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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: Final Rule.

SUMMARY: EPA is promulgating a regulation to require 

monitoring and reporting of greenhouse gas emissions from

petroleum and natural gas systems. This action adds this

source category to the list of source categories already 

required to report greenhouse gas emissions. This action 

applies to sources with carbon dioxide equivalent emissions 

above certain threshold levels as described in this 

regulation. This action does not require control of 

greenhouse gases. 

DATES: The final rule is effective on [INSERT THE 

DATE 60 DAYS AFTER PUBLICATION IN THE FEDERAL REGISTER]. 

The incorporation by reference of certain publications 

listed in the rule is approved by the Director of Federal 

Register as of [INSERT THE DATE 60 DAYS AFTER PUBLICATION 

IN THE FEDERAL REGISTER].
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ADDRESSES: EPA established a single docket under 

Docket ID No. EPA-HQ-OAR-2009-0923 for this action. All 

documents in the docket are listed on the 

www.regulations.gov website. Although listed in the index, 

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

confidential business information (CBI) or other 

information whose disclosure is restricted by statute. 

Certain other material, such as copyrighted material, is 

not placed on the internet and will be publicly available 

only in hard copy form. Publicly available docket 

materials are available either electronically through 

www.regulations.gov or in hard copy at EPA’s Docket Center, 

Public Reading Room, EPA West Building, Room 3334, 1301 

Constitution Avenue, 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) 566-1741. 

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: GHGReportingRule@epa.gov. For technical 
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information and implementation materials, please go to the 

website 

www.epa.gov/climatechange/emissions/ghgrulemaking.html. To

submit a question, select Rule Help Center, followed by 

Contact Us.

SUPPLEMENTARY INFORMATION:

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.”). The final rule 

affects 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

Petroleum and 

Natural Gas 

Systems

486210 Pipeline transportation of natural gas.

221210 Natural gas distribution facilities.

211 Extractors of crude petroleum and 

natural gas.

211112 Natural gas liquid extraction 

facilities.

Table 1 of this preamble is not intended to be 

exhaustive, but rather provides a guide for readers 

regarding facilities likely to be affected by this action. 

Although Table 1 of this preamble lists the types of 

facilities of which EPA is aware of that could be 

potentially affected by this action, other types of 
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facilities not 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 40 CFR part 98, subpart A 

as amended by this action. If you have questions regarding 

the applicability of this action to a particular facility, 

consult the person listed in the preceding “FOR FURTHER 

GENERAL INFORMATION CONTACT” section. 

Many facilities that are affected by the final rule 

have GHG emissions from multiple source categories listed 

in 40 CFR part 98. Table 2 of this preamble has been

developed as a guide to help potential reporters in the 

petroleum and natural gas industry affected by this action 

identify other source categories (by subpart) that they may 

need to (1) consider in their facility applicability 

determination, and (2) include in their reporting. Table 2

of this preamble identifies the subparts that are likely to 

be relevant to sources with petroleum and natural gas 

systems. The table should only be seen as a guide. 

Additional subparts in 40 CFR part 98 may be relevant for a 

given reporter. Similarly, not all listed subparts are 

relevant for all reporters. 
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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 

Under CAA section 307(b)(1), judicial review of this 

final rule is available only by filing a petition for 

review in the U.S. Court of Appeals for the District of 

Columbia Circuit by [INSERT THE DATE 60 DAYS AFTER 

PUBLICATION IN THE FEDERAL REGISTER]. Under CAA section 

307(d)(7)(B), only an objection to this final rule that was

raised with reasonable specificity during the period for 

public comment can be raised during judicial review. This 

section also provides a mechanism for us to convene a 

proceeding for reconsideration, “[i]f the person raising an 

objection can demonstrate to EPA that it was impracticable 

to raise such objection within [the period for public 

comment] or if the grounds for such objection arose after 

the period for public comment (but within the time 

specified for judicial review) and if such objection is of 

central relevance to the outcome of this rule.” Any person 

seeking to make such a demonstration to us should submit a 

Judicial Review.
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Petition for Reconsideration to the Office of the 

Administrator, Environmental Protection Agency, Room 3000, 

Ariel Rios Building, 1200 Pennsylvania Ave., NW., 

Washington, DC 20004, with a copy to the person listed in 

the preceding FOR FURTHER GENERAL INFORMATION CONTACT

section, and the Associate General Counsel for the Air and 

Radiation Law Office, Office of General Counsel (Mail Code 

2344A), Environmental Protection Agency, 1200 Pennsylvania 

Ave., NW., Washington, DC 20004. Note, under CAA section 

307(b)(2), the requirements established by this final rule 

may not be challenged separately in any civil or criminal 

proceedings brought by EPA to enforce these requirements.

Acronyms and Abbreviations

cf cubic feet

. The following acronyms 

and abbreviations are used in this document.

AAPG American Association of Petroleum Geologists

AGA American Gas Association

AGR acid gas removal

ANSI American National Standards Institute

API American Petroleum Institute

ASME American Society of Mechanical Engineers

ASTM American Society for Testing and Materials

BLS Bureau of Labor Statistics

BOEMRE Bureau of Ocean Energy Management, Regulation and 

Enforcement

CAA Clean Air Act

CBI confidential business information

CBM coal bed methane

CEMS continuous emission monitoring systems
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CFR Code of Federal Regulations

CH4 methane

CO2 carbon dioxide

CO2e CO2-equivalent

DOE Department of Energy

E&P exploration and production

EIA Economic Impact Analysis

EO Executive Order

EOR enhanced oil recovery

EPA U.S. Environmental Protection Agency

ESD emergency shutdown

FPSO floating production and storage offloading

FR Federal Register

GHG greenhouse gas

GOR gas to oil ratio

GRI Gas Research Institute

GWP global warming potential

IBR incorporation by reference

ICR information collection request

IPCC Intergovernmental Panel on Climate Change

IR infrared

ISO International Organization for Standardization

kg kilograms

LACT lease automatic custody transfer

LDCs local natural gas distribution companies

LNG liquefied natural gas

LPG liquefied petroleum gas

M&R meters and regulators

MMBTU million British thermal units

MMS Minerals Management Service

mmscfd million standard cubic feet per day

MMTCO2e million metric tons carbon dioxide equivalent 

MRR mandatory GHG reporting rule

N2O nitrous oxide

NAESB North American Energy Standards Board
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NAICS North American Industry Classification System

