (EPA/DC), Mailcode 6102T, Attention Docket ID No. 

[insert docket], 1200 Pennsylvania Avenue, NW., Washington, 

DC 20460. 

• Hand Delivery: EPA Docket Center, Public Reading 

Room, EPA West Building, Room 3334, 1301 Constitution 
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3 

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. [insert 

docket]. 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 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 
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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 only in hard copy. 

Publicly available docket materials are available either 

electronically in http:// www.regulations.gov or in hard 

copy at the Air Docket, EPA/DC, EPA West, Room [insert 

room], 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 GENERAL INFORMATION CONTACT: Carole Cook, 

Climate Change Division, Office of Atmospheric Programs 

(MC-6207J), Environmental Protection Agency, 1200 

Pennsylvania Ave., NW, Washington, DC 20460; telephone 
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number: (202) 343-9263; fax number: (202) 343-2342; e-mail 

address: GHGReportingRule@epa.gov. For technical 

information contact the Greenhouse Gas Reporting Rule 

Hotline at telephone number: (877)444-1188; or e-mail: 

ghgmrr@epa.gov. To obtain information about the public 

hearings or to register to speak at the hearings, please go 

to http://www.epa.gov/ climatechange/emissions/ 

ghgrulemaking.html. Alternatively, contact Carole Cook at 

202–343–9263. 

SUPPLEMENTARY INFORMATION: 

EPA first proposed Mandatory GHG Reporting 

requirements for petroleum and natural gas systems (under 

40 CFR, part 98, subpart W) in April 2009. EPA received a 

substantial number of comments on this initial proposal for 

petroleum and natural gas systems. For this reason, EPA 

decided not to finalize the rule for petroleum and natural 

gas systems, and instead to propose a supplemental rule. 

EPA reviewed and considered comments submitted on the 

previous proposal in drafting this proposed supplemental 

rulemaking. However, as this is a new proposal, EPA is not 

here responding to comments on the earlier version of this 

rule. Any comments must be submitted as provided herein, 

to be considered. A more detailed background concerning 
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the subpart W rulemaking and proposed changes can be found 

in section II-A. 

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 

GHGReportingRule@epa.gov. 

Although as indicated above, EPA previously proposed a 

version of this rule, that proposal never became final. 

This is a newly proposed rule and comments which were 

submitted on the earlier version of the rule are not being 

considered in the context of this rule. Any parties 

interested in commenting must do so at this time. 

Regulated Entities. The Administrator determined that 

this action is subject to the provisions of Clean Air Act 

(CAA) section 307(d). See CAA section 307(d)(1)(V) (the 

provisions of section 307(d) apply to “such other actions 

as the Administrator may determine.”). This is a proposed 

regulation. If finalized, these regulations would affect 

owners or operators of petroleum and natural gas systems. 
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Regulated categories and entities include those listed in 

Table 1 of this preamble: 

TABLE 1. EXAMPLES OF AFFECTED ENTITIES BY CATEGORY 

Source Category NAICS Examples of affected facilities 

486210 Pipeline transportation of natural 

gas. 

221210 Natural gas distribution 

facilities. 

211 Extractors of crude petroleum and 

natural gas. 

Petroleum and 

Natural Gas 

Systems 

211112 Natural gas liquid extraction 

facilities. 

Table 1 of this preamble is not intended to be 

exhaustive, but rather provides a guide for readers 

regarding facilities likely to be affected by this action. 

Table 1 of this preamble lists the types of facilities that 

EPA is now aware could be potentially affected by the 

reporting requirements. Other types of facilities listed 

in the table could also be subject to reporting 

requirements. To determine whether you are affected by 

this action, you should carefully examine the applicability 

criteria found in proposed 40 CFR part 98, subpart A or the 

relevant criteria in the sections related to petroleum and 

natural gas systems. 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. 
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Many facilities that are affected by the proposed 

supplemental rule have GHG emissions from multiple source 

categories listed in Table 1 of this preamble. Table 2 of 

this preamble has been developed as a guide to help 

potential reporters in the petroleum and natural gas 

industry subject to the proposed rule identify the source 

categories (by subpart) that they may need to (1) consider 

in their facility applicability determination, and/or (2) 

include in their reporting. The table should only be seen 

as a guide. Additional subparts in 40 CFR part 98 may be 

relevant for a given reporter. Similarly, not all listed 

subparts are relevant for all reporters. 

TABLE 2. SOURCE CATEGORIES AND RELEVANT SUBPARTS 

Source category Other Subparts recommended for review 

to determine applicability 

Petroleum and Natural 

Gas Systems 

40 CFR part 98, subpart C 

40 CFR part 98, subpart Y 

40 CFR part 98, subpart MM 

40 CFR part 98, subpart NN 

40 CFR part 98, subpart PP 

40 CFR part 98, subpart RR 

(proposed)

Acronyms and Abbreviations. The following acronyms 

and abbreviations are used in this document. 

ASTM American Society for Testing and Materials 

CAA Clean Air Act 

CBI confidential business information 

cf cubic feet 
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CFR Code of Federal Regulations 

CH4 methane 

CO2 carbon dioxide 

CO2e CO2-equivalent 

EO Executive Order 

EOR enhanced oil recovery 

EPA U.S. Environmental Protection Agency 

GHG greenhouse gas 

GWP global warming potential 

ICR information collection request 

IPCC Intergovernmental Panel on Climate Change 

kg kilograms 

LDCs local natural gas distribution companies 

LNG liquefied natural gas 

LPG liquefied petroleum gas 

MRR mandatory GHG reporting rule 

MMTCO2e million metric tons carbon dioxide equivalent 

N2O nitrous oxide 

NAICS North American Industry Classification System 

NGLs natural gas liquids 

OMB Office of Management and Budget 

QA quality assurance 

QA/QC quality assurance/quality control 

RFA Regulatory Flexibility Act 
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RGGI Regional Greenhouse Gas Initiative 

SSM startup, shutdown, and malfunction 

TCR The Climate Registry 

TSD technical support document 

U.S. United States 

UMRA Unfunded Mandates Reform Act of 1995 

VOC volatile organic compound(s) 

WCI Western Climate Initiative 

TABLE OF CONTENTS 

I. Background 

A. Organization of this Preamble 

B. Background on the Proposed Rule 

C. Legal Authority 

D. Relationship to other Federal, State and Regional 

Programs 

II. Rationale for the Reporting, Recordkeeping and 

Verification Requirements 

A. Overview of Proposal 

B. Major Changes since Initial Rule Proposal 

C. Definition of the Source Category 

D. Selection of Reporting Threshold 

E. Selection of Proposed Monitoring Methods 
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F. Selection of Procedures for Estimating Missing Data 

G. Selection of Data Reporting Requirements 

H. Selection of Records That Must be Retained 

III. Economic Impacts of the Proposed Rule 

A. How were compliance costs estimated? 

B. What are the costs of the proposed rule? 

C. What are the economic impacts of the proposed rule? 

D. What are the impacts of the proposed rule on small 

businesses? 

E. What are the benefits of the proposed rule for society? 

IV. Statutory and Executive Order Reviews 

A. Executive Order 12866: Regulatory Planning and 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 
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J. Executive Order 12898: Federal Actions to Address 

Environmental Justice in Minority Populations and LowIncome Populations 

I. Background 

A. Organization of This Preamble

 This preamble is broken into several large sections, 

as detailed above in the Table of Contents. The paragraphs 

below describe the layout of the preamble and provide a 

brief summary of each section. 

The first section of this preamble contains the basic 

background information about the origin of this proposed 

supplemental rulemaking, including a discussion of the 

initial proposed rule for petroleum and natural gas 

systems. This section also discusses EPA’s use of our 

legal authority under the Clean Air Act to collect the 

proposed data, and the benefits of collecting the data. 

The relationship between the mandatory GHG reporting 

program and other mandatory and voluntary reporting 

programs at the national, regional and state level also is 

discussed. 

The second section of this preamble summarizes the 

general provisions of this proposed supplemental rulemaking 

for petroleum and natural gas systems. It also highlights 

the major changes between the initial proposed rule and the 
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supplemental rule that we are proposing today, including 

changes in the scope of the proposed rule and the 

monitoring methods proposed. This section then provides a 

brief summary of, and rationale for, selection of key 

design elements. Specifically, this section describes 

EPA’s rationale for (i) the definition of the source 

category (ii) selection of reporting thresholds (iii) 

selection of monitoring methods, (iv) missing data 

procedures (v) proposed data reporting requirements, and 

(vi) recordkeeping requirements. Thus, for example, there 

is a specific discussion regarding appropriate thresholds, 

monitoring methodologies and reporting and recordkeeping 

requirements for each segment of the petroleum and natural 

gas industry proposed for inclusion in the rule: onshore 

petroleum and natural gas production, offshore petroleum 

and natural gas production, natural gas processing, natural 

gas transmission compressor stations, natural gas 

underground storage, LNG storage, LNG import and export 

terminals, and distribution. EPA describes the proposed 

options for each design element, as well as the other 

options considered. Throughout this discussion, EPA 

highlights specific issues on which we solicit comment. 

Please refer to the specific source category of interest 

for more details. 
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The third section provides the summary of the cost 

impacts, economic impacts, and benefits of this proposed 

rule from the Economic Analysis. Finally, the last section 

discusses the various statutory and executive order 

requirements applicable to this proposed rulemaking. 

B. Background on the Proposed Rule

The Final Mandatory GHG Reporting Rule (“Final MRR”), 

(40 CFR part 98) was signed by EPA Administrator Lisa 

Jackson on September 22, 2009 and published in the Federal 

Register on October 30, 2009 (74 Federal Register 209 

(October 30, 2009) pp. 56260-56519). The Final MRR which 

is effective on December 29, 2009 included reporting of 

GHGs from facilities and suppliers that EPA determined met 

the criteria in the 2008 Consolidated Appropriations Act1. 

These source categories capture approximately 85 percent of 

U.S. GHG emissions through reporting by direct emitters as 

well as suppliers of fossil fuels and industrial gases. 

There are, however, many additional types of data and 

reporting that the Agency deems important and necessary to 

address an issue as large and complex as climate change 

(e.g. indirect emissions from electricity use). In that 

sense, one could view the Final MRR (40 CFR part 98) as 

focused on certain sources of emissions and upstream 

 

1 Consolidated Appropriations Act, 2008, Public Law 110–161, 121 Stat. 

1844, 2128. 
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suppliers. For information on existing programs at the 

Federal, Regional and State levels that also collect 

valuable information to inform and implement policies 

necessary to address climate change, relationship of the 

Final MRR to EPA and U.S. government climate change efforts 

and to other State and Regional Programs, see the Preamble 

to the Final MRR. 

In the April 2009 proposed mandatory GHG reporting 

rule the petroleum and natural gas systems subcategory was 

included as Subpart W. EPA received a number of lengthy, 

detailed comments regarding this subpart W proposal. Some 

comments were focused on the significant cost burden that 

the April 2009 proposed rule would impose on petroleum and 

natural gas systems, whereas others focused on whether 

certain sources, such as onshore production and 

distribution, that were not included in the initial 

proposal, should be included. EPA recognized the concerns 

raised by stakeholders, and decided not to finalize subpart 

W with the Final MRR, but instead to propose a new 

supplemental rule for petroleum and natural gas systems. 

This proposed supplemental rule incorporates a number of 

changes including, but not limited to, different 

methodologies that provide improved emissions coverage at a 

lower cost burden to facilities than would have been 
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covered under the initial proposed rule; the inclusion of 

onshore production and distribution facilities; and 

separate definitions for “vented” and “fugitive” emissions. 

As noted earlier, stakeholders should submit comments in 

the context of this new proposed supplemental rule. 

This proposed supplemental rule 40 CFR part 98, 

subpart W requires annual reporting of fugitive and vented 

carbon dioxide (CO2)and methane (CH4) emissions from 

petroleum and natural gas systems facilities, as well as 

combustion-related CO2, CH4, and nitrous oxide (N2O) emissions 

from flares at those facilities, following the methods 

outlined in the proposal. This proposed rule would also 

establish appropriate thresholds and frequency for 

reporting, as well as provisions to ensure the accuracy of 

emissions through monitoring, reporting and recordkeeping 

requirements. 

This proposed rule applies to facilities in specific 

segments of the petroleum and natural gas industry that 

emit GHGs greater than or equal to 25,000 metric tons of CO2

equivalent per year. Reporting would be at the facility 

level. 

C. Legal Authority

EPA is proposing this rule under its existing CAA 

authority, specifically authorities provided in section 114 
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of the CAA. As discussed further below and in ‘‘Mandatory 

Greenhouse Gas Reporting Rule: EPA’s Response to Public 

Comments, Legal Issues’ (EPA-HQ-OAR-2008-0508-2264), EPA is 

not citing the FY 2008 Consolidated Appropriations Act as 

the statutory basis for this action. While that law 

required that EPA spend no less than $3.5 million on a rule 

requiring the mandatory reporting of GHG emissions, it is 

the CAA, not the Appropriations Act, that EPA is citing as 

the authority to gather the information proposed by this 

rule. 

As stated in the Final MRR, CAA section 114 provides 

EPA broad authority to require the information proposed 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 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, 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. EPA notes that while climate change legislation 

approved by the U.S. House of Representatives, and pending 

in the U.S. Senate, would provide EPA additional authority 
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for a GHG registry similar to this proposed rule, and would 

do so for purposes of that pending legislation, this 

proposed rule is authorized by, and the information being 

gathered by this proposed rule is relevant to implementing, 

the existing CAA. EPA expects, however, that the 

information collected by this proposed rule would also 

prove useful to legislative efforts to address GHG 

emissions. 

EPA notes that comments were submitted on the initial 

rule proposal regarding EPA’s authority under the Clean Air 

Act to collect emissions information on offshore petroleum 

and natural gas platforms. Some who commented argued that 

EPA does not have the authority to collect emissions 

information from offshore platforms, as these areas are 

under the jurisdiction of the Department of the Interior. 

EPA retains the proposal to include offshore platforms in 

this supplemental proposed rulemaking that EPA is proposing 

today. EPA believes that our jurisdiction under the CAA 

extends to these offshore platforms because, as noted 

above, EPA has broad authority under Section 114 to collect 

information that the Administrator believes necessary for 

carrying out the Clean Air Act. Because EPA is 

comprehensively considering how to address climate change 

under the CAA, including both regulatory and non-regulatory 
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options, a rule that requests detailed information from a 

broad spectrum of sources, including offshore platforms, is 

reasonable. 

For further information about EPA’s legal authority, 

see the proposed and final MRR. 

D. Relationship to other Federal, State and Regional

Programs 

In developing the initial proposal for mandatory 

reporting from petroleum and natural gas systems that was 

released in April 2009, as well as this supplemental 

proposed rulemaking, EPA reviewed monitoring methods 

included in international guidance (e.g., Intergovernmental 

Panel on Climate Change), as well as Federal voluntary 

programs (e.g., EPA Natural Gas STAR Program and the U.S. 

Department of Energy Voluntary Reporting of Greenhouse 

Gases Program (1605(b))), corporate protocols (e.g., World 

Resources Institute and World Business Council for 

Sustainable Development GHG Protocol) and industry guidance 

(e.g., methodological guidance from the American Petroleum 

Institute, the Interstate Natural Gas Association of 

America, and the American Gas Association). 

EPA also reviewed State reporting programs (e.g., 

California and New Mexico) and Regional partnerships (e.g., 

The Climate Registry, the Western Regional Air 
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Partnership). These are important programs that not only 

led the way in reporting of GHG emissions before the 

Federal government acted but also assist in quantifying the 

GHG reductions achieved by various policies. Many of these 

programs collect different or additional data as compared 

to this proposed rule. For example, State programs may 

establish lower thresholds for reporting, request 

information on areas not addressed in EPA’s reporting rule, 

or include different data elements to support other 

programs (e.g., offsets). For further discussion on the 

relationship of this proposed rule to other programs, refer 

to the preamble to the Final MRR. 

II. Rationale for the Reporting, Recordkeeping and 

Verification Requirements 

A. Overview of Proposal

The U.S. petroleum and natural gas industry 

encompasses hundreds of thousands of wells, hundreds of 

processing facilities, and over a million miles of 

transmission and distribution pipelines. This proposed 

rule would apply to the calculation and reporting of 

vented, fugitive, and flare combustion emissions from 

selected equipment at the following facilities that emit 

equal to or greater than 25,000 metric tons of CO2

equivalent per year from source categories covered by the 
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mandatory GHG reporting rule: offshore petroleum and 

natural gas production facilities, onshore petroleum and 

natural gas production facilities (including enhanced oil 

recovery (EOR)), onshore natural gas processing facilities, 

onshore natural gas transmission compression facilities, 

onshore natural gas storage facilities, LNG storage 

facilities, LNG import and export facilities and natural 

gas distribution facilities owned or operated by local 

distribution companies(LDC’s). Methods and reporting 

procedures for stationary combustion emissions other than 

flares at petroleum and natural gas industry facilities are 

covered under Subpart C of the Final MRR. 

This proposed supplemental rule incorporates a number 

of different methodologies to provide improved emissions 

coverage at a lower cost burden to affected facilities, as 

compared to the initial proposed rule. In this 

supplemental proposal, EPA is requiring the use of direct 

measurement of emissions for only the most significant 

emissions sources where other options are not available, 

and proposing the use of engineering estimates, emissions 

modeling software, and leak detection and publicly 

available emission factors for most other vented and 

fugitive sources. For smaller fugitive and inaccessible 

sources, component count and population emissions factors 
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are proposed. In the case of offshore platforms, EPA is 

recommending that emissions sources identified under the 

Minerals Management Services (MMS) GOADS (Gulfwide Offshore 

Activities Data System) be used for reporting, and the 

GOADS process be extended to platforms in other Federal 

regions (i.e. California and Alaska) and in State waters. 

The alternative methodologies proposed in this rule will 

provide similar or better estimation of vented and fugitive 

CH4 and CO2 emissions in the petroleum and gas industry, 

while significantly reducing industry burden. 

Under this supplemental proposal, facilities not 

already reporting but required to report under subpart W 

would begin data collection in 2011 following the methods 

outlined in the proposed rule, and submit data to EPA by 

March 31, 2012. 

EPA would require reporting of calendar year 2011 

emissions in 2012 because the data are crucial to the 

timely development of future GHG policy and regulatory 

programs. In the Appropriation Act, Congress requested EPA 

to develop this reporting program on an expedited schedule, 

and Congressional inquiries along with public comments 

reinforce that data collection for calendar year 2011 is a 

priority. Delaying data collection until calendar year 

2012 would mean the data would not be received until 2013, 
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which would likely be too late for many ongoing GHG policy 

and program development needs. 

EPA considered, but decided not to propose, the use of 

best available monitoring methods for part or all of the 

first year of data collection. EPA concluded that the time 

period that would be allowed under this schedule is 

sufficient to allow facilities to implement the monitoring 

methods that would be required by the proposed rule. In 

general, the proposed monitors, such as flow meters, are 

widely available and are not time consuming to install. 

Further, some of the monitoring methods (e.g., use of 

emission factors) may not require the installation of any 

monitoring equipment. Finally, the emissions assessment 

may be done at any time during the year, and measurements 

do not necessarily need to be undertaken during the first 

quarter. 

EPA seeks comment on the proposal not to allow use of 

best available monitoring methods for part or all of the 

first year of data collection. 

Proposed Amendments to the General Provisions. EPA is 

proposing harmonizing changes to the general provisions for 

the GHG reporting rule (40 CFR part 98, subpart A) to 

accommodate the addition of the proposed petroleum and 

natural gas systems subpart. The changes affect paragraphs 
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on rule applicability, schedule, definitions, and 

incorporation by reference. 

In particular, we propose to revise 40 CFR 98.2(a) to 

add petroleum and natural gas systems to the list of source 

categories that must report their annual emissions starting 

with calendar year 2011. We also propose to restructure 40 

CFR 98.2(a) to move the lists of source categories from the 

text into tables. The table format improves clarity and 

facilitates the addition of source categories that were not 

included in calendar year 2010 reporting and begin 

reporting in future years. Because facilities with 

petroleum and natural gas systems (as defined in proposed 

40 CFR part 98, subpart W) would be subject to the rule if 

facility emissions exceed 25,000 metric tons CO2e per year, 

this source category would be added to the table of 

threshold source categories referenced from 40 CFR 

98.2(a)(2). The introductory text of 40 CFR 98.2(a)(2) and 

a few other sentences throughout 40 CFR part 98, subpart A 

that reference “subparts C through JJ” would be reworded to 

refer to the source category tables because the tables will 

make it clear which source categories are to be considered 

for determining the applicability threshold and reporting 

requirements for calendar years 2010, 2011, and future 

years. (The existing wording implied all source categories 
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in subparts C through JJ must be reported in 2010, which is 

not the case for the proposed petroleum and natural gas 

systems source category (subpart W) and other source 

category subparts that may be proposed or promulgated in 

the future.) 

We propose to revise 40 CFR 98.3(b), which establishes 

the schedule for annual reporting. The text in 40 CFR 

98.3(b)(1) and (b)(2) indicate that existing facilities 

subject to the rule must report emissions for calendar year 

2010. When proposed 40 CFR part 98, subpart W is added, 

facilities will become subject to the reporting rule due to 

petroleum and natural gas systems and their first annual 

GHG report that includes emissions from petroleum and 

natural gas systems would cover calendar year 2011 rather 

than 2010. Therefore, we propose to modify the text of 

98.3(b) to allow reporting to start in different years, as 

appropriate. We also propose to remove and reserve 40 CFR 

98.3(b)(1). It would no longer be accurate, and it would 

not be needed because 40 CFR 98.2(a) would indicate the 

first reporting year for source categories added to the 

rule and the requirement for facilities to report in each 

subsequent year is already contained in 40 CFR 98.2(i). 

We propose to amend 40 CFR 98.6 to add definitions for 

several terms used in proposed 40 CFR part 98, subpart W 
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and to clarify the meaning of certain terms for purposes of 

subpart W. We also propose to amend 40 CFR 98.7 

(incorporation by reference) to include standard methods 

used in proposed subpart W. In particular, we propose to 

incorporate by reference the AAPG-CSD Geologic Code 

Provinces Code Map available from The American Association 

of Petroleum Geologists Bulletin, Volume75, No. 10 (October 

1991) pages 1644-1651. It would be used to define the 

geographic boundaries for reporting of onshore oil and gas 

production systems. We also proposed to incorporate by 

reference models, including Glycalc and E&P Tanks that 

would be used to calculate emissions and were not developed 

by the Federal government. 

B. Summary of the Major Changes since Initial Proposal

Mandatory GHG reporting requirements were proposed for 

Petroleum and Natural Gas Systems under Subpart W in April 

2009 along with a number of other sectors of the economy. 

As noted in the Preamble to the Final MRR, EPA received a 

number of lengthy, detailed comments regarding Petroleum 

and Natural Gas Systems. In total, EPA received comments 

from over 80 organizations and over 1,200 pages of formal 

comments on the Petroleum and Gas Systems Initial Proposed 

Rule. Some comments proposed simplified alternatives to 

the proposed reporting requirements based on the potential 
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that the proposed requirements would entail significant 

burden and cost. Other comments addressed whether to 

include onshore production and the distribution segment, 

which were excluded from the initial proposal as EPA sought 

comments on approaches for the level of reporting of 

fugitive and vented GHG emissions from these segments 

(e.g., facility or corporate). 

EPA has reviewed the comments and issues and 

suggestions raised by stakeholders within and outside the 

petroleum and natural gas industry related to emissions 

coverage and the level of cost burden in this sector. In 

response, EPA is proposing a new supplemental rule for 

Petroleum and Natural Gas Systems. This proposed 

supplemental rule now incorporates all segments of the 

petroleum and gas industry, adding onshore production and 

distribution. 

Total fugitive, vented and combustion emissions 

estimated to be covered in this supplemental proposed 

rulemaking amount to 351 MMTCO2e; 272 MMTCO2e from fugitive 

and vented emissions and 79 MMTCO2e from combustion 

emissions2. Fugitive and vented emissions estimates 

 

2 Some petroleum and natural gas facilities will already be required to 

report emissions from stationary combustion under the MRR that was 

signed in September 2009. This proposed petroleum and natural gas 

subpart will require additional facilities to report to the MRR that 

are not currently required to report. These facilities will have to 
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28 

included in the supplemental proposed rulemaking are 

significantly higher than the 131 MMTCO2e reported in the 

2008 U.S. Inventory of Greenhouse Gases, due to the 

inclusion of items believed to be under-reported in the 

inventory (discussed further below). 

Table W-1 summarizes the estimated fugitive, vented 

and combustion emissions for the segments included in the 

initial proposal and the added segments of onshore 

production and distribution. Additional details can be 

found in the Petroleum and Natural Gas Systems Economic 

Analysis (EPA-HQ-OAR-2008-0508-XXX). 

TABLE W-1. FUGITIVE/VENTED AND COMBUSTION EMISSIONS FROM 

PETROLEUM AND NATURAL GAS SYSTEMS, MMTCO2E 

Segment 

Fugitive and 

Vented 

Emissions: 

Initial 

Proposed Rule 

Fugitive and 

Vented 

Emissions: 

Supplemental 

Proposed 

Rulemaking 

Combustion 

Emissions: 

Supplemental 

Proposed 

Rulemaking 

Initial 

Proposed Rule 

Six Segments 

85 94.3 9.8 

Onshore 

Production NA 154.9 69.3 

Natural Gas 

Distribution NA 22.7 NA 

Total Emissions 85 271.9 79.11

1 This estimate reflects only incremental combustion emissions 

(i.e., only those combustion emissions from facilities above and beyond 

what will already be required to be reported under the Final MRR). For 

example, combustion-related emissions from many natural gas processing 

 

report combustion, fugitive and vented emissions. These incremental 

combustion emissions are estimated at 79 MMTCO2e. 
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29 

plants are already required to be reported under subpart C and are 

therefore not included here. The combustion estimate also includes 

combustion emissions from flares. 

Inclusion of onshore production and distribution 

results in estimated fugitive and vented emissions that are 

more than triple the estimated emissions in the initial 

rule proposal for petroleum and natural gas systems. 

In addition to expanding emissions coverage under the 

proposed supplemental rule, EPA has assessed a number of 

alternative methodologies that were either recommended by 

commenters or are known to provide effective quantification 

of emissions at a significantly lower cost burden. The 

changes include the use of: 

• Limited use of fugitive leak detection. 

• Leaker factors to quantify detected fugitive 

emissions. 

• Population factors and component count for fugitive 

emissions that are widely scattered or inaccessible. 

• Use of existing MMS GOADS methods and calculated 

emissions for offshore production facilities. 

• Modeling software to quantify glycol dehydrator and 

tank emissions. 
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30 

• Engineering estimation for well venting from liquids 

unloading. 

• Engineering estimation for well venting from 

completions and workovers. 

• Engineering estimation for well testing and flaring. 

• Engineering estimation for flaring emissions. 

• Limited sampling to determine gas composition. 

Another significant change in the proposed 

supplemental rule is the use of the term “fugitives”. The 

initial rule proposal from April 2009 included both vented 

and fugitive emissions sources, and collectively defined 

both sources as “fugitive”. EPA received a large number of 

comments from industry stakeholders and others indicating 

that this definition created confusion. Hence EPA is 

defining vented emissions separately from fugitives in the 

supplemental proposed rulemaking. For this supplemental 

rulemaking, emissions from the petroleum and natural gas 

industry are defined as 1) vented emissions, which include 

intentional or designed releases of CH4 and/or CO2

containing natural gas or hydrocarbon gas (not including 

stationary combustion flue gas) from emissions sources 

including, but not limited to, process designed flow to the 

atmosphere through seals or vent pipes, equipment blowdown 
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31 

for maintenance, and direct venting of gas used to power 

equipment (such as pneumatic devices). In addition, this 

supplemental rule includes 2) fugitive emissions, or 

unintentional emissions, which are defined to include those 

emissions which could not reasonably pass through a stack, 

chimney, vent, or other functionally-equivalent opening. 

This supplemental rule also includes 3) flare combustion 

emissions, which include CH4, CO2 and N2O emissions 

resulting from combustion of gas in flares. 

