6560.50 

ENVIRONMENTAL PROTECTION AGENCY 

40 CFR Part 98 

[EPA-HQ-OAR-2009-0923; FRL-] 

RIN 2060-AP99 

Mandatory Reporting of Greenhouse Gases: Petroleum and 

Natural Gas Systems 

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. 

DATES: Comments must be received on or before [INSERT 

THE DATE 60 DAYS AFTER PUBLICATION IN THE FEDERAL 
2

REGISTER]. There will be one public hearing. The hearing 

will be on April 19, 2010 in Arlington, VA and will begin 

at 8am local time and end at 5pm local time. 

ADDRESSES: You may submit your comments, identified 

by docket EPA-HQ-OAR-2009-0923 and/or RIN number 2060-AP99 

by any of the following methods: 

Χ Federal eRulemaking Portal: 

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

instructions for submitting comments. 

Χ E-mail: 

GHG_Reporting_Rule_Oil_and_Natural_Gas@epa.gov. 

Include EPA-HQ-OAR-2009-0923 and/or RIN number 2060-

AP99 in the subject line of the message. 

Χ Fax: (202) 566–1741. 

Χ Phone: (202) 566-1744. 

Χ Mail: Environmental Protection Agency, EPA Docket 

Center (EPA/DC), Attention Docket EPA-HQ-OAR-2009-

0923, Mail Code 2822T, 1200 Pennsylvania Avenue, NW., 

Washington, DC 20460. 

Χ Hand/Courier Delivery: EPA Docket Center Public 

Reading Room, Room 3334, EPA West Building, Attention 

Docket EPA-HQ-OAR-2009-0923, 1301 Constitution Avenue, 

NW., Washington, DC 20004. Such deliveries are only 

accepted during the Docket’s normal hours of 

operation, and special arrangements should be made for 

deliveries of boxed information. 

Instructions: Direct your comments to Docket ID No. 

EPA-HQ-OAR-2009-0923. 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 
3

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 

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., 
4

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’s Docket Center, Public Reading 

Room, EPA West Building, Room 3334, 1301 Constitution Ave., 

NW., Washington, DC 20004. 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 

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

address: GHGMRR@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. 
5

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 

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, 1200 

Pennsylvania Ave., NW, Washington, DC, 20460, telephone 
6

(202) 343–9263, e-mail: 

GHG_Reporting_Rule_Oil_and_Natural_Gas@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. 

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. 
7

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. 

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 
8

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 

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 
9

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 

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. Summary of the Major Changes since Initial Proposal 

C. Definition of the Source Category 

D. Selection of Reporting Threshold 

E. Selection of Proposed Monitoring Methods 

F. Selection of Procedures for Estimating Missing Data 

G. Selection of Data Reporting Requirements 

H. Selection of Records That Must be Retained 
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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 

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 
11

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 

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 
12

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. 

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 
13

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 

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 

 

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

1844, 2128. 
14

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 

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 
15

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 

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 to 
16

be gathered by this rule because such data would inform and 

are relevant to EPA’s carrying out a wide variety of CAA 

provisions. As discussed in the initial proposed rule (74 

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

authorizes the Administrator to require emissions sources, 

persons subject to the CAA, manufacturers of control 

equipment, or persons whom the Administrator believes may 

have necessary information to monitor and report emissions 

and provide such other information the Administrator 

requests for the purposes of carrying out any provision of 

the CAA. 

EPA notes that comments were submitted on the initial 

rule proposal questioning EPA’s authority under the Clean 

Air Act to collect emissions information from certain 

offshore petroleum and natural gas platforms. Some 

commenters argued that EPA does not have the authority to 

collect emissions information from offshore platforms 

located in areas of the Western Gulf because they are under 

the jurisdiction of the Department of the Interior. They 

cited, among other things, the Outer Continental Shelf Act, 

43 U.S.C. 1334. Without opining on the accuracy of the 

commenter’s summary of OCSLA or other law, we note that 

even the commenter describes these authorities as relating 

to the regulation of air emissions. Today’s proposal does 
17

not regulate GHG emissions; rather it gathers information 

to inform EPA’s evaluation of various CAA provisions. 

Moreover, EPA’s authority under CAA Section 114 is broad, 

and extends to any person “who the Administrator believes 

may have information necessary for the purposes” of 

carrying out the CAA, even if that person is not subject to 

the CAA. Indeed, by specifically authorizing EPA to 

collect information from both persons subject to any 

requirement of the CAA, as well as any person who the 

Administrator believes may have necessary information, 

Congress clearly intended that EPA could gather information 

from a person not otherwise subject to CAA requirements. 

EPA is comprehensively considering how to address climate 

change under the CAA, including both regulatory and nonregulatory options. The information from these and other 

offshore platforms will inform our analyses, including 

options applicable to emissions of any offshore platforms 

that EPA is authorized to regulate under the CAA. 

EPA is proposing to amend 40 CFR 98.2(a) so that the 

final MRR applies to facilities located in the United 

States and on or under the Outer Continental Shelf. These 

revisions are necessary to ensure that any petroleum or 

natural gas platforms located on our under the Outer 

Continental Shelf of the United States would be required to 
18

report under this rule. In addition, EPA is proposing 

revisions to the definition of United States to clarify 

that the United States includes the territorial seas. 