NGLs natural gas liquids

NTTAA National Technology Transfer and Advancement Act

OAQPS Office of Air Quality, Planning and Standards

OMB Office of Management and Budget

OVA organic vapor analyzer

ppm parts per million

QA quality assurance

QA/QC quality assurance/quality control

RFA Regulatory Flexibility Act

RGGI Regional Greenhouse Gas Initiative

RIA Regulatory Impact Analysis

SBREFA Small Business Regulatory Enforcement and 

Fairness Act

SSM startup, shutdown, and malfunction

STP standard temperature and pressure

TCR The Climate Registry

TSD technical support document

TVA toxic vapor analyzer

U.S. United States

UMRA Unfunded Mandates Reform Act of 1995

USC United States Code

USGS United States Geologic Society

VOC volatile organic compound(s)

WCI Western Climate Initiative

TABLE OF CONTENTS 

I. Background

A. Organization of this Preamble 

B. Background on the Final Rule 

C. Legal Authority 

II. Reporting Requirements for Petroleum and Natural Gas 

Systems 
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A. Overview of Greenhouse Gas Reporting Program

B. Overview of Confidentiality Determination for Data 

Elements in the Greenhouse Gas Reporting Program

C. Summary of Changes to the General Provisions of the 

Greenhouse Gas Reporting Program

D. Summary of the Requirements for Petroleum and Natural 

Gas Systems (Subpart W)

E. Summary of Major Changes and Clarifications Since 

Proposal

F. Summary of Comments and Responses

III. Economic Impacts of the Rule

A. How Were Compliance Costs Estimated?

B. What are the Costs of the Rule?

C. What are the Economic Impacts of the Rule?

D. What are the Impacts of the Rule on Small Businesses?

E. What are the Benefits of the 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
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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

K. Congressional Review Act

I. Background

This preamble consists of four sections. The first 

section provides a brief history of 40 CFR part 98 and 

describes the purpose and legal authority for this action. 

A. Organization of this Preamble

The second section of this preamble summarizes the 

revisions made to the general provisions in 40 CFR part 98, 

subpart A and outlines the specific requirements for 

subpart W being incorporated into 40 CFR part 98 by this 

action. It also describes the major changes made to this

source category since proposal and provides a brief summary 

of significant public comments and EPA’s responses on 

issues specific to each industry segment. 
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The third section of this preamble provides the 

summary of the cost impacts, economic impacts, and benefits 

of the final rule and discusses comments on the economic 

impact analyses for subpart W. 

Finally, the last section discusses the various 

statutory and executive order requirements applicable to 

this rulemaking.

On April 12, 2010, EPA proposed this rule, amending 40 

CFR part 98 (i.e., the regulatory requirements for the 

Greenhouse Gas Reporting Program). The GHG Reporting 

Program requires reporting of GHG emissions and other 

relevant information from certain source categories in the 

United States. The Greenhouse Gas (GHG) Reporting Program, 

which became effective on December 29, 2009, includes 

reporting requirements for facilities and suppliers in 32 

subparts. EPA established this program in response to the 

fiscal year 2008 Consolidated Appropriations Act

B. Background on the Final Rule

This action, finalizes monitoring and reporting 

requirements for the following source category: petroleum 

and natural gas systems. 

1

 

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

1844, 2128. Congress reaffirmed interest in a GHG reporting rule, and 

provided additional funding in the 2009 and 2010 Appropriations Acts 

(Consolidated Appropriations Act, 2009, Pub. L/ 110-329, 122 Stat. 

. This Act 
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authorized funding for EPA to develop and publish a rule 

“...to require the mandatory reporting of greenhouse gas 

emissions above appropriate thresholds in all sectors of 

the economy of the United States.” An accompanying joint 

explanatory statement directed EPA to “use its existing 

authority under the Clean Air Act” to develop a mandatory 

GHG reporting rule. For more detailed background 

information on the GHG Reporting Program, see the preamble 

to the final rule establishing the GHG Reporting Program 

(74 FR 56260, October 30, 2009). 

This final action adds requirements for facilities 

that contain petroleum and natural gas systems to report 

equipment leaks and vented GHG emissions (subpart W) to the 

GHG Reporting Program. The 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

 3574-3716 and Consolidated Appropriations Act, 2010, Pub. L. 111-117, 

Stat. 3034-3408). 

equivalent per year. These data will inform EPA’s 

implementation of CAA section 103 (g) regarding 

improvements in sector based non-regulatory strategies and 

technologies for preventing or reducing air pollutants, and 

inform policy on possible regulatory actions to address 

greenhouse gas emissions. As stated above, this rule was 

proposed by EPA on April 12, 2010. One public hearing was 
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held in April 2010, and the sixty day public comment period 

ended June 11, 2010. 

EPA is finalizing 40 CFR part 98, subpart W under the 

existing CAA authorities provided in CAA section 114. As 

discussed in detail in Sections I.C and II.Q of the 

preamble to the 2009 final rule (74 FR 56260, October 30, 

2009), CAA section 114(a)(1) provides EPA with broad 

authority to require emissions sources, persons subject to 

the CAA, manufacturers of process or 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 may 

gather information for a variety of purposes, including for 

the purpose of assisting in the development of emissions

reduction regulations in the petroleum and natural gas 

industry, determining compliance with implementation plans 

or such standards, or more broadly for “carrying out any 

provision” of the CAA. Section 103 of the CAA authorizes 

EPA to establish a national research and development 

program, including non-regulatory approaches and 

technologies, for the prevention and control of air 

pollution, including GHGs. As discussed in the proposal 

C. Legal Authority
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(75 FR 18608, April 12, 2010), among other things, data 

from petroleum and natural gas systems will inform 

decisions about possible emissions reduction regulations in 

the petroleum and natural gas industry. The data collected 

will also inform EPA’s implementation of CAA section 103(g)

regarding improvements in sector based non-regulatory 

strategies and technologies for preventing or reducing air 

pollutants. 

EPA has the authority under the Clean Air Act to 

collect emissions information from offshore petroleum and 

natural gas platforms including those located in areas of 

the Western Gulf. This final action does 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 
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comprehensively considering how to address climate change 

under the CAA, including both regulatory and non-regulatory 

options. The information from offshore platforms will 

inform our analyses, including options applicable to 

emissions of any offshore platforms that EPA is authorized 

to regulate under the CAA.

II. Reporting Requirements for Petroleum and Natural Gas 

Systems

A. Overview of Greenhouse Gas Reporting Program 

The GHG Reporting Program requires reporting of GHG 

emissions and other relevant information from certain 

source categories in the United States, as discussed in 

section I.B. of this preamble. The rule requires annual 

reporting of GHGs including carbon dioxide (CO2), methane 

(CH4), nitrous oxide (N2O), hydrofluorocarbons (HFCs), 

perfluorocarbons (PFCs), sulfur hexafluoride (SF6

The GHG Reporting Program requires that source 

categories subject to 40 CFR part 98, monitor and report 

GHGs in accordance with the methods specified in the 

individual subparts. For a list of the specific GHGs to be 

reported and the GHG calculation procedures, monitoring, 

missing data procedures, recordkeeping, and reporting 

), and 

other fluorinated compounds (e.g., hydrofluoroethers 

(HFEs)).
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required by facilities subject to subpart W included in 

this action, see Section II.C of this preamble. 