C. Definition of the Source Category 

EPA discusses here the general approach used in 

identifying the key segments of the petroleum and natural 

gas industry that would be required to report under the 

proposal. This general discussion is followed by a 

specific discussion for each industry segment. 

One factor EPA considered in assessing the 

applicability of certain petroleum and natural gas industry 

emissions in the proposed rule is the definition of a 

facility. In other words, what physically constitutes a 

facility? This definition is important to determine the 

reporting entity, to ensure that delineation is clear, and 

to minimize double counting or omissions of emissions. For 

some segments of the industry (e.g., onshore natural gas 

processing facilities, natural gas transmission compression 
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32 

facilities, and offshore petroleum and natural gas 

facilities), identifying the facility is clear since there 

are physical boundaries and ownership structures that lend 

themselves to identifying scope of reporting and 

responsible reporting entities. In other segments of the 

industry (e.g., the pipelines between compressor stations 

and onshore petroleum and natural gas production) such 

distinctions are not as straightforward. In defining a 

facility, EPA reviewed current definitions used in the 

Clean Air Act (CAA), ISO definitions, comments provided 

under the initial proposed rule, and current regulations 

relevant to the industry. A complete description of our 

assessment can be found in the Petroleum and Natural Gas 

Systems TSD (EPA-HQ-OAR-2008-0508-XXX). 

At the same time, EPA also decided that it was 

impractical to include each of the over 160 different 

sources of vented and fugitive CH4 and CO2 emissions in the 

petroleum and natural gas industry. In response to 

comments received on the initial proposed rule, EPA 

undertook a systematic review of each emissions source 

included in the 2008 U.S. GHG Inventory in order to propose 

reporting of only the most significant emissions sources 

(e.g. emissions that account for the majority of oil and 

gas fugitive and vented emissions). In determining the 
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33 

most relevant vented and fugitive emissions sources for 

inclusion in this supplemental proposed rulemaking, EPA 

considered the following criteria: the coverage of 

emissions for the source category as a whole; the coverage 

of emissions per unit of the source category; the 

feasibility of a viable monitoring method, including direct 

measurement and engineering estimations; and the number of 

facilities that would be required to report. Sources that 

contribute significantly large emissions were considered 

for inclusion in this supplemental proposed rulemaking, 

since they increase the coverage of emissions reporting. 

Typically, at petroleum and gas facilities, 80 percent 

or more of a facility’s emissions come from approximately 

10 percent of the emissions sources. EPA used this 

benchmark to reduce the number of emissions sources 

required for reporting while keeping the reporting burden 

to a minimum. Sources in each segment of the petroleum and 

natural gas industry were sorted into two main categories: 

(1) the largest sources contributing to approximately 80 

percent of the emissions from the segment, and (2) the 

sources contributing to the remaining 20 percent of the 

emissions from that particular segment. EPA assigned 

sources into these two groups by determining the emissions 

contribution of each emissions source to its relevant 
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34 

segment of the petroleum and gas industry, listing the 

emissions sources in a descending order, and identifying 

all the sources at the top that contribute to approximately 

80 percent of the emissions. Generally, those sources that 

fell into approximately the top 80 percent were considered 

for inclusion. Details of the analysis can be found in the 

Petroleum and Natural Gas Systems TSD (EPA-HQ-OAR-2008-

0508-XXX). 

The following is a brief discussion of the proposed 

emission sources to be included and excluded based on our 

analysis. Additional information can be found in the 

Petroleum and Natural Gas Systems TSD (EPA-HQ-OAR-2008-

0508-XXX). Note that this subpart of the GHG reporting 

rule addresses only vented, fugitive and flare combustion 

emissions. As mentioned previously, stationary combustion 

emissions are included in Subpart C of the Final MRR 

Preamble. 

Onshore Petroleum and Natural Gas Production: 

The onshore petroleum and natural gas production 

segment uses wells to extract raw natural gas, condensate, 

crude oil, and associated gas from underground formations 

and inject CO2 for EOR. Extraction includes several types 

of processes: reservoir management, primary recovery, 

secondary recovery such as down-hole pumps, water flood or 
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35 

natural gas/ nitrogen/ immiscible CO2 injection, and 

tertiary recovery such as using critical phase miscible CO2

injection. The largest sources of CH4 and CO2 emissions 

include, but are not limited to, natural gas driven 

pneumatic devices and pumps, field crude oil and condensate 

storage tanks, glycol dehydration units, releases and 

flaring during well completions, well workovers, and well 

blowdowns for liquids unloading, releases and flaring of 

associated gas, and blowdowns of compressors and EOR pumps. 

EPA is proposing to include the onshore petroleum and 

natural gas production segment due to the fact that these 

operations represent a significant emissions source, 

representing approximately 66 percent of fugitive, vented 

and incremental3 combustion emissions from the petroleum and 

natural gas segments covered by the proposed rule. 

EPA considered a range of possible options for 

reporting emissions from onshore petroleum and natural gas 

facilities. Although several options for defining the 

facility were considered and described below, EPA has 

determined that only two of the options are feasible: 

basin-level reporting and field-level reporting. For this 

supplemental proposed rulemaking, EPA proposes that 

 

3 The denominator includes total fugitive and vented emissions, as well 

as any additional combustion related emissions that will be required to 

be reported by the petroleum and natural gas industry and that wasn’t 

already covered in the final MRR. 
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36 

emissions from onshore petroleum and natural gas production 

be reported at the basin level. The reporting entity for 

onshore petroleum and natural gas production would be the 

operating entity listed on the state well drilling permit, 

or a state operating permit for wells where no drilling 

permit is issued by the state, who operates onshore 

petroleum and natural gas production wells and controls by 

means of ownership (including leased and rented) and 

operation (including contracted) stationary and portable 

(as defined in this Subpart) equipment located on all well 

pads within a single hydrocarbon basin as defined by the 

American Association of Petroleum Geologists (AAPG) threedigit Geological Province Code. The equipment referenced 

above includes all structures associated with wells used in 

the production, extraction, recovery, lifting, 

stabilization, separation or treating of petroleum and/or 

natural gas (including condensate) including equipment that 

is leased, rented or contracted. This includes equipment 

such as compressors, generators or storage facilities, 

piping (such as flowlines or intra-facility gathering 

lines), and portable non-self-propelled equipment (such as 

well drilling and completion equipment, workover equipment, 

gravity separation equipment, auxiliary non-transportationrelated equipment). This also includes associated storage 
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37 

or measurement equipment and all equipment engaged in 

gathering produced gas from multiple wells, EOR operations 

using CO2, and all petroleum and natural gas production 

operations located on islands, artificial islands or 

structures connected by a causeway to land, an island, or 

artificial island. 

 Where more than one entity may hold the state well 

drilling permit, or well operating permit where no drilling 

permit is issued by the state, the permitted entities for 

the facility would be required to designate one entity to 

report all emissions from the jointly controlled facility. 

Where an operating entity holds more than one permit to 

operate wells in a basin, then all onshore petroleum and 

natural gas production well permits in their name in the 

basin, including all equipment on the well pads, would be 

considered one onshore petroleum and natural gas production 

facility for purposes of reporting. 

There are at least two industry recognized definitions 

available that identify hydrocarbon basins; one from the 

United State Geological Survey (USGS) and the other from 

the AAPG. The AAPG definition is based on County 

boundaries and hence likely to be familiar to the industry, 

i.e. if the owner or operator knows in which county their 

well is located then they know to which basin they belong. 
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38 

On the other hand, the USGS definition is based purely on 

the geology of the hydrocarbon basin without consideration 

of State and County boundaries. Hence using the USGS 

definition may make it more difficult to map surface 

operations to a particular basin. Therefore, EPA is 

proposing to use the AAPG definition of a basin. EPA seeks 

comments on the availability of other appropriate standard 

basin level definitions that could be applied for the 

purposes of this rule and their merits over the AAPG 

definition. 

EPA is proposing a basin level approach, because the 

boundaries for reporting are clearly defined and the 

approach covers approximately 81 percent of emissions from 

onshore petroleum and natural gas production. 

EPA evaluated and is taking comment on one alternative 

option for reporting from onshore petroleum and natural gas 

production; field level. Field level reporting would 

require aggregation of emissions from all covered equipment 

at onshore petroleum and natural gas production facilities 

at the field level, as opposed to the basin level as 

described above. A typical field level definition is 

available from the Energy Information Administration Oil 

and Gas Field Code Master. As outlined in the Economic 

Impact Analysis for this proposed rule, the field level 
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39 

option would result in a significantly lower coverage in 

emissions, estimated at 55 percent in comparison to the 

basin level coverage of 81 percent. In essence the two 

reporting options are not different from a methodological 

point of view because both definitions rely on geographical 

boundaries. Therefore, EPA has proposed the use of a basin 

level definition to increase coverage. EPA seeks comments 

on our decision to propose the basin level approach, and 

whether there would be advantages to requiring reporting at 

the field level instead. 

In addition to basin and field level reporting, EPA 

considered one other alternative approach for defining a 

facility for onshore petroleum and natural gas production; 

individual well pads. This well pad approach included all 

stationary and portable equipment operating in conjunction 

with that well, including drilling rigs with their 

ancillary equipment, gas/liquid separators, compressors, 

gas dehydrators, crude oil heater-treaters, gas powered 

pneumatic instruments and pumps, electrical generators, 

steam boilers and crude oil and gas liquids stock tanks. 

This definition was analyzed with available data including 

four cases to represent the full range of petroleum and 

natural gas well pad operations ranging from unconventional 

well drilling and operation starting in the beginning of 
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40 

the year with higher emitting practices, to production at 

an associated gas and oil well (no drilling) with minimal 

equipment and a vapor recovery unit. 

EPA analyzed the average emissions associated with 

each of the four well pad facility cases and determined 

that average emissions at these operations were low (from 

about 370 metric tons of CO2e per year to slightly less than 

5,000 metric tons of CO2e per year). This analysis shows 

that the threshold would have to be set at less than 400 

metric tons CO2e per year to capture the largest possible 

amount of onshore production emissions (only 33 percent) 

which would result in close to 170,000 reporters. 

Additional information can be found in the Petroleum and 

Natural Gas Systems TSD (EPA-HQ-OAR-2008-0508-XXX). If the 

threshold was set at approximately 5,000 metric tons, EPA 

estimates that the number of reporters would decrease 

significantly to approximate 3,300 but the emission 

coverage would be only 6%.Based on the results above, EPA 

did not consider the well pad definition further in the 

Economic Impact Analysis. 

Offshore Petroleum and Natural Gas Production. 

Offshore petroleum and natural gas production is any 

platform structure, either floating in the ocean or lake, 

or fixed on the ocean or lake bed, that houses equipment to 
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41 

extract hydrocarbons from the ocean or lake floor and 

transports it to storage or transport vessels or transports 

onshore. In addition, offshore production includes 

secondary platform structures and floating storage tanks 

connected to the platform structure by a pipeline. GHG 

emissions result from sources housed on the platforms. 

In 2006, offshore petroleum and natural gas production 

CO2 and CH4 emissions accounted for 5.1 million metric tons 

CO2e. The primary sources of emissions from offshore 

petroleum and natural gas production are from valves, 

flanges, open-ended lines, compressor seals, platform vent 

stacks, and other source types. Flare stacks account for 

the majority of combustion CO2 emissions. 

Offshore petroleum and natural gas production 

facilities are proposed for inclusion due to the fact that 

this segment represents approximately 1.9 percent of 

fugitive, vented and incremental4 combustion emissions from 

the petroleum and natural gas industry, an existing 

activity data collection system already exists that can 

readily be used to calculate GHG emissions (i.e. GOADS) and 

major fugitive and vented emissions sources can be 

characterized by an existing reasonable methodology which 

 

4 The denominator includes total fugitive and vented emissions, as well 

as any additional combustion related emissions that will be required to 

be reported by the petroleum and natural gas industry and that wasn’t 

already covered in the final MRR. 
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42 

will minimize incremental burden for reporters. This is 

consistent with comments received on the initial proposed 

rule. 

Onshore Natural Gas Processing. Natural gas 

processing facilities remove hydrocarbon and water liquids 

and various other constituents (e.g. hydrogen sulfide, 

carbon dioxide, helium, nitrogen, and hydrocarbons heavier 

than methane) from the produced natural gas. The resulting 

“pipeline quality” natural gas is transported to 

transmission pipelines. Natural gas processing facilities 

also include gathering/ boosting stations that dehydrate 

and compress natural gas to be sent to natural gas 

processing facilities or directly to natural gas 

transmission or distribution systems. Compressors are used 

within gathering/ boosting stations to adequately 

pressurize the natural gas so that it can be transported to 

natural gas processing, transmission, and distribution 

facilities through gathering pipelines. In addition, 

compressors at natural gas processing facilities are used 

to boost natural gas pressure so that it can pass through 

all of the processes and into the high-pressure 

transmission pipelines. 

Vented and fugitive CH4 emissions from reciprocating 

and centrifugal compressors, including centrifugal 
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43 

compressor wet and dry seals, wet seal degassing vents, 

reciprocating compressor rod packing vents, and all other 

compressor emissions, are the primary CH4 emission sources 

from this segment. The majority of vented CO2 emissions 

come from acid gas removal vent stacks, which are designed 

to remove CO2 and hydrogen sulfide, when present, from 

natural gas. While these are the major emissions sources 

in natural gas processing facilities, other potential 

sources such as piping connectors, open-ended vent and 

drain lines and gathering pipelines associated with the 

processing plant would also need to be reported under the 

proposed supplemental rule. 

Onshore natural gas processing facilities are proposed 

for inclusion due to the fact that these operations 

represent a significant emissions source, approximately 8 

percent of fugitive, vented and incremental5 combustion 

emissions from the natural gas segment, methods are 

available to estimate emissions, and there are a reasonable 

number of reporters. Most natural gas processing 

facilities proposed for inclusion in this supplemental 

 

5 The denominator includes total fugitive and vented emissions, as well 

as any additional combustion related emissions that will be required to 

be reported by the petroleum and natural gas industry and that wasn’t 

already covered in the final MRR. 
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44 

proposed rulemaking would already be required to report 

under subpart C and/or subpart NN of the Final MRR. 

Onshore Natural Gas Transmission Compression 

Facilities and Underground Natural Gas Storage. 

Natural gas transmission compression facilities move 

natural gas throughout the U.S. natural gas transmission 

system. Natural gas is also injected and stored in 

underground formations during periods of low demand (e.g., 

spring or fall) and withdrawn, processed, and distributed 

during periods of high demand (e.g., winter or summer). 

Storage compressor stations are dedicated to gas injection 

and extraction at underground natural gas storage 

facilities. 

Vented and fugitive CH4 emissions from reciprocating 

and centrifugal compressors, including compressor and 

station blowdowns, centrifugal compressor wet and dry 

seals, wet seal oil degassing vents, reciprocating 

compressor rod packing vents, unit isolation valves, 

blowdown valves, compressor scrubber dump valves, gas 

pneumatic continuous bleed devices and all other compressor 

fugitive emissions, are the primary CH4 emission source from 

natural gas transmission compression stations and 

underground natural gas storage facilities. Dehydrators 

are also a significant source of CH4 emissions from 
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45 

underground natural gas storage facilities. While these 

are the major emissions sources in natural gas 

transmission, other potential sources include, but are not 

limited to, condensate (water and hydrocarbon) tanks, openended lines and valve stem seals. Condensate tank vents in 

transmission can be a significant source of emissions from 

malfunctioning compressor scrubber dump valves and will 

require detection of such leakage by an optical imaging 

instrument and direct measurement where found present. 

Onshore natural gas transmission compression 

facilities and underground natural gas storage facilities 

are proposed for inclusion due to the fact that these 

operations represent significant sources of fugitive, 

vented and incremental6 combustion emissions, 15 and 2 

percent, respectively, methods are available to estimate 

emissions, and there are a reasonable number of reporters. 

Further, this segment was included in the initial proposed 

rule and EPA has made improvements to the proposal based on 

comments received. 

LNG Import and Export and LNG Storage. 

The U.S. imports and exports natural gas in the form 

of LNG, which is received, stored, and, when needed, re-

 

6 The denominator includes total fugitive and vented emissions, as well 

as any additional combustion related emissions that will be required to 

be reported by the petroleum and natural gas industry and that wasn’t 

already covered in the final MRR. 
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46 

gasified at LNG import and export terminals. Import and 

export include both LNG movements between U.S. and foreign 

sources as well as transport between U.S. sources. LNG 

storage facilities liquefy and store natural gas from 

processing plants and transmission pipelines during periods 

of low demand (e.g., spring or fall) and re-gasify for send 

out during periods of high demand (e.g., summer and winter) 

Fugitive and vented CH4 and CO2 emissions from 

reciprocating and centrifugal compressors, including 

centrifugal compressor wet and dry seals, wet seal 

degassing vents, reciprocating compressor rod packing 

vents, and all other compressor fugitive emissions, are the 

primary CH4 and CO2 emission source from LNG storage 

facilities and LNG import and export facilities. Process 

units at these facilities can include vapor recovery 

compressors to re-liquefy natural gas tank boil-off (at LNG 

storage facilities), re-condensers, vaporization units, 

tanker unloading equipment (at LNG import terminals), 

transportation pipelines, and/or LNG pumps. 

LNG storage “facilities” can be defined as facilities 

that store liquefied natural gas in above ground storage 

tanks. LNG import terminal can be defined as onshore or 

offshore facilities that receive imported LNG via ocean 

transport, store it in storage tanks, re-gasify it, and 
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47 

deliver re-gasified natural gas to a natural gas 

transmission or distribution system. LNG export terminal 

(facility) can be defined as onshore or offshore facilities 

that receive natural gas, liquefy it, store it in storage 

tanks, and send out the LNG via ocean transportation, 

including to import facilities in the United States. EPA 

is proposing inclusion of these facilities because the 

National Inventory has very little data on methane 

emissions in these segments which are expected to grow 

substantially in forward years. 

Petroleum and Natural Gas Pipelines. 

Natural gas transmission involves high pressure, large 

diameter pipelines that transport gas long distances from 

field production and natural gas processing facilities to 

natural gas distribution pipelines or large volume 

customers such as power plants or chemical plants. Crude 

oil transportation involves pump stations and bulk tank 

terminals to move crude oil through pipelines and loading 

and unloading crude oil tanks, marine vessels, and railroad 

tank cars. The majority of vented and fugitive emissions 

from the transportation of natural gas occur at the 

compressor stations, which are proposed for inclusion in 

the supplemental rule and discussed above. 
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48 

EPA is not proposing to include reporting of fugitive 

emissions from natural gas pipeline segments between 

compressor stations, or crude oil pipelines and tank 

terminals in the supplemental rulemaking due to the 

dispersed nature of the fugitive emissions, and the fact 

that once fugitives are found, the emissions are generally 

addressed quickly. For natural gas gathering pipelines, 

EPA is proposing that producers who own or operate 

gathering lines associated with their production fields and 

natural gas processors who own or operate gathering lines 

associated with their processing plants should include 

those gathering lines in their field or processing plant 

reported emissions. 

Natural Gas Distribution: 

Natural gas distribution facilities are local 

distribution companies (LDCs) that include the above grade 

(above ground) gas metering and pressure regulation (M&R) 

equipment, M&R equipment below grade in vaults, buried 

pipelines and customer meters used to transport natural gas 

primarily from high pressure transmission pipelines to end 

users. In the distribution segment, high-pressure gas from 

natural gas transmission pipelines enters a “city gate” 

station, which reduces the pressure and distributes the gas 

through primarily underground mains and service lines to 
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49 

individual end users. Distribution system CH4 and CO2

emissions result mainly from fugitive emissions from above 

ground gate stations (metering and regulating stations), 

below grade vaults (regulator stations), and fugitive 

emissions from buried pipelines. At gate stations, 

fugitive and vented CH4 emissions primarily come from 

valves, open-ended lines, connectors, pressure safety 

valves, and natural gas driven pneumatic devices. CH4

emissions in vaults are entirely fugitive, primarily from 

piping connectors to meters and regulators. 

Although emissions from a single vault, gate station 

or segment of pipeline in the natural gas distribution 

segment may not be significant, collectively these 

emissions sources contribute a significant share of 

emissions from natural gas systems. 

EPA proposes to include natural gas distribution 

facilities because these operations represent a significant 

emissions source, approximately 6 percent of fugitive, 

vented and incremental7 combustion emissions from the 

petroleum and natural gas industry. EPA proposes that 

LDC’s would report for all of the distribution facilities 

that they own or operate. 

 

7 The denominator includes total fugitive and vented emissions, as well 

as any additional combustion related emissions that will be required to 

be reported by the petroleum and natural gas industry and that wasn’t 

already covered in the final MRR. 
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50 

Crude Oil Transportation. 

Crude oil is commonly transported by barge, tanker, 

rail, truck, and pipeline from production operations and 

import terminals to petroleum refineries or export 

terminals. Typical equipment associated with these 

operations is storage tanks and pumping stations. The 

major sources of CH4 and CO2 emissions include releases from 

tanks and marine vessel loading operations. 

EPA is not proposing to include the crude oil 

transportation segment of the petroleum and natural gas 

industry in this supplemental rulemaking due to its small 

contribution to total petroleum and natural gas CH4 and CO2

emissions, accounting for much less than 1 percent. 

D. Selection of Reporting Threshold 

EPA proposes that owners or operators of facilities 

with emissions equal to or greater than 25,000 metric tons 

CO2e per year be subject to these reporting requirements. 

This threshold is applicable to all petroleum and natural 

gas system reporters covered by this subpart: onshore 

petroleum and natural gas production facilities, offshore 

petroleum and natural gas production facilities, onshore 

natural gas processing facilities, including gathering/ 

boosting stations; natural gas transmission compression 

facilities, underground natural gas storage facilities; LNG 
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51 

storage facilities; LNG import and export facilities and 

natural gas distribution facilities. As described above, 

under the proposed rule, for onshore petroleum and natural 

gas production facilities an owner or operator (as defined 

by the proposed rule) would evaluate emissions from all 

equipment covered by the proposed rule, including vented, 

fugitive, flared and stationary combustion, in a defined 

basin against the threshold to determine applicability. 

Consistent with the rest of the Final MRR, EPA is 

proposing that for the purposes of determining whether a 

facility emits equal to or greater than a 25,000 mtCO2e, a 

facility must include emissions from all source categories 

for which methods are provided in the rule. EPA proposes 

that when a facility determines emissions for the purposes 

of the threshold determination under subpart W, that the 

fuel combustion emissions estimates include both stationary 

and portable equipment (e.g., compressors, drilling rigs, 

and dehydrators that are skid-mounted) that are controlled 

by well operators through ownership, direct operation, 

leased and rented equipment, and contracted operation. 

Fugitive, vented and combustion emissions from portable 

equipment are proposed for inclusion in the threshold 

determination for this source category due to the unique 

nature of the petroleum and natural gas industry. In 
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52 

addition to well drilling rigs and their ancillary 

equipment for well completions, it is common practice in 

onshore production to use skid mounted portable 

compressors, glycol dehydrators and other equipment partly 

for installation cost savings and partly because well flow 

rates decline over time and well-head equipment becomes 

over sized, and is moved around to match equipment capacity 

with wells of the same production capacity. 

Also due to the unique nature of the industry, EPA 

believes that it may be possible that onshore petroleum and 

natural gas production equipment from onshore petroleum and 

natural gas production facilities may be co-located with 

other manufacturing facilities already covered under other 

subparts of the rule (e.g., cement manufacturing facilities 

or glass manufacturing facilities). It is not EPA’s intent 

to have these manufacturing facilities include emissions 

from onshore petroleum and natural gas production equipment 

in their threshold determination. EPA seeks comment on 

this approach. 

To identify the most appropriate threshold level for 

reporting of emissions, EPA conducted analyses to determine 

emissions reporting coverage and facility reporting 

coverage at four different threshold levels: 1,000 metric 

tons CO2e per year, 10,000 metric tons CO2e per year, 25,000 
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53 

metric tons CO2e per year, and 100,000 metric tons CO2e per 

year. Table W-2 provides coverage of emissions and number 

of facilities reporting at each threshold level for all the 

industry segments under consideration for this proposed 

supplemental rule. 
TABLE W-2. THRESHOLD ANALYSIS FOR EMISSIONS FROM THE PETROLEUM AND NATURAL GAS INDUSTRY 

Segment Total National 

Emissions

Total Number 

of 

Facilities 

Threshold 

Level 

Total Emissions 

Covered by Threshold 

Facilities Covered 

(metric tons 

CO2e per year) 

(metric 

tons CO2e 

per year) 

Percent Number Percent 

100,000 187,175,289 67% 466 2% 

25,000 224,227,559 81% 1,232 4% 

10,000 242,390,849 87% 2,413 9% 

Onshore Petroleum & 

Gas Production 

277,798,737 27,993 

1,000 268,848,529 97% 10,604 38% 

100,000 3,242,389 29% 4 0% 

25,000 5,119,405 45% 58 2% 

10,000 7,111,563 63% 184 6% 

Offshore Petroleum 

& Gas Production 

11,261,305 3,235 

1,000 10,553,889 94% 1192 37% 

100,000 24,874,783 73% 130 23% 

25,000 31,229,071 92% 289 51% 

10,000 32,982,975 97% 396 70% 

Natural Gas 

Processing 

33,984,015 566 

1,000 33,984,015 100% 566 100% 

100,000 34,518,927 54% 433 22% 

25,000 57,683,144 90% 1,145 59% 

10,000 62,672,905 98% 1,443 74% 

Natural Gas 

Transmission 

Compression 

64,059,125 1,944 

1,000 64,051,661 100% 1,695 87% 

100,000 3,548,988 37% 36 9% 

25,000 7,846,609 81% 133 34% 

10,000 8,968,994 92% 200 50% 

Underground Natural 

Gas Storage 

9,713,029 397 

1,000 9,696,532 100% 347 87% 

100,000 695,459 33% 4 3% 

25,000 1,900,793 90% 33 21% 

10,000 2,030,842 96% 41 26% 

LNG Storage 2,113,601 157 

1,000 2,096,974 99% 54 34% 
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55 

Segment Total National 

Emissions

Total Number 

of 

Facilities 

Threshold 

Level 

Total Emissions 

Covered by Threshold 

Facilities Covered 

100,000 314,803 99.7% 4 80% 

25,000 314,803 99.7% 4 80% 

10,000 314,803 99.7% 4 80% 

LNG Import and 

Export2

315,888 5 

1,000 315,888 100.00% 5 100% 

100,000 18,470,457 73% 66 5% 

25,000 22,741,042 90% 143 10% 

10,000 23,733,488 94% 203 14% 

Natural Gas 

Distribution

25,258,347 1,427 

1,000 24,983,115 99% 594 42% 

1 The emissions include fugitive and vented CH4 and CO2 and combusted CO2, N2O, and CH4 gases. The 

emissions for each industry segment do not match the 2008 U.S. Inventory either because of added details in 

the estimation methodology or use of a different methodology than the U.S. Inventory. For additional 

discussion, refer to the Petroleum and Natural Gas Systems TSD (EPA-HQ-OAR-2008-0508-023). 

2 The analysis included only import facilities. There is only one export facility, located in Kenai, 

Alaska. 
EPA is proposing a threshold of 25,000 metric tons CO2e 

applied to those emissions sources listed in Table W-2, 

which will cover approximately 83 percent of estimated 

vented and fugitive emissions and incremental combustion 

emissions from facilities that did not meet the reporting 

requirements under Subpart C alone, from the entire 

petroleum and natural gas industry, while requiring only a 

small fraction of total facilities to report. For 

additional information, please refer to the Petroleum and 

Natural Gas Systems TSD (EPA-HQ-OAR-2008-0508-XXX). For 

specific information on costs, including unamortized first 

year capital expenditures, please refer to section 4 of the 

Economic Impact Analysis. 

Although EPA is proposing an emissions threshold of 

25,000 mtCO2e for all segments of the petroleum and natural 

gas industry, EPA is taking comment on whether a 10,000 

mtCO2e threshold for onshore petroleum and natural gas 

production would be more appropriate. 

For onshore petroleum and natural gas production, EPA 

is proposing that portable and stationary fuel combustion 

emissions be included in the threshold determination due to 

the large percentage of emissions from portable equipment 

in the petroleum and natural gas industry. EPA considered 

lowering the threshold to 10,000 mtCO2e and excluding 
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57 

portable equipment from the threshold determination (and 

reporting), however, data were not available to distinguish 

portable and stationary combustion emissions in order to 

evaluate the lower threshold considering just stationary 

combustion emissions. 