Other facilities located offshore of the United States 

covered by the mandatory reporting program at 40 CFR part 

98 would also be affected by this change in the definition 

of United States. Revising the definition of United 

States will also ensure that facilities located offshore of 

the United States that are injecting CO2 into sub-seabed for 

long-term containment will also be required to report data 

regarding greenhouse gases. EPA is proposing a separate rule 

on geologic sequestration and any comments specific to that 

issue should be directed to the Agency on that rulemaking 

not this one. Finally, in addition to the change to the 

definition of United States, EPA is adding a definition of 

“Outer Continental Shelf.” This definition is drawn from 

the definition in the U.S. Code. Together, these changes 

make clear that the Mandatory GHG Reporting Rule applies to 

facilities on land, in the territorial seas, or on or under 

the Outer Continental Shelf, of the United States, and that 

otherwise meet the applicability criteria of the rule. 

For further information about EPA’s legal authority, 

see the proposed and final MRR. 
19

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 

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 
20

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 

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, 
21

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). This proposal does not 

address the production of gas from landfills or manure 

management systems. 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 to 

plain view sources, component count and population 

emissions factors are proposed. In the case of offshore 

platforms, EPA is recommending that emissions sources 

identified under the Minerals Management Services (MMS) 
22

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, 

which would likely be too late for many ongoing GHG policy 

and program development needs. 
23

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

best available monitoring methods for part (e.g., the first 

three months) 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 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. Further, if commenters 

recommend that EPA allow the use of best available 

monitoring methods for a designated time period (e.g., 

three months), EPA seeks comments on whether requests for 

use of best available monitoring methods should only be 

approved for parameters subject to direct measurement, or 

also in cases where engineering calculations and/or 

emission factors are used. 
24

Amendments to the General Provisions. In a separate 

rulemaking package that was recently published (March 16, 

2010), EPA issued minor harmonizing changes to the general 

provisions for the GHG reporting rule (40 CFR part 98, 

subpart A) to accommodate the addition of source categories 

not included in the 2009 final rule (e.g., subparts 

proposed in April 2009 but not finalized in 2009, any new 

subparts that may be proposed in the future). The changes 

update 98.2(a) on rule applicability and 98.3 regarding the 

reporting schedule to accommodate any additional subparts 

and the schedule for their reporting obligations (e.g., 

source categories finalized in 2010 would not begin data 

collection until 2011 and reporting in 2012). 

In particular, we restructured 40 CFR 98.2(a) to move 

the lists of source categories from the text into tables. 

A table format improves clarity and facilitates the 

addition of source categories that were not included in 

calendar year 2010 reporting and would begin reporting in 

future years. A table, versus list, approach allows other 

sections of the rule to be updated automatically when the 

table is updated; a list approach requires separate updates 

to the various list references each time the list is 

changed. In addition to reformatting the 98.2(a)(1)-(2) 

lists into tables, other sections of subpart A were 
25

reworded to refer to the source category tables because the 

tables 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. 

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, in today’s rule we are 

proposing to add this source category to those threshold 

categories referenced from 40 CFR 98.2(a)(2) whether the 

reference is to a list or a table2. 

In today’s proposal, we also propose to amend 40 CFR 

98.6 to add definitions for several terms used in proposed 

40 CFR part 98, subpart W 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 

 

2 Since we are proposing to change the list of covered subcategories to 

tables, we are not providing regulatory text in this proposal because 

the preamble is clear. 
26

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 

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). 
27

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 

emissions3. Fugitive and vented emissions estimates 

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). 

 

3 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 

report combustion, fugitive and vented emissions. These incremental 

combustion emissions are estimated at 79 MMTCO2e. 
28

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 Economic Impact Analysis for the Mandatory 

Reporting of Greenhouse Gas Emissions under Subpart W 

Supplemental Rule (EPA-HQ-OAR-2009-0923).

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 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. 
29

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: 

Χ Limited use of fugitive leak detection. 

Χ Leaker factors to quantify detected fugitive 

emissions. 

Χ Population factors and component count for fugitive 

emissions that are widely scattered or inaccessible to 

plain view. 

Χ Use of existing MMS GOADS methods and calculated 

emissions for offshore production facilities. 

Χ Modeling software to quantify glycol dehydrator and 

tank emissions. 

Χ Engineering estimation for well venting from liquids 

unloading. 

Χ Engineering estimation for well venting from 

completions and workovers. 

Χ Engineering estimation for well testing and flaring. 

Χ Engineering estimation for flaring emissions. 

Χ 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 
30

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 

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. EPA seeks 

comment on the use of the term “equipment leak” versus 

“fugitive” and “vented” as defined in the proposed 

supplemental rule. 

C. Definition of the Source Category 
31

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 

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 
32

under the initial proposed rule, and current regulations 

relevant to the industry. A complete description of our 

assessment can be found in Greenhouse Gas Emissions from 

the Petroleum and Natural Gas Industry: Background 

Technical Support Document (TSD) (EPA-HQ-OAR-2009-0923). 