B. Overview of Confidentiality Determination for Data 

Elements in the Greenhouse Gas Reporting Program

This final rule does not address whether data reported 

under subpart W will be released to the public or will be 

treated as confidential business information. EPA 

published a proposed rule and confidentiality determination 

on July 7, 2010 (75 FR 39094) which addressed this issue. 

In that action, EPA proposed which specific data elements 

would be released to the public and which would be treated 

as confidential business information. EPA received several 

comments on the proposal, and is in the process of 

considering these comments. A final rule and determination 

will be issued before any data is released, and the final 

determination will include all of the data elements under 

subpart W.

C. Summary of Changes to the General Provisions of the 

Greenhouse Gas Reporting Program

This final action amends certain requirements in 40 

CFR part 98, subpart A (General Provisions). These 

amendments are summarized in this section of the preamble.

Changes to Applicability. In this final action, EPA 

is amending Table A-4 referenced in 40 CFR 98.2(a)(2) to 
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include the petroleum and natural gas systems source 

category. 

In addition, EPA is amending 40 CFR 98.2(a) so that 40 

CFR Part 98 applies to facilities located in the United 

States and on or under the Outer Continental Shelf. This 

revision is necessary to ensure that any petroleum or 

natural gas platforms located on or under the Outer 

Continental Shelf of the United States will be required to 

report under this rule. 

Changes to Definitions. In this final action, EPA is 

also amending 40 CFR 98.6 (definitions). EPA is revising 

the definition of United States as applied under the rule 

to clarify that it includes the territorial seas. Other 

facilities located offshore of the United States covered by 

the GHG Reporting Program at 40 CFR part 98 may also be 

affected by this change in the definition of United States 

(for example, subparts RR and UU Injection and Geologic 

Sequestration of CO2). In addition to the change to the 

definition of United States, EPA has amended 40 CFR 98.6 by 

adding a definition of “Outer Continental Shelf.” This 

definition is drawn from the definition in the U.S. Code. 

These revisions are necessary to ensure that facilities on 

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

Continental Shelf, of the United States, and that otherwise 
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meet the applicability criteria of the rule are required to 

report. 

Incorporation by Reference (IBR). In the April 2010 

proposal, EPA proposed to amend §98.7 by including the 

following standard methods: GRI GlyCalc software, the E&P 

Tank software, and the American Association of Petroleum 

Geologist (AAPG) Geologic Provinces Code Map. EPA has 

revised the listing of proposed methods for incorporation 

by reference. Hence, in this final action EPA is 

finalizing those amendments to 40 CFR 98.7 (incorporation 

by reference) to include standard methods referenced in 40 

CFR part 98, subpart W. Those include: American 

Association of Petroleum Geologists Geologic Provinces Code 

Map including the Alaska Geological Province Boundary Map; 

Energy Information Administration Oil and Gas Field Code 

Master List; and Year 2005 Gulfwide Emission Inventory 

Study.

D. Summary of the Requirements for Petroleum and Natural 

Gas Systems (subpart W)

1. Summary of the Final Rule

Source Category Definition. This source category 

consists of the following segments of the petroleum and 

natural gas systems source category: 
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 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 processes and/or transfers such hydrocarbons to 

storage, transport vessels, or onshore. In addition, 

offshore production includes secondary platform 

structures connected to the platform structure, 

storage tanks associated with the platform structure,

and floating production and offloading equipment 

(FPSO).

Onshore petroleum and natural gas production.



 Onshore 

petroleum and natural gas production equipment means 

all structures associated with wells (including 

compressors, generators, or storage facilities), and 

portable non-self-propelled equipment (including well 

drilling and completion equipment, workover equipment, 

gravity separation equipment, auxiliary nontransportation-related equipment, and leased, rented 

or contracted equipment) used in the production, 

extraction, recovery, lifting, stabilization, 

separation or treating of petroleum and/or natural gas 

(including condensate). This also includes associated 

storage or measurement and all enhanced oil recovery 

(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.

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 

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. This segment also includes all 

residue gas compression equipment owned or operated by 

the natural gas processing plant, whether inside or 

outside the processing plant fence.

Onshore natural gas transmission compression. Onshore 

natural gas transmission compression includes any 

fixed combination of compressors that move natural gas 
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at elevated pressure from production fields or natural 

gas processing facilities, in transmission pipelines, 

to natural gas distribution pipelines, or into 

storage. In addition, transmission compressor 

stations include equipment for liquids separation, 

natural gas dehydration, and tanks for the storage of 

water and hydrocarbon liquids. Residue (sales) gas 

compression operated by Natural Gas Processing 

Facilities are included in the processing segment and 

excluded from this segment.

 Underground natural gas storage



. Underground natural 

gas storage includes subsurface storage, including 

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 compression, dehydration and flow 

measurement, and excluding transmission pipelines); 

and all the wellheads connected to the compression 

units located at the facility.

Liquefied natural gas (LNG) storage



. LNG storage 

includes 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 regasification of the liquefied natural gas.

LNG import and export facilities



. LNG import 

equipment includes all onshore or offshore equipment 

that receives imported LNG via ocean transport, stores 

LNG, re-gasifies 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.

Natural Gas Distribution. Natural gas distribution 

includes the distribution pipelines (not interstate 

pipelines or intrastate pipelines) and metering and 

regulating equipment at city gate stations, and 

excluding customer meters, that physically deliver 

natural gas to end users and is operated by a Local 

Distribution Company (LDC) that is regulated as a 

separate operating company by a public utility 
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commission or that is operated as an independent 

municipally-owned distribution system. This segment

excludes customer meters and infrastructure and 

pipelines (both interstate and intrastate) delivering 

natural gas directly to major industrial users and 

"farm taps" upstream of the local distribution company 

inlet.

Facilities from the following segments: 1) offshore 

petroleum and natural gas production, 2) onshore natural 

gas processing plants, 3) onshore natural gas transmission 

compression, 4) underground natural gas storage, 5) LNG 

storage, 6) LNG import and export equipment, and 7)_ 

natural gas distribution facilities, that meet the 

applicability criteria in the General Provisions (40 CFR 

98.2(a)(2)) and summarized in section II.C. of this 

preamble must report GHG emissions. For facilities 

assessing their applicability in the onshore petroleum and 

natural gas production segment (as defined in 98.238), they 

must include only emissions from equipment, as specified in 

98.232(c), to determine if they exceed the 25,000 metric

ton CO2e threshold and thus are required to report their 

GHG emissions. For other segments, facilities would assess 

applicability based on all source categories for which 

methods are provided in the GHG Reporting Program. 