Secondly, for onshore petroleum and natural gas 

production, EPA is proposing that owners or operators 

report at the basin level. EPA is seeking comment on 

owners or operators reporting at the field level. Although 

EPA believes that a 25,000 mtCO2e threshold is appropriate 

for the basin level approach, as described above, EPA seeks 

comment on whether the threshold should be lowered to 

10,000 mtCO2e if reporting were to be at the field level. 

Table W-3 presents the emissions and facility coverage for 

a field level definition for onshore petroleum and natural 

gas production. 

TABLE W-3. EMISSIONS COVERAGE AND ENTITIES REPORTING 

FOR FIELD LEVEL FACILITY DEFINITION

Emissions Covered Facilities Covered 

Threshold 

Level2 Metric Tons 

CO2e/year Percent Number Percent 

100,000 99,776,033 38% 305 0% 

25,000 144,547,282 55% 1,253 2% 

10,000 169,160,462 64% 2,846 3% 

1,000 242,621,431 92% 39,652 48% 
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58 

In addition to seeking comment on the proposed 

threshold for onshore production, EPA more broadly is 

seeking comment on the selection of the threshold for all 

segments of the petroleum and natural gas industry. 

E. Selection of Proposed Monitoring Methods

Many domestic and international GHG monitoring 

guidelines and protocols include methodologies for 

estimating emissions from petroleum and natural gas 

operations, including the 2006 IPCC Guidelines, U.S. GHG 

Inventory, DOE 1605(b), and corporate industry protocols 

developed by the American Petroleum Institute, the 

Interstate Natural Gas Association of America, and the 

American Gas Association. The methodologies proposed vary 

by the emissions source and the level of accuracy desired 

in the estimation. 

EPA has carefully considered possible options to 

estimate emissions from every emission source proposed for 

reporting. EPA has proposed to use the most appropriate 

method taking into account both the cost to the reporter as 

well as accuracy of emissions achieved through the proposed 

method. Overall, we propose the following types of 

monitoring methods: (1) direct measurement to develop site 

and source-specific emission factors; (2) engineering 

estimation; (3) combination of direct measurement and 
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59 

engineering estimation; (4) leak detection and use of 

leaker emission factor; and (5) population count and 

population emission factors. Table W-4 of this preamble 

provides a list of the emissions sources to be reported 

with the corresponding monitoring methods. 

A monitoring method proposed for a specific source is 

to be used across all reporting segments of the petroleum 

and gas system. Two exceptions to this are: (1) for tanks 

in onshore natural gas transmission facilities that exhibit 

gas bypass from scrubber dump valves, EPA is proposing to 

require direct measurement under the proposal, whereas in 

other segments under the proposal, the emissions from tanks 

would be required to be estimated using E&P Tank simulation 

software; and (2) under the proposal, fugitive emissions 

from onshore petroleum and natural gas production and 

inaccessible (buried or below grade in vaults) emissions in 

gas distribution would require estimation using population 

emissions factors as opposed to other segments’ fugitive 

emissions that require leak detection and the use of leaker 

emissions factors. Finally, offshore petroleum and natural 

gas production platforms would be required under the 

proposal to use methods provided by the most recent GOADS 

reporting system. This means that Federal Gulf of Mexico 

platforms would report emissions already being calculated 
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60 

and reported to MMS as a part of the GOADS study and the 

remaining platforms that are not a part of the GOADS study 

(i.e. platforms in all state waters and other Federal 

waters outside the Gulf of Mexico) would be required to 

adopt the GOADS methodology.
TABLE W-4. SOURCE SPECIFIC MONITORING METHODS AND EMISSIONS QUANTIFICATION 

Emission Source Monitoring Methods Emissions Quantification Methods 

Natural Gas Pneumatic 

Bleed Devices (High or 

Continuous) 

Engineering Estimation Manufacturer device model bleed rate 

and engineering calculation 

Natural Gas Pneumatic 

Bleed Devices (Low) 

Component Count Population emissions factor 

Natural Gas Driven 

Pneumatic Pump Venting 

Engineering Estimation Manufacturer model emissions per unit 

volume and volume pumped 

Acid Gas Removal Vent 

Stacks (CO2 only) 

Engineering Estimation Engineering Calculation and flow 

meters 

Dehydrator Vent Stacks Engineering Estimation GlyCalc simulation software 

Well Venting for Liquids 

Unloading 

1) Engineering Estimation 

or 2) Direct Measurement 

1) Field specific emission factor 

times events or 

2) Flow metered emission factor times 

events 

Gas Well Venting during 

Completions or Workovers 

1) Engineering Estimation, 

or 

2) Direct Measurement 

1) Field specific emission factor 

times events or 

2) Flow metered emission factor times 

events 

Blowdown Vent Stacks Engineering Estimation Equipment specific emission factor and 

number of events 

Storage Tanks (Onshore 

Production and 

Processing) 

Engineering Estimation E&P Tank equipment specific emission 

factor times throughput 

Storage Tanks 

(Transmission) 

Direct Measurement Flow metered emission factor time 

operating hours 

Well Testing Venting and 

Flaring 

Engineering Estimation Gas to oil Ratio (GOR); flow rate 
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62 

Emission Source Monitoring Methods Emissions Quantification Methods 

Associated Gas Venting 

and Flaring 

Engineering Estimation Gas to oil Ratio (GOR); flow rate 

Flare Stacks 1) Direct Measurement or 

2) Engineering Estimation 

Engineering Calculation 

Centrifugal Compressor 

Wet Seal Oil Degassing 

Vent 

Direct Measurement Flow metered equipment specific 

emission factor times operating hours 

Large Reciprocating 

Compressor Rod Packing 

Vents 

Direct Measurement Flow metered equipment specific 

emission factor times operating hours 

Large Compressor 

Blowdown Valve Leak 

Leak Detection with 

optical gas imaging 

instrument 

Flow metered equipment specific 

emission factor times operating hours 

Large Compressor 

Blowdown Vent (Unit 

Isolation Valve Leak) 

Leak Detection with 

optical gas imaging 

instrument 

Flow metered equipment specific 

emission factor times stand-by 

depressurized hours 

Fugitive Sources 

(Processing, 

Transmission, 

Underground Storage, LNG 

Storage, LNG Import 

Export, LDC) 

Leak Detection with 

optical gas imaging 

instrument 

 

Leaker emission factors times detected 

leaks 

Fugitive Sources 

(Onshore Production, 

LDC) 

Component Count 

 

Population Emission Factors times 

components 
a. Direct Measurement 

EPA is proposing to require five sources in this 

supplemental proposal to directly measure emissions: 

storage tanks (transmission) when scrubber dump valves are 

detected leaking, centrifugal compressor wet seal oil 

degassing vents, large reciprocating compressor rod packing 

vents, large compressor blowdown vent valve leaks, and 

large compressor blowdown vent (unit isolation valve 

leaks), the latter two when leakage is detected. For 

example, storage tanks in the onshore natural gas 

transmission segment typically store the condensate (water, 

light hydrocarbons, seal oil) from the scrubbing of 

pipeline quality gas. The volume and composition of liquid 

is typically low and variable, respectively, in comparison 

to the volumes and composition of hydrocarbon liquids 

stored in the upstream segments of the industry. Hence the 

emissions from condensate itself in the transmission 

segment are considered insignificant. However, scrubber 

dump valves malfunction or stick-open due to debris in the 

condensate and can remain open resulting in natural gas 

bypass via the open dump valve to and through the 

condensate tank, and therefore the use of E&P Tanks and 

other models are not applicable to tanks in the 

transmission segment. The only potential option for 
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64 

measuring emissions from scrubber dump valves is to monitor 

storage tank emissions with a gas imaging camera to 

determine if the emissions do not subside and become 

negligible when dump valves close. If the scrubber dump 

valve is stuck and leaking natural gas through the tank 

then the emissions will be visibly significant and will not 

subside to inconspicuous volumes. If the scrubber dump 

valve functions normally and shuts completely after the 

condensate has been dumped then the storage tank, emissions 

should subside and taper off to insignificant quantities. 

If emissions are detected to be continuous for a duration 

of five minutes then a one-time measurement would be 

required using a temporary meter to establish an equipment 

specific emission factor. 

This proposal is based on the fact that the emissions 

magnitude from these five sources are significant enough to 

warrant reporting for the supplemental proposed rule and 

that no credible engineering estimation methods or 

emissions factors exist that can accurately characterize 

the emissions. There are several public reference studies 

and guidance documents that provide emissions factors for 

these sources. However, after close review, EPA has 

determined that these emissions factors cannot uniquely 

characterize the emissions specifically from individual 
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65 

equipment or a facility. For example, the emissions from 

wet seal degassing and rod packing are directly correlated 

to the size of the compressor, throughput, and the 

operating time of the compressor in the reporting year. 

Also, in the case of unit isolation valves and compressor 

blow down valves the emissions magnitude varies depending 

on operational and maintenance practices as valves can have 

excessive leakage, especially when a compressor is not in 

operation. These factors do not get accounted for using an 

emissions factor. 

The proposed supplemental rule would require that rod 

packing and blowdown valves be measured for emissions both 

in operating as well as standby pressurized modes. In 

addition, unit isolation valve leaks would be required to 

be measured at the blowdown vent in the standby depressurized mode. To correctly quantify emissions from 

centrifugal and large reciprocating compressors the 

proposal would require that, for each compressor, one 

measurement be taken in each of the operational modes that 

occurs during a reporting period: (i) operating, (ii) 

standby pressurized, and (iii) not operating, 

depressurized. Depending on the operational practices each 

mode could have significantly different emissions and would 
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66 

need to be separately quantified as a part of the proposed 

rule. 

For direct measurement, EPA proposes that the 

following technologies be used: high volume samplers, 

meters (such as rotameters, turbine meters, hot wire 

anemometers, and others), and/or calibrated bags. EPA 

recognizes that different measurement equipment would be 

required for different source emissions measurement 

depending on the configuration of the system. Hence the 

proposed rule provides these options for multiple direct 

measurement equipment, but the reporter must calibrate and 

maintain the equipment based on either consensus based 

standards or an appropriate method specified by the 

equipment manufacturer, as specified in the proposed rule. 

Where a vent emission source cannot be accessed on the 

ground or from a fixed platform, the reporter has the 

choice of using a man-lift or installing either a permanent 

or temporary vent line access port through which a meter 

can be inserted to measure flow or velocity. If emissions 

exceed the maximum range of one measurement instrument, the 

reporter would be required to use a different instrument 

option that can measure larger magnitude emissions levels. 

For example, if a high volume sampler maximum rate is 

exceeded by an emissions source, then emissions would be 
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67 

required to be directly measured using either calibrated 

bagging or a meter. CH4 and CO2 emissions from the 

emissions stream would be required to be calculated using 

the composition of the gas in the process equipment 

(compressor). 

b. Engineering estimation 

This proposed rule would require two main types of 

engineering calculation methods for emissions; (1) 

volumetric calculation method, and (2) engineering first 

principle methods. 

(1) Volumetric calculation method 

The volumetric calculation method has been proposed 

for calculating CH4 and CO2 vent emissions from sources 

where the variable in the emissions magnitude on an annual 

basis is the number of times the source releases CH4 and CO2

emissions to the atmosphere. In addition, the estimation 

of the total volume of emissions is a matter of simple 

arithmetic calculation without the need for complex 

calculations. For example, when a compressor is taken 

offline for maintenance, the volume of CH4 and CO2 blowdown 

vent emissions that are released is the same during each 

release, is easily calculable, and the only variable is the 

number of times the compressor is taken offline and vented. 

(2) Engineering first principle methods 
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68 

Emissions from sources such as tanks and glycol 

dehydrators can be reliably calculated using standard 

engineering first principle methods such as those available 

in E&P Tank and GlyCalc. The use of such standard and 

readily available software is a cost-effective way to 

uniformly estimate emissions that are representative for 

the two sources. To maintain standardization across 

reporters the proposed rule would require the use of E&P 

Tank for estimating the emissions from well-pad separator 

conditions when flashed to atmospheric pressure in any 

downstream stock tank, and GlyCalc for glycol dehydrators. 

E&P Tank is available for free and GlyCalc can be 

purchased at a small fee. Also, these two software models 

are widely used in the industry and the operation of the 

software is well understood. Using such software also 

addresses safety concerns that are associated with direct 

measurement from the two sources. For example, sometimes 

the temperature of the emissions stream for glycol 

dehydrator vent stacks is too high for operators to safely 

measure emissions. 

In cases where tank emissions do not represent 

equilibrium conditions of the liquid in a gas-liquid 

separator and no publicly available data are available on 

vapor bypass direct measurement would be required under the 
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69 

proposal. For pressurized liquids sent to atmospheric 

storage tanks where tank emissions are not expected to be 

represented by the equilibrium conditions of the liquid in 

a gas-liquid separator as calculated by the E&P Tank Model, 

then emissions calculated by E&P Tank would be multiplied 

by an empirical factor. 

The supplemental proposed rulemaking does not include 

emissions from tanks containing primarily water with the 

exception of transmission station condensate tanks where 

dump valve are determined to be bypassing gas. Therefore, 

EPA seeks comments on how to quantify emissions from tanks 

storing water without resulting in additional reporting 

burden to the facilities. 

For further discussion of these software programs and 

emissions calculation methods, refer to the Petroleum and 

Natural Gas Systems TSD (EPA-HQ-OAR-2008-0508-XXX). 

c. Combination of direct measurement and engineering 

estimation 

Several sources provide a choice between engineering 

estimation based on operating data and direct measurement 

(if meters are already installed). For continuous flaring, 

a one-time direct measurement or engineering estimate may 

be performed in conjunction with engineering estimation 

based on operating data that relates to the quantity of 
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70 

flared gas. For well completion venting and well workover 

venting (each during flowback after hydraulic fracturing, 

the only significant well completion emissions), EPA 

explored the possibility of using a meter for measuring 

hydrocarbon gas lost during these venting events which may 

last from one to ten days. Some companies have reported 

directly measuring these emissions under certain 

circumstances. However, such metering could be technically 

challenging, if not impossible, and also burdensome given 

the number of well completions and workovers being 

conducted on an annual basis. 

It is important to note, however, that no body of data 

has been identified that can be summarized into generally 

applicable emissions factors to characterize emissions from 

these sources in each unique field. In fact, the emissions 

factor being used in the 2008 U.S. GHG Inventory is 

believed to significantly underestimate emissions based on 

industry experience as included in the Natural Gas STAR 

Program publicly available information 

(http://www.epa.gov/gasstar/). In addition, the 2008 U.S. 

GHG Inventory emissions factor was developed prior to the 

boom in unconventional well drilling (1992) and in the 

absence of any field data and does not capture the 

diversity of well completion and workover operations or the 
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71 

variance in emissions that can be expected from different 

hydrocarbon reservoirs in the country. 

As a result, EPA proposes the development of a fieldspecific emission factor either by direct measurement of 

flow rate of hydrocarbons using a meter or by an 

engineering estimation based on well choke pressure drop. 

Given the large number of well completions and well 

workovers, EPA proposes that one representative well 

completion and one well workover per field horizon be 

developed to characterize emissions per day of venting from 

all other completions and workovers in that field horizon. 

The reporter would be required to update this factor every 

two years. This would alleviate burden but at the same 

time achieve a reasonable characterization of the emissions 

from these two sources. 

d. Use of Leak detection and leaking component 

emission factors 

Each segment of the petroleum and gas system has a 

variety of fugitive emissions sources that at a source type 

level have low emissions volume, but combined together at a 

segment level contribute significantly towards the total 

emissions from petroleum and gas systems. EPA considered 

several options for estimating emissions from fugitive 

emissions sources. One option considered was to use a 
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72 

population count of each fugitive emissions source (e.g. 

source types such as valves, connectors, etc.) and multiply 

it by a population emissions factor. However, such a 

method has a significant draw back. This option does not 

account for differences in operational and maintenance 

practices among facilities. If population emissions 

factors are used then the fugitive emissions from a 

particular facility will remain constant indefinitely until 

the facilities are modified (i.e., change the population of 

equipment) or new factors are provided. This approach also 

will not account for fugitive emissions reduction measures 

the industry has undertaken in the last few years since the 

population emission factors were developed. Facilities 

with good maintenance practices may have fugitive emissions 

lower than the population emission factors. 

Another option considered was the use of fugitive 

emissions detection (e.g., an infrared camera) and direct 

measurement (e.g., calibrated bags or high volume samplers) 

for fugitive sources. This option may be more costeffective when the sources of fugitive emissions are in a 

relatively small geographic area such as at a processing 

plant, gas compressor station, or distribution gate 

station. This approach, however, could be less cost 
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73 

effective for widely dispersed sources (e.g. well pads and 

gathering lines). 

Hence, to overcome these issues, EPA proposes 

conducting fugitive emissions detection and then applying 

leaking component (or leak only) emissions factors for 

processing, transmission, underground storage, LNG storage, 

LNG import and export terminals, and LDC gate stations. 

The fugitive emissions leak detection method does not 

require corresponding direct measurement of the fugitive 

emissions, which is significantly more burdensome than 

fugitive emissions detection using the most modern optical 

gas imaging instrument detection technology adopted as an 

alternative work practice by EPA’s LDAR Program (Method 

21). This method is an improvement over the use of 

population emissions factors because the factors were 

developed for leaking components and applied only to 

leaking components, leading to a more accurate calculation 

of emissions from each piece of equipment. Several 

commenters to the initial proposed rule recommended leak 

detection with an optical gas imaging instrument and 

quantification with emission factors. In addition, leaking 

component emissions factors are applied only to those 

emissions sources that are determined to be emitting as a 

result of the fugitive emissions detection process. 
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74 

EPA analyzed new fugitive leak studies specifically 

performed on natural gas facilities in processing plants 

and transmission compressor stations, as recommended by 

several Subpart W initial proposed rule commenters. These 

studies include numbers 3, 12, and 13 below. Leaking 

component emissions factors from these studies were 

compared with other studies (see below). EPA found that 

emission factors generated from the three Clearstone 

studies related better to methane-rich stream fugitives and 

were more appropriate than other emission factors developed 

for highly regulated refinery and petrochemical plants on 

VOC emissions. Therefore, EPA is using emissions data from 

the three Clearstone studies (#3, #12, #13 below) as the 

basis for the leaker factors proposed in this rule. For 

further details see Petroleum and Natural Gas Systems TSD 

(EPA-HQ-OAR-2008-0508-XXX). 

1. API. Compendium of Greenhouse Gas Emissions 

Methodologies for the Oil and Gas Industry. 

American Petroleum Institute. Table 4-7, page 4-

30. February 2004. 

2. API. Emission Factors for Oil and Gas Production 

Operations. Table 8, page 10. API Publication 

Number 4615. January 1995. 
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75 

3. EPA. Identification and Evaluation of 

Opportunities to Reduce Methane Losses at Four 

Gas Processing Plants. Clearstone Engineering 

Ltd. June 20, 2002. 

http://www.epa.gov/gasstar/documents/four_plants.

pdf 

4. EPA. Inventory of U.S. Greenhouse Gas Emissions 

and Sinks: 1990-2007. Annexes. Tables A-112 – 

A-125. U.S. EPA. April 2009. 

http://epa.gov/climatechange/emissions/downloads0

9/Annexes.pdf. 

5. EPA. Protocol for Equipment Leak Emission 

Estimates. Emission Standards Division. U.S. 

EPA. Table 2-7. November 1995. 

http://www.epa.gov/ttn/chief/efdocs/equiplks.pdf. 

6. GRI. Methane Emissions from the Natural Gas 

Industry. Volume 6. Table 4-2 and Appendix A, 

page A-2. June 1996. 

http://www.epa.gov/gasstar/documents/emissions_re

port/6_vented.pdf. 

7. GRI. Methane Emissions from the Natural Gas 

Industry. Volume 7. Page B-9. June 1996. 

http://www.epa.gov/gasstar/documents/emissions_re

port/7_blowandpurge.pdf. 
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76 

8. GRI. Methane Emissions from the Natural Gas 

Industry. Volume 8. Tables 4-3, 4-6 and 4-24. 

June 1996. 

http://www.epa.gov/gasstar/documents/emissions_re

port/8_equipmentleaks.pdf

9. GRI. Methane Emissions from the Natural Gas 

Industry. Volume 9. Tables 8-9 and 9-4. June 

1996. 

http://www.epa.gov/gasstar/documents/emissions_re

port/9_underground.pdf. 

10. GRI. Methane Emissions from the Natural Gas 

Industry. Volume 10. Table 7-1. June 1996. 

http://epa.gov/gasstar/documents/emissions_report

/10_metering.pdf. 

11. ICF. Estimates of Methane Emissions from 

the U.S. Oil Industry. Draft. Page 13. October 

1999. 

12. Picard, D.J., et al. Handbook for 

Estimating Methane Emissions from Canadian 

Natural Gas Systems. Clearstone Engineering 

Ltd., Enerco Engineering Ltd, and Radian 

International. Pages 61-63. May 25, 1998. 

13. National Gas Machinery Laboratory, Kansas 

State University; Clearstone Engineering, Ltd; 
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77 

Innovative Environmental Solutions, Inc. CostEffective Directed Inspection and Maintenance 

Control Opportunities at Five Gas Processing 

Plants and Upstream Gathering Compressor Stations 

and Well Sites. For EPA Natural Gas STAR Program. 

March 2006. 

EPA considered the use of the three major types of 

emissions detection equipment: optical gas imaging 

instruments, IR laser detector instruments and Toxic Vapor 

Analyzers (TVA) or Organic Vapor Analyzers (OVA). Optical 

gas imaging instruments are able to scan hundreds of source 

types quickly, allowing for the most efficient survey of 

emissions at a broad range of facilities. In addition, EPA 

recently adopted detailed performance standards for the 

optical gas imaging camera in the Alternative work practice 

for monitoring equipment leaks (AWP)(40 CFR part 60 subpart 

A §60.18 (i) (1) through (3)). We recognize that the 

purchase of optical gas imaging instruments can be costly, 

especially for smaller facilities. However, EPA believes 

that most facilities will opt for contractors to conduct 

emissions detection once per year. As mentioned above, 

several commenters to the initial proposed rule recommended 

leak detection with an optical gas imaging instrument in 

accordance with the EPA AWP. Hence, the supplemental 
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78 

proposed rule requires the use of an optical gas imaging 

instrument compliant with the operational requirements of 

the EPA AWP. In contrast to the EPA AWP, however, the 

proposed rule does not require multiple surveys per year 

and does not require leak repair. As discussed further 

below, for this proposed rule, EPA requires comprehensive 

annual leak detection of the fugitive emissions sources 

specified in the proposed rule. The proposed supplemental 

rule does not allow for the use of an OVA/TVA. The OVA/TVA 

requires the operator to physically access the emissions 

source with the probe and thus is much more time intensive 

than using the optical gas imaging instrument. In 

addition, the OVA/TVA range is limited to the reach of an 

operator standing on the ground or fixed platform, thus 

excluding all emissions out of reach. However, EPA is 

seeking comments on allowing the OVA/TVA to be used as 

another option to the optical imaging camera in this 

proposed rule. 

EPA is aware that the optical gas imaging instrument’s 

“detection sensitivity levels” as required by the AWP were 

established from data on volatile organic compound (VOC) 

emissions from petroleum refineries and chemical plants. 

The optical gas imaging instrument has been used 

extensively to successfully detect methane emissions in the 
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79 

petroleum and gas industry by petroleum and gas companies 

and in recent studies funded by EPA. A 2006 independent 

study funded through a grant by EPA and conducted by 

Clearstone Engineering used the optical gas imaging 

instrument to conduct an extensive study of methane 

emissions in gas processing plants and upstream gathering 

compressor stations and well sites. This study surveyed 

approximately 50,000 components finding 3,650 leaks (7.3%). 

Of these leaks, 497 (1% of total components) contributed 

90% of the total fugitive emissions. The smallest of the 

497 leaks was 177 grams per hour, well above the 6 to 10 

gram per hour detection sensitivity in Table A of the AWP. 

Therefore, for the purposes of this reporting rule, EPA 

determined that a camera that meets the detection 

sensitivity requirements of the AWP for any monitoring 

frequency as specified in Table A of the AWP, is acceptable 

for use under this proposed rule. 

The proposed rule requires that the survey for 

fugitive emissions detection be comprehensive. This means 

that, on an annual basis, the entire population of fugitive 

emissions sources proposed for reporting in this rule would 

be surveyed at least once. EPA proposes that emissions are 

quantified using leaker emissions factors. Under the 

proposal, if a component fugitive emission is detected, 
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80 

emissions are assumed to occur the entire 365 days in the 

year. EPA considered, but did not propose, allowing the 

facility the option to conduct multiple surveys and to 

report emission depending on the results of those surveys. 

Under this alternative approach, total emissions from each 

source would be quantified under one of the following three 

scenarios: 1) if a facility conducts one comprehensive leak 

survey each year, applicable component leaker emissions 

factors would be applied to all specific component 

emissions sources and emissions are quantified based on 

emissions occurring for the entire year; 2) if a facility 

conducts two comprehensive leak surveys during a single 

calendar year, applicable component leaker emissions 

factors would be applied to all component emissions 

sources. If a specific emission source is found not 

leaking in the first survey but leaking in the second 

survey, emissions would be quantified from the date of the 

first leak survey conducted in the same year forward 

through the remainder of the year. If a specific emissions 

source is found leaking in the first survey but not leaking 

in the second survey, emissions would be quantified from 

the first day of the year to the date of the second survey. 

If a component is found leaking in both surveys, emissions 

would be quantified based on an emission occurring for an 
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81 

entire year; 3) if a facility conducts multiple 

comprehensive leak surveys during the same year, applicable 

component leaker emissions factors are applied to component 

emissions sources. Each specific source found leaking in 

one or more surveys would be quantified for the period from 

a prior finding of no leak (or beginning of the year) to a 

subsequent finding of no leak (or end of the year. If a 

component is found leaking in all surveys, emissions would 

be quantified based on an emissions occurring for an entire 

year. Hence, emissions would reflect leak reductions as 

determined by repairs and follow-up detection surveys 

The proposed rule does not require more than an annual 

survey. If a leak is found, the owner or operator would be 

required to assume that the leak continues for the entire 

year. We recognize that this may lead to emissions 

reported being higher than actual. EPA seeks comment on 

this proposal, and whether the approach described above, 

which would be optional for owners or operators, would be 

an appropriate means to address this issue without 

resulting in additional reporting burden to the facilities. 

e. Use of Population count and population emission 

factor 

Fugitive emissions detection and use of leaking 

component emissions factors are not always cost effective 
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82 

and can be burdensome. This is particularly true of 

onshore petroleum and natural gas production where the 

fugitive sources are spread out across large geographical 

areas and fugitive emissions are a minor contributor to 

total segment emissions. In the distribution segment, 

pipeline fugitive emissions are a large fraction of total 

emissions, but the pipelines are buried where leaks are 

difficult to detect. Similarly, metering/regulator 

stations, which are an important source of fugitive 

emissions, are sometimes located inside underground vaults 

that are difficult to access. In such scenarios, fugitive 

emissions detection can be burdensome. Therefore, for 

onshore petroleum and natural gas production, gas gathering 

pipelines and LDC pipelines and M&R stations below grade in 

vaults, the proposed rule requires the use of population 

count of emissions sources and population emissions factor 

to estimate fugitive emissions. 

f. Alternative Monitoring Methods Considered 

Before selecting the monitoring methods proposed 

above, we considered additional measurement methods. The 

use of Method 21 was considered for fugitive emissions 

detection and measurement. Although Toxic Vapor Analyzers 

(TVA) and Organic Vapor Analyzers (OVA) were considered 
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83 

they were not proposed for fugitive emissions detection and 

quantification. 