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 

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 
33

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 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 

Greenhouse Gas Emissions from the Petroleum and Natural Gas 

Industry: Background TSD (EPA-HQ-OAR-2009-0923). 
34

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 

Greenhouse Gas Emissions from the Petroleum and Natural Gas 

Industry: Background TSD (EPA-HQ-OAR-2009-0923. 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 

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 
35

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 incremental4 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 

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 

 

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. 
36

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 

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. 
37

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 geologic definition is referenced to 

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. Basins are mapped to county boundaries only 

to give a surface manifestation to the underground geologic 

structures, thus making it easier to relate surface 

facilities to basin underground geologic boundaries. On 

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

geology of the hydrocarbon basin without consideration of 
38

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 

option would result in a significantly lower coverage in 

emissions, estimated at 55 percent in comparison to the 
39

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 

the year with higher emitting practices, to production at 
40

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 Greenhouse Gas 

Emissions from the Petroleum and Natural Gas Industry: 

Background TSD (EPA-HQ-OAR-2009-0923). 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 percent.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, affixed temporarily or permanently to 

offshore submerged lands, that houses equipment to extract 
41

hydrocarbons from the ocean or lake floor and that 

transfers such hydrocarbons to storage, transport vessels, 

or onshore. In addition, offshore production includes 

secondary platform structures and storage tanks associated 

with the platform structure. 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 incremental5 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 

 

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. 
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 
43

compressor wet and dry seals, wet seal oil 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 dehydrator vent stacks, 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 incremental6 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 

proposed rulemaking would already be required to report 

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

 

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. 
44

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 

underground natural gas storage facilities. While these 

are the major emissions sources in natural gas 
45

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 incremental7 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, regasified at LNG import and export terminals. Import and 

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

 

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. 
46

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 

deliver re-gasified natural gas to a natural gas 

transmission or distribution system. LNG export terminal 
47

(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. 

EPA is not proposing to include reporting of fugitive 

emissions from natural gas pipeline segments between 

compressor stations, or crude oil pipelines and tank 
48

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 

individual end users. Distribution system CH4 and CO2

emissions result mainly from fugitive emissions from above 

ground gate stations (metering and regulating stations), 
49

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 incremental8 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. 

Crude Oil Transportation. 

Crude oil is commonly transported by barge, tanker, 

rail, truck, and pipeline from production operations and 

 

8 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. 
50

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 

storage facilities; LNG import and export facilities and 

natural gas distribution facilities. As described above, 

under the proposed rule, for onshore petroleum and natural 
51

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 

addition to well drilling rigs and their ancillary 

equipment for well completions, it is common practice in 

onshore production to use skid mounted portable 
52

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 

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 
53

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% 

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 
54

U.S. Inventory. For additional discussion, refer to Greenhouse Gas 

Emissions from the Petroleum and Natural Gas Industry: Background TSD 

(EPA-HQ-OAR-2009-0923). 

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 Greenhouse Gas 

Emissions from the Petroleum and Natural Gas Industry: 

Background TSD (EPA-HQ-OAR-2009-0923). 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 
55

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 

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% 
56

Emissions Covered Facilities Covered Threshold 

Level2 Metric Tons 

CO2e/year Percent Number Percent 

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% 

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 
57

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 

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 to plain view (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 
58

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 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 

1) Engineering 

Estimation, or 

2) Direct 

1) Field specific emission 

factor times events or 

2) Flow metered emission 
59

Emission Source Monitoring Methods 

Emissions Quantification 

Methods 

Workovers Measurement 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 

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 
60

1. 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 
61

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 
62

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 
63

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 
64

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). 

2. 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 
65

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. EPA seeks comment on whether there are 

additional or alternative software packages to E&P Tank and 

GlyCalc that should be required to be used to calculate 

emissions. 
66

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 

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 Greenhouse Gas 

Emissions from the Petroleum and Natural Gas Industry: 

Background TSD (EPA-HQ-OAR-2009-0923). 

3. Combination of direct measurement and engineering 

estimation 
67

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 

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 
68

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 

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. 

5. Use of Leak detection and leaking component emission 

factors 
69

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 

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

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

it by a population emissions factor. This option would 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. As described 

further below, EPA requests comment on the use of emission 

factors and ways in which these shortcomings may be 

overcome. 
70

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 

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. 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 
71

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. 

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. 

Leaking component emissions factors from these studies were 

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

emission factors generated from the 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 

Clearstone studies as the basis for the leaker factors 

proposed in this rule. EPA requests comments on the use of 

emission factors from the Clearstone studies. For further 

details see Greenhouse Gas Emissions from the Petroleum and 

Natural Gas Industry: Background TSD (EPA-HQ-OAR-2009-

0923). 
72

Emission References for Petroleum and Natural Gas 

Systems 

API. Compendium of Greenhouse Gas Emissions 

Methodologies for the Oil and Gas Industry. American 

Petroleum Institute. Table 4-7, page 4-30. February 2004. 

API. Emission Factors for Oil and Gas Production 

Operations. Table 8, page 10. API Publication Number 

4615. January 1995. 

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 

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/downloads09/Annexes.

pdf. 

EPA. Lessons Learned: Replacing Wet Seals with Dry 

Seals in Centrifugal Compressors. U.S. EPA 2006. 

http://www.epa.gov/gasstar/documents/ll_wetseals.pdf. 