GHGs to Report. Facilities must report:
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 Carbon dioxide (CO2) and methane (CH4

 CO

) emissions from 

equipment leaks and vents .

2, CH4, and nitrous oxide (N2

 CO

O) from combustion

2, CH4, and nitrous oxide (N2O) emissions from 

combustion at flares.

GHG Emissions Calculation and Monitoring. The 

petroleum and natural gas source category consists of 

several segments (.e.g, onshore production, natural gas 

processing, etc). Within those segments, there are 

different types of emissions sources, some of which appear 

in multiple segments (e.g., e.g., pneumatic devices, 

blowdown vents, etc.)._ Subpart W provides methodologies 

for calculating emissions from each source type. Table W-3 

below, summarizies those source types and indicates their

applicable segments. After the table, there are summaries 

of the different methodologies reporters must use to 

monitor and calculate their GHG emissions from each

emissions source.

It is important to note, as detailed in section II. F. 

of this preamble, for specified time periods during the 

2011 data collection year, reporters may use best available 

monitoring methods for certain emissions sources.

Table W-3. Summary of Source Type in Each Industry Segment
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Source 

Type

Onshore 

Product

ion

Natural 

Gas 

Process

ing

Natural 

Gas 

Transmissi

on 

Compressio

ns

Under

groun

d 

Stora

ge

LNG 

Storage

LNG 

Import 

and 

Export 

Equipme

nt

Distrib

ution

Natural 

gas 

pneumatic 

device 

venting 

X X X 

Natural 

gas driven 

pneumatic 

pump 

venting 

X 

Well 

venting 

for 

liquids 

unloading 

X 

Gas well 

venting 

during 

well 

completion

s without 

hydraulic 

fracturing

X 

Gas well 

venting 

during 

well 

completion

s with 

hydraulic 

fracturing

X 

Gas well 

venting 

during 

well 

workovers 

without 

hydraulic 

fracturing

X 

Gas well 

venting 

during

well 

workovers 

with 

hydraulic 

fracturing

X 

Onshore X 
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production 

storage 

tanks 

Transmissi

on storage 

tanks 

X 

Reciprocat

ing 

compressor 

rod 

packing 

venting 

X X X X X X 

Well 

testing 

venting 

and 

flaring 

X 

Associated 

gas 

venting 

and 

flaring 

X 

Dehydrator 

vent 

stacks 

X X 

Enhanced 

Oil 

Recovery 

injection 

pump 

blowdown 

X 

Acid gas 

removal 

vent stack 

X X 

Enhanced 

Oil 

Recovery 

hydrocarbo

n liquids

dissolved 

CO2 

X 

Centrifuga

l 

compressor 

wet seal 

degassing 

venting 

X X X X X X 

Other 

emissions 

from 

equipment 

leaks 

X X X X X X 

Blowdown 

vent 

stacks 

X X X X 
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

Summary of Methodologies for Each Source Type in Table 

W-3

Natural gas pneumatic device venting: Calculate CO2 and 

CH4



emissions from natural gas pneumatic devices using 

component count for each type (i.e. continuous high 

bleed, continuous low bleed, and intermittent bleed) 

together with a population emission factor for each 

type from Tables W-1A, W-1D, W-3, and W-4.

Natural gas driven pneumatic pump venting: Calculate 

CO2 and CH4



emissions using component count of natural 

gas pneumatic pumps together with a population 

emission factor from Table W-1A.

Acid gas removal (AGR) vent stacks: Calculate CO2

emissions using metered flow and volume weighted CO2

content of natural gas flowing into the AGR unit. The 

approaches available to measure the volume weighted CO2 

Flare 

stacks 

content include using a continuous gas analyzer or 

sampling the gas quarterly.

X X 

Above 

ground 

meters 

regulators 

at city 

gate 

station 

equipment 

leaks 

X 

Below 

ground 

meter and 

regulator 

station 

equipment 

leaks 

X 

Pipeline 

main 

equipment 

leaks 

X 

Service 

line 

equipment 

leaks 

X 
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 Dehydrator vent stacks. Calculate CH4 and CO2

 For glycol dehydrators with a throughput greater 

than or equal to 0.4 million standard cubic feet 

per day use a software program to calculate 

emissions. The software program must determine 

the equilibrium coefficient using the PengRobinson equation of state, speciate CH

emissions using the following calculation 

methodologies:

4 and CO2

 For glycol dehydrators with a throughput less 

than 0.4 million standard cubic feet per day use 

daily flow rate of wet natural gas together with 

an emission factor to calculate CO

emissions from dehydrators, and have provisions 

to include regenerator control devices, a 

separator flash tank, stripping gas, and gas 

injection pump or gas assist pump. 

2 and CH4

 For desiccant dehydrators, calculate the amount 

of gas vented from the vessel every time it is 

depressurized for desiccant replacement. This 

involves knowing the dimensions of the dehydrator 

and percent of the vessel that is packed with 

desiccant.

emissions. There are separate emission factors 

for dehydrator units with a gas assist pump.

 Well venting for liquids unloading: Calculate CO2 and 

CH4

 Determine the average gas flow using a meter on 

the vent line. A new average flow rate must be 

calculated every other year starting in the first 

calendar year of reporting. Use the total 

venting time during the year together with the 

gas flow rate to determine the gas vented during 

liquid unloading. 

emissions using either of the following calculation 

methodologies (the same methodology must be used for 

the entire duration of the calendar year). 

 Determine the casing dimension, the shut-in 

pressure, sales flow rate and hours that the well 

was left open to the atmosphere to calculate the 

volume of gas emitted during liquid unloading. 

 Gas well venting during well completions and workovers 

from hydraulic fracturing: Calculate CO2 and CH4

emissions using the cumulative vent time during the 

year and the flow rate of gas vented, separately for

both completions and workovers. Use either of the 
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following methodologies to determine the flow rate of 

the gas. 

 Determine the flow rate of vented gas from both 

one well during a well completion, and also one

well workover event, using a meter installed on 

the vent line. A flow rate determined from a 

well during a well completion can be applied to 

all wells in the same field that undergo a 

completion. A flow rate determined from a well 

during a well workover can be applied to all 

wells in the same field that undergo a workover. 

A field-level emissions factor must be developed 

every two years starting in the first calendar 

year of reporting.