Method 21. This is the reference method for equipment 

leak detection and repair regulations for volatile organic 

compound (VOC) and hazardous air pollutant (HAP) emissions 

under several 40 CFR Part 60, 40 CFR Part 61, 40 CFR Part 

63, and 40 CFR Part 65 emission standards. Petroleum 

refineries, chemical plants and large gas processing plants 

are required under state and federal laws to perform LDAR 

(Leak Detection and Repair) to control VOC air pollution 

emissions. This program requires VOC and/or HAP leak 

detection using instruments specified in Method 21, and 

requires repair of leaks if the rate is above the leak 

definitions specified within the specific regulation 

(typically between 500 parts per million to 10,000 parts 

per million as read on an OVA). Some states and air 

quality districts have lower leak definitions than the 

Federal standards. Method 21 requires facilities to conduct 

multiple surveys per year: either following equipmentspecific frequencies using VOC monitoring instruments, or 

bi-monthly, semi-quarterly or monthly using an optical gas 

imaging instrument, frequency depending on the sensitivity 

detection of the instrument. While LDAR programs do not 

require quantification, state inventories of air emissions 
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84 

use this LDAR leak detection data with “leaker” factors 

developed by the Synthetic Organic Chemicals Manufacturing 

Industry (SOCMI) to estimate the quantity of fugitive VOC 

emissions. These factors were developed from petroleum 

refinery and petrochemical plant data using Method 21. 

SOCMI factors adjusted for methane content are considerably 

lower than the methane factors proposed in this rule, which 

were developed from more recent studies of gas processing 

plants and compressor stations. 

The Federal LDAR program recently adopted an 

alternative work practice that allows use of optical gas 

imaging instruments in place of the VOC monitoring 

instrument specified in Method 21. In a similar vein, this 

rule proposes the use of optical gas imaging instruments to 

detect leaks once per year, and has developed leaker 

factors specific to methane from several recent studies 

quantifying component fugitive leaks in petroleum and gas 

facilities. While this rule proposes a similar approach to 

Method 21, given that this is a reporting rule for 

collecting annual GHG emissions, there are several key 

differences: the proposed annual reporting rule is focused 

on gathering fugitive and vented CO2 and CH4 emissions, does 

not require multiple surveys per year, and does not allow 

measurement using an OVA/ TVA for the reasons cited above. 
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85 

Optical gas imaging instruments were found to be more 

appropriate for fugitive leak detection for the proposed 

supplemental rule as these instruments are able to scan 

hundreds of source components quickly, including components 

out of reach for an OVA/TVA. 

Mass Balance for Quantification. Except in one case, 

EPA considered, but decided not to propose, the use of a 

mass balance approach for quantifying emissions across an 

entire facility. This approach would take into account the 

volume of gas entering a facility and the amount exiting 

the facility, with the difference assumed to be emitted to 

the atmosphere. This is most often discussed for emissions 

estimation from the transportation segment of the industry. 

However, for pipeline transportation, the mass balance is 

often not recommended because of the uncertainties 

surrounding meter readings, the highly variable line pack 

of high pressure gas and the large volumes of throughput 

relative to emissions. 

EPA is proposing this approach in the case of one 

emission source – acid gas recovery units. Typically, the 

natural gas volumes and compositions are measured both at 

the inlet and outlet of the acid gas recovery units as it 

is required to ensure that natural gas meets transmission 

system pipeline specifications. Hence, it is considered 
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86 

sufficiently feasible to use the mass balance approach for 

this source. For all other facilities and sources, the 

accuracy required in volume measurements will be a 

significant added burden in addition to being unreliable in 

many cases. 

F. Selection of Procedures for Estimating Missing Data

The proposal requires data collection for a single 

source a minimum of once a year. If data are lost or an 

error occurs during emissions detection and/or measurement 

or calculation, the operator would be required to carry out 

the detection, direct measurement, and/or calculation a 

second time to obtain the relevant data point(s) as soon as 

the missing data are discovered. If this falls outside of 

the reporting year (e.g. between the end of the reporting 

year and the date when the emissions must be reported) the 

operator would be required to perform the necessary data 

development and report the results for the previous year. 

This prior year’s lost data replacement could not be used 

as the one-time data collection for the current year. 

Where missing data procedures are used for the previous 

year, at least 30 days would be required to separate 

emissions estimation and/or measurements for the previous 

year and emissions estimation and/or measurements for the 

current year of data collection in order to better 
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87 

represent emissions estimates for different years. 

Similarly, engineering estimates would account for relevant 

source counts and frequency from the previous reporting 

period. 

G. Selection of Data Reporting Requirements

EPA proposes that emissions from the petroleum and 

natural gas industry be reported on an annual basis. The 

reporting should be by the owner or operator of the 

facility as defined in the supplemental rule. Emissions 

from each source type at the facility would be required to 

be aggregated for reporting, with a few exceptions for 

field level reporting (e.g., well completions and well 

workovers). For other equipment, unit-level reporting 

would not be required. For example, the owner or operator 

with multiple reciprocating compressors in an onshore 

production basin would be required to report emissions 

collectively from all rod packings on all cylinders from 

all compressors for all fields in that basin as specified 

in this proposed rulemaking. 

Emissions from all sources proposed for monitoring, 

whether in operating condition or on standby, would have to 

be reported. Any emissions resulting from standby 

compressor sources would be separately identified from the 

aggregate emissions. 
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88 

The owner or operator would be required to report the 

following information to EPA as a part of the annual 

emissions reporting: fugitive, vented and flare combustion 

emissions monitored at an aggregate source level (unless 

specified otherwise), emissions from standby sources; and 

activity data for each aggregate source type level. Owners 

or operators of natural gas distribution facilities would 

report emissions at the individual station level. 

Additional data are proposed to be reported to support 

verification: engineering estimate of total component 

count; total number of compressors and average operating 

hours per year in each mode of operation for compressors, 

if applicable; minimum, maximum and average throughput per 

year; and specification of the type of any control device 

used, including flares. For offshore petroleum and natural 

gas production facilities, the number of connected wells, 

and whether they are producing oil, gas, or both is 

proposed to be reported. For compressors specifically, EPA 

proposes that the total number of compressors of each type 

(reciprocating, centrifugal with dry seals and centrifugal 

with wet seals) and average operating hours per year be 

reported. 

A full list of data proposed to be reported is 

included in proposed 40 CFR part 98, subparts A and W. 
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89 

H. Selection of Records That Must Be Retained

The owner or operator shall retain relevant 

information associated with the monitoring and reporting of 

emissions to EPA for three years as follows: throughput of 

the facility when the emissions direct measurement was 

conducted; date(s) of measurement, detection and 

measurement instruments used, if any; and results of the 

emissions detection survey, including a video record of the 

leak survey. 

A full list of records proposed to be retained is 

included in proposed 40 CFR part 98, subparts A and W. 

III. Economic Impacts on the Rule 

This section of the preamble examines the costs and 

economic impacts of this proposed supplemental rule, 

including the estimated costs and benefits of the rule, and 

the estimated economic impacts of the rule on affected 

entities, including estimated impacts on small entities. 

Complete details of the economic impacts of the final rule 

can be found in the text of the Economic Impact Analysis 

(EPA-HQ-OAR-2008-0508-XXX).. In brief, all equipment and 

labor activities for complying with each emissions estimate 

in the rule were analyzed by technical experts with 

relevant industry experience. The estimated labor hours 

and labor categories were applied to each industry segment, 
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90 

in some cases proportioned to small, medium and large 

facilities where such variation exists, to quantify the 

total labor hours, multiplied by Government statistics on 

labor rates, arriving at the total labor and equipment 

costs for the estimated numbers of sources. Administrative 

costs for reviewing the reporting rules, training 

personnel, documenting emissions data and emissions 

estimates, approving the submission to the EPA, submitting 

reports and maintaining records were included for each 

reporting company. These total bottom-up cost estimates 

were divided by the emissions captured to arrive at the 

dollar per metric ton, and divided by the number of 

reporting entities to arrive at average costs per entity. 

The methods proposed by EPA are a balance between 

minimizing these costs, maximizing emissions coverage and 

maximizing quality of emissions estimates. The cost to 

affected parties on a dollar per metric ton has been 

reduced by greater than 50% when compared to the initial 

petroleum and natural gas proposal. To achieve this cost 

reduction, EPA significantly modified the rule to rely 

significantly less on direct measurement and more on 

engineering estimates, leaker factors and emissions 

factors. Table W-5 and Table W-6 compare the first year 

and subsequent year costs, respectively, to reporters for 
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91 

reporting fugitive and vented emissions based on the 

reporting requirements proposed under the initial proposal 

as compared to the new supplemental proposed rule. 

Table W-5. ESTIMATED FIRST YEAR COST FOR REPORTING 

FUGITIVE AND VENTED EMISSIONS FOR PETROLEUM AND NATURAL GAS 

SYSTEMS, MMTCO2e 

Initial Proposed Rule1 New Supplemental 

Proposed Rulemaking 

Segment 

Cost 

($Million)

Cost per 

tonne 

($/tonne)

Cost 

($Million)

Cost per 

tonne 

($/tonne) 

Original six 

segments $32.5 $0.38 $26.7 $0.28 

Onshore 

Production NA NA $27.7 $0.18 

Natural Gas 

Distribution NA NA $1.6 $0.07 

Total 

Segments 

$32.5 $0.38 $56.0 $0.21 

1. The costs for the initial proposed rule, shown here, reflect 

the in-house monitoring option. Costs for the alternative contractor 

monitoring option can be found in Docket EPA-HQ-OAR-2008-0508-0138. 
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92 

TABLE W-6. ESTIMATED SUBSEQUENT YEAR COST FOR REPORTING 

FUGITIVE AND VENTED EMISSIONS FOR PETROLEUM AND NATURAL GAS 

SYSTEMS, MMTCO2E 

Initial Proposed Rule New Supplemental 

Proposed Rulemaking 

Segment 

Cost 

($Million)

Cost per 

tonne 

($/tonne) 

Cost 

($Million)

Cost per 

tonne 

($/tonne) 

Original six 

segments $28.1 $0.33 11.8 $0.13 

Onshore 

Production NA NA 8.6 $0.06 

Natural Gas 

Distribution NA NA 1.0 $0.04 

Total 

Segments 

$28.1 $0.33 21.4 $0.08 

1. Subsequent year in the initial proposed rule was defined as 

Year 2 whereas in the supplemental proposed rule it is defined as the 

average of Years 2, 3, and 4. 

A. How were compliance costs estimated?

1. Summary of EPA’s Consideration of Comments Received on 

the Initial Proposal 

A majority of the comments received on the compliance 

costs of the fugitive emissions reporting rule focused on 

facility level costs for detection and measurement of 

emissions. Commenters noted that costs estimated for 

certain petroleum and gas industry segments ignored 

available data on average leak factors. Some who commented 

specifically referred to government programs that gather 
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93 

similar, or in the case of offshore petroleum and gas 

production in the Gulf of Mexico Federal waters, some of 

the same data as required under Subpart W. Others who 

commented noted that Subpart W had higher estimated 

compliance costs than other sectors for much smaller GHG 

emissions. 

EPA recognizes that the costs presented for some 

petroleum and gas industry segments in the initial proposal 

were relatively high for smaller emissions quantified than 

other industry sectors. EPA also recognizes that for many 

fugitive and vented emissions sources, new data exist on 

component emission factors, and long established data may 

be justified for smaller, inaccessible or more burdensome 

to identify emission sources. Furthermore, EPA recognizes 

that other government programs gather similar or the same 

data as proposed by this rule. 

This proposed supplemental rule incorporates a number 

of different methodologies to provide improved emissions 

coverage at a lower cost burden to affected facilities. 

The approach used in determining the appropriate 

methodology for the supplemental was to minimize the use of 

direct measurement of emissions (which results in a higher 

cost burden to affected facilities) except for the most 

significant emissions sources where other options are not 
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94 

available, and to use engineering estimates, emissions 

modeling software, and leak detection and publicly 

available emission factors for most vented and fugitive 

sources. For smaller fugitive and inaccessible sources, 

component count and population emissions factors are 

proposed. In the case of Offshore platforms, EPA is 

recommending that emissions identified under the Minerals 

Management Services (MMS) GOADS (Gulfwide Offshore 

Activities Data System) be used for reporting, and the 

GOADS process be extended to platforms in other Federal 

regions (i.e. California and Alaska) and all State waters. 

These alternative methodologies will provide similar or 

better coverage of vented and fugitive methane and carbon 

dioxide emissions in the petroleum and gas industry, while 

significantly reducing industry burden. 

 As described in the next section, EPA collected and 

evaluated cost data from multiple sources, and weighed the 

analysis prepared at initial proposal against the input 

received through public comments. In any analysis of this 

type, there will be variations in costs among facilities, 

and after thoroughly reviewing the available information, 

we have concluded that the costs developed for this 

supplemental proposed rule in each petroleum and gas 
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95 

industry segment appropriately reflects a “representative 

facility” in those segments. 

2. Summary of Method Used to Estimate Compliance Costs 

EPA estimated costs of complying with the rule for 

reporting fugitive and vented GHG emissions in each 

affected petroleum and gas industry facility, as well as 

emissions from stationary combustion sources at petroleum 

and gas industry facilities (for threshold and burden 

analysis only; stationary combustion is reported under 

Subpart C). This supplemental rulemaking proposes 

methodologies for reporting fugitive and vented emissions 

from oil and gas facilities. Once triggering the proposed 

rule, all of these facilities would also have to report 

emissions from stationary combustion. The costs of 

compliance for this proposed rule includes the costs 

associated with calculating and reporting fugitive and 

vented emissions, as well as the costs of any incremental 

combustion-related emissions that would be required to be 

reported by facilities (i.e., combustion emissions that 

were not already required to be reported under the final 

MRR). The representative year of the analysis is 2006 and 

all annual costs were estimated using the 2006 population 

of emitting sources. EPA used available industry and EPA 

data to characterize conditions at affected sources. 
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96 

Incremental monitoring, recordkeeping, and reporting 

activities were then identified for each type of facility 

and the associated costs were estimated. 

The costs of complying with the rule will vary from 

one petroleum and gas industry segment and facility to 

another, depending on the types of emissions, the number of 

affected sources at the facility, existing monitoring, 

recordkeeping, and reporting activities at the facility, 

etc. The costs include labor costs for developing a plan, 

setting up records, collecting field data, performing 

monitoring, inputting field data into engineering models, 

recordkeeping, and reporting activities necessary to comply 

with the rule. For some facilities, costs include 

expenditures related to monitoring, recording, and 

reporting both process emissions of GHGs and emissions from 

stationary combustion. For other facilities (e.g., LDCs), 

the only emissions of GHGs are process emissions. EPA’s 

estimated costs of compliance are discussed in greater 

detail below: 

Labor Costs. The costs of complying with and 

administering this rule include time of managers, 

technical, operational and administrative staff in the 

private sector. Staff hours are estimated for activities, 

including: 
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97 

Χ Developing a plan: reporting entity management and 

technical staff hours to applicability to the rule, 

organize indoctrination of rule requirements, identify 

staffing assignments, train staff, schedule activities 

as required below. 

Χ Setting up records: technical and field staff hours to 

develop data collection sheets and analytical model 

equations or linkages to input data into standardized 

models 

Χ Collecting field data: technical and field staff hours 

to collect necessary site-specific data and input that 

data into the analytical input tables. 

Χ Monitoring: staff hours to procure, install, operate 

and maintain emissions monitoring equipment, 

instruments and engineering analysis systems. 

Χ Engineering models: technical staff hours to link and 

execute engineering emissions estimation models and 

analytical procedures and to organize output data as 

required for reporting emissions. 

Χ Record keeping: staff hours required to organize, file 

and secure critical data and emissions quantification 

results as required for reporting and for documenting 
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98 

determinations of facilities exceeding and not 

exceeding reporting thresholds. 

Χ Reporting: management and staff hours to organize 

data, perform quality assurance/quality control, 

inform key management personnel, and reporting it to 

EPA through electronic systems. 

Staff activities and associated labor costs will vary 

from facility to facility and potentially vary over 

time where first year start-up costs are more 

significant and where site-specific emissions factors 

are developed every two or three years. Thus, cost 

estimates are developed for start-up and first-time 

reporting, and subsequent reporting. Wage rates to 

monetize staff time are obtained from the Bureau of 

Labor Statistics (BLS). 

Equipment Costs. Equipment costs include both the 

initial purchase price of monitoring equipment and any 

facility/process modification that may be required for 

installation and/or use of monitoring equipment. For 

example, the cost estimation method for large compressor 

seal emissions includes both purchase of a flow measurement 

instrument and installation of a measurement port in the 

vent piping where the end of the vent is inaccessible. 

Based on expert judgment, the engineering costs analyses 
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99 

annualized capital equipment costs with appropriate 

lifetime and interest rate assumptions. Cost recovery 

periods and interest rates vary by industry, but typically, 

one-time capital costs are amortized over a 10-year cost 

recovery period at a rate of seven percent. 

B. What are the costs of the rule?

1. Summary of Costs 

For the cost analysis, EPA gathered existing data from 

EPA studies and publications, industry trade associations 

and publicly available data sources (e.g., labor rates from 

the BLS) to characterize the processes, sources, sectors, 

facilities, and companies/entities affected. EPA also 

considered cost data submitted in public comments on the 

proposed rule. Costs were estimated on a per entity basis 

and then weighted by the number of entities affected at the 

25,000 metric tons CO2e threshold. 

To develop the costs for the rule, EPA estimated the 

number of affected facilities in each source category, the 

number and types of process equipment at each facility, the 

number and types of processes that emit GHGs, process 

inputs and outputs (especially for monitoring procedures 

that involve a carbon mass balance), and the measurements 

that are already being made for reasons not associated with 

the rule (to allow only the incremental costs to be 
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100 

estimated). Many of the affected source categories, 

especially those that are the largest emitters of GHGs 

(e.g., glycol dehydrators, petroleum stock tanks, gas 

processing plants) are subject to national emission 

standards and we use data generated in the development of 

these standards to estimate the number of sources affected 

by the proposed reporting rule. 

Other components of the cost analysis included 

estimates of labor hours to perform specific activities, 

cost of labor, and cost of monitoring equipment. Estimates 

of labor hours were based on previous analyses of the costs 

of monitoring, reporting, and recordkeeping for other 

rules; information from the industry characterization on 

the number of units or process inputs and outputs to be 

monitored; and engineering judgment by industry and EPA 

industry experts and engineers. Labor costs were taken 

from the BLS and adjusted to account for overhead. 

Monitoring costs were generally based on cost algorithms or 

approaches that had been previously developed, reviewed, 

accepted as adequate, and used specifically to estimate the 

costs associated with various types of measurements and 

monitoring. 

A detailed engineering analysis was conducted for each 

petroleum and gas industry segment of this proposed rule to 
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101 

develop unique unit costs. This analysis is documented in 

the Economic Analysis for the proposed rule. The TSD 

(reference) provides a discussion of the applicable 

engineering estimating and measurement technologies and any 

existing programs and practices. Incremental combustionrelated emissions that would be required to be reported by 

facilities (as noted above) were estimated using Tier 1 

factors from Subpart C of the Final MRR. Section 4 of the 

Economic Analysis for the proposed rule contains a 

description of the engineering cost analysis. 

Table W-7 of this preamble presents: the emissions 

covered under this proposed supplemental rule, the first 

year total costs and the first year cost per ton for 

process and combustion emissions, and these values for the 

subsequent years. EPA estimates that the total cost for 

process emissions in the first year is $56.0 million, and 

the total national annualized cost for subsequent years is 

$21.4 million (2006$). Of these costs, roughly 49.5 

percent fall upon the onshore production segment in the 

first year, while 34.5 percent fall upon the gas 

transmission segment. Offshore production, which is 

largely covered by the MMS GOADS study data, is estimated 

to incur approximately 0.5 percent of costs every three or 

four years; other segments incurring relatively large 
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102 

shares of costs are gas processing (12.5 percent) and local 

distribution companies (3 percent). The reporting of 

incremental combustion related emission for all segments of 

the petroleum and natural gas industry are estimated to 

cost $3.9 million in both the first and subsequent years. 

The threshold, in large part, determines the number of 

entities required to report GHG emissions and hence the 

costs of the rule. The number of entities excluded 

increases with higher thresholds. Table W-8 of this 

preamble provides the cost-effectiveness analysis for 

various thresholds examined. Two metrics are used to 

evaluate the cost-effectiveness of the emissions threshold. 

The first is the average cost per metric ton of emissions 

reported ($/metric ton CO2e). The second metric for 

evaluating the threshold option is the incremental cost of 

reporting emissions. The incremental cost is calculated as 

the additional (incremental) cost per metric ton starting 

with the least stringent option and moving successively 

from one threshold option to the next. For more 

information about the first year capital costs 

(unamortized), project lifetime and the amortized 

(annualized) costs for each petroleum and gas industry 

segment please refer to section 4 of the Economic Analysis 

for the proposed rule. Not all segments require capital 
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103 

expenditures but those that do are clearly documented in 

the Economic Impact Analysis for the proposed rule. 
TABLE W-7. NATIONAL COST ESTIMATES FOR PETROLEUM AND NATURAL GAS SYSTEMS (2006$) 

First Year Subsequent Years 

$Million1 Subpart W – $Million

Petroleum and 

Natural Gas 

systems NAICS 2006 

Million 

MtCO2e $/ton 2006 

Million 

MtCO2e $/ton

Fugitive and 

Vented 

Emissions 

211, 

486 

$56 272.0 $0.21 $21.4 272.0 $0.08 

Combustion 

Emissions $3.9 79.1 $0.05 $3.9 79.1 $0.05 

Total Private 

Sector 

Emissions $59.9 351.1 $0.17 $25.3 351.1 $0.07

TABLE W-8. THRESHOLD COST-EFFECTIVENESS ANALYSIS (SUBSEQUENT YEAR, 2006$) 

Threshold 

(metric tons 

CO2e) 

Facilities 

Required to 

Report 

Total Costs 

(million 

$2006) 

Downstream 

Emissions 

Reported 

(MtCO2e/year

) 

Percenta

ge of 

Total 

Downstre

am 

Emission

s 

Reported 

Averag

e 

Report

ing 

Cost 

($/ton

) 

Increm

ental 

Cost 

($/met

ric 

ton) 1

100,000 1,143 $13.66 273 64% $0.05 $0.05 

25,000 3,037 $27.21 351 83% $0.08 $0.13 

10,000 4,884 $38.62 380 90% $0.10 $0.23 

1,000 15,057 $97.18 415 98% $0.23 $0.46 

1 Cost per metric ton relative to the selected option. 
C. What are the economic impacts of the rule?

1. Summary of Economic Impacts 

EPA prepared an economic impact analysis to evaluate 

the impacts of the rule on affected small to large 

reporting entities. In evaluating the various reporting 

options considered, EPA conducted a cost-effectiveness 

analysis, comparing the cost per metric ton of GHG 

emissions across reporting options. EPA used this 

information to identify the preferred options described in 

today’s proposed rule. 

To estimate the economic impacts of the rule, EPA 

first conducted a screening assessment, comparing the 

estimated total annualized compliance costs for the 

petroleum and gas industry, where industry is defined in 

terms of North American Industry Classification System 

(NAICS) code, with industry average revenues. Overall 

national costs of the rule are significant because there 

are a large number of affected entities, but per-entity 

costs are low due to large coverage of emissions from these 

entities. Average cost-to-sales ratios for establishments 

in the affected NAICS codes for all segments is less than 1 

percent, except in the 1-20 employee range for the onshore 

petroleum and natural gas segment. 
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106 

These low average cost-to-sales ratios indicate that 

the proposed rule is unlikely to result in significant 

changes in firms’ production decisions or other behavioral 

changes, and thus unlikely to result in significant changes 

in prices or quantities in affected markets. Thus, EPA 

followed its Guidelines for Preparing Economic Analyses

(EPA, 2002, p.124-125) and used the engineering cost 

estimates to measure the social cost of the rule, rather 

than modeling market responses and using the resulting 

measures of social cost. Table W-9 of this preamble 

summarizes cost-to-sales ratios for affected industries. 

TABLE W-9. ESTIMATED COST-TO-SALES RATIOS FOR AFFECTED 

ENTITIES (YEAR 1) 

NAICS NAICS Description 

Average Cost 

Per Entity 

($1,000/entity)

Average 

Entity 

Cost-toSales 

Ratio1

211 Crude Petroleum and Natural Gas 

Extraction 

$24 0.11%

486210 Pipeline Transportation of Natural 

Gas 

$18 0.10%

221210 Natural Gas Distribution $11 0.05%

1 This ratio reflects first year costs. Subsequent year costs 

will be slightly lower because they do not include initial start-up 

activities. 

D. What are the impacts of the rule on small businesses?

1. Summary of Impacts on Small Businesses 

As required by the RFA and Small Business Regulatory 

Enforcement and Fairness ACT (SBREFA), EPA assessed the 
OMB DRAFT: Please do not cite, quote or distribute 

107 

potential impacts of the rule on small entities (small 

businesses, governments, and non-profit organizations). 

(See Section IV.C of this preamble for definitions of small 

entities.) 

EPA has determined the selected threshold maximizes 

the rule coverage with 83 percent of U.S. GHG emissions 

from the industry segments reported by approximately 3,037 

reporters, while keeping reporting burden to a minimum. 

Furthermore, many industry stakeholders that EPA met with 

expressed support for a 25,000 metric ton CO2e threshold 

because it sufficiently captures the majority of GHG 

emissions in the U.S., while excluding most of the smaller 

facilities and sources. We received many comments related 

to monitoring and reporting requirements in specific source 

categories, and made many changes in response to reduce 

burden on reporters. For information on these issues, 

refer to the discussion of each segment in this preamble. 

EPA conducted a screening assessment comparing 

compliance costs to onshore petroleum and natural gas 

production specific receipts data for establishments owned 

by small businesses. This ratio constitutes a “sales” test 

that computes the annualized compliance costs of this rule 

as a percentage of sales and determines whether the ratio 
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108 

exceeds one percent.8 The cost-to-sales ratios were 

constructed at the establishment level (average reporting 

program costs per establishment/average establishment 

receipts) for several business size ranges. This allowed 

EPA to account for receipt differences between 

establishments owned by large and small businesses and 

differences in small business definitions across affected 

industries. The results of the screening assessment are 

shown in Table W-10 of this preamble. 

 

8 EPA’s RFA guidance for rule writers suggests the “sales” test 

continues to be the preferred quantitative metric for economic impact 

screening analysis. 
TABLE W-10. ESTIMATED COST-TO-SALES RATIOS FOR FIRST YEAR COSTS BY INDUSTRY AND 

ENTERPRISE SIZEA

Owned by Enterprises with:

Industry NAICS NAICS Description

SBA Size 

Standard 

(effective 

March 

11, 

2008)

Average 

Cost Per 

Entity 

($1,000/

entity)

All Enterprises 

<20 

Employeesf

20 to 99

Employees 

100 to 

499 

Employees 

500 to 

749 

Employees 

< 500 

Employee

s 

750 to 

999 

Employees 

1,000 to 

1,499 

Employees 

Onshore petroleum 

and natural gas 

production; 

offshore 

petroleum and 

natural gas 

production; LNG 

storage; LNG 

import and export

211 Crude Petroleum 

and Natural Gas 

Extraction 

500 

employee

s 

$24 0.11% 1.83% 0.16% 0.07% 0.03% 0.65% 0.04% 0.03% 

Onshore natural 

gas processing; 

onshore natural 

gas transmission; 

underground 

natural gas 

storage 

486210 Pipeline 

Transportation 

of Natural Gas 7.5 

million 

dollars

$18 0.10% 0.14% 0.47%b

0.28%b

0.12% 

Natural gas 

distribution 

221210 Natural Gas 

Distribution 

7.5 

million 

dollars

$11 0.05% 0.22% 0.02% 0.05% 0.09% 0.06% 0.02% 0.02% 

1 The Census Bureau defines an enterprise as a business organization consisting of one or more 

domestic establishments that were specified under common ownership or control. The enterprise and the 

establishment are the same for single-establishment firms. Each multi-establishment company forms one 

enterprise—the enterprise employment and annual payroll are summed from the associated establishments. 

Enterprise size designations are determined by the summed employment of all associated establishments. 
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110 

Since the SBA’s business size definitions (http://www.sba.gov/size) apply to an establishment’s ultimate 

parent company, we assume in this analysis that the enterprise definition above is consistent with the 

concept of ultimate parent company that is typically used for SBREFA screening analyses. 