EPA. Protocol for Equipment Leak Emission Estimates. 

Emission Standards Division. U.S. EPA. SOCMI Table 2-7. 

November 1995. 

http://www.epa.gov/ttn/chief/efdocs/equiplks.pdf. 
73

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_report/6_ven

ted.pdf. 

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_report/8_equ

ipmentleaks.pdf

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_report/9_und

erground.pdf. 

GRI. Methane Emissions from the Natural Gas Industry. 

Volume 10. Table 7-1. June 1996. 

http://epa.gov/gasstar/documents/emissions_report/10_meteri

ng.pdf. 

ICF. Estimates of Methane Emissions from the U.S. Oil 

Industry. Draft. Page 13. October 1999. 

Clearstone. 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. 

National Gas Machinery Laboratory, Kansas State 

University; Clearstone Engineering, Ltd; Innovative 
74

Environmental Solutions, Inc. Cost-Effective 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. 

Clearstone. Handbook for Estimating Methane Emissions 

from Canadian Natural Gas Systems. Clearstone Engineering 

Ltd., Enerco Engineering Ltd, and Radian International. 

2007. 

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) and (2)). 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 
75

commenters to the initial proposed rule recommended leak 

detection with an optical gas imaging instrument in 

accordance with the EPA AWP. Hence, the supplemental 

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) 
76

emissions from petroleum refineries and chemical plants. 

The optical gas imaging instrument has been used 

extensively to successfully detect methane emissions in the 

petroleum and gas industry by petroleum and gas companies. 

A 2006 independent study funded through a grant by EPA and 

conducted by Clearstone Engineering, was an extensive study 

of methane emissions in gas processing plants and upstream 

gathering compressor stations and well sites. Method 21 

was employed to detect leaks and HiFlow samplers were used 

to determine the emissions from those leaks. This study 

surveyed approximately 74,000 components finding 3,650 

leaks (4.9 percent). Of these leaks, 497 (<1 percent of 

total components) contributed 90 percent of the total 

fugitive emissions. The smallest of the 497 leaks was 177 

grams per hour, so an optical gas imaging instrument should 

be able to adequately image methane leaks since the 

smallest leak was well above the 60 to 100 gram per hour 

detection sensitivity in Table 1 of the AWP. Therefore, 

for the purposes of this reporting rule, EPA determined 

that an optical gas imaging instrument that meets the 

detection sensitivity requirements of the AWP for any 

monitoring frequency as specified in Table 1 of the AWP, is 

acceptable for use under this proposed rule. Leak 

detection and leaker emission factors only apply to 
77

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. 

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, 

emissions are assumed to occur the entire 365 days in the 

year. 

EPA is aware that the petroleum and natural gas 

industry is already implementing voluntary fugitive 

emissions detection and repair programs. Such voluntary 

programs are useful, but pose an accounting challenge with 

respect to emissions reporting for this proposed rule. The 

proposed approach does not preclude any owner or operator 

from detecting and repairing fugitive emissions prior to 

quantifying emissions for the purposes of reporting under 

this proposed rule. 

To address this issue, EPA considered, but did not 

propose, requiring a facility to conduct multiple surveys 
78

and to report emissions using the appropriate leaker 

factors. Under this approach, if a specific emission 

source is found not leaking in the initial survey but 

leaking in subsequent surveys, emissions would be 

quantified from the date of the first survey where a leak 

was detected forward through the time when the leak is 

fixed, or the end of the year, whichever is first. 

Similarly, if an emissions source is found to be leaking in 

the initial survey, emissions would be quantified from the 

date of that survey through to when the leak is repaired, 

or the end of the year, whichever is first. Under this 

approach, emissions would reflect leak reductions as 

determined by repairs and follow-up detection surveys 

EPA seeks comment on whether this alternative approach 

better estimates annual facility emissions without 

resulting in additional reporting burden to the facilities. 

Further, we seek comment on whether, if implemented, 

multiple surveys should be optional or required for owners 

or operators. 

6. Use of Population count and population emission factor 

Fugitive emissions detection and use of leaking 

component emissions factors are not always cost effective 

and can be burdensome. This is particularly true of 

onshore petroleum and natural gas production where the 
79

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. Population count and 

population emission factors only apply to 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. EPA is using emissions data from 

studies listed in the Emission References (#2, #4, #5, #7, 

#8, #9 above) as the basis for the population emissions 

factors proposed in this rule. However, the API compendium 

emissions factors that we are proposing to use in the 
80

upstream oil and gas production sector may be 

underestimating emissions. EPA seeks comment on how to 

improve these factors and/or collect more accurate data. 

7. 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 

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. LDAR programs require 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 
81

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

quality districts have lower leak definitions than the 

Federal standards. LDAR programs require facilities to 

conduct multiple surveys per year: either following 

equipment-specific 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 use this LDAR leak detection data with 

“leaker” factors developed by the Synthetic Organic 

Chemicals Manufacturing Industry (SOCMI) to estimate the 

quantity of 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 
82

factors specific to methane from several recent studies 

quantifying component 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. 