- Measure the pressure before and after the well 

choke for both one well during a well completion,

and also one well workover event. A flow rate 

determined from a well during a well completion 

can be applied to all wells in the same field 

that undergo a completion. A flow rate 

determined from a well during a well workover can 

be applied to all wells in the same field that 

undergo a workover. The flow rate must be 

determined in the first year of every two year 

period.

 Gas well venting during well completions and workovers 

without hydraulic fracturing: Calculate CO2 and CH4



emissions using the cumulative vent time during the 

year and average daily gas production.

Blowdown vent stacks. Calculate CH4 and CO2 emissions 

from blowdown vent stacks by calculating the total 

volume of equipment and vessels blown down between 

isolation valves. This includes the volume of all 

piping, compressor cases or cylinders, manifolds, 

suction and discharge bottles or any other gascontaining volume contained between the valves. Total 

volumes between isolation valves of process vessels 

less than 5,000 cubic feet do not have to be reported. 

The total volume contained between isolation valves 

for each process vessel and the number of times it was 

blowndown in the calendar year equals the actual 

volume of emissions, which are then converted to 

volumes at standard conditions and greenhouse gas 

emissions using the concentration of CH4 and CO2 in the 

applicable stream. For process vessels blowndown to a 

flare, calculate the volume of emissions the same as 
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if they were not flared, then use that volume as an 

input parameter in the flare stacks section to 

estimate combustion emissions.

 Onshore production storage tanks: Calculate CH4 and CO2

 For tanks with separator and well production

throughput greater than or equal to 10 barrels 

per day, use a software program that uses the 

Peng-Robinson equation of state, models flashing 

emissions, and speciates CH

emissions using one of the following calculation 

methodologies: 

4 and CO2

 For tanks with separator and well production 

throughput greater than or equal to 10 barrels 

per day you may assume all of the CH

emissions 

from tanks. The low pressure separator oil 

composition and Reid vapor pressure can be 

determined using the default values within the 

software program, or using a representative 

sample analysis. 

4 and CO2

 For throughput less than 10 barrels per day use a 

population emission factor together with the flow 

rate. Account for occurrences when the dump 

valve is improperly open, by determining the 

number of hours the dump valve is open and scale 

the emissions upwards using the correction 

factor. The number of hours the dump valve is 

open can be determined using the maintenance or 

operations records. It should be assumed that if 

a dump valve is found open, that it was open from 

either the beginning of the calendar year, or 

since the most recent maintenance or operations 

record confirming proper closure of the dump 

valve. Assume that a dump valve is improperly 

open until there is a maintenance or operations 

record showing that the dump valve is closed or 

to the end of the calendar year. 

in 

the low pressure oil separator is emitted. The 

low pressure separator oil composition shall be 

determined using an appropriate sample analysis.

 Transmission storage tanks. For transmission storage 

tanks, reporters must monitor the tank vapor vent 

stack using an optical gas imaging instrument, to view 

the emissions for 5 minutes. If the vent stack emits 

continuously over that time period, then the reporter 

must use a meter to measure the flow rate of the vent 
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to determine emissions. If a tank is vented to a 

flare, then use the onshore petroleum and natural gas 

production storage tanks methodology option 1 

(simulation) to estimate the volume and composition of 

vapors flared. Then use the flare stacks methodology 

to estimate the emissions.

 Associated gas venting and flaring. Calculate CH4 and 

CO2



emissions from associated gas venting and flaring 

by multiplying available data from production records 

on the gas-oil ratio for produced hydrocarbon liquids,

by the volume of liquids produced in the calendar 

year. If gas-oil ratios are not readily available, 

use a sample analysis to determine gas-oil ratios. 

For the calculated associated gas volume that is 

flared, use the method set forth for flare stacks to 

estimate the emissions.

Flare stacks. Calculate CH4 and CO2

Where methodologies for other sources in subpart W

refer to this methodology in order to estimate flaring 

emissions, use the estimated volume of flared gas from 

those sources as the gas to flare volume in this 

methodology, and report those emissions under those 

sources. 

Calculate N

emissions from 

flare stacks by metering or using engineering 

estimation to determine the volume of gas sent to the 

flare, and the gas composition to then estimate the 

portion that is combusted and the portion that is not 

combusted, using the flare efficiency. 

2



O from flare stacks using the gas to flares 

in the calendar year, and multiplying it by an 

emission factor.

Centrifugal compressor wet seal venting. Calculate CH4

and CO2 emissions from wet seal oil degassing vents in 

onshore petroleum and natural gas production by 

counting the total population of centrifugal 

compressors and multiplying it by appropriate emission 

factors. Calculate CH4 and CO2 emissions from 

centrifugal compressor blowdown valves, wet seal 

degassing, and unit isolation valves (see Table W-4) 

found in onshore natural gas processing, onshore 

natural gas transmission compression, underground 

natural gas storage, LNG storage, and LNG import and 

export equipment by:
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 Measuring venting from blowdown valves when the 

compressor is found in the operating mode using a 

meter.

 Measuring wet seal degassing venting when the 

compressor is found in the operating mode using a 

meter.

 Measuring venting from unit isolation valves when 

the compressor is found in not operating, 

depressurized mode using a meter.

If the sources above are vented through a common 

manifold, you must measure each vent source 

separately. Determine average emissions from 

each mode of operation by summing the emissions 

from each source in each mode and dividing it by 

the total population measured. The result will 

be an emission factor per compressor per hour for 

each mode of operation. Multiply each emission 

factor by the total number of compressor-hours in 

each mode of operation. Reporters are not 

required to shutdown compressors to conduct 

measurements. The owner or operator must 

schedule an annual measurement of each compressor 

and the owner or operator can take the 

measurement in the mode in which the compressor 

is found during the annual measurement. However, 

the owner or operator must conduct at least one 

measurement of each compressor in the not

operating, depressurized mode at any time during 

the three calendar years. Please see “As-is 

Compressor Mode Emissions Monitoring,” Docket 

EPA-HQ-OAR-2009-0923.

Table W-4. Summary of Emission Factor Categories for 

Centrifugal Compressor Venting. 

Component

Operating Mode

Operating Not Operating –

Depressurized

Blowdown Valve Individual Factor Not Applicable

Wet Seal Oil 

Degassing Vent Individual Factor Not Applicable 

Unit Isolation 

Valve Not Applicable Individual Factor

 Reciprocating compressor rod packing venting. 