2 The Census Bureau has missing data ranges for this employee range. Hence the receipts are an 

underestimate of the true value. Therefore, the cost-to-sales ratio is a conservative estimate. 
OMB DRAFT: Please do not cite, quote or distribute 

111 

 As shown, the cost-to-sales ratios are less than one 

percent for establishments owned by small businesses that 

EPA considers most likely to be covered by the reporting 

program, except the ratio for 1-20 employee range for crude 

petroleum and natural gas extraction, which is greater than 

1 percent but less than 2 percent. The petroleum and 

natural gas industry has a large number of enterprises, the 

majority of them in the 1-20 employee range. However, a 

large fraction of production comes from large corporations 

and not those with less than 20 employee enterprises. The 

smaller enterprises in most cases deal with very small 

operations (such as a single family owning a few production 

wells) that are unlikely to cross even the 25,000 metric 

tons CO2e threshold considered for the rule. An exception 

to such a scenario is a small (less than 20 employee) 

enterprise owning large operations but conducting nearly 

all of its operations through contractors. This is not an 

uncommon practice in the onshore petroleum and natural gas 

production segment. Such enterprises, however, are a very 

small group among the over 19,000 enterprises in the less 

than 20 employee category and EPA proposes to cover them in 

the rule. 

EPA took a conservative approach with the model entity 

analysis. Although the appropriate SBA size definition 
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112 

should be applied at the parent company (enterprise) level, 

data limitations allowed us only to compute and compare 

ratios for a model establishment within several enterprise 

size ranges. 

Although this rule will not have a significant 

economic impact on a substantial number of small entities, 

the Agency nonetheless tried to reduce the impact of this 

rule on small entities, including seeking input from a wide 

range of private- and public-sector stakeholders. When 

developing the rule, the Agency took special steps to 

ensure that the burdens imposed on small entities were 

minimal. The Agency conducted several meetings with 

industry trade associations to discuss regulatory options 

and the corresponding burden on industry, such as 

recordkeeping and reporting. The Agency investigated 

alternative thresholds and analyzed the marginal costs 

associated with requiring smaller entities with lower 

emissions to report. The Agency also recommended a hybrid 

method for reporting, which provides flexibility to 

entities and helps minimize reporting costs. 

E. What are the benefits of the rule for society?

EPA examined the potential benefits of the proposed 

GHG reporting rule for petroleum and natural gas systems. 

The benefits of a reporting system are based on their 
OMB DRAFT: Please do not cite, quote or distribute 

113 

relevance to policy making, transparency issues, and market 

efficiency. Benefits are very difficult to quantify and 

monetize. Instead of a quantitative analysis of the 

benefits, EPA conducted a systematic literature review of 

existing studies including government, consulting, and 

scholarly reports. 

A mandatory reporting system for petroleum and natural 

gas systems will benefit the public by increased 

transparency of facility emissions data. Transparent, 

public data on emissions allows for accountability of 

polluters to the public stakeholders who bear the cost of 

the pollution. Citizens, community groups, and labor 

unions have made use of data from Pollutant Release and 

Transfer Registers to negotiate directly with polluters to 

lower emissions, circumventing greater government 

regulation. Publicly available emissions data also will 

allow individuals to alter their consumption habits based 

on the GHG emissions of producers. 

The greatest benefit of mandatory reporting of 

petroleum and natural gas systems GHG emissions to 

government will be realized in developing future GHG 

policies. For example, in the European Union’s Emissions 

Trading System, a lack of accurate monitoring at the 

facility level before establishing CO2 allowance permits 
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114 

resulted in allocation of permits for emissions levels an 

average of 15 percent above actual levels in every country 

except the United Kingdom. 

As the primary constituent of natural gas, methane is 

also an important energy source. As a result, methane 

emissions reductions can provide significant economic and 

environmental benefits. EPA has been working in 

collaboration with oil and natural companies in the U.S. as 

part of the Natural Gas STAR Program since 1993. Through 

this collaborative partnership program, EPA has identified 

over 120 proven, cost effective technologies and practices 

to reduce methane emissions across operations in all of the 

major industry sectors—production, gathering and 

processing, transmission, and distribution. The proposed 

reporting rule will increase knowledge of the location and 

magnitude of significant methane emissions sources in the 

oil and gas industry which can result in cross-cutting 

benefits on domestic energy supply, industrial efficiency 

and safety, and revenue generation. 

Benefits to industry of GHG emissions monitoring 

include the value of having independent, verifiable data to 

present to the public to demonstrate appropriate 

environmental stewardship, and a better understanding of 
OMB DRAFT: Please do not cite, quote or distribute 

115 

their emission levels and sources to identify opportunities 

to reduce emissions. Such monitoring allows for inclusion 

of standardized GHG data into environmental management 

systems, providing the necessary information to achieve and 

disseminate their environmental achievements. 

Standardization will also be a benefit to industry, 

once facilities invest in the institutional knowledge and 

systems to report emissions, the cost of monitoring should 

fall and the accuracy of the accounting should improve. A 

standardized reporting program will also allow for 

facilities to benchmark themselves against similar 

facilities to understand better their relative standing 

within their industry. 

Section VI of the RIA for the Final MRR summarizes the 

anticipated benefits of the finalized rule, which include 

providing the government with sound data on which to base 

future policies and providing industry and the public 

independently verified information documenting firms’ 

environmental performance. While EPA has not quantified 

the benefits of the mandatory reporting rule, EPA believes 

that they are substantial and outweigh the estimated costs. 

IV. Statutory and Executive Order Reviews 

A. Executive Order 12866: Regulatory Planning and Review
OMB DRAFT: Please do not cite, quote or distribute 

116 

Under Executive Order (EO) 12866 (58 FR 51735, October 

4, 1993), this action is a "significant regulatory action” 

because it raises novel legal or policy issues arising out 

of legal mandates, the President’s priorities, or the 

principles set forth in the EO. Accordingly, EPA submitted 

this action to the Office of Management and Budget (OMB) 

for review under EO 12866. 

B. Paperwork Reduction Act

The information collection requirements in this 

proposed rule 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 prepared by EPA has been 

assigned EPA ICR number [XXXX.XX]. [Insert EPA ICR number.] 

EPA plans to collect complete and accurate facilitylevel GHG emissions from the petroleum and natural gas 

industry. Accurate and timely information on GHG emissions 

is essential for informing future climate change policy 

decisions. Through data collected under this proposed 

rule, EPA will gain a better understanding of the relative 

emissions of different segments of the petroleum and 

natural gas industry and the distribution of emissions from 

individual facilities within those industries. The 

facility-specific data will also improve our understanding 
OMB DRAFT: Please do not cite, quote or distribute 

117 

of the factors that influence GHG emission rates and 

actions that facilities are already taking to reduce 

emissions. Additionally, EPA will be able to track the 

trend of emissions from facilities within the petroleum and 

natural gas industry over time, particularly in response to 

policies and potential regulations. The data collected by 

this proposed rule will improve EPA’s ability to formulate 

climate change policy options and to assess which segments 

of the petroleum and gas industry would be affected, and 

how these segments would be affected by the options. 

This information collection is mandatory and will be 

carried out under CAA section 114. Information identified 

and marked as CBI will not be disclosed except in 

accordance with procedures set forth in 40 CFR part 2. 

However, emissions data collected under CAA section 114 

cannot generally be claimed as CBI and will be made public.9

The projected cost and hour burden for non-federal 

respondents is $37.8 million and 478,774 hours per year. 

The estimated average burden per response is 98.2 hours; 

the frequency of response is annual for all respondents 

 

9 Although CBI determinations are usually made on a case-by-case basis, 

EPA has issued guidance in an earlier Federal Register notice on what 

constitutes emissions data that cannot be considered CBI (956 FR 7042 – 

7043, February 21, 1991). As discussed in Section II.R of the Final 

MRR preamble, EPA is initiating a separate notice and comment process 

to make CBI determinations for the data collected under this 

rulemaking. EPA intends to issue this notice in early 2010, and will 

include in the notice the data proposed for collection in this 

rulemaking. 
OMB DRAFT: Please do not cite, quote or distribute 

118 

that must comply with the proposed rule’s reporting 

requirements; and the estimated average number of likely 

respondents per year is 3,038. The cost burden to 

respondents resulting from the collection of information 

includes the total capital cost annualized over the 

equipment’s expected useful life (averaging $5.3 million), 

a total operation and maintenance component (averaging $1.6 

million per year), and a labor cost component (averaging 

$30.9 million per year)10. Burden is defined at 5 CFR 

1320.3(b). 

An agency may not conduct or sponsor, and a person is 

not required to respond to, a collection of information 

unless it displays a currently valid OMB control number. 

The OMB control numbers for EPA's regulations in 40 CFR are 

listed in 40 CFR part 9. 

To comment on the Agency's need for this information, 

the accuracy of the provided burden estimates, and any 

suggested methods for minimizing respondent burden, EPA has 

established a public docket for this rule, which includes 

this ICR, under Docket ID number (EPA-HQ-OAR-2008-0508-XXX)

 

10 Burden is defined at 5 CFR 1320.3(b). These cost numbers differ from 

those shown elsewhere in the Economic Analysis because the ICR costs 

represent the average cost over the first three years of the proposed 

rule, but costs are reported elsewhere in the Economic Analysis for the 

first year of the proposed rule and for subsequent years of the 

proposed rule. In addition, the ICR focuses on respondent burden, while 

the Economic Analysis includes EPA Agency costs. 
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119 

Submit any comments related to the ICR to EPA and OMB. See 

ADDRESSES section at the beginning of this notice for where 

to submit comments to EPA. Send comments to OMB at the 

Office of Information and Regulatory Affairs, Office of 

Management and Budget, 725 17th Street, NW, Washington, DC 

20503, Attention: Desk Office for EPA. Since OMB is 

required to make a decision concerning the ICR between 30 

and 60 days after [Insert date of publication in the 

Federal Register.], a comment to OMB is best assured of 

having its full effect if OMB receives it by [Insert date 

30 days after publication in the Federal Register.]. The 

final rule will respond to any OMB or public comments on 

the information collection requirements contained in this 

proposal. 

C. Regulatory Flexibility Act (RFA)

The 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. 
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120 

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 regulations at 13 CFR 121.201; (2) a small 

governmental jurisdiction that is a government of a city, 

county, town, school district or special district with a 

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

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

independently owned and operated and is not dominant in its 

field. 

After considering the economic impacts of today’s 

proposed rule on small entities, I certify that this action 

will not have a significant economic impact on a 

substantial number of small entities. In determining 

whether a rule has a significant economic impact on a 

substantial number of small entities, the impact of concern 

is any significant adverse economic impact on small 

entities, since the primary purpose of the regulatory 

flexibility analyses is to identify and address regulatory 

alternatives “which minimize any significant economic 

impact of the rule on small entities.” 5 USC 603 and 604. 

Thus, an agency may certify that a rule will not have a 

significant economic impact on a substantial number of 

small entities if the rule relieves regulatory burden, or 
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121 

otherwise has a positive economic effect on all of the 

small entities subject to the rule. 

The small entities directly regulated by this proposed 

rule include small businesses in the petroleum and gas 

industry, small governmental jurisdictions and small nonprofits. We have determined that some small businesses 

will be affected because their production processes emit 

GHGs that must be reported. 

For affected small entities, EPA conducted a screening 

assessment comparing compliance costs for affected industry 

segments to petroleum and gas-specific data on revenues for 

small businesses. This ratio constitutes a “sales” test 

that computes the annualized compliance costs of this 

proposed rule as a percentage of sales and determines 

whether the ratio exceeds some level (e.g., 1 percent or 3 

percent). The cost-to-sales ratios were constructed at the 

establishment level (average compliance cost for the 

establishment/ average establishment revenues). 

As shown in Table W-10, the average ratio of 

annualized reporting program costs to receipts of 

establishments owned by model small enterprises was less 

than 1 percent for industries presumed likely to have small 

businesses covered by the reporting program. Although the 

costs to receipts for entities with 1-20 employees is over 
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122 

1 percent, these facilities would likely not exceed the 

proposed 25,000 mtCO2e threshold, a threshold supported by 

many stakeholders as one that sufficiently captures the 

majority of GHG emissions while excluding small facilities. 

Further, these sales tests examine the average 

establishment’s total annualized mandatory reporting costs 

to the average establishment receipts for enterprises 

within several employment categories. The average entity 

costs used to compute the sales test are the same across 

all of these enterprise size categories. As a result, the 

sales-test will overstate the cost-to-receipt ratio for 

establishments owned by small businesses, because the 

reporting costs are likely lower than average entity 

estimates provided by the engineering cost analysis. 

The screening analysis thus indicates that the 

proposed rule will not have a significant economic impact 

on a substantial number of small entities. The screening 

assessment for small governments for the Final MRR compared 

the sum of average costs of compliance for combustion, 

local distribution companies, and landfills to average 

revenues for small governments. Even for a small 

government owning all three source types, the costs 

constitute less than 1 percent of average revenues for the 
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123 

smallest category of governments (those with fewer than 

10,000 people). 

Although this proposed rule will not have a 

significant economic impact on a substantial number of 

small entities, EPA nonetheless took several steps to 

reduce the impact of this proposed rule on small entities. 

For example, EPA determined appropriate thresholds that 

reduce the number of small businesses reporting. In 

addition, EPA is proposing different monitoring methods for 

different emissions sources, requiring direct measurement 

only for selected sources. Also, EPA is proposing annual 

instead of more frequent reporting. 

Through comprehensive outreach activities prior to 

proposal of the initial rule, EPA held approximately 100 

meetings and/or conference calls with representatives of 

the primary audience groups, including numerous trade 

associations and industries in the petroleum and gas 

industry that include small business members. EPA’s 

outreach activities prior to proposal of the initial rule 

are documented in the memorandum, “Summary of EPA Outreach 

Activities for Developing the Greenhouse Gas Reporting 

Rule,” located in Docket No. EPA-HQ-OAR-2008-0508-053. 

After the initial proposal, EPA posted a guide for small 

businesses on the EPA GHG reporting rule Web site, along 
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124 

with a general fact sheet for the rule, information sheets 

for every source category, and an FAQ document. EPA also 

operated a hotline to answer questions about the proposed 

rule. We continued to meet with stakeholders and entered 

documentation of all meetings into the docket. 

During rule implementation, EPA would maintain an 

“open door” policy for stakeholders to ask questions about 

the proposed rule or provide suggestions to EPA about the 

types of compliance assistance that would be useful to 

small businesses. EPA intends to develop a range of 

compliance assistance tools and materials and conduct 

extensive outreach for the proposed rule. 

We have therefore concluded that today's proposed rule 

will relieve regulatory burden for all affected small 

entities. We continue to be interested in the potential 

impacts of the proposed rule on small entities and welcome 

comments on issues related to such impacts. 

D. Unfunded Mandates Reform Act (UMRA)

The UMRA seeks to protect State, local, and Tribal 

governments from the imposition of unfunded Federal 

mandates. In addition, the Act seeks to strengthen the 

partnership between the Federal government and State, 

local, and Tribal governments and ensure that the Federal 
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125 

government covers the costs incurred during compliance with 

Federal mandates. 

Title II of the UMRA of 1995, Public Law 104-4, 

establishes requirements for Federal agencies to assess the 

effects of their regulatory actions on State, local, and 

tribal governments and the private segment. Under section 

202 of UMRA, EPA generally must prepare a written 

statement, including a cost-benefit analysis, for proposed 

and final rules with Federal mandates that may result in 

expenditures to State, local, and Tribal governments, in 

the aggregate, or to the private segment, of $100 million 

or more in any one year. 

Before promulgating an EPA rule for which a written 

statement is needed, section 205 of UMRA generally requires 

EPA to identify and consider a reasonable number of 

regulatory alternatives and adopt the least costly, most 

cost-effective or least burdensome alternative that 

achieves the objectives of the rule. The provisions of 

section 205 do not apply when they are inconsistent with 

applicable law. Moreover, section 205 allows EPA to adopt 

an alternative other than the least costly, most costeffective or least burdensome alternative if the 

Administrator publishes with the final rule an explanation 

why that alternative was not adopted. 
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126 

Before EPA establishes any regulatory requirements 

that may significantly or uniquely affect small 

governments, including Tribal governments, it must have 

developed under section 203 of UMRA a small government 

agency plan. The plan must provide for notifying 

potentially affected small governments, enabling officials 

of affected small governments to have meaningful and timely 

input in the development of EPA regulatory proposals with 

significant Federal intergovernmental mandates, and 

informing, educating, and advising small governments on 

compliance with the regulatory requirements. 

EPA has determined that the Subpart W rule does 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 segment in 

any one year. Expenditures associated with compliance, 

defined as the incremental costs beyond the existing 

regulations will not surpass $100 million in the aggregate 

in any year. Thus, today's rule is not subject to the 

requirements of sections 202 and 205 of 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 regulation applies to facilities 
OMB DRAFT: Please do not cite, quote or distribute 

127 

that directly emit greenhouse gases. It does not apply to 

governmental entities unless the government entity owns a 

facility in the petroleum and gas industry that directly 

emits greenhouse gases above threshold levels. In addition, 

this proposed rule does not impose any implementation 

responsibilities on State, local, or Tribal governments and 

it is not expected to increase the cost of existing 

regulatory programs managed by those governments. Thus, the 

impact on governments affected by the proposed rule is 

expected to be minimal. 

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. However, for a more 

detailed discussion about how this proposed rule relates to 

existing State programs, please see Section II of the 

proposal preamble for the Mandatory GHG Reporting Rule (74 

FR 16457 to 16461, April 10, 2009). 

This regulation applies to facilities that emit 

greenhouse gases. It does not apply to governmental 

entities unless the government entity owns a petroleum and 
OMB DRAFT: Please do not cite, quote or distribute 

128 

gas facility that directly emits greenhouse gases above 

threshold levels, so relatively few government facilities 

would be affected. This regulation also does not limit the 

power of States or localities to collect GHG data and/or 

regulate GHG emissions. Thus, EO 13132 does not apply to 

this action. 

Although section 6 of Executive Order 13132 does not 

apply to this action, EPA did consult with State and local 

officials or representatives of state and local governments 

in developing the mandatory GHG reporting rule that was 

proposed in April 2009 and finalized in September 2009. 

Today’ action is a supplemental proposal to that rule. EPA 

maintained an “open door” policy for stakeholders to 

provide input on key issues and to help inform EPA’s 

understanding of issues, including impacts to State and 

local officials. The outreach audience included State 

environmental protection agencies and regional 

organizations, and other State and local government 

organizations. EPA contacted several States and State and 

regional organizations already involved in GHG emissions 

reporting. For example, EPA held meetings and conference 

calls with groups such as TRI, NACAA, ECOS, and with State 

members of RGGI, the Midwestern GHG Reduction Accord, and 

WCI. See the “Summary of EPA Outreach Activities for 
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129 

Developing the Greenhouse Gas Reporting Rule,” in Docket 

No. EPA-HQ-OAR-2008-0508-0053 for a complete list of 

organizations and groups that EPA contacted. Since the 

signature of the original proposed rule, EPA has continued 

to meet with stakeholders interested in the petroleum and 

natural gas industry. See “Outreach Since Initial 

Proposal” in Docket No. EPA-HQ-OAR-2008-0508-XXX 

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

EPA has concluded that this action may have tribal 

implications. However, it will neither impose substantial 

direct compliance costs on tribal governments, nor preempt 

Tribal law. This regulation would apply directly to 

petroleum and natural gas facilities that emit greenhouses 

gases. Although few facilities that would be subject to 

the rule are likely to be owned by tribal governments, EPA 

has sought opportunities to provide information to tribal 

governments and representatives during rule development. 

EPA consulted with tribal officials early in the process of 
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130 

developing this regulation to permit them to have 

meaningful and timely input into its development. EPA 

sought opportunities to provide information to Tribal 

governments and representatives during development of the 

mandatory GHG reporting rule that was proposed in April 

2009 and finalized in September 2009. Today’ action is a 

supplemental proposal to that rule. In consultation with 

EPA’s American Indian Environment Office, EPA’s outreach 

plan included tribes. EPA conducted several conference 

calls with Tribal organizations during the proposal phase. 

For example, EPA staff provided information to tribes 

through conference calls with multiple Indian working 

groups and organizations at EPA that interact with tribes 

and through individual calls with two Tribal board members 

of TCR. In addition, EPA prepared a short article on the 

GHG reporting rule that appeared on the front page a Tribal 

newsletter—Tribal Air News—that was distributed to 

EPA/OAQPS’s network of Tribal organizations. EPA gave a 

presentation on various climate efforts, including the 

mandatory reporting rule, at the National Tribal Conference 

on Environmental Management on June 24-26, 2008. In 

addition, EPA had copies of a short information sheet 

distributed at a meeting of the National Tribal Caucus. 

See the “Summary of EPA Outreach Activities for Developing 
OMB DRAFT: Please do not cite, quote or distribute 

131 

the GHG reporting rule,” in Docket No. EPA-HQ-OAR-2008-

0508-055 for a complete list of Tribal contacts. EPA 

participated in a conference call with tribal air 

coordinators in April 2009 and prepared a guidance sheet 

for Tribal governments on the proposed rule. It was posted 

on the MRR website and published in the Tribal Air 

Newsletter. 

EPA specifically solicits additional comment on this 

proposed rule from tribal officials. 

G. Executive Order 13045: Protection of Children from 

Environmental Health Risks and Safety Risks

EPA interprets EO 13045 (62 F.R. 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 EO has the potential to 

influence the regulation. This action is not subject to EO 

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 proposed rule is not a “significant energy 

action” as defined in EO 13211 (66 FR 28355, May 22, 2001) 

because it is not likely to have a significant adverse 

effect on the supply, distribution, or use of energy. 
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132 

Further, we have concluded that this proposed rule is not 

likely to have any adverse energy effects. This proposed 

rule relates to monitoring, reporting and recordkeeping at 

petroleum and gas facilities that emit over 25,000 mtCO2e 

and does not impact energy supply, distribution or use. 

Therefore, we conclude that this proposed rule is not 

likely to have any adverse effects on energy supply, 

distribution, or use. 

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 (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 rulemaking involves technical standards. EPA 

provides the flexibility to use any one of the voluntary 

consensus standards from at least seven different voluntary 
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133 

consensus standards bodies, including the following: ASTM, 

ASME, ISO, Gas Processors Association, and American Gas 

Association. These voluntary consensus standards will help 

facilities monitor, report, and keep records of greenhouse 

gas emissions. No new test methods were developed for this 

proposed rule. Instead, from existing rules for source 

categories and voluntary greenhouse gas programs, EPA 

identified existing means of monitoring, reporting, and 

keeping records of greenhouse gas emissions. The existing 

methods (voluntary consensus standards) include a broad 

range of measurement techniques, including many for 

combustion sources such as methods to analyze fuel and 

measure its heating value; methods to measure gas or liquid 

flow; and methods to gauge and measure petroleum and 

petroleum products. 

By incorporating voluntary consensus standards into 

this proposed rule, EPA is both meeting the requirements of 

the NTTAA and presenting multiple options and flexibility 

for measuring greenhouse gas emissions. 

J. Executive Order 12898: Federal Actions to Address 

Environmental Justice in Minority Populations and LowIncome Populations

Executive Order (EO) 12898 (59 FR 7629 (Feb. 16, 

1994)) establishes federal executive policy on 
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134 

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. 

Date: 

Lisa P. Jackson, 

Administrator.
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135 

For the reasons stated in the preamble, the Environmental 

Protection Agency proposes to amend 40 CFR part 98 as set 

forth below: 

Part 98—MANDATORY GREENHOUSE GAS REPORTING 

1. The authority citation for part 98 continues to 

read as follows: 

Authority: 42 U.S.C. 7401, et seq. 

Subpart A—[Amended] 

2. Section 98.1 is amended by revising paragraph (b) 

to read as follows: 

§98.1 Purpose and Scope. 

* * * * * 

(b) Owners and operators of facilities and suppliers 

that are subject to this part must follow the requirements 

of subpart A and all applicable subparts of this part. If 

a conflict exists between a provision in subpart A and any 

other applicable subpart, the requirements of the 

applicable subpart shall take precedence. 

3. Section 98.2 is amended by revising paragraph (a) 

to read as follows: 

§98.2 Who must report? 

(a) The GHG reporting requirements and related 

monitoring, recordkeeping, and reporting requirements of 
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136 

this part apply to the owners and operators of any facility 

that is located in the United States and that meets the 

requirements of either paragraph (a)(1), (a)(2), or (a)(3) 

of this section; and any supplier that meets the 

requirements of paragraph (a)(4) or (a)(5) of this section: 

(1) A facility that contains any source category that 

is listed in Table A-3 of this subpart in any calendar year 

starting in 2010. For these facilities, the annual GHG 

report must cover stationary fuel combustion sources 

(subpart C), miscellaneous use of carbonates (subpart U), 

and all applicable source categories listed in Table A-3 or 

Table A-4 of this subpart. 

(2) A facility that contains any source category that 

is listed in Table A-4 of this subpart in any calendar year 

starting in 2010 and that emits 25,000 metric tons CO2e or 

more per year in combined emissions from stationary fuel 

combustion units, miscellaneous uses of carbonate, and all 

applicable source categories that are listed in Table A-4 

of this subpart. For these facilities, the annual GHG 

report must cover stationary fuel combustion sources 

(subpart C), miscellaneous use of carbonates (subpart U), 

and all applicable source categories listed in Table A-4 of 

this subpart. 
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137 

* * * * * 

4. Section 98.3 is amended by revising paragraphs 

(b), (c), and (i) to read as follows: 

§98.3 What are the general monitoring, reporting, 

recordkeeping and verification requirements of this part? 

* * * * * 

(b) Schedule. The annual GHG report must be 

submitted no later than March 31 of each calendar year for 

GHG emissions in the previous calendar year. As an 

example, for a facility that is subject to the rule in 

calendar year 2010, the first report must be submitted on 

March 31, 2011. 

(1) [Reserved] 

(2) For a new facility or supplier that begins 

operation on or after January 1, 2010 and becomes subject 

to the rule in the year that it becomes operational, report 

emissions beginning with the first month that the facility 

or supplier begins operation and ending on December 31 of 

that year. Each subsequent annual report must cover 

emissions for the calendar year, beginning on January 1 and 

ending on December 31. 

* * * * * 

(c) * * * 

(4) * * * 
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138 

(i) Annual emissions (excluding biogenic CO2) 

aggregated for all GHG from all applicable source 

categories listed in Tables A-3 and Table A-4 of this 

subpart and expressed in metric tons of CO2e calculated 

using Equation A-1 of this subpart. 

(ii) Annual emissions of biogenic CO2 aggregated for 

all applicable source categories in listed in Tables A-3 

and A-4 of this subpart. 

(iii) Annual emissions from each applicable source 

category listed in Tables A-3 and Table A-4 of this 

subpart, expressed in metric tons of each GHG listed in 

this paragraph (4)(iii)(A) through (4)(iii)(E). 

* * * * * 

(i) * * * 

(1) Except as provided in paragraphs (i)(4) through 

(i)(6) of this section, flow meters and other devices 

(e.g., belt scales) that measure data used to calculate GHG 

emissions shall be calibrated using the procedures 

specified in this paragraph and each relevant subpart of 

this part. All measurement devices must be calibrated 

according to the manufacturer’s recommended procedures, an 

appropriate industry consensus standard, or a method 

specified in a relevant subpart of this part. All 

measurement devices shall be calibrated to an accuracy of 5 
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139 

percent. For facilities and suppliers that are subject to 

this part on January 1, 2010, the initial calibration shall 

be conducted by April 1, 2010. For facilities and 

suppliers that become subject to this part after April 1, 

2010, the initial calibration shall be conducted by the 

date that data collection is required to begin. Subsequent 

calibrations shall be performed at the frequency specified 

in each applicable subpart. 

* * * * * 

5. Section 98.6 is amended by adding the following 

definitions in alphabetical order to read as follows: 

§98.6 Definitions.

Absorbent circulation pump means a pump commonly 

powered by natural gas pressure that circulates the 

absorbent liquid between the absorbent regenerator and 

natural gas contactor. 

Acid Gas means hydrogen sulfide (H2S) and carbon 

dioxide (CO2) contaminants that are separated from sour 

natural gas by an acid gas removal. 