Optical gas imaging instruments were found to be more 

appropriate for 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 
83

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 

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 
84

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 

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 
85

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. Generally, EPA has proposed 

that onshore production be reported at the basin level, as 

opposed to the unit or field level, to minimize reporting 

burden. EPA notes that in a concurrent proposed rulemaking 

for facilities that conduct CO2 injection or geologic 

sequestration (subpart RR), the term “facility” is defined 

at a more disaggregated level, specifically as a “well or 

group of wells.” EPA seeks comment on the use of more 

disaggregated reporting options for subpart W. 

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. 

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 
86

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. 

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 
87

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 of the Proposed 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 

for the Mandatory Reporting of Greenhouse Gas Emissions 

under Subpart W Supplemental Rule (EPA-HQ-OAR-2009-0923). 

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, 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. 
88

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 percent 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 

reporting fugitive and vented emissions based on the 

reporting requirements proposed under the initial proposal 

as compared to the new supplemental proposed rule. 
89

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 inhouse monitoring option. Costs for the alternative contractor 

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

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 
90

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 

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 to plain view 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. 
91

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 

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 to plain 

view (i.e. buried or below grade in vaults) 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. 
92

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 

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 
93

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. 

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), 
94

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: 

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 

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. 
95

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 

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 proposed rule?
96

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 

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 
97

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 

develop unique unit costs. This analysis is documented in 

the Economic Impact Analysis for the Mandatory Reporting of 

Greenhouse Gas Emissions under Subpart W Supplemental Rule 

(EPA-HQ-OAR-2009-0923). The Greenhouse Gas Emissions from 

the Petroleum and Natural Gas Industry: Background TSD 
98

(EPA-HQ-OAR-2009-0923) provides a discussion of the 

applicable engineering estimating and measurement 

technologies and any existing programs and practices. 

Incremental combustion-related 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 Impact 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 

shares of costs are gas processing (12.5 percent) and local 
99

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 
100

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 $Million

Subpart W – 

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) 

Percentage 

of Total 

Downstream 

Emissions 

Reported 

Average 

Reporting 

Cost 

($/ton) 

Incrementa

l Cost 

($/metric 

ton) 1

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

25,000 3,037 $25.30 351 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 

1Cost per metric ton relative to the selected option. 

C. What are the economic impacts of the proposed 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 
101

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. 

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 
102

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 proposed 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 

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 
103

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 

exceeds one percent.9 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 

 

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

continues to be the preferred quantitative metric for economic impact 

screening analysis. 
104

industries. The results of the screening assessment are 

shown in Table W-10 of this preamble. 

Table W-10. Estimated Cost-To-Sales Ratios for First Year 

Costs by Industry and Enterprise Sizea

Owned by Enterprises with:

Industry NAICS

NAICS 

Descriptio

n

SBA 

Size 

Standar

d 

(effective 

March 

11, 

2008)

Average 

Cost 

Per 

Entity 

($1,000

/ 

entity)

All 

Enterprises

<20 

Emplo

yeesf

20 to 

99 

Emplo

y-ees

100 to 

499 

Employ

- 

ees 

500 to 

749 

Employees 

< 500 

Employees 

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 

Extractio

n 

500 

employe

es 

$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 

Transport

ation 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 

Distribut

ion 

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 singleestablishment 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. 

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. 

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

percent for establishments owned by small businesses that 
105

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 

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

data limitations allowed us only to compute and compare 
106

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 proposed 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 

relevance to policy making, transparency issues, and market 

efficiency. Benefits are very difficult to quantify and 
107

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 

resulted in allocation of permits for emissions levels an 
108

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 

their emission levels and sources to identify opportunities 

to reduce emissions. Such monitoring allows for inclusion 
109

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

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 
110

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 2376.01. 

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 

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 
111

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.10

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 

that must comply with the proposed rule’s reporting 

requirements; and the estimated average number of likely 

 

10 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. 
112

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)11. 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-2009-0923). 

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

ADDRESSES section at the beginning of this notice for where 

 

11 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. 
113

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. 

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 
114

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. The small entities 

directly regulated by this proposed rule include small 

businesses in the petroleum and natural gas industry, small 

governmental jurisdictions and small non-profits. We have 

determined that some small businesses will be affected 

because their production processes emit GHGs that must be 

reported. 

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. 
115

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 

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 
116

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 

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 
117

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 

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 
118

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 not have a significant economic impact on a 

substantial number of 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 

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 
119

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. 

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 
120

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 

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 
121

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. This regulation 

applies directly to petroleum and natural gas facilities 

that emit greenhouse gases. Few, if any, state or local 

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, 

Executive Order 13132 does not apply to this action. 

In the spirit of Executive Order 13132, and consistent 

with EPA policy to promote communications between EPA and 

State and local governments, EPA specifically solicits 

comment on this proposed action from State and local 

officials. 

F. Executive Order 13175: Consultation and Coordination 

with Indian Tribal Governments

EPA has concluded that this action may have tribal 

implications. However, it will neither impose substantial 
122

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 

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 
123

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 

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 
124

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. 

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, 
125

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 

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. 
126

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 

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. 
127
Mandatory Reporting of Greenhouse Gases 

Page 128 of 214

List of Subjects in 40 CFR Part 98

Environmental protection, Administrative practice and 

procedure, Greenhouse gases, Incorporation by reference, 

Suppliers, Reporting and recordkeeping requirements. 