Calculate CH4 and CO2 emissions from reciprocating 

compressor rod packing venting in onshore petroleum 
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and natural gas production by counting the total 

population of reciprocating compressors and 

multiplying it by the emission factors provided in 

§98.233(p)(10). Calculate CH4 and CO2

 Measuring venting from blowdown valves when the 

compressor is found in operating and standby 

pressurized modes using a meter.

emissions for 

reciprocating compressor blowdown valves, rod packing, 

and unit isolation valves (see Table W-5) from onshore 

natural gas processing, onshore natural gas 

transmission compression, underground natural gas 

storage, LNG storage, and LNG import and export 

equipment by:

 Measuring rod packing vents when the compressor 

is found in operating and standby pressurized 

modes using a meter. If there is not a vent 

line, a rigorous approach of scanning for all 

potential leakage paths for the gas must be used 

with a meter, high volume sampler, or calibrated 

bag as appropriate.

 Measuring venting from unit isolation valves

using a meter when the compressor is found in not 

operating, depressurized mode.

If the sources above are vented through a common 

manifold, you must measure each vent source 

separately. Determine average emissions from 

each mode of operation by summing the emissions 

from each source in each mode and dividing it by 

the total population measured. The result will 

be an emission factor per compressor per hour for 

each mode of operation. Multiply each emission 

factor by the total number of compressor-hours in 

each mode of operation. Reporters are not 

required to shutdown compressors to conduct 

measurements. The owner or operator must conduct

an annual measurement of each compressor, and 

measure the compressor in the mode as it found 

during the annual measurement. The owner or 

operator must then conduct the measurement in the 

mode in which the compressor is found. However, 

the owner or operator must conduct at least one 

measurement of each compressor in the not 

operating, depressurized mode at one time during 

the three calendar years. Please see “As-is 

Compressor Mode Emissions Monitoring,” Docket 

EPA-HQ-OAR-2009-0923.
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Table W-5. Summary of Emission Factor Categories for 

Reciprocating Compressor Venting. 

Component

Operating Mode

Operating Standby 

Pressurized

Not Operating –

Depressurized

Blowdown Valve Use measurements in either mode to 

develop combined factor. Not Applicable 

Rod Packing 

Seals Individual Factor Individual Factor Not Applicable 

Unit Isolation 

Valve Not Applicable Not Applicable Individual Factor

 Leak detection and leaker factors 

 Use an optical gas imaging instrument. This 

method must be used for all sources that cannot 

be monitored without elevating personnel more 

than 2 meters above a support surface.

(onshore natural gas 

processing, onshore natural gas transmission

compression, underground natural gas storage, LNG 

storage, LNG import export, natural gas distribution). 

Perform a leak detection survey using one of the three

following methods:

 Use an infrared laser beam illuminated 

instrument.

 Use Method 21. 

Multiply the count of each type of leaking 

component by the appropriate leaker factors in 

Tables W-2, W-3, W-4, W-5, W-6, and W-7. Tubing 

systems less than 1⁄2 inch are exempt from 

reporting. 

For natural gas distribution, leak detection is 

required only for above ground metering and 

regulating stations (also called “gate stations”) 

at which custody transfer occurs. The leak 

detection and monitoring requirements prescribed 

in subpart W do not include customer meters. All 

facilities under this source must conduct at 

least one leak survey each calendar year. 

Multiple leak surveys may be conducted in order 

to account for leak repairs. If multiple surveys 

are chosen by the owner or operator and 

performed, each survey must be facility wide.
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 If only one leak survey is conducted in the 

calendar year, assume that all leaks found emit

for the entire year.

 If multiple leak surveys are conducted, assume 

that each leak that is found has been emitting

since the last survey; or since the beginning of 

the calendar year. Assume that each leak found

continues to emit until the end of the calendar 

year after the last leak survey.

 Population count and emission factor. Calculate CH4

and CO2

 For onshore petroleum and natural gas production, 

each component must either be counted 

individually; or major equipment pieces must be 

counted and then the appropriate average 

component counts should be applied using Tables 

W-1B, W-1C, and W-1D. Gas composition of the 

produced gas must be used to determine the 

percent of the leaked gas that is CH

emissions from the sources listed in 

§98.233(r).

4 and CO2

 For underground natural gas storage, the emission 

factors in Table W-4 must be applied to 

population counts of components on storage 

wellheads.

.

 For LNG storage, the emission factor for vapor 

recovery compressors, must be applied to the 

total population count.

 For LNG import and export equipment, the emission 

factor for vapor recovery compressors must be 

applied to the total population count.

 For natural gas distribution, all emissions from 

above ground custody transfer metering and 

regulating stations as determined by leak 

detection surveys must be totaled and then 

divided by the total number of surveyed meter 

runs to develop and average emission factor for 

above grade metering and regulating stations. 

This average emission factor will be multiplied 

by the total number of above ground metering and 

regulating stations meter runs at which custody 

transfer does not occur to estimate emissions 

from those stations. Emission factors in Table 

W-7 will be used to account for equipment leaks 

in underground meter and regulation stations and 

pipelines.
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 Offshore production. Calculate CH4 emissions from 

offshore petroleum and natural gas production 

facilities using the methods outlined by MMS2

 For the first calendar year, use the latest GOADS 

methodologies. If you have already reported to 

MMS, report the latest available emissions from 

GOADS from your facility.

Gulfwide 

Emissions Inventory Study, herein after referred to as 

“GOADS.”

 When a new GOADS methodology is released, perform 

a survey in accordance with the new methodology 

and report the resulting emissions.

 For calendar years between GOADS reporting years, 

use the latest submission to EPA, but adjust the 

emissions based on the operating time for each 

platform by assuming that components not in 

operation do not emit while not in service.

 If GOADS is delayed or discontinued, then every 

fourth year the reporter must collect monthly 

activity data in accordance with the last GOADS 

methodologies and report the resulting emissions 

information to EPA.

 EOR Hydrocarbon liquids dissolved CO2. Calculate CO2

emissions downstream of storage tanks from hydrocarbon 

liquids produced as a result of enhanced oil recovery 

operations by conducting annual composition sampling 

of the produced hydrocarbon liquids by taking samples 

downstream of the storage tank. Use the mass of CO2

from the sample to determine the mass of CO2



dissolved 

in oil beyond storage per barrel of produced liquid 

hydrocarbons. 

EOR injection pump blowdown. Calculate CO2 emissions 

from enhanced oil recovery CO2

 

2 Minerals Management Service (MMS) has been renamed to the Bureau of 

Ocean Energy Management, Regulation, and Enforcement (BOEMRE)

injection pump blowdowns 

by calculating the volume of gas-containing structures

between isolation valves, including piping. Maintain 

logs of the number of blowdowns in the calendar year

for each EOR pump. Using an appropriate standard 

method published by a consensus-based standards 

organization or, if no such standard exists, an 

industry standard practice, determine the density of 

the supercritical EOR injection gas. Calculate 

emissions using the number of blowdowns, the volume of 
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the blown down equipment, the mass fraction of CO2



in 

the injection gas, the density of the injection gas, 

and a conversion factor.