Acid Gas Removal unit (AGR) means a process unit that 

separates hydrogen sulfide and/or carbon dioxide from sour 

natural gas using liquid or solid absorbents or membrane 

separators. 
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140 

Acid gas removal vent stack emissions mean the acid 

gas separated from the acid gas absorbing medium (e.g., an 

amine solution) and released with methane and other light 

hydrocarbons to the atmosphere or a flare. 

Air injected flare means a flare in which air is blown 

into the base of a flare stack to induce complete 

combustion of low Btu natural gas (i.e., high noncombustible component content). 

Blowdown vent stack emissions mean natural gas 

released due to maintenance and/or blowdown operations 

including but not limited to compressor blowdown and 

emergency shut-down (ESD) system testing. 

Calibrated bag means a flexible, non-elastic, antistatic bag of a calibrated volume that can be affixed to a 

emitting source such that the emissions inflate the bag to 

its calibrated volume. 

Centrifugal compressor means any equipment that 

increases the pressure of a process natural gas by 

centrifugal action, employing rotating movement of the 

driven shaft. 

Centrifugal compressor dry seals mean a series of 

rings around the compressor shaft where it exits the 

compressor case that operates mechanically under the 
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141 

opposing forces to prevent natural gas from escaping to the 

atmosphere. 

Centrifugal compressor dry seals emissions mean 

natural gas released from a dry seal vent pipe and/or the 

seal face around the rotating shaft where it exits one or 

both ends of the compressor case. 

Centrifugal compressor wet seal degassing venting 

emissions means emissions that occur when the high-pressure 

oil barriers for centrifugal compressors are depressurized 

to release absorbed natural gas. High-pressure oil is used 

as a barrier against escaping gas in centrifugal compressor 

shafts. Very little gas escapes through the oil barrier, 

but under high pressure, considerably more gas is absorbed 

by the oil. The seal oil is purged of the absorbed gas 

(using heaters, flash tanks, and degassing techniques) and 

recirculated. The separated gas is commonly vented to the 

atmosphere. 

Coal Bed Methane (CBM) means natural gas which is 

extracted from underground coal deposits or “beds.” 

Component, for the purposes of subpart W only, means 

but is not limited to each metal to metal joint or seal of 

non-welded connection separated by a compression gasket, 

screwed thread (with or without thread sealing compound), 
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142 

metal to metal compression, or fluid barrier through which 

natural gas or liquid can escape to the atmosphere. 

Compressor means any machine for raising the pressure 

of a natural gas by drawing in low pressure natural gas and 

discharging significantly higher pressure natural gas. 

Condensate means hydrocarbon and other liquid 

separated from natural gas that condenses due to changes in 

the temperature, pressure, or both, and remains liquid at 

storage conditions, includes both water and hydrocarbon 

liquids. 

Conventional wells mean gas wells in producing fields 

that do not employ hydraulic fracturing to produce 

commercially viable quantities of natural gas. 

Dehydrator means a device in which a liquid absorbent 

(including but not limited to desiccant, ethylene glycol, 

diethylene glycol, or triethylene glycol) directly contacts 

a natural gas stream to absorb water vapor. 

Dehydrator vent stack emissions means natural gas 

released from a natural gas dehydrator system absorbent 

(typically glycol) reboiler or regenerator, including 

stripping natural gas and motive natural gas used in 

absorbent circulation pumps. 

De-methanizer means the natural gas processing unit 

that separates methane rich residue gas from the heavier 
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143 

hydrocarbons (e.g., ethane, propane, butane, pentane-plus) 

in feed natural gas stream). 

Desiccant means a material used in solid-bed 

dehydrators to remove water from raw natural gas by 

adsorption. Desiccants include activated alumina, 

palletized calcium chloride, lithium chloride and granular 

silica gel material. Wet natural gas is passed through a 

bed of the granular or pelletized solid adsorbent in these 

dehydrators. As the wet gas contacts the surface of the 

particles of desiccant material, water is adsorbed on the 

surface of these desiccant particles. Passing through the 

entire desiccant bed, almost all of the water is adsorbed 

onto the desiccant material, leaving the dry gas to exit 

the contactor. 

E&P Tank means the most current version of an 

exploration and production field tank emissions equilibrium 

program that estimates flashing, working and standing 

losses of hydrocarbons, including methane, from produced 

crude oil and gas condensate. Equal or successors to E&P 

Tank Version 2.0 for Windows Software. Copyright (C) 1996-

1999 by The American Petroleum Institute and The Gas 

Research Institute. 

Engineering estimation means an estimate of emissions 

based on engineering principles applied to measured and/or 
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144 

approximated physical parameters such as dimensions of 

containment, actual pressures, actual temperatures, and 

compositions. 

Enhanced Oil Recovery (EOR) means the use of certain 

methods such as water flooding or gas injection into 

existing wells to increase the recovery of crude oil from a 

reservoir. In the context of this rule, EOR applies to 

injection of critical phase carbon dioxide into a crude oil 

reservoir to enhance the recovery of oil. 

Field means standardized field names and codes of all 

oil and gas fields identified in the United States as 

defined by the Energy Information Administration Oil and 

Gas Field Code Master List. 

Flare combustion efficiency means the fraction of 

natural gas, on a volume or mole basis, that is combusted 

at the flare burner tip. 

Flare combustion means unburned hydrocarbons including 

CH4, CO2, N2O emissions resulting from the incomplete 

combustion of gas in flares. 

Fugitive emissions means those emissions which are 

unintentional and could not reasonably pass through a 

stack, chimney, vent, or other functionally-equivalent 

opening. 
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145 

Fugitive emissions detection means the process of 

identifying emissions from equipment, components, and other 

point sources. 

Gas conditions mean the actual temperature, volume, 

and pressure of a gas sample. 

Gas gathering/booster stations mean centralized 

stations where produced natural gas from individual wells 

is co-mingled, compressed for transport to processing 

plants, transmission and distribution systems, and other 

gathering/booster stations which co-mingle gas from 

multiple production gathering/booster stations. Such 

stations may include gas dehydration, gravity separation of 

liquids (both hydrocarbon and water), pipeline pig 

launchers and receivers, and gas powered pneumatic devices. 

Gas to oil ratio (GOR) means the ratio of the volume 

of gas at standard temperature and pressure that is 

produced from a volume of oil when depressurized to 

standard temperature and pressure. 

High-Bleed Pneumatic Devices are automated flow 

control devices powered by pressurized natural gas and used 

for maintaining a process condition such as liquid level, 

pressure, delta-pressure and temperature. Part of the gas 

power stream which is regulated by the process condition 

flows to a valve actuator controller where it vents 
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146 

(bleeds) to the atmosphere at a rate in excess of six 

standard cubic feet per hour. 

Liquefied natural gas (LNG) means natural gas 

(primarily methane) that has been liquefied by reducing its 

temperature to -260 degrees Fahrenheit at atmospheric 

pressure. 

LNG boiloff gas means natural gas in the gaseous phase 

that vents from LNG storage tanks due to ambient heat 

leakage through the tank insulation and heat energy 

dissipated in the LNG by internal pumps. 

Low-Bleed Pneumatic Devices mean automated flow 

control devices powered by pressurized natural gas and used 

for maintaining a process condition such as liquid level, 

pressure, delta-pressure and temperature. Part of the gas 

power stream which is regulated by the process condition 

flows to a valve actuator controller where it vents 

(bleeds) to the atmosphere at a rate equal to or less than 

six standard cubic feet per hour. 

Natural gas driven pneumatic pump means a pump that 

uses pressurized natural gas to move a piston or diaphragm, 

which pumps liquids on the opposite side of the piston or 

diaphragm. 
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147 

Offshore means tidal-affected borders of the U.S. 

lands, both state and Federal, adjacent to oceans, bays, 

lakes or other normally standing water. 

Onshore petroleum and natural gas production owner or 

operator means the entity who is the permitee to operate 

petroleum and natural gas wells on the state drilling 

permit or a state operating permit where no drilling permit 

is issued by the state, which operates an onshore petroleum 

and/or natural gas production facility (as described in 

§98.230(b)(2). Where more than one entity are permitees on 

the state drilling permit, or operating permit where no 

drilling permit is issued by the state, the permitted 

entities for the joint facility must designate one entity 

to report all emissions from the joint facility. 

Operating pressure means the containment pressure that 

characterizes the normal state of gas or liquid inside a 

particular process, pipeline, vessel or tank. 

Pump means a device used to raise pressure, drive, or 

increase flow of liquid streams in closed or open conduits. 

Pump seals means any seal on a pump drive shaft used 

to keep methane and/or carbon dioxide containing light 

liquids from escaping the inside of a pump case to the 

atmosphere. 
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148 

Pump seal emissions means hydrocarbon gas released 

from the seal face between the pump internal chamber and 

the atmosphere. 

Reciprocating compressor means a piece of equipment 

that increases the pressure of a process natural gas by 

positive displacement, employing linear movement of a shaft 

driving a piston in a cylinder. 

Reciprocating compressor rod packing means a series of 

flexible rings in machined metal cups that fit around the 

reciprocating compressor piston rod to create a seal 

limiting the amount of compressed natural gas that escapes 

to the atmosphere. 

Re-condenser means heat exchangers that cool 

compressed boil-off gas to a temperature that will condense 

natural gas to a liquid. 

Reservoir means a porous and permeable underground 

natural formation containing significant quantities of 

hydrocarbon liquids and/o r gases. A reservoir is 

characterized by a single natural pressure system. 

Sales oil means produced crude oil or condensate 

measured at the production lease automatic custody transfer 

(LACT) meter or custody transfer meter tank gauge. 

Sour natural gas means natural gas that contains 

significant concentrations of hydrogen sulfide and/or 
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149 

carbon dioxide that exceed the concentrations specified for 

commercially saleable natural gas delivered from 

transmission and distribution pipelines. 

Sweet Gas is natural gas with low concentrations of 

hydrogen sulfide (H2S) CO2) that does not require (or has 

already had) acid gas treatment to meet pipeline corrosionprevention specifications for transmission and 

distribution. 

Transmission pipeline means high pressure cross 

country pipeline transporting sellable quality natural gas 

from production or natural gas processing to natural gas 

distribution pressure let-down, metering, regulating 

stations where the natural gas is typically odorized before 

delivery to customers. 

Turbine meter means a flow meter in which a gas or 

liquid flow rate through the calibrated tube spins a 

turbine from which the spin rate is detected and calibrated 

to measure the fluid flow rate. 

Unconventional wells means gas well in producing 

fields that employ hydraulic fracturing to enhance gas 

production volumes. 

Vapor recovery system means any equipment located at 

the source of potential gas emissions to the atmosphere or 

to a flare, that is composed of piping, connections, and, 
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150 

if necessary, flow-inducing devices, and that is used for 

routing the gas back into the process as a product and/or 

fuel. 

Vaporization unit means a process unit that performs 

controlled heat input to vaporize LNG to supply 

transmission and distribution pipelines or consumers with 

natural gas. 

Vented emissions means intentional or designed 

releases of CH4 or CO2 containing natural gas or hydrocarbon 

gas (not including stationary combustion flue gas), 

including but not limited to process designed flow to the 

atmosphere through seals or vent pipes, equipment blowdown 

for maintenance, and direct venting of gas used to power 

equipment (such as pneumatic devices). 

Well Completions means a process that allows for the 

flow of petroleum or natural gas from newly drilled wells 

to expel drilling and reservoir fluids and test the 

reservoir flow characteristics. This process includes 

high-rate back-flow of injected water and sand used to 

fracture and prop-open fractures in low permeability gas 

reservoirs. 

Well Workover means the performance of one or more of 

a variety of remedial operations on producing oil and gas 

wells to try to increase production. This process also 
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151 

includes high-rate back-flow of injected water and sand 

used to re-fracture and prop-open new fractures in existing 

low permeability gas reservoirs. 

Wellhead means the piping, casing, tubing and 

connected valves protruding above the Earth’s surface for 

an oil and/ or natural gas well. The wellhead ends where 

the flow line connects to a wellhead valve. 

Wet natural gas means natural gas in which water vapor 

exceeds the concentration specified for commercially 

saleable natural gas delivered from transmission and 

distribution pipelines. This input stream to a natural gas 

dehydrator is referred to as ‘‘wet gas’’. 

6. Section 98.7 is amended by adding paragraphs (k), 

(l), and (m) to read as follows: 

§98.7 What standardized methods are incorporated by 

reference into this part? 

* * * * * 

(k) The following material is available for purchase 

from the Gas Technology Institute, 1700 South Mount 

Prospect Road, Des Plaines, Illinois 60018, 

www.gastechnology.org. 

(1) GRI-GLYCalc Version 4.0, IBR approved for 

§98.233(e). 
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152 

(l) The following material is available for purchase 

from IHS Standards Store, Jane’s Information Group, Inc., 

110 North Royal Street, Suite 200, Alexandria, Virginia 

22314, www.ihs.com. 

(1) E&P Tank Version 2.0, IBR approved for §98.233(j) 

and §98.236(c). 

(m) The following material is available for purchase 

from the American Association of Petroleum Geologists, 1444 

South Boulder Avenue, Tulsa, Oklahoma 74119, www.aapg.org. 

(1) AAPG-CSD Geologic Provinces Code Map: AAPG 

Bulletin, Volume 75, Number 10 (October 1991), pages 1644-

1651, IBR approved for §98.6 and §98.230(b). 

7. Subpart A is amended by adding Tables A-3 and A-4 

to read as follows: 

Table A-3 of Subpart A—Source Category List for §98.2(a)(1) 

Source Categories1 for 2010 and Future Years 

Adipic acid production (subpart E) 

Aluminum production (subpart F) 

Ammonia manufacturing (subpart G) 

Cement production (subpart H) 

Electricity generation units that report CO2 mass emissions 

year round through 40 CFR part 75 (subpart D) 

HCFC-22 production (subpart O) 

HFC-23 destruction processes that are not collocated with a 

HCFC-22 production facility and that destroy more than 2.14 

metric tons of HFC-23 per year (subpart O) 

Lime manufacturing (subpart S) 
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153 

Source Categories1 for 2010 and Future Years 

Manure management systems with combined CH4 and N2O emissions 

in amounts equivalent to 25,000 metric tons CO2e per year or 

more (subpart JJ) 

Municipal solid waste landfills that generate CH4 in amounts 

equivalent to 25,000 metric tons CO2e per year or more (subpart 

HH) 

Nitric acid production (subpart V) 

Petrochemical production (subpart X) 

Petroleum refineries 

(subpart Y) 

Phosphoric acid production (subpart Z) 

Silicon carbide production (subpart BB) 

Soda ash manufacturing 

(subpart CC) 

Titanium dioxide production (subpart EE) 

1 Source categories are defined in each subpart. 

Table A-4 of Subpart A—Source Category List for §98.2(a)(2) 

Source Categories1 for 2010 and Future Years 

Ferroalloy production (subpart K) 

Glass production (subpart N) 

Hydrogen production (subpart P) 

Iron and steel production (subpart Q) 

Lead production (subpart R) 

Pulp and paper manufacturing (subpart AA) 

Zinc production (subpart GG) 

Additional Source Categories1 for 2011 and Future Years

Oil and natural gas systems (subpart W) 

1 Source categories are defined in each subpart. 

8. Add subpart W to read as follows: 
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154 

A.

B. Subpart W—Petroleum and Natural Gas Systems

C.

D. Sec.

E. 98.230 Definition of the source category.

F. 98.231 Reporting threshold.

G. 98.232 GHGs to report.

H. 98.233 Calculating GHG emissions.

I. 98.234 Monitoring and QA/QC requirements.

J. 98.235 Procedures for estimating missing data.

K. 98.236 Data reporting requirements.

L. 98.237 Records that must be retained.

M. 98.238 Definitions.

§98.230 Definition of the source category. 

(a) This source category consists of the following: 

(1) Offshore petroleum and natural gas production. 

Offshore petroleum and natural gas production is any 

platform structure, either floating in the ocean or lake, 

or fixed on the ocean or lake bed, that houses equipment to 

extract hydrocarbons from the ocean or lake floor and 

transports it to storage or transport vessels or transports 

onshore. In addition, offshore production includes 

secondary platform structures and floating storage tanks 

connected to the platform structure by a pipeline. 

(2) Onshore petroleum and natural gas production. 

Onshore petroleum and natural gas production equipment 

means all structures associated with wells (including but 
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155 

not limited to compressors, generators, or storage 

facilities), piping (including but not limited to flowlines 

or intra-facility gathering lines), and portable non-selfpropelled equipment (including but not limited to well 

drilling and completion equipment, workover equipment, 

gravity separation equipment, auxiliary non-transportationrelated 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 also 

includes associated storage or measurement and all systems 

engaged in gathering produced gas from multiple wells, all 

EOR operations using CO2, and all petroleum and natural gas 

production located on islands, artificial islands or 

structures connected by a causeway to land, an island, or 

artificial island. 

(3) Onshore natural gas processing plants. Natural 

gas processing plants are designed to separate and recover 

natural gas liquids (NGLs)or other non-methane gases and 

liquids from a stream of produced natural gas to meet 

onshore natural gas transmission pipeline quality 

specifications through equipment performing one or more of 

the following processes: oil and condensate removal, water 

removal, separation of natural gas liquids, sulfur and 
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156 

carbon dioxide removal, fractionation of NGLs, or other 

processes, and also the capture of CO2 separated from 

natural gas streams for delivery outside the facility. In 

addition, field gathering and/or boosting stations that 

gather and process natural gas from multiple wellheads, and 

compress and transport natural gas (including but not 

limited to flowlines or intra-facility gathering lines or 

compressors) as feed to the natural gas processing plants 

are considered a part of the processing plant. Gathering 

and boosting stations that send the natural gas to an 

onshore natural gas transmission compression facility, or 

natural gas distribution facility, or to an end user are 

considered stand alone natural gas processing facilities. 

All residue gas compression equipment operated by a 

processing plant, whether inside or outside the processing 

plant fence, are considered part of natural gas processing 

plant. 

(4) Onshore natural gas transmission compression. 

Onshore natural gas transmission compression means any 

fixed combination of compressors that move natural gas at 

elevated pressure from production fields or natural gas 

processing facilities, in transmission pipelines, to 

natural gas distribution pipelines, or into storage. In 

addition, transmission compressor station includes 
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157 

equipment for liquids separation, natural gas dehydration, 

and tanks for the storage of water and hydrocarbon liquids. 

(5) Underground natural gas storage. Underground 

natural gas storage means subsurface storage, including but 

not limited to, depleted gas or oil reservoirs and salt 

dome caverns utilized for storing natural gas that has been 

transferred from its original location for the primary 

purpose of load balancing (the process of equalizing the 

receipt and delivery of natural gas); natural gas 

underground storage processes and operations (including, 

but not limited to, compression, dehydration and flow 

measurement); and all the wellheads connected to the 

compression units located at the facility. 

(6) Liquefied natural gas (LNG) storage. LNG storage 

means onshore LNG storage vessels located above ground, 

equipment for liquefying natural gas, compressors to 

capture and re-liquefy boil-off-gas, re-condensers, and 

vaporization units for re-gasification of the liquefied 

natural gas. 

(7) LNG import and export equipment. LNG import 

equipment means all onshore or offshore equipment that 

receives imported LNG via ocean transport, stores LNG, regasifies LNG, and delivers re-gasified natural gas to a 
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158 

natural gas transmission or distribution system. LNG 

export equipment means all onshore or offshore equipment 

that receives natural gas, liquefies natural gas, stores 

LNG, and transfers the LNG via ocean transportation to any 

location, including locations in the United States. 

(8) Natural Gas Distribution. Natural gas distribution 

means distribution pipelines (not interstate pipelines or 

intrastate pipelines) and metering and regulating stations, 

that physically deliver natural gas to end users. 

(b) The term “facility” shall have the same meaning 

as defined in §98.6, except for offshore petroleum and 

natural gas production, for onshore petroleum and natural 

gas production, and for natural gas distribution the term 

“facility” shall have the meaning prescribed in this 

paragraph (b). 

(1) For offshore petroleum and natural gas 

production, facility means each platform structure and all 

associated equipment as defined in paragraph (a)(1) of this 

section. All production equipment that is connected via 

causeways are one facility. 

(2) For onshore petroleum and natural gas production, 

facility means all petroleum or natural gas equipment 

associated with all petroleum or natural gas production 
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159 

wells under common ownership or common control by an 

onshore petroleum and natural gas production owner or 

operator located in a single hydrocarbon basin as defined 

by the American Association of Petroleum Geologists which 

is assigned a three digit Geologic Province Code. Where an 

operating entity holds more than one permit in a basin, 

then all onshore petroleum and natural gas production 

equipment relating to all permits in their name in the 

basin is one onshore petroleum and natural gas production 

facility. 

(3) For natural gas distribution, facility means the 

distribution pipelines, metering stations, and regulating 

stations that are operated by a Local Distribution Company 

(LDC) that is regulated as a separate operating company by 

a public utility commission or that are operated as an 

independent municipally-owned distribution system. 

§98.231 Reporting threshold. 

(a) You must report GHG emissions from petroleum and 

natural gas systems if your facility as defined in §98.230 

meets the requirements of §98.2(a)(2). 

(b)For applying the threshold defined in 98.2(a)(2), 

you must include combustion emissions from portable 

equipment that cannot move on roadways under its own power 
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160 

and drive train and that is stationed at a wellhead for 

more than thirty days in a reporting year, including 

drilling rigs, dehydrators, compressors, electrical 

generators, steam boilers, and heaters. 

§98.232 GHGs to report. 

(a) You must report CO2 and CH4 emissions from each 

industry segment specified in paragraph (b) through (i) of 

this section. 

(b) For offshore petroleum and natural gas 

production, report emissions from all “stationary fugitive” 

and “stationary vented” sources as identified in the 

Minerals Management Service (MMS) Gulfwide Offshore 

Activity Data System (GOADS) study. 

(c) For onshore petroleum and natural gas production, 

report emissions from the following source types: 

(1) Natural gas pneumatic high bleed device venting. 

(2) Natural gas pneumatic low bleed device venting. 

(3) Natural gas driven pneumatic pump venting. 

(4) Well venting for liquids unloading. 

(5) Gas well venting during conventional well 

completions. 
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161 

(6) Gas well venting during unconventional well 

completions. 

(7) Gas well venting during conventional well 

workovers. 

(8) Gas well venting during unconventional well 

workovers. 

(9) Gathering pipeline fugitives. 

(10) Storage tanks. 

(11) Reciprocating compressor rod packing venting. 

(12) Well testing venting and flaring. 

(13) Associated gas venting and flaring. 

(14) Dehydrator vent stacks. 

(15) Coal bed methane produced water emissions. 

(16) EOR injection pump blowdown. 

(17) Acid gas removal vent stack. 

(18) Hydrocarbon liquids dissolved CO2. 

(19) Centrifugal compressor wet seal degassing 

venting. 

(20) Produced water dissolved CO2. 

(21) Fugitive emissions from valves, connectors, open 

ended lines, pressure relief valves, compressor starter gas 
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162 

vents, pumps, flanges, and other fugitive sources (such as 

instruments, loading arms, pressure relief valves, stuffing 

boxes, compressor seals, dump lever arms, and breather caps 

for crude services). 

(d) For onshore natural gas processing, report 

emissions from the following sources: 

(1) Reciprocating compressor rod packing venting. 

(2) Centrifugal compressor wet seal degassing 

venting. 

(3) Storage tanks. 

(4) Blowdown vent stacks. 

(5) Dehydrator vent stacks. 

(6) Acid gas removal vent stack. 

(7) Flare stacks. 

(8) Gathering pipeline fugitives. 

(9) Fugitive emissions from: valves, connectors, open 

ended lines, pressure relief valves, meters, and 

centrifugal compressor dry seals. 

(e) For onshore natural gas transmission compression, 

report emissions from the following sources: 

(1) Reciprocating compressor rod packing venting. 
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163 

(2) Centrifugal compressor wet seal degassing 

venting. 

(3) Transmission storage tanks. 

(4) Blowdown vent stacks. 

(5) Natural gas pneumatic high bleed device venting. 

(6) Natural gas pneumatic low bleed device venting. 

(7) Fugitive emissions from connectors, block valves, 

control valves, compressor blowdown valves, pressure relief 

valves, orifice meters, other meters, regulators, and open 

ended lines. 

(f) For underground natural gas storage, report 

emissions from the following sources: 

(1) Reciprocating compressor rod packing venting. 

(2) Centrifugal compressor wet seal degassing venting. 

(3) Natural gas pneumatic high bleed device venting. 

(4) Natural gas pneumatic low bleed device venting. 

(5) Fugitive emissions from connectors, block valves, 

control valves, compressor blowdown valves, pressure 

relief valves, orifice meters, other meters, regulators, 

and open ended lines. 

(g) For LNG storage, report emissions from the 

following sources: 
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164 

(1) Reciprocating compressor rod packing venting. 

(2) Centrifugal compressor wet seal degassing venting. 

(3) Fugitive emissions from valves; pump seals; 

connectors; vapor recovery compressors, and other fugitive 

sources. 

(h) LNG import and export equipment, report 

emissions from the following sources: 

(1) Reciprocating compressor rod packing venting. 

(2) Centrifugal compressor wet seal degassing 

venting. 

(3) Blowdown vent stacks. 

(4) Fugitive emissions from valves, pump seals, 

connectors, vapor recovery compressors, and other fugitive 

sources. 

(i) For natural gas distribution, report emissions 

from the following sources: 

(1) Above ground meter regulators and gate station 

fugitive emissions from connectors, block valves, control 

valves, pressure relief valves, orifice meters, other 

meters, regulators, and open ended lines. 

(2) Below ground meter regulators and vault 

fugitives. 
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165 

(3) Pipeline main fugitives. 

(4) Service line fugitives. 

(j) You must report the CO2, CH4, and N2O emissions 

from each flare. 

(k) You must 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. 

(l) You must report under subpart PP of this part 

(Suppliers of Carbon Dioxide), CO2 emissions captured and 

transferred off site by following the requirements of 

subpart PP. 

§98.233 Calculating GHG emissions. 

(a) Natural gas pneumatic high bleed device venting. 

Calculate emissions from a natural gas pneumatic high bleed 

flow control device venting as follows: 

(1) Calculate vented emissions using manufacturer 

data. 

(i) Obtain from the manufacturer specific pneumatic 

device model natural gas bleed rate during normal 

operation. 
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166 

(ii) Calculate the natural gas emissions for each 

continuous bleed device using Equation W-1 of this section. 

Es,n = Bs * T

 (Eq. W-1) 

Where: 

Es,n = Annual natural gas emissions at standard 

conditions, in cubic feet. 

Bs = Natural gas driven pneumatic device bleed rate 

volume at standard conditions in cubic feet per 

minute, as provided by the manufacturer. 

T = Amount of time in minutes that the pneumatic 

device has been operational through the reporting 

period. 

(iii) 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, or 

(2) If manufacturer data for a specific device is not 

available then use data for a similar device model, size 

and operational characteristics to estimate emissions. 

(b) Natural gas pneumatic low bleed device venting. 

Calculate emissions from natural gas pneumatic low 

continuous bleed device venting using Equation W-2 of this 

section. 

(Eq. W-2) 

Where: 

Masss,i = Annual total mass GHG emissions in metric tons 

per year at standard conditions from all 

Masss,i = Count * EF * GHGi*Convi* 24*365
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167 

natural gas pneumatic low bleed device venting, 

for GHG i. 

Count = Total number of natural gas pneumatic low bleed 

devices. 

EF = Population emission factors for natural gas 

pneumatic low bleed device venting listed in 

Tables W-1, W-3, and W-4 of this subpart for 

onshore petroleum and natural gas production, 

onshore natural gas transmission, and 

underground natural gas storage facilities, 

respectively. 

GHGi = For onshore petroleum and natural gas 

production facilities, concentration of GHG i, 

CH4 or CO2, in produced natural gas; for 

facilities listed in §98.230 (3) – (8), GHGi

equals 1. 

Convi = Conversion from standard cubic feet to metric 

tons CO2e; 0.000404 for CH4, and 0.00005189 for 

CO2

24 * 365 = Conversion to yearly emissions estimate. 

(c) Natural gas driven pneumatic pump venting. 

Calculate emissions from natural gas driven pneumatic pump 

venting as follows: 

(1) Calculate emissions using manufacturer data. 