Dated: 

Lisa P. Jackson, 

Administrator. 
129

For the reasons stated in the preamble, the 

Environmental Protection Agency proposes to amend 40 CFR 

part 98 as follows: 

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 98.2 is amended by revising paragraph (a) 

introductory text to read as follows: 

§98.2 Who must report? 

(a) The GHG reporting requirements and related 

monitoring, recordkeeping, and reporting requirements of 

this part apply to the owners and operators of any facility 

that is located in the United States or under or attached 

to the Outer Continental Shelf (as defined in 43 U.S.C. 

§1331) 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) of this 

section: 

* * * * * 
130

3. Section 98.6 is amended by adding the following 

definitions in alphabetical order and revising the 

definition of “United States” 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. 

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 
131

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 

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 
132

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), 

metal to metal compression, or fluid barrier through which 

natural gas or liquid can escape to the atmosphere. 
133

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. 

* * * * * 
134

De-methanizer means the natural gas processing unit 

that separates methane rich residue gas from the heavier 

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-
135

1999 by The American Petroleum Institute and The Gas 

Research Institute. 

* * * * * 

Engineering estimation, for purposes of subpart W,

means an estimate of emissions based on engineering 

principles applied to measured and/or 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 means unburned hydrocarbons including 

CH4, CO2, N2O emissions resulting from the incomplete 

combustion of gas in flares. 
136

Flare combustion efficiency means the fraction of 

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

at the flare burner tip. 

* * * * * 

Fugitive emissions means those emissions which are 

unintentional and could not reasonably pass through a 

stack, chimney, vent, or other functionally-equivalent 

opening. 

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. 

* * * * * 
137

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 

(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 
138

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. 

* * * * * 

Offshore means seaward of the terrestrial borders of 

the United States, including waters subject to the ebb and 

flow of the tide, as well as adjacent bays, lakes or other 

normally standing waters, and extending to the outer 

boundaries of the jurisdiction and control of the United 

States under the Outer Continental Shelf Lands Act. 

* * * * * 

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 
139

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. 

* * * * * 

Outer Continental Shelf means all submerged lands 

lying seaward and outside of the area of lands beneath 

navigable waters as defined in 43 U.S.C. § 1301 , and of 

which the subsoil and seabed appertain to the United States 

and are subject to its jurisdiction and control. 

* * * * * 

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. 
140

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. 

* * * * * 
141

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 

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) and/or carbon dioxide (CO2) that does 

not require (or has already had) acid gas treatment to meet 

pipeline corrosion-prevention 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. 

* * * * * 
142

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. 

* * * * * 

United States means the 50 States, the District of 

Columbia, the Commonwealth of Puerto Rico, American Samoa, 

the Virgin Islands, Guam, and any other Commonwealth, 

territory or possession of the United States, as well as 

the territorial sea as defined by Presidential Proclamation 

No. 5928. 

* * * * * 

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, 

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 
143

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 

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. 
144

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”. 

4. 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). 

(2) [Reserved] 

(l) The following material is available for purchase 

from IHS Standards Store, Jane’s Information Group, Inc., 
145

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). 

(2) [Reserved] 

(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 §98.230(b). 

(2) [Reserved] 

5. Add subpart W to read as follows: 
146

Subpart W—Petroleum and Natural Gas Systems 

Sec.

98.230 Definition of the source category.

98.231 Reporting threshold.

98.232 GHGs to report.

98.233 Calculating GHG emissions.

98.234 Monitoring and QA/QC requirements.

98.235 Procedures for estimating missing data.

98.236 Data reporting requirements.

98.237 Records that must be retained.

98.238 Definitions.

Subpart W—Petroleum and Natural Gas Systems

§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, affixed temporarily or permanently to 

offshore submerged lands, that houses equipment to extract 

hydrocarbons from the ocean or lake floor and that 

transfers such hydrocarbons to storage, transport vessels, 

or onshore. In addition, offshore production includes 

secondary platform structures and storage tanks associated 

with the platform structure. 
147

(2) Onshore petroleum and natural gas production. 

Onshore petroleum and natural gas production equipment 

means all structures associated with wells (including but 

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 
148

specifications through equipment performing one or more of 

the following processes: oil and condensate removal, water 

removal, separation of natural gas liquids, sulfur and 

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 
149

processing facilities, in transmission pipelines, to 

natural gas distribution pipelines, or into storage. In 

addition, transmission compressor station includes 

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 
150

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

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) [Reserved] 

§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 and drive train and that is stationed at a 

wellhead for more than 30 days in a reporting year, 

including drilling rigs, dehydrators, compressors, 

electrical generators, steam boilers, and heaters. 
151

§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 (2005 Gulfwide Emission 

Inventory Study MMS 2007-067). 

(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. 

(6) Gas well venting during unconventional well 

completions. 

(7) Gas well venting during conventional well 

workovers. 

(8) Gas well venting during unconventional well 

workovers. 
152

(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 

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. 
153

(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. 

(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: 
154

(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: 

(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. 
155

(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. 

(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.
156

(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. 

(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. 
157

(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 

thissection. 

(Eq. W-2) 

Where: 

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

per year at standard conditions from all 

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(a)(3) through 

(a)(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. 