Onshore petroleum and natural gas production 

combustion emissions. Calculate CO2

 If the fuel combusted is listed in Table C-1 of 

subpart C, or any blend of the fuels listed, use 

the Tier 1 methodology of that subpart.

combustion 

emissions from stationary and portable combustion 

equipment in onshore petroleum and natural gas 

production using the following methods:

 If the fuel combusted is neither listed in Table 

C-1 nor a combination of the listed fuels and the 

fuel is not field gas, then use either the Tier 3 

or Tier 4 methodologies of subpart C.

 If the fuel combusted is field gas or a 

combination of field gas and one or more fuels 

listed in Table C-1, then use the volume of fuel 

and the composition of the fuel to calculate CO2

External fuel combustion sources with a rated 

heat capacity less than or equal to 5 mmBtu/hour 

do not have to be reported. 

Calculate N

emissions. If meters are installed on the fuel 

stream, the meter must be used to determine the 

volume of fuel combusted; otherwise the reporter 

can estimate that volume using other methods. If 

a continuous gas analyzer is installed on the 

fuel stream, the composition reading must be 

used; otherwise another accepted method to 

estimate the composition may be used.

2O emissions from combustion equipment 

using emission factors and the fuel volume 

consumed. The high heat value of the fuel can be 

estimated using Table C-1 if possible. If the 

fuel is field gas, a default high heat value is 

provided. If another fuel, not covered by Table 

C-1 or field gas, is used; then the appropriate 

methodology from subpart C to estimate high heat 

value must be used.

Data Reporting Requirements. In addition to the 

information required to be reported by the General 

Provisions (40 CFR 98.3(c)), reporters must submit 
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additional data that are needed for EPA verification of the 

reported GHG emissions from petroleum and natural gas 

systems. The specific data to be reported are found in 40 

CFR part 98, subpart W. 

Recordkeeping. In addition to the records required by 

the General Provisions (40 CFR 98.3(g)), reporters must 

keep records of additional data used to calculate GHG 

emissions. These records are described in 40 CFR part 98, 

subpart W.

Definitions

We are also including two distinctive definitions of 

facility for onshore petroleum and natural gas production

and the natural gas distribution. Defining a facility in 

these cases is not as straightforward as other industry 

segments covered under Subpart W. For some segments of the 

. EPA added some definitions specific to 

subpart W to section 98.238 to avoid any confusion with the 

definitions found in 98.6. The subpart W specific 

definitions supersede any of the same definitions also 

found in subpart A.

We are including a definition of the term “Offshore” 

in §98.238 to fully identify those petroleum and natural 

gas production platforms, secondary platforms and 

associated storage tanks covered by this rule. 
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industry (e.g., onshore natural gas processing, natural gas 

transmission compression, and offshore petroleum and 

natural gas production) 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. However, in 

onshore petroleum and natural gas production and natural 

gas distribution such distinctions are more challenging. 

As explained in the April 2010 proposal, EPA evaluated 

existing definitions used under current regulations and

determined that it was necessary to define a unique 

facility for each of those two segments in order to ensure 

that the reporting delineation is clear, to avoid double 

counting, and ensure appropriate emissions coverage. For 

more information please see the preamble for the April 2010 

proposal and the Greenhouse Gas Emissions from Petroleum 

and Natural Gas Industry: Background Technical Support 

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

First, as proposed in April 2010, the definition of 

natural gas distribution facility for this subpart is the 

distribution pipelines, metering stations, and regulating 

stations that are operated by a Local Distribution Company 

(LDC) that is regulated as a separate operating company by 
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a public utility commission or that are operated as an 

independent municipally-owned distribution system. This 

facility definition provides clear reporting delineation 

because the equipment that they operate is clearly known, 

the ownership is clear to one company, and reporting at 

this level is consistent with 40 CFR Part 98 as well as 

other existing data reporting mechanisms. In this action, 

EPA is finalizing this definition for the natural gas 

distribution industry segment. This facility definition for 

natural gas distribution will result in 90% GHG emissions 

coverage of this industry segment. 

Second, as proposed in April 2010, the definition of 

an onshore petroleum and natural gas production facility 

for this subpart is all petroleum or natural gas equipment 

associated with all petroleum or natural gas production 

wells and CO2 EOR operations that are under common ownership 

or common control including leased, rented, and contracted 

activities by an onshore petroleum and natural gas 

production owner or operator and that are located in a 

single hydrocarbon basin as defined in §98.238. Where a 

person or entity owns or operates more than one well in a 

basin, then all onshore petroleum and natural gas 

production equipment associated with all wells that the 
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person or entity owns or operates in the basin would be 

considered one facility. In the April 2010 proposal, EPA 

evaluated at least two industry recognized definitions 

available that identify hydrocarbon basins: one from the 

United States Geological Survey (USGS) and the other from 

the American Association of Petroleum Geologists. Basins 

are mapped to county boundaries only to give a surface 

manifestation to the underground geologic boundaries. EPA 

decided to use the AAPG geologic definition of basin 

because it 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. In addition, the 

owner or operator of the wells within a basin would have 

access to the information related to the equipment on the 

permit. Hence, in this action, EPA is finalizing the 

facility definition at the basin level for the onshore 

petroleum and natural gas production industry segment 

because the operational boundaries and basin demarcations 

are clearly defined and are widely known, and reporting at 

this level would provide the necessary coverage of GHG 

emissions to inform policy. In addition, EPA has clarified 

its intent by stating that onshore petroleum and natural 

gas production equipment associated with all petroleum or 
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natural gas production wells and CO2 EOR operations include

any leased, rented or contracted activities by the owner or 

operator of those wells in that basin. This facility 

definition for onshore petroleum and natural gas production 

will result in 85% GHG emissions coverage of this industry 

segment.

E. Summary of Major Changes and Clarifications Since 

Proposal 

The major changes and clarifications in this rule 

since the April 2010 proposal are identified in the 

following list. For a full description of the rationale 

for these and any other significant changes to 40 CFR part 

98, subpart W, see the “Mandatory Greenhouse Gas Reporting 

Rule: EPA's Response to Public Comments, Subpart W: 

Petroleum and Natural Gas Systems.” The changes are 

categorized by the different sections of the subpart W 

regulatory text.

 EPA revised the definition for natural gas processing 

and onshore petroleum and natural gas production to 

exclude gathering lines and boosting stations from the 

source category.

Definition of the Source Category

 EPA clarified that meters and regulators in the 

natural gas distribution industry segment do not 

include customer meters. 

GHGs to Report. 
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 EPA removed the reporting requirements for produced 

water from coal bed methane(CBM) and enhanced oil 

recovery (EOR) operations.