(i) Obtain from the manufacturer specific pump model 

natural gas emission (or manufacturer “gas consumption”) 

per unit volume of liquid circulation rate at pump speeds 

and operating pressures. 

(ii) Maintain a log of the amount of liquid pumped 

annually from individual pumps. 
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168 

(iii) Calculate the natural gas emissions for each 

pump using Equation W-3 of this section. 

Es,n =Fs *V

 (Eq. W-3) 

Where: 

Es,n = Annual natural gas emissions at standard 

conditions in cubic feet per year. 

Fs = Natural gas driven pneumatic pump gas emission in 

“emission per volume of liquid pumped at 

operating pressure” in scf/gallon at standard 

conditions, as provided by the manufacturer. 

V = Volume of liquid pumped annually in gallons/year. 

(iv) 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. 

 (2) If manufacturer data for a specific pump in 

Equation W-3 is not available then use data for a similar 

pump model, size and operational characteristics to 

estimate emissions. 

 (d) Acid gas removal (AGR) vent stacks. For AGR 

(including but not limited to processes such as amine, 

membrane, molecular sieve or other absorbents and 

adsorbents), calculate emissions for CO2 only (not CH4) 

using Equation W-4 of this section. 

Ea,CO2 = (V1 * %Vol1) - (V2 * %Vol2) (Eq. W-4) 
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169 

Where: 

Ea,CO2 = Annual volumetric CO2 emissions at ambient 

condition, in cubic feet per year. 

V1 = Metered total annual volume of natural gas flow 

into AGR unit in cubic feet per year at ambient 

condition. 

%Vol1 = Volume weighted CO2 content of natural gas into 

the AGR unit. 

V2 = Metered total annual volume of natural gas flow 

out of the AGR unit in cubic feet per year at 

ambient condition. 

%Vol2 = Volume weighted CO2 content of natural gas out of 

the AGR unit. 

(1) If a continuous gas analyzer is installed, then 

the continuous gas analyzer results must be used. If 

continuous gas analyzer is not available, quarterly gas 

samples must be taken to determine %Vol1 and %Vol2 according 

to methods set forth in §98.234 (b). 

(2) Calculate CO2 volumetric emissions at standard 

conditions using calculations in paragraph (t) of this 

section. 

(3) Mass CO2 emissions shall be calculated from 

volumetric CO2 emissions using calculations in paragraphs 

(u) and (v) of this section. 

(e) Dehydrator vent stacks. For dehydrator vent stacks 

without vapor recovery or thermal control devices, 

calculate annual mass CH4 and CO2 emissions at standard 
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170 

temperature and pressure (STP) conditions using the 

simulation software package GLYCalcTM. 

(1) A minimum of the following parameters must be used 

for characterizing emissions from dehydrators: 

(i) Feed natural gas flow rate. 

(ii) Feed natural gas water content. 

(iii) Outlet natural gas water content. 

(iv) Absorbent circulation pump type(natural gas 

pneumatic/ air pneumatic/ electric). 

(v) Absorbent circulation rate. 

(vi) Absorbent type: including, but not limited to, 

triethylene glycol (TEG), diethylene glycol (DEG) or 

ethylene glycol (EG). 

(vii) Use of stripping natural gas. 

(viii) Use of flash tank separator (and disposition 

of recovered gas). 

(ix) Hours operated. 

(x) Wet natural gas temperature, pressure, and 

composition. 

(2) Calculate annual emissions from dehydrator vent 

stacks to flares or regenerator fire-box/fire tubes as 

follows: 
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171 

(i) Use the dehydrator vent stack volume and gas 

composition as determined in paragraph (e)(1) of this 

section. 

(ii) Use the calculation methodology of flare stacks 

in paragraph (n) of this section to determine dehydrator 

vent stack emissions from the flare or regenerator 

combustion gas vent. 

(3) Dehydrators that use desiccant shall calculate 

emissions from the amount of gas vented from the vessel 

every time it is depressurized for the desiccant refilling 

process using Equation W-5 of this section. 

Es,n = (H*D2*P*P2*%G*365days/yr) (Eq. W-5) 

(4*P1*T*1,000cf/Mcf) 

Where: 

Es,n = Annual natural gas emissions at standard 

conditions. 

H = Height of the dehydrator vessel (ft). 

D = Inside diameter of the vessel (ft). 

P1 = Atmospheric pressure (psia). 

P2 = Pressure of the gas (psia). 

P = pi (3.14). 

%G = Percent of packed vessel volume that is gas. 

T = Time between refilling (days). 

(i) Both CH4 and CO2 volumetric and mass emissions 

shall be calculated from volumetric natural gas emissions 
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172 

using calculations in paragraphs (u) and (v) of this 

section. 

(f) Well venting for liquids unloadings. 

(1) The emissions for well venting for liquids 

unloading shall be determined using either of the 

calculation methodologies described in paragraphs (f)(1) of 

this section. The same calculation methodology must be 

used for the entire volume for the reporting year. 

(i) Calculation methodology 1. For each unique well 

tubing diameter and producing horizon/formation combination 

in each gas producing field 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-6 of this section. 

Ea,n = T * FR (Eq. W-6) 

Where: 

Ea,n = Annual natural gas emissions at ambient 

conditions in cubic feet. 

T = Cumulative amount of time in hours of well 

venting during the year. 
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173 

FR = Flow Rate in cubic feet per hour, under ambient 

conditions as required in (A), (B) and (C) of 

this section. 

Calculate natural gas volumetric emissions at standard 

conditions using calculations in paragraph(t)of this 

section. 

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. 

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

calculated for each unique tubing diameter and producing 

horizon/formation combination in each producing field. 

(B) This factor is applied to all wells in the field 

that have the same tubing diameter and producing 

horizon/formation combination, multiplied by the number of 

minutes of venting from all wells of the same tubing 

diameter and producing horizon/formation combination in 

that field. 

(C) A new emission factor is calculated every other 

year for each reporting field and horizon. 

(ii) Calculation methodology 2. Calculate emissions 

from each well venting for liquids unloading using Equation 

W-7 of this section. 
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174 

Es,n = {(0.37×10-3)*CD2*WD*SP*V}+{SFR*HR} (Eq. W-7) 

Where: 

Es,n = Annual natural gas emissions at standard 

conditions, in cubic feet/year. 

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

pounds per square feet} 

CD = Casing diameter (inches). 

WD = Well depth (feet). 

SP = Shut-in pressure (psig). 

V = Number of vents per year. 

SFR = Sales flow rate of gas well in cubic feet per 

hour. 

HR = Hours that the well was left open to the 

atmosphere during unloading. 

 (A) 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. 

(g) Gas well venting during unconventional well 

completions and workovers. Calculate emissions from gas 

uncoventional well venting during well completions and 

workovers from hydraulic fracturing using Equation W-8 of 

this section: 

Ea,n = T * FR (Eq. W-8) 

Where: 

Ea,n = Annual natural gas vented emissions at ambient 

conditions in cubic feet. 

T = Cumulative amount of time in hours of well 

venting during the year. 

FR = Flow Rate in cubic feet per hour, under ambient 

conditions, as required in (1) of this section. 
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175 

Calculate natural gas volumetric emissions at standard 

conditions using calculations in paragraph (t) of this 

section. 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. 

(1) The flow rate for gas well venting during well 

completions and workovers from hydraulic fracturing shall 

be determined using either of the calculation methodologies 

described in paragraphs (g)(1) of this section. The same 

calculation methodology must be used for the entire volume 

for the reporting year. 

(i) Calculation methodology 1. For one well 

completion in each gas producing field and for one well 

workover in each gas producing field, a recording flow 

meter shall be installed on the vent line during each well 

unloading event according to methods set forth in §98.234 

(b). 

(A) The average flow rate in cubic feet per minute of 

venting is calculated for one well completion in each field 

and for one well workover in each field. 
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176 

(B) The respective flow rates are applied to all well 

completions in the field and to all well workovers in the 

field, multiplied by the number of minutes of venting of 

all well completions and workovers, respectively, in that 

field. 

(C) New flow rates for completions and workovers are 

calculated every other year for each reporting field and 

horizon. 

(ii) Calculation methodology 2. For one well 

completion in each gas producing field and for one well 

workover in each gas producing field, record the pressures 

measured before and after the well choke according to 

methods set forth in §98.234 (b). 

(A) The average flow rate in cubic feet per minute of 

venting across the choke is calculated for one well 

completion in each field and for one well workover in each 

field. 

(B) The respective flow rates are applied to all well 

completions in the field and to all well workovers in the 

field, multiplied by the number of minutes of venting of 

all well completions and workovers in that field. 
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177 

(C) New flow rates for completions and workovers are 

calculated every other year for each reporting field and 

horizon. 

(iii) Calculate natural gas volumetric emissions at 

standard conditions using calculations in paragraph (t) of 

this section. 

(iv) 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. 

(2) Calculate annual emissions from gas well venting 

during well completions and workovers to flares as follows: 

(i) Use the gas well venting volume during well 

completions and workovers as determined in paragraph (g)(1) 

of this section. 

(ii) Use the calculation methodology of flare stacks 

in paragraph (n) of this section to determine gas well 

venting during well completions and workovers emissions 

from the flare. 

(h) Gas well venting during conventional well 

completions and workovers. Calculate emissions from each 

gas well venting during conventional well completions and 

workovers using Equation W-9 of this section: 
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178 

Ea,n = V * T (Eq. W-9) 

Where: 

Ea,n = Annual emissions in cubic feet at ambient 

conditions from gas well venting during 

conventional well completions or workovers. 

V = Daily gas production rate in cubic feet per 

minute. 

T = Cumulative amount of time of well venting in 

minutes during the year. 

(i) Calculate natural gas volumetric emissions at 

standard conditions using calculations in paragraph (t) of 

this section. 

(ii) 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. 

 (i) Blowdown vent stacks. Calculate blowdown vent 

stack emissions as follows:

(1) Calculate the total volume (including, but not 

limited to, pipelines, compressor case or cylinders, 

manifolds, suction and discharge bottles and vessels) 

between isolation valves. 

(2) Retain logs of the number of blowdowns for each 

equipment type. 
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179 

(3) Calculate the total annual venting emissions 

using Equation W-10 of this section: 

 (Eq. W-10) 

Where: 

Ea,n = Annual natural gas venting emissions at ambient 

conditions from blowdowns in cubic feet. 

N = Number of blowdowns for the equipment in 

reporting year. 

Vv = Total volume of blowdown equipment chambers 

(including, but not limited to, pipelines, 

compressors and vessels) between isolation valves 

in cubic feet. 

(4) Calculate natural gas volumetric emissions at 

standard conditions using calculations in paragraph (t) of 

this section. 

(5) Calculate both CH4 and CO2 volumetric and mass 

emissions from volumetric natural gas emissions using 

calculations in paragraphs (u) and (v) of this section. 

(j) Onshore production and processing storage tanks. 

For emissions from atmospheric pressure storage tanks 

receiving produced liquids from onshore petroleum and 

natural gas production faciliites (including stationary 

liquid storage not owned or operated by the reporter) and 

onshore natural gas processing facilities, calculate annual 

Ea n N Vv* , =
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180 

CH4 and CO2 emissions using the latest software package for 

E&P TANK. 

(1) A minimum of the following parameters must be used 

to characterize emissions from liquid transfer to 

atmospheric pressure storage tanks. 

(i) Separator oil composition. 

(ii) Separator temperature. 

(iii) Separator pressure. 

(iv) Sales oil API gravity. 

(v) Sales oil production rate. 

(vi) Sales oil Reid vapor pressure. 

(vii) Ambient air temperature. 

(viii) Ambient air pressure. 

(2) Determine if the storage tank has vapor recovery 

or thermal control devices. 

(A) Adjust the emissions estimated using E&P TANK 

downward by the magnitude of emissions captured using a 

vapor recovery system for benefitial use. 

(3) Calculate emissions from liquids sent to 

atmospheric storage tanks vented to flares as follows: 
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181 

(i) Use the storage tank emissions volume and gas 

composition as determined in this section. 

(ii) Use the calculation methodology of flare stacks 

in paragraph (n) of this section to determine storage tank 

emissions from the flare. 

(4) If liquids are sent to atmospheric storage tanks 

where the tank emissions are not represented by the 

equilibrium conditions of the liquid in a gas-liquid 

separator and calculated by the E&P Tank Model, then 

emissions shall be calculated as follows: 

(i) Use the storage tank emissions as determined in 

this section. 

(ii) Multiply the emissions by 3.87 for sales oil less 

than 45 API gravity. 

(iii) Multiply the emissions by 5.37 for sales oil 

equal to or greater than 45 API gravity. 

(k) Transmission storage tanks. For storage tanks 

without vapor recovery or thermal control devices in 

onshore natural gas transmission compression facilities 

calculate annual emissions as follows: 

(1) Monitor tank vapor vent stack for emissions using 

an optical gas imaging instrument according to methods set 

forth in §98.234 (a)(1) for a duration of 5 minutes. 
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182 

(2) If the tank vapors are continuous then use a meter 

to measure tank vapors. 

(i) Use a meter, such as, but not limited to a turbine 

meter, to estimate tank vapor volumes according to methods 

set forth in §98.234 (b). 

(ii) Use the appropriate gas composition in paragraph 

(u)(2)(iii)of this section. 

(3) Calculate emissions from storage tanks to flares 

as follows: 

(i) Use the storage tank emissions volume and gas 

composition as determined in paragraph (j)(1) of this 

section. 

(ii) Use the calculation methodology of flare stacks 

in paragraph (n) of this section to determine storage tank 

emissions from the flare. 

(l) Well testing venting and flaring. Calculate well 

testing venting and flaring emissions as follows: 

(1) Determine the gas to oil ratio (GOR) of the 

hydrocarbon production from each well tested. 

(i) If GOR is not available then use an appropriate 

standard method published by a consensus-based standards 

organization to determine GOR. 
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183 

(2) Estimate venting emissions using Equation W-11 of 

this section. 

Ea,n = GOR * FR*D (Eq. W-11) 

Where: 

Ea,n = Annual volumetric natural gas emissions from well 

testing in cubic feet under ambient conditions. 

GOR = Gas to oil ratio in cubic feet of gas per barrel 

of oil; oil here refers to hydrocarbon liquids 

produced of all API gravities. 

FR = Flow rate in barrels of oil per day for the well 

being tested. 

D = Number of days during the year, the well is 

tested. 

(3) Calculate natural gas volumetric emissions at 

standard conditions using calculations in paragraph (t) of 

this section. 

(4) Calculate both CH4 and CO2 volumetric and mass 

emissions from volumetric natural gas emissions using 

calculations in paragraphs (u) and (v) of this section. 

(5) Calculate emissions from well testing to flares 

as follows: 

(i) Use the well testing emissions volume and gas 

composition as determined in paragraph (l)(1) through (3) 

of this section. 
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184 

(ii) Use the calculation methodology of flare stacks 

in paragraph (n) of this section to determine well testing 

emissions from the flare. 

(m) Associated gas venting and flaring. Calculate 

associated gas venting and flaring emissions as follows: 

(1) Determine the GOR ratio of the hydrocarbon 

production from each well whose associated natural gas is 

vented or flared. 

(i) If GOR is not available then use an appropriate 

standard method published by a consensus-based standards 

organization to determine GOR. 

(2) Estimate venting emissions using the Equation W-12 

of this section. 

Ea,n = GOR * V (Eq. W-12) 

Where: 

Ea,n = Annual volumetric natural gas emissions from 

associated gas venting under ambient conditions, 

in cubic feet. 

GOR = Gas to oil ratio in cubic feet of gas per barrel 

of oil; oil here refers to hydrocarbon liquids 

produced of all API gravities. 

V = Total volume of oil produced in barrels in the 

reporting year. 

(3) Calculate natural gas volumetric emissions at 

standard conditions using calculations in paragraph (t) of 

this section. 
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185 

(4) Calculate both CH4 and CO2 volumetric and mass 

emissions from volumetric natural gas emissions using 

calculations in paragraphs (u) and (v) of this section. 

(5) Calculate emissions from associated natural gas 

to flares as follows: 

(i) Use the associated natural gas volume and gas 

composition as determined in paragraph (m)(1) through (3) 

of this section. 

(ii) Use the calculation methodology of flare stacks 

in paragraph (n) of this section to determine associated 

gas emissions from the flare. 

(n) Flare stacks. Calculate emissions from a flare 

stack as follows: 

(1) Flow measurement. If you have a continuous flow 

monitor on the flare, you must use the measured flow 

volumes to calculate the flare gas emissions. If you do not 

have a continuous flow monitor on the flare, you can 

install a flow measuring device on the flare or use 

engineering calculations, company records, or similar 

estimates of volumetric flare gas flow. 

(2) If you have a continuous gas composition analyzer 

on gas to the flare, you must use these compositions in 

calculating emissions. If you do not have a continuous gas 
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186 

composition analyzer on gas to the flare, you must use the 

appropriate gas compositions for each stream of 

hydrocarbons going to the flare as follows: 

(i) 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 and GHG mole percent 

in facility specific residue gas to transmission pipeline 

systems for all emissions sources downstream of the demethanizer overhead for onshore natural gas processing 

facilities. 

(ii) When the stream going to the flare is a 

hydrocarbon product stream, such as ethane or butane, then 

use a representative composition from the source for the 

stream. 

(3) Determine flare combustion efficiency from 

manufacturer. If not available, assume that flare 

combustion efficiency is 98 percent. 

(4) Calculate GHG volumetric emissions at actual 

conditions using Equations W-13, W-14 and W-15 of this 

section. 

a i Va Xi E ,

(un − combusted) = *(1 −h) * (Eq. W-13)

= ∑

j

a CO Va Yj Rj E (combusted) * * * , 2 h (Eq. W-14)
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187 

( ) ( ) ( ) , , , Ea itotal = Ea icombusted + Ea i un − combusted (Eq. W-15) 

Where: 

Ea,i (un-combusted) = Contribution of annual uncombusted GHG 

i emissions from flare stack in cubic 

feet, under ambient conditions. 

Ea,CO2 (combusted) = Contribution of annual emissions from 

combustion from flare stack in cubic 

feet, under ambient conditions 

Ea,I (total) = Total annual emissions from flare stack 

in cubic feet, under ambient conditions 

Va = Volume of natural gas sent to flare in 

cubic feet, during the year. 

η = Percent of natural gas combusted by 

flare (default is 98 percent). 

Xi = Concentration of GHG i in gas to the 

flare. 

Yj = Concentration of natural gas 

hydrocarbon constituents j (such as 

methane, ethane, propane, butane, and 

pentanes plus). 

Rj = Number of carbon atoms in the natural 

gas hydrocarbon constituent j; 1 for 

methane, 2 for ethane, 3 for propane, 4 

for butane, and 5 for pentanes plus). 

(5) Calculate GHG volumetric emissions at standard 

conditions using calculations in paragraph (t) of this 

section. 

(6) Calculate both CH4 and CO2 mass emissions from 

volumetric CH4 and CO2 emissions using calculation in 

paragraph (v) of this section. 

 (7) Calculate N2O emissions using the emission 

factors for Gas Flares listed in Table W-8 of this subpart. 
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188 

 (8) This emissions source excludes any emissions 

calculated under other emissions sources in §98.233. 

 (o) Centrifugal compressor wet seal degassing vents. 

Calculate emissions from centrifugal compressor wet seal 

degassing vents as follows: 

(1) For each centrifugal compressor determine the 

volume of vapors from wet seal oil degassing tank sent to 

an atmospheric vent or flare using a temporary or permanent 

flow measurement meter such as, but not limited to, a vane 

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

(2) Estimate annual emissions using meter flow 

measurement using Equation W-16 of this section. 

* * *(1 ) Ea,i= MT T Mi − B (Eq. W-16) 

Where: 

Ea,i = Annual GHG i (either CH4 or CO2) volumetric 

emissions at ambient conditions. 

MT = Meter reading of gas emissions per unit time. 

T = Total time the compressor associated with the wet 

seal(s) is operational in the reporting year. 

Mi = Mole percent of GHG i in the degassing vent gas; 

use the appropriate gas compositions in paragraph 

(u)(2) of this section. 

B = Percentage of centrifugal compressor wet seal 

degassing vent gas sent to vapor recovery or fuel 

gas or other beneficial use as determined by 

keeping logs of the number of operating hours for 

the vapor recovery system and the amount of vent 

gas that is directed to the fuel gas system. 
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189 

(3) Calculate CH4 and CO2 volumetric emissions at 

standard conditions using paragraph (t) of this section. 

(4) Calculate both CH4 and CO2 mass emissions from 

volumetric emissions using calculations in paragraph (v) of 

this section. 

(5) Calculate emissions from degassing vent vapors to 

flares as follows: 

(i) Use the degassing vent vapor volume and gas 

composition as determined in paragraph (o)(1) through (3) 

of this section. 

(ii) Use the calculation methodology of flare stacks 

in paragraph (n) of this section to determine degassing 

vent vapor emissions from the flare. 

 (p) Reciprocating compressor rod packing venting. 

Calculate annual CH4 and CO2 emissions from each 

reciprocating compressor rod packing venting as follows: 

(1) Estimate annual emissions using a meter flow 

measurement using Equation W-17 of this section. 

Ea,i= MT *T * Mi (Eq. W-17) 

Where: 

Ea,i = Annual GHG i (either CH4 or CO2) volumetric 

emissions at ambient conditions. 

MT = Meter volumetric reading of gas emissions per 

unit time, under ambient conditions. 
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190 

T = Total time the compressor associated with the 

venting is operational in the reporting year. 

Mi = Mole percent of GHG i in the vent gas; use the 

appropriate gas compositions in paragraph (u)(2) 

of this section. 

(2) If the rod packing case is connected to an open 

ended vent line then use one of the following two methods 

to calculate emissions.

(i) Measure emissions from all vents (including 

emissions manifolded to common vents) including rod 

packing, unit isolation valves, and blowdown valves using 

bagging according to methods set forth in §98.234 (c). 

(ii) Use a temporary meter such as, but not limited 

to, a vane anemometer or a permanent meter such as, but not 

limited to, an orifice meter to measure emissions from all 

vents (including emissions manifolded to a common vent) 

including rod packing vents, unit isolation valves, and 

blowdown valves according to methods set forth in §98.234 

(b). 

(3) If the rod packing case is not equipped with a 

vent line use the following method to estimate emissions: 

(i) You must use the methods described in §98.234 

(a) to conduct annual leak detection of fugitive emissions 

from the packing case into an open distance piece, or from 
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191 

the compressor crank case breather cap or vent with a 

closed distance piece. 

(ii) Measure emissions using a high flow sampler, 

or calibrated bag, or appropriate meter according to 

methods set forth in §98.234 (d). 

(4) Conduct one measurement for each compressor in 

each of the operational modes that occurs during a 

reporting period: 

(i) Operating. 

(ii) Standby pressurized. 

(iii) Not operating, depressurized. 

(5) Calculate CH4 and CO2 volumetric emissions at 

standard conditions using calculations in paragraph (t) of 

this section. 

(6) Estimate CH4 and CO2 volumetric and mass emissions 

from volumetric natural gas emissions using the 

calculations in paragraphs (u) and (v) of this section. 

(q) Leak detection and leaker emission factors. You 

must use the methods described in §98.234 (a) to conduct an 

annual leak detection of fugitive emissions from all 

sources listed in section §98.232 – (d)(9), (e)(7), (f)(5), 

(g)(3), (h)(4), (i)(1). This paragraph applies to 
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192 

emissions sources in streams with gas content greater than 

10 percent CH4 plus CO2 by weight. Emissions sources in 

streams with gas content less than 10 percent CH4 plus CO2

by weight do not need to be reported. If fugitive 

emissions are detected for sources listed in this 

paragraph, calculate emissions using Equation W-18 of this 

section for each source with fugitive emissions. 

Es,i= Count * EF *GHGi*T (Eq. W-18) 

Where: 

Es,i = Annual total volumetric GHG emissions at standard 

conditions from each fugitive source. 

Count = Total number of source types. 

EF = Leaker emission factor for specific sources 

listed in Table W-2 through Table W-7 of this 

subpart. 

GHGi = For onshore natural gas processing facilities, 

concentration of GHG i, CH4 or CO2, in feed 

natural gas; for other facilities listed in 

§98.230 (3)through (8),GHGi equals 1. 

T = Total time the specific source associated with 

the fugitive emission was operational in the 

reporting year, in hours. 

Calculate both CH4 and CO2 mass emissions from 

volumetric emissions using calculations in paragraph (v) of 

this section. 

(1) Onshore natural gas processing facilities shall 

use the appropriate default leaker emission factors listed 

in Table W-2 of this subpart for fugitive emissions 

detected from valves; connectors; open ended lines; 
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193 

pressure relief valves; meters; and centrifugal compressor 

dry seals. 

(2) Onshore natural gas transmission compression 

facilities shall use the appropriate default leaker 

emission factors listed in Table W-3 of this subpart for 

fugitive emissions detected from connectors; block valves; 

control valves; compressor blowdown valves; pressure relief 

valves; orifice meters; other meters; regulators; and open 

ended lines. 

(3) Underground natural gas storage facilities for 

storage stations shall use the appropriate default leaker 

emission factors listed in Table W-4 of this subpart for 

fugitive emissions detected from connectors; block valves; 

control valves; compressor blowdown valves; pressure relief 

valves; orifice meters; other meters; regulators; and open 

ended lines. 

(4) LNG storage facilities shall use the appropriate 

default leaker emission factors listed in Table W-5 of this 

subpart for fugitive emissions detected from valves; pump 

seals; connectors; and other. 

(5) LNG import and export facilities shall use the 

appropriate default leaker emission factors listed in Table 
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194 

W-6 of this subpart for fugitive emissions detected from 

valves; pump seals; connectors; and other. 

(6) Natural gas distribution facilities for above 

ground meter regulator and gate stations shall use the 

appropriate default leaker emission factors listed in Table 

W-7 of this subpart for fugitive emissions detected from 

connectors; block valves; control valves; pressure relief 

valves; orifice meters; other meters; regulators; and open 

ended lines. 

(r) Population count and emission factors. This 

paragraph applies to emissions sources listed in §98.232 - 

(c)(21), (d)(9), (e)(8), (f)(5), (g)(3), (h)(4), (i)(1), on 

streams with gas content greater than 10 percent CH4 plus 

CO2 by weight. Emissions sources in streams with gas 

content less than 10 percent CH4 plus CO2 by weight do not 

need to be reported. Calculate emissions from all sources 

listed in this paragraph using Equation W-19 of this 

section. 

Es,i= Count * EF *GHGi*T (Eq. W-19) 

Where: 

Es,I = Annual total volumetric GHG emissions at standard 

conditions from each fugitive source. 

Count = Total number of sources at the facility. 

EF = Population emission factor for specific sources 

listed in Table W-1 through Table W-7 of this 

subpart. 
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195 

GHGi = for onshore petroleum and natural gas production 

facilities and onshore natural gas processing 

facilities, concentration of GHG i, CH4 or CO2, in 

produced natural gas or feed natural gas; for 

other facilities listed in §98.230 (3) – (8),GHGi

equals 1. 

T = Total time the specific source associated with 

the fugitive emission was operational in the 

reporting year, in hours. 

Calculate both CH4 and CO2 mass emissions from 

volumetric emissions using calculations in paragraph (v) of 

this section. 

(1) Onshore petroleum and natural gas production 

facilities shall use the appropriate default population 

emission factors listed in Table W-1 of this subpart for 

fugitive emissions from valves; connectors; open ended 

lines; pressure relief valves; compressor starter gas vent; 

pump; flanges; other; and CBM well water production. Where 

facilities conduct EOR operations the emissions factor 

listed in Table W-1 shall be used to estimate all streams 

of gases, including recycle CO2 stream. In cases where the 

stream is almost all CO2, the emissions factors in Table W-1 

shall be assumed to be for CO2 instead of natural gas. 

(2) Onshore natural gas processing facilities shall 

use the appropriate default population emission factor 

listed in Table W-2 of this subpart for fugitive emissions 

from gathering pipelines. 
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196 

(3) Underground natural gas storage facilities for 

storage wellheads shall use the appropriate default 

population emission factors listed in Table W-4 of this 

subpart for fugitive emissions from connectors; valves; 

pressure relief valves; and open ended lines. 