Masss,i = Count * EF * GHGi*Convi* 24*365
158

(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. 

(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 
159

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) 

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 
160

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 

temperature and pressure (STP) conditions using the 

simulation software package GRI-GLYCalc Version 4.0 

(incorporated by reference, see §98.7). 

(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. 
161

(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: 

(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) 
162

(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 

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 paragraph (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 
163

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. 

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

conditions as required in paragraph (f)(1)(i)(A), 

(f)(1)(i)(B) and (f)(1)(i)(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. 
164

(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. 

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 
165

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

section. 

(B) [Reserved] 

(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. 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. 

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 paragraph (g)(1) 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 this paragraph (g)(1). The same calculation 
166

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. 

(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). 
167

(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. 

(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. 
168

(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: 

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. 
169

(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. 

(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. 

Ea n N Vv* , =
170

(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 

CH4 and CO2 emissions using the latest software package for 

E&P Tank (incorporated by reference, see §98.7). 

(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. 
171

(i) Adjust the emissions estimated using E&P Tank 

(incorporated by reference, see §98.7) downward by the 

magnitude of emissions captured using a vapor recovery 

system for benefitial use. 

(ii) [Reserved] 

(3) Calculate emissions from liquids sent to 

atmospheric storage tanks vented to flares as follows: 

(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 E&P Tank (incorporate by 

reference, see §98.7), 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. 
172

(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. 

(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: 
173

(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. 

(ii) [Reserved] 

(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. 
174

(5) Calculate emissions from well testing to flares 

as follows: 

(i) Use the well testing emissions volume and gas 

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

of this section. 

(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. 

(i) [Reserved] 

(2) Estimate venting emissions using the Equation W12 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. 
175

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. 

(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) If you have a continuous flow measurement device 

on the flare, you must use the measured flow volumes to 

calculate the flare gas emissions. If you do not have a 

continuous flow measurement device on the flare, you can 
176

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 

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. 
177

(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)

( ) ( ) ( ) , , , 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). 
178

(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. 

(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: 
179

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. 

(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 paragraphs (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. 
180

(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. 

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) 
181

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 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. 
182

(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 §98.232(d)(9), (e)(7), (f)(5), (g)(3), 

(h)(4), and (i)(1). This paragraph (q) applies to 

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 this type of emission source 

found to be leaking. 

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 the total 

hydrocarbon of the feed natural gas; for other 
183

facilities listed in §98.230(a)(3) through 

(a)(8), GHGi equals 1. 

T = Total time the specific source associated with 

the fugitive emission was operational in the 

reporting year, in hours. 

(1) Calculate GHG mass emissions in carbon dioxide 

equivalent at standard conditions using calculations in 

paragraph (v) of this section. 

(2) 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; 

pressure relief valves; meters; and centrifugal compressor 

dry seals. 

(3) 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. 

(4) 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; 
184

control valves; compressor blowdown valves; pressure relief 

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

ended lines. 

(5) 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. 

(6) LNG import and export facilities shall use the 

appropriate default leaker emission factors listed in Table 

W-6 of this subpart for fugitive emissions detected from 

valves; pump seals; connectors; and other. 

(7) 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)(2), (c)(9), (c)(15), (c)(21), (d)(8), (e)(6), 

(f)(4), (f)(5), (g)(3), (h)(4), (i)(2), (i)(3) and (i)(4), 

on streams with gas content greater than 10 percent CH4 

plus CO2 by weight. Emissions sources in streams with gas 
185

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 this type of emission source at 

the facility. 

EF = Population emission factor for specific sources 

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

subpart. 

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 (b)(3) 

through (b)(8),GHGi equals 1. 

T = Total time the specific source associated with 

the fugitive emission was operational in the 

reporting year, in hours. 

(1) Calculate both CH4 and CO2 mass emissions from 

volumetric emissions using calculations in paragraph (v) of 

this section. 

(2) 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; 
186

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. 

(3) 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. 

(4) 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. 

(5) 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. 

(6) 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. 
187

(7) 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. Report GHG 

emissions from all “stationary fugitive” and “stationary 

vented” sources as identified in the Minerals Management 

Service (MMS) Gulfwide Offshore Activity Data System 

(GOADS) study (2005 Gulfwide Emission Inventory Study MMS 

2007-067) 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 software. 

(ii) For each reporting year that does not overlap 

with the GOADS reporting year, report the last reported 
188

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. 

(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 
189

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. 

(t) Volumetric emissions. 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). 
190

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: 

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) GHG volumetric emissions. 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) 
191

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 

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 
192

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. 

(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) GHG mass emissions. Calculate GHG mass emissions 

in carbon dioxide equivalent at standard conditions by 

converting the GHG volumetric emissions into mass emissions 

using Equation W-23 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. 
193

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. 

(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. 
194

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 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: 
195

(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. 

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

Where: 

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 
196

1 methodology described in subpart C of this part (General 

Stationary 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) 

and (2) Alternative work practice for monitoring 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. 

(2) [Reserved]

(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 
197

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. 

(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). 
198

(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. 

(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.
199

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 

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 contain reported 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 
200

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. 

(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: 
201

(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. 

(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. 

(B) [Reserved] 

(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. 
202

(ii) Number of completions involving hydraulic 

fracturing. 