(4) LNG storage facilities shall use the appropriate 

default population emission factors listed in Table W-5 of 

this subpart for fugitive emissions from vapor recovery 

compressors. 

(5) LNG import and export facilities shall use the 

appropriate default population emission factor listed in 

Table W-6 of this subpart for fugitive emissions from vapor 

recovery compressors. 

(6) Natural gas distribution facilities shall use the 

appropriate default population emission factors listed in 

Table W-7 of this subpart for fugitive emissions from below 

grade M&R stations; gathering pipelines; mains; and 

services. 

(s) Offshore petroleum and natural gas production 

facilities in both state and federal waters must report GHG 

emissions from all “stationary fugitive” and “stationary 

vented” sources as identified in the Minerals Management 
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197 

Service (MMS) Gulfwide Offshore Activity Data System 

(GOADS) study for each platform. 

(1) MMS GOADS Reporters. Offshore production 

facilities currently reporting under the MMS GOADS program 

will report the same annual emissions as calculated by 

GOADS under paragraph (s) of this section 

(i) For the first reporting year, report the latest 

available emissions from GOADS. 

(ii) In subsequent reporting years when GOADS is 

updated reporters shall report the new emissions that are 

made available from the latest GOADS. 

(ii) For each reporting year that does not overlap 

with the GOADS reporting year, report the last reported 

GOADS emissions with emissions adjusted based on the 

operating time for each platform. 

(iii) If MMS discontinues or delays their GOADS survey 

by more than 4 years, then Platform operators shall collect 

monthly activity data every 4 years from platform sources 

in accordance with the latest version of the MMS GOADS 

program instructions, beginning in the year that the GOADS 

survey would have been conducted, and annual emissions 

shall be calculated using the latest available MMS GOADS 

emission factors and methods. 
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198 

(2) Non-MMS GOADS Reporters. Offshore production 

facilities not reporting under the MMS GOADS program shall 

collect monthly activity data from platform sources for the 

first reporting year in accordance with the latest MMS 

GOADS program instructions. Annual emissions shall be 

calculated using the latest MMS GOADS emission factors and 

methods. 

(i) In subsequent reporting years, facilities not 

reporting under GOADS shall follow the data collection 

cycle as GOADS in collecting new activity data monthly to 

estimate emissions and report emissions. 

 (ii) For each reporting year that does not overlap 

with the GOADS reporting year, report the last reported 

emissions data with emissions adjusted based on the 

operating time for each platform. 

(iii) If MMS discontinues or delays their GOADS survey 

by more than 4 years, then Platform operators shall collect 

monthly activity data every 4 years from platform sources 

in accordance with the latest version of the MMS GOADS 

program instructions, and annual emissions shall be 

calculated using currently available MMS GOADS emission 

factors and methods. 
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199 

(t) Calculate volumetric emissions at standard 

conditions as specified in paragraphs (t)(1) or (2) of this 

section. 

(1) Calculate natural gas volumetric emissions at 

standard conditions by converting ambient temperature and 

pressure of natural gas emissions to standard temperature 

and pressure natural gas using Equation W-20 of this 

section. 

a s

a n s a

s n

T P

E T P

E

(460 )*

*(460 )* ,

,

+

+

=

 (Eq. W-20) 

Where: 

Es,n = Natural gas volumetric emissions at standard 

temperature and pressure (STP) conditions. 

Ea,n = Natural gas volumetric emissions at ambient 

conditions. 

Ts = Temperature at standard conditions. (oF). 

Ta = Temperature at actual emission conditions. (oF). 

Ps = Absolute pressure at standard conditions (inches 

of Hg). 

Pa = Absolute pressure at ambient conditions (inches 

of Hg). 

(2) Calculate GHG volumetric emissions at standard 

conditions by converting ambient temperature and pressure 

of GHG emissions to standard temperature and pressure using 

Equation W-21 of this section. 

a s

a i s a

s i

T P

E T P

E

(460 ) *

* (460 ) * ,

,

+

+

= (Eq. W-21) 

Where: 
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200 

Es,i = GHG i volumetric emissions at standard 

temperature and pressure (STP) conditions. 

Ea,i = GHG i volumetric emissions at actual conditions. 

Ts = Temperature at standard conditions. (oF). 

Ta = Temperature at actual emission conditions. (oF). 

Ps = Absolute pressure at standard conditions (inches 

of Hg). 

Pa = Absolute pressure at ambient conditions (inches 

of Hg). 

(u) Calculate GHG volumetric emissions at standard 

conditions as specified in paragraphs (u)(1) and (2) of 

this section.

(1) Estimate CH4 and CO2 emissions from natural gas 

emissions using Equation W-22 of this section. 

Es,i =Es,n * Mi (Eq. W-22) 

Where: 

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

standard conditions. 

Es,n = Natural gas volumetric emissions at standard 

conditions. 

Mi = Mole percent of GHG i in the natural gas. 

(2) For Equation W-22 of this section, the mole 

percent, Mi, shall be the annual average mole percent for 

each facility, as specified in paragraphs (u)(2)(i) through 

(vii) of this section. 

(i) GHG mole percent in produced natural gas for 

onshore petroleum and natural gas production facilities. 

If you have a continuous gas composition analyzer for 
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201 

produced natural gas, you must use these values in 

calculating emissions. If you do not have a continuous gas 

composition analyzer, then quarterly samples must be taken 

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

(ii) GHG mole percent in feed natural gas for all 

emissions sources upstream of the de-methanizer and GHG 

mole percent in facility specific residue gas to 

transmission pipeline systems for all emissions sources 

downstream of the de-methanizer overhead for onshore 

natural gas processing facilities. If you have a 

continuous gas composition analyzer on feed natural gas, 

you must use these values in calculating emissions. If you 

do not have a continuous gas composition analyzer, then 

quarterly samples must be taken according to methods set 

forth in §98.234 (b). 

(iii) GHG mole percent in transmission pipeline 

natural gas that passes through the facility for onshore 

natural gas transmission compression facilities. 

(iv) GHG mole percent in natural gas stored in 

underground natural gas storage facilities. 

(v) GHG mole percent in natural gas stored in LNG 

storage facilities. 
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202 

(vi) GHG mole percent in natural gas stored in LNG 

import and export facilities. 

(vii) GHG mole percent in local distribution pipeline 

natural gas that passes through the facility for natural 

gas distribution facilities. 

(v) Calculate GHG mass emissions in carbon dioxide 

equivalent at standard conditions by converting the GHG 

volumetric emissions into mass emissions using Equation W23 of this section. 

3

, , * * * 10− Masss i = Es i ri GWP

 (Eq. W-23) 

Where: 

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

standard conditions in metric tons CO2e. 

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

standard conditions, in cubic feet. 

ri = Density of GHG i, 0.053 kg/ft3 for CO2 and 0.0193 

kg/ft3 for CH4. 

GWP = Global warming potential, 1 for CO2 and 21 for 

CH4. 

(w) EOR injection pump blowdown. Calculate pump 

blowdown emissions as follows: 

(1) Calculate the total volume in cubic feet 

(including, but not limited to, pipelines, compressors and 

vessels) between isolation valves. 
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203 

(2) Retain logs of the number of blowdowns per 

reporting period. 

(3) Calculate the total annual venting emissions 

using Equation W-24 of this section: 

3

, * * * *10 − Ma c i= N Vv Rc GHGi

ss (Eq. W-24) 

Where: 

Massc,i = Annual EOR injection gas venting emissions in 

metric tons at critical conditions “c” from 

blowdowns. 

N = Number of blowdowns for the equipment in 

reporting year. 

Vv = Total volume in cubic feet of blowdown equipment 

chambers (including, but not limited to, 

pipelines, compressors, manifolds and vessels) 

between isolation valves. 

Rc = Density of critical phase EOR injection gas in 

kg/ft3. Use an appropriate standard method 

published by a consensus-based standards 

organization to determine density of super 

critical EOR injection gas. 

GHGi = Mass fraction of GHGi in critical phase injection 

gas. 

 (x) Hydrocarbon liquids dissolved CO2. Calculate 

dissolved CO2 in hydrocarbon liquids as follows: 

(1) Determine the amount of CO2 retained in hydrocarbon 

liquids after flashing in tankage at STP conditions. 

Quarterly samples must be taken according to methods set 

forth in §98.234 (b) to determine retention of CO2 in 

hydrocarbon liquids immediately downstream of the storage 
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204 

tank. Use the average of the quarterly analysis for the 

reporting period. 

(2) Estimate emissions using Equation W-25 of this 

section. 

Masss, CO2 = Shl * Vhl (Eq. W-25) 

Where: 

Masss, CO2 = Annual CO2 emissions from CO2 retained in 

hydrocarbon liquids beyond tankage, in metric 

tons. 

Shl = Amount of CO2 retained in hydrocarbon liquids 

in metric tons per barrel, under standard 

conditions. 

Vhl = Total volume of hydrocarbon liquids produced in 

barrels in the reporting year. 

 (y) Produced water dissolved CO2. Calculate dissolved 

CO2 in produced water as follows: 

(1) Determine the amount of CO2 retained in produced 

water at STP conditions. Quarterly samples must be taken 

according to methods set forth in §98.234 (b) to determine 

retention of CO2 in produced water immediately downstream of 

the separator where hydrocarbon liquids and produced water 

are separated. Use the average of the quarterly analysis 

for the reporting period. 

(2) Estimate emissions using the Equation W-26 of this 

section. 

Masss, CO2 = Spw * Vpw (Eq. W-26) 

Where: 
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205 

Masss, CO2 = Annual CO2 emissions from CO2 retained in 

produced water beyond tankage, in metric tons. 

Spw = Amount of CO2 retained in produced water in 

metric tons per barrel, under standard 

conditions. 

Vpw = Total volume of produced water produced in 

barrels in the reporting year. 

 (3) EOR operations that route produced water from 

separation directly to re-injection into the hydrocarbon 

reservoir in a closed loop system without any leakage to 

the atmosphere are exempt from paragraph (y) of this 

section. 

(z) Portable equipment combustion emissions. Calculate 

emissions from portable equipment using the Tier 1 

methodology described in subpart C of this part (General 

Staitonary Fuel Combustion Sources). 

§98.234 Monitoring and QA/QC requirements. 

(a) You must use the method described as follows to 

conduct annual leak detection of fugitive emissions from 

all source types listed in §98.233 (p)(3)(i) and (q) in 

operation or on standby mode that occur during a reporting 

period. 

(1) Optical gas imaging instrument. Use an optical 

gas imaging instrument for fugitive emissions detection in 

accordance with 40 CFR part 60 subpart A §60.18 (i) (1), 

(2), and (4)(v) Alternative work practice for monitoring 
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206 

equipment leaks. In addition, you must operate the optical 

gas imaging instrument to image the source types required 

by this proposed reporting rule in accordance with the 

instrument manufacturer's operating parameters.

(b) All flow meters, composition analyzers and 

pressure gauges that are used to provide data for the GHG 

emissions calculations shall use measurement methods, 

maintenance practices, and calibration methods, prior to 

the first reporting year and in each subsequent reporting 

year using an appropriate standard method published by a 

consensus standards organization such as, but not limited 

to, ASTM International, American National Standards 

Institute (ANSI), and American Petroleum Institute (API). 

If a consensus based standard is not available, you must 

use manufacturer instructions to calibrate the meters, 

analyzers, and pressure gauges. 

(c) Use calibrated bags (also known as vent bags) 

only where the emissions are at near-atmospheric pressures 

such that it is safe to handle and can capture all the 

emissions, below the maximum temperature specified by the 

vent bag manufacturer, and the entire emissions volume can 

be encompassed for measurement. 
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207 

(1) Hold the bag in place enclosing the emissions 

source to capture the entire emissions and record the time 

required for completely filling the bag. If the bag 

inflates in less than one second, assume one second 

inflation time. 

(2) Perform three measurements of the time required 

to fill the bag, report the emissions as the average of the 

three readings. 

(3) Estimate natural gas volumetric emissions at 

standard conditions using calculations in §98.233(t). 

(4) Estimate CH4 and CO2 volumetric and mass emissions 

from volumetric natural gas emissions using the 

calculations in §98.233(u) and (v). 

 (d) Use a high volume sampler to measure emissions 

within the capacity of the instrument. 

(1) A technician following manufacturer instructions 

shall conduct measurements, including equipment 

manufacturer operating procedures and measurement 

methodologies relevant to using a high volume sampler, 

including, but not limited to, positioning the instrument 

for complete capture of the fugitive emissions without 

creating backpressure on the source. 
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208 

(2) If the high volume sampler, along with all 

attachments available from the manufacturer, is not able to 

capture all the emissions from the source then you shall 

use anti-static wraps or other aids to capture all 

emissions without violating operating requirements as 

provided in the instrument manufacturer’s manual. 

(3) Estimate CH4 and CO2 volumetric and mass emissions 

from volumetric natural gas emissions using the 

calculations in §98.233(u) and (v). 

(4) Calibrate the instrument at 2.5 percent methane 

with 97.5 percent air and 100 percent CH4 by using 

calibrated gas samples and by following manufacturer’s 

instructions for calibration. 

§98.235 Procedures for estimating missing data. 

A complete record of all estimated and/ or measured 

parameters used in the GHG emissions calculations is 

required. If data are lost or an error occurs during 

annual emissions estimation or measurements, you must 

repeat the estimation or measurement activity for those 

sources as soon as possible, including in the subsequent 

reporting year if missing data are not discovered until 

after December 31 of the reporting year, until valid data 

for reporting is obtained. Data developed and/or collected 
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209 

in a subsequent reporting year to substitute for missing 

data cannot be used for that subsequent year’s emissions 

estimation. Where missing data procedures are used for the 

previous year, at least 30 days must separate emissions 

estimation or measurements for the previous year and 

emissions estimation or meausrements for the current year 

of data collection. 

§98.236 Data reporting requirements. 

In addition to the information required by §98.3(c), each 

annual report must report emissions as specified in this 

section 

(a) Report annual emissions separately for each of 

the industry segment listed in paragraphs (a) (1) through 

(8) of this section. For each segment, report emissions 

from each source type in the aggregate, unless specified 

otherwise. For example, an underground natural gas storage 

operation with multiple reciprocating compressors must 

report emissions from all reciprocating compressors as an 

aggregate number. 

(1) Onshore petroleum and natural gas production . 

(2) Offshore petroleum and natural gas production . 

(3) Onshore natural gas processing. 

(4) Onshore natural gas transmission compression . 
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210 

(5) Underground natural gas storage. 

(6) LNG storage. 

(7) LNG import and export. 

(8) Natural gas distribution. Report each source in 

the aggregate for pipelines and for Metering and Regulating 

(M&R) stations. 

(b) Report emissions separately for standby 

equipment. 

(c) Report activity data for each aggregated source 

type as follows: 

(1) Count of natural gas pneumatic high bleed devices. 

(2) Count of natural gas pneumatic low bleed devices. 

(3) Count of natural gas driven pneumatic pumps. 

(4) For each acid gas removal unit report the 

following: 

(i) Total volume of natural gas flow into the acid gas 

removal unit. 

(ii) Total volume of natural gas flow out of the acid 

gas removal unit. 

(iii) Volume weighted CO2 content of natural gas into 

the acid gas removal unit. 
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211 

(5) For each dehydrator unit report the 

following: 

(i) Glycol dehydrators: 

(A) Glycol dehydrator feed natural gas flow rate. 

(B) Glycol dehydrator absorbent circulation pump type. 

(C) Glycol dehydrator absorbent circulation rate. 

(D) Whether stripper gas is used in glycol dehydrator. 

(E) Whether a flash tank separator is used in glycol 

dehydrator. 

(ii) Desiccant dehydrators: 

(A) The number of desiccant dehydrators operated. 

(6) Count of wells vented to the atmosphere for 

liquids unloading for each field in the basin. 

(7) Count of wells venting during well completions for 

each field in the basin. 

(i) Number of conventional completions. 

(ii) Number of completions involving hydraulic 

fracturing. 

(8) Count of wells venting during well workovers for 

each field in the basin. 
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212 

(i) Number of conventional well workovers involving 

well venting to the atmosphere. 

(ii) Number of unconventional well workovers involving 

well venting to the atmosphere. 

(9) For each compressor blowdown vent stack report the 

following for each compressor: 

(i) Type of compressor whether reciprocating or 

centrifugal. 

(ii) Compressor capacity in horse powers. 

(iii) Volume of gas between isolation valves. 

(iv) Number of blowdowns per year. 

(10) For each estimate of gas emitted from liquids 

sent to atmospheric tank using E&P Tank report the 

following: 

(i) Immediate upstream separator temperature and 

pressure. 

(ii) Sales oil API gravity. 

(iii) Estimate of individual tank or tank battery 

capacity in barrels. 

(iv) Oil, hydrocarbon condensate and water sent to 

tank(s) in barrels. 
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213 

(v) Control measure: either vapor recovery system or 

flaring of tank vapors. 

(11) For tank emissions identified using optical gas 

imaging instrument per §98.234 (a), report the following 

for each tank: 

(i) Immediate upstream separator temperature and 

pressure. 

(ii) Sales oil API gravity. 

(iii) Tank capacity in barrels. 

(iv) Tank throughput in barrels. 

(v) Control measure: either vapor recovery system or 

flaring of tank vapors. 

(vi) Optical gas imagining instrument used. 

(vii) Meter used for measuring emissions. 

(viii) List of emissions sources routed to the tank. 

(12) For well testing report the following for each 

field in the basin: 

(i) Number of wells tested in reporting period. 

(ii) Average gas to oil ratio for each field. 

(iii) Average flow rate during testing for each field. 

(iv) Average number of days the well is tested. 
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214 

(v) Whether the hydrocarbons produced during testing 

are vented or flared. 

(13) For associated natural gas venting report the 

following for each field in the basin: 

(i) Number of wells venting or flaring associated 

natural gas in reporting period. 

(ii) Average gas to oil ratio for each field. 

(iii) Average volume of oil produced per well per 

field. 

(iv) Whether the associated natural gas is vented or 

flared. 

(14) For flare stacks report the following for each 

flare: 

(i) Whether flare has a continuous flow monitor. 

(ii) If using engineering estimation methods, identify 

sources of emissions going to the flare. 

(iii) Whether flare has a continuous gas analyzer. 

(iv) Identify proportion of total natural gas to pure 

hydrocarbon stream being sent to the flare annually for the 

reporting period. 

(v) Flare combustion efficiency. 
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215 

(15) For well venting for liquids unloading report the 

following by field, basin, and well tubing size: 

(i) Number of wells being unloaded for liquids in 

reporting year. 

(ii) Average number of unloading(s) per well per 

reporting year. 

(iii) Average volume of natural gas produced per well 

per reporting year during liquids unloading. 

(16) For well completions and workovers report the 

following for each field in the basin: 

(i) Number of wells completed (worked over) in 

reporting year. 

(ii) Average number of days required for completion 

(workover). 

(iii) Average volume of natural gas produced per well 

per reporting year during well completion (workover). 

(17) For compressor wet seal degassing vents report 

the following for each degassing vent: 

(i) Number of wet seals connected to the degassing 

vent. 

(ii) Number of compressors whose wet seals are 

connected to the degassing vent. 
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216 

(iii) Total throughput of compressors whose wet seals 

are connected to the degassing vent. 

(iv) Type of meter used for making measurements. 

(v) Whether emissions estimate is based on a 

continuous or one time measurement. 

(vi) Total time the compressor(s) associated with the 

degassing vent stack is operating. Sum the hours of 

operation if multiple compressors are connected to the vent 

stack. 

(vii) Proportion of vent gas recovered for fuel gas or 

sent to a flare. 

(18) For reciprocating compressor rod packing report 

the following per rod packing: 

(i) Total throughput of the reciprocating compressor 

whose rod packing emissions is being reported. 

(ii) Total time in hours the reciprocating compressor 

is in operating mode. 

(iii) Whether or not the rod packing case is connected 

to an open ended line. 

(iv) If rod packing is connected to an open ended 

line, report type of device used for measurement emissions. 
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217 

(v) If rod packing is not connected to an open ended 

vent line, report the locations from where the emissions 

from the rod packing are detected. 

(19) For fugitive emissions sources using emission 

factors for estimating emissions report the following: 

(i) Component count for each fugitive emissions 

source. 

(ii) CH4 and CO2 in produced natural gas for onshore 

petroleum and natural gas production. 

(20) For EOR injection pump blowdown report the 

following per pump: 

(i) Pump capacity. 

(ii) Volume of gas between isolation valves. 

(iii) Number of blowdowns per year. 

(iv) Supercritical phase EOR injection gas density. 

(21) For hydrocarbon liquids dissolved CO2 report the 

following for each field in the basin: 

(i) Volume of crude oil produced. 

(22) For produced water dissolved CO2 report the 

following for each field in the basin: 

(i) Volume of produced water produced. 
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218 

(d) Minimum, maximum and average throughput for each 

operation listed in paragraphs (a) (1) through (8) of this 

section. 

(e) For offshore petroleum and natural gas production 

facilities, the number of connected wells, and whether the 

wells are producing oil, gas, or both. 

(f) Report emissions separately for portable equipment 

for the following source types: drilling rigs, dehydrators, 

compressors, electrical generators, steam boilers, and 

heaters. 

(i) Aggregate emissions by source type. 

(ii) Report count of each source type. 

§98.237 Records that must be retained. 

In addition to the information required by §98.3(g), you 

must retain the following records: 

(a) Dates on which measurements were conducted. 

(b) Results of all emissions detected and 

measurements. 

(c) Calibration reports for detection and measurement 

instruments used. 
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219 

(d) Inputs and outputs of calculations or emissions 

computer model runs used for engineering estimation of 

emissions. 

§98.238 Definitions. 

All terms used in this subpart have the same meaning 

given in the Clean Air Act and subpart A of this part. 
TABLE W-1 OF SUBPART W - DEFAULT NATURAL GAS EMISSION FACTORS FOR ONSHORE PRODUCTION 

Onshore production 

Emission Factor 

(scf/hour/component) 

Population Emission Factors - All Components, Gas Service 

Valve 0.08 

Connector 0.01 

Open-ended Line 0.04 

Pressure Relief Valve 0.17 

Low-Bleed Pneumatic Device Vents 2.75

Gathering Pipelines1 2.81

CBM Well Water Production2 0.11

Population Emission Factors - All Components, Light Crude 

Service3 

Valve 0.04

Connector 0.01

Open-ended Line 0.04

Pump 0.01

Other5 0.24

Population Emission Factors - All Components, Heavy Crude 

Service4

 

Valve 0.001

Flange 0.001

Connector (other) 0.0004

Open-ended Line 0.01

Other5 0.003

1 Emission Factor is in units of "scf/hour/mile" 

2 Emission Factor is in units of "scf methane/gallon", in this case the operating factor is 

"gallons/year" and do not multiply by methane content 

3 Hydrocarbon liquids greater than or equal to 20 ̊API are considered "light crude" 

4 Hydrocarbon liquids less than 20 ̊API are considered "heavy crude" 

5 ”Others” category includes instruments, loading arms, pressure relief valves, stuffing boxes, 

compressor seals, dump lever arms, and vents. 
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221 

TABLE W-2 OF SUBPART W - DEFAULT METHANE EMISSION FACTORS FOR PROCESSING

Processing 

Emission Factor 

(scf/hour/component) 

Leaker Emission Factors - Reciprocating Compressor Components, Gas Service 

Valve 13.47

Connector 8.48

Open-ended Line 16.57

Pressure Relief Valve 28.45

Meter 33.88

Leaker Emission Factors - Centrifugal Compressor Components, Gas Service 

Valve 1.90

Connector 2.36

Open-ended Line 8.86

Dry Seal 

Leaker Emission Factors - Other Components, Gas Service 

Valve 4.52

Connector 4.26

Open-ended Line 22.81

Pressure Relief Valve 12.90

Meter 2.25

Population Emission Factors - Other Components, Gas Service 

Gathering Pipelines1 2.81

1 Emission Factor is in units of "scf/hour/mile" 
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222 

TABLE W-3 OF SUBPART W - DEFAULT METHANE EMISSION FACTORS FOR TRANSMISSION

Transmission 

Emission Factor 

(scf/hour/component) 

Leaker Emission Factors - All Components, Gas Service 

Connector 0.96 

Block Valve 2.02 

Control Valve 3.94 

Compressor Blowdown Valve 66.15 

Pressure Relief Valve 19.80 

Orifice Meter 0.46 

Other Meter 0.01 

Regulator 1.03 

Open-ended Line 6.01 

Population Emission Factors - Other Components, Gas Service 

Low-Bleed Pneumatic Device Vents 2.57
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223 

TABLE W-4 OF SUBPART W - DEFAULT METHANE EMISSION FACTORS FOR UNDERGROUND STORAGE 

Underground Storage 

Emission Factor 

(scf/hour/component) 

Leaker Emission Factors - Storage Station, Gas Service 

Connector 0.96 

Block Valve 2.02 

Control Valve 3.94 

Compressor Blowdown Valve 66.15 

Pressure Relief Valve 19.80 

Orifice Meter 0.46 

Other Meter 0.01 

Regulator 1.03 

Open-ended Line 6.01 

Population Emission Factors - Storage Wellheads, Gas Service 

Connector 0.01 

Valve 0.10

Pressure Relief Valve 0.17

Open-ended Line 0.03

Population Emission Factors - Other Components, Gas Service 

Low-Bleed Pneumatic Device Vents 2.57
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224 

TABLE W-5 OF SUBPART W - DEFAULT METHANE EMISSION FACTORS FOR LIQUEFIED NATURAL GAS (LNG) 

STORAGE

LNG Storage 

Emission Factor 

(scf/hour/component) 

Leaker Emission Factors - LNG Storage Components, LNG Service 

Valve 1.19

Pump Seal 4.00

Connector 0.34

Other1 1.77

Population Emission Factors - LNG Storage Compressor, Gas Service 

Vapor Recovery Compressor 6.81

1 "other" equipment type should be applied for any equipment type other than connectors, pumps, 

or valves. 

TABLE W-6 OF SUBPART W - DEFAULT METHANE EMISSION FACTORS FOR LNG TERMINALS

LNG Terminals 

Emission Factor 

(scf/hour/component) 

Leaker Emission Factors - LNG Terminals Components, LNG Service 

Valve 1.19

Pump Seal 4.00

Connector 0.34

Other 1.77

Population Emission Factors - LNG Terminals Compressor, Gas Service 

Vapor Recovery Compressor 6.81
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225 

TABLE W-7 OF SUBPART W - DEFAULT METHANE EMISSION FACTORS FOR DISTRIBUTION

Distribution 

Emission Factor 

(scf/hour/component) 

Leaker Emission Factors - Above Grade M&R Stations Components, Gas Service 

Connector 0.67 

Block Valve 1.49 

Control Valve 3.94 

Pressure Relief Valve 5.24 

Orifice Meter 0.46 

Other Meter 0.01 

Regulator 2.14 

Open-ended Line 6.01 

Population Emission Factors - Below Grade M&R Stations Components, Gas Service1

Below Grade M&R Station, Inlet Pressure > 300 psig 1.30

Below Grade M&R Station, Inlet Pressure 100 to 300 psig 0.20

Below Grade M&R Station, Inlet Pressure < 100 psig 0.10

Population Emission Factors - Distribution Mains, Gas Service2 

Unprotected Steel 12.58

Protected Steel 0.35

Plastic 1.13

Cast Iron 27.25

Population Emission Factors - Distribution Services, Gas Service2 

Unprotected Steel 0.19

Protected Steel 0.02

Plastic 0.001

Copper 0.03

1 Emission Factor is in units of "scf/hour/station" 

2 Emission Factor is in units of "scf/hour/service" 
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226 

TABLE W-8 OF SUBPART W - DEFAULT NITROUS OXIDE EMISSION FACTORS FOR GAS FLARING

Gas Flaring 

Emission Factor 

(metric tons/MMscf gas 

production or receipts) 

Population Emission Factors - Gas Flaring 

Gas Production 5.90E-07 

Sweet Gas Processing 7.10E-07 

Sour Gas Processing 1.50E-06 

Conventional Oil Production1 1.00E-04 

Heavy Oil Production2 7.30E-05 

1 Emission Factor is in units of "metric tons/barrel conventional oil production" 

2 Emission Factor is in units of "metric tons/barrel heavy oil production"