(8) Count of wells venting during well workovers for 

each field in the basin. 

(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. 
203

(iv) Oil, hydrocarbon condensate and water sent to 

tank(s) in barrels. 

(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. 
204

(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. 

(15) For well venting for liquids unloading report 

the following by field, basin, and well tubing size: 
205

(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. 

(iii) Total throughput of compressors whose wet seals 

are connected to the degassing vent. 

(iv) Type of meter used for making measurements. 
206

(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. 

(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: 
207

(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. 

(ii) [Reserved] 

(22) For produced water dissolved CO2 report the 

following for each field in the basin: 

(i) Volume of produced water produced. 

(ii) [Reserved] 

(d) Minimum, maximum and average throughput for each 

operation listed in paragraphs (a)(1) through (a)(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. 
208

(f) Report emissions separately for portable 

equipment for the following source types: drilling rigs, 

dehydrators, compressors, electrical generators, steam 

boilers, and heaters. 

(1) Aggregate emissions by source type. 

(2) 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. 

(d) Inputs and outputs of calculations or emissions 

computer model runs used for engineering estimation of 

emissions. 

§98.238 Definitions.

Except as provided below, all terms used in this 

subpart have the same meaning given in the Clean Air Act 

and subpart A of this part. 

Natural gas distribution facility means the 

distribution pipelines, metering stations, and regulating 

stations that are operated by a Local Distribution Company 
209

(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.

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 or 

walkways are one facility. 

Onshore petroleum and natural gas production facility

means all petroleum or natural gas equipment associated 

with all petroleum or natural gas production 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. 

Separator means a vessel in which streams of multiple 

phases are gravity separated into individual streams of 

single phase. 
210

TABLE W-1 OF SUBPART W–DEFAULT WHOLE GAS EMISSION FACTORS 

FOR ONSHORE PRODUCTION 

TABLE W-2 OF SUBPART W–DEFAULT TOTAL HYDROCARBON EMISSION 

FACTORS FOR PROCESSING 

Processing 

Before De-methanizer

Emission Factor 

(scf/hour/component)

After De-methanizer 

Emission Factor 

(scf/hour/component)

Leaker Emission Factors - Reciprocating Compressor Components, 

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. 
211

Processing 

Before De-methanizer

Emission Factor 

(scf/hour/component)

After De-methanizer 

Emission Factor 

(scf/hour/component)

Gas Service 

Valve 15.88 18.09

Connector 4.31 9.10

Open-ended Line 17.90 10.29

Pressure Relief 

Valve 2.01 30.46

Meter 0.02 48.29

Leaker Emission Factors - Centrifugal Compressor Components, Gas 

Service

Valve 0.67 2.51

Connector 2.33 3.14

Open-ended Line 17.90 16.17

Dry Seal 105 105

Leaker Emission Factors - Other Components, Gas Service

Valve 6.42

Connector 5.71

Open-ended Line 11.27

Pressure Relief Valve 

2.01

Meter 2.93

Population Emission Factors - Other Components, Gas Service

Gathering Pipelines1 2.81

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

TABLE W-3 OF SUBPART W–DEFAULT METHANE EMISSION FACTORS FOR 

TRANSMISSION 

Transmission 

Emission Factor 

(scf/hour/compo

nent) 

Leaker Emission Factors - All Components, Gas Service

Connector 2.7

Block Valve 10.4

Control Valve 3.4

Compressor Blowdown Valve 543.5

Pressure Relief Valve 37.2

Orifice Meter 14.3

Other Meter 0.1

Regulator 9.8

Open-ended Line 21.5

Population Emission Factors - Other Components, Gas Service

Low-Bleed Pneumatic Device Vents 2.57
212

TABLE W-4 OF SUBPART W–DEFAULT METHANE EMISSION FACTORS FOR 

UNDERGROUND STORAGE 

Underground Storage 

Emission Factor 

(scf/hour/compon

ent) 

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

TABLE W-5 OF SUBPART W–DEFAULT METHANE EMISSION FACTORS FOR 

LIQUEFIED NATURAL GAS (LNG) STORAGE 

LNG Storage 

Emission Factor 

(scf/hour/compo

nent) 

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/compo

nent) 

Leaker Emission Factors - LNG Terminals Components, LNG Service

Valve 1.19
213

LNG Terminals 

Emission Factor 

(scf/hour/compo

nent) 

Pump Seal 4.00

Connector 0.34

Other 1.77

Population Emission Factors - LNG Terminals Compressor, Gas 

Service

Vapor Recovery Compressor 6.81

TABLE W-7 OF SUBPART W–DEFAULT METHANE EMISSION FACTORS FOR 

DISTRIBUTION 

Distribution 

Emission Factor 

(scf/hour/compo

nent) 

Leaker Emission Factors - Above Grade M&R Stations Components, 

Gas Service 

Connector 1.69

Block Valve 0.557

Control Valve 9.34

Pressure Relief Valve 0.270

Orifice Meter 0.212

Regulator 0.772

Open-ended Line 26.131

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" 

TABLE W-8 OF SUBPART W–DEFAULT NITROUS OXIDE EMISSION 

FACTORS FOR GAS FLARING 
214

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"