Monitoring, QA/QC, and Calculating Emissions

 For industry segments where equipment leak detection 

is required (onshore natural gas processing, onshore 

natural gas transmission compression, underground 

natural gas storage, LNG storage and LNG import and 

export equipment, and natural gas distribution 

facilities) EPA is including the option to use Method 

21 methods and infrared laser beam illuminated 

instruments to detect leaks for sources that are 

accessible. Inaccessible equipment leaks and vented 

emissions are still required to be monitored using an 

optical leak imaging instrument. 

. 

 For applicable industry segments (onshore petroleum 

and natural gas production, onshore natural gas 

processing, onshore natural gas transmission 

compression, underground natural gas storage, and LNG 

storage and LNG import and export equipment), EPA 

clarified the monitoring and reporting requirements 

for centrifugal and reciprocating compressors. 

Reporters are required to conduct an annual 

measurement of each compressor in the mode in which it 

is found at the time of the annual measurement. 

However, based on commenter feedback, EPA requires 

reporters to conduct at least one measurement of each 

compressor in the not operating, depressurized mode 

during every three year period. Commenters suggested 

to EPA that based on their operational experience, 3 

years is an appropriate maximum time period at which 

compressors will be shutdown for routine maintenance, 

and for which operators would not need to shutdown 

compressors specifically for the purposes of 

monitoring. For more detail, please see EPA-HQ-OAR2009-0923-1011 excerpt 44. 

 EPA clarified reporting requirements and in some cases 

included alternative data collection methodologies for 

certain sources to balance burden with data quality 

and emissions coverage:

 For onshore petroleum and natural gas production, 

EPA is allowing the use of major equipment counts 

and default average counts for associated

components rather than all individual component 
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counts for equipment leak population factors for 

onshore petroleum and natural gas production. 

 For collecting gas composition data for produced 

natural gas, EPA is allowing reporters to use 

existing sampling data (e.g., composition 

analysis of gas sold) if reporters do not have a 

continuous gas composition analyzer already 

installed. 

 EPA is including emission factors for calculating 

GHG emissions from the following sources: vented 

GHG emissions from onshore petroleum and natural 

gas production tanks with less than 10 barrels 

per day separator and well production throughput; 

onshore production and natural gas processing 

dehydrators with less than 0.4 million standard 

cubic feet per day; vented GHG emissions from all 

onshore petroleum and natural gas production 

pneumatic devices and pneumatic pumps, and 

pneumatic devices in onshore natural gas 

transmission compression facilities and 

underground natural gas storage facilities.

 In all industry segments, for external fuel 

combustion emissions from portable and stationary 

equipment with heat input less than or equal to 5 

mmBtu/hr, only activity data must be reported.

 For reciprocating and centrifugal compressor 

measurement requirements, EPA clarified that the 

installation of permanent meters is an option but 

is not required; temporary meters are acceptable. 

 EPA is allowing Best Available Monitoring Methods for 

certain sources and time periods (for more detailed 

information, refer to section II F of this preamble).

 To assist reporters in determining applicability, EPA 

is planning to develop screening tools to assist 

reporters in threshold determination.

Applicability. 

This section contains a brief summary of major 

comments and responses. EPA received many comments on this 

F. Summary of Comments and Responses
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subpart covering numerous topics. EPA’s responses to all 

comments, including those below, can be found in the 

comment response document for petroleum and natural gas 

systems in “Mandatory Greenhouse Gas Reporting Rule: EPA’s 

Response to Public Comments, Subpart W: Petroleum and 

Natural Gas Systems.” Additional comments and responses 

related to cost issues on the proposed rule can be located 

in Section III.B.2 of the preamble.

Definition of the Source Category

Comment: Numerous commenters objected to the 

inclusion of gathering lines and booster stations in the 

natural gas processing plant definition. Commenters 

specifically stated that including gathering lines and 

booster stations would result in undue burden on reporters 

stemming from 1) the additional cost to include gathering

lines and boosting stations that typically are associated 

with a single gas processing plant and 2) the numerous 

complexities and variations of ownership that currently 

exist with gathering lines and boosting stations. One 

commenter further detailed that there are at least three 

different owner/operator variations that exist ranging from 

a scenario where a single company owns and/or operates the 

wells, gathering lines, and processing plant, to a scenario 

where a single company owns the wells, a second distinct 
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company (or multiple companies) own the gathering lines, 

and a third distinct company may own the processing plant. 

The commenter further explained that these scenarios are 

further complicated because the variations fluctuate daily 

due to the need to balance production demands for natural 

gas against the capacity of the gathering lines and the 

natural gas processing plant. 

Finally, a number of commenters requested that the 

gathering lines and boosting stations be excluded from the 

natural gas processing plant definition or be defined as a 

separate industry segment. 

Response: EPA has decided not to include gathering 

lines and boosting stations as an emissions source in 

subpart W at this time. The primary reason for excluding

gathering lines and boosting stations at this time is that 

emissions coverage from gathering lines and boosting 

stations within the natural gas processing industry segment

requires further analysis to ensure an effective coverage 

of emissions from this source in order to appropriately 

inform future policy decisions. As a result, EPA is 

continuing to review the comments received and the analysis 

described above, and is considering the most appropriate 

mechanism for future actions to ensure the collection of 
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appropriate data on gathering lines and boosting stations 

while minimizing industry burden. 

Comment: Several commenters stated that meters and 

regulators (M&R) were not clearly defined and could result 

in the inclusion of customer meters in the reporting 

requirements for the natural gas distribution industry 

segment. 

Response: EPA did not intend to require reporting of 

GHG emissions from customer meters in subpart W. In this

final action, EPA has clarified its intent to not require 

reporting of GHG emissions from customer meters. The 

definition of the natural gas distribution industry segment 

and the listing of GHGs to report under this industry 

segment have been refined to make clear what emissions are 

to be reported for this industry segment. 

GHGs to Report

Comment: Numerous commenters argued against the 

reporting of emissions, specifically combustion emissions, 

from portable equipment for the onshore petroleum and 

natural gas industry segment. Commenters noted that 

tracking emissions from portable non-self propelled 

equipment would result in heavy burden due to the fact that 

the majority of portable equipment are operated by an 

entity that is separate from the owner. Further, 
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commenters stated that the reporting of emissions from 

portable equipment will only marginally increasing coverage 

of the proposed rule. Some commenters argued that subpart 

C excludes portable equipment from combustion emissions 

reporting, and questioned why it was required for subpart 

W. 

Response

In order to manage the burden, the emissions 

estimation methods for portable equipment require the use 

of existing data, for the most part. Moreover, the 

allowance of Best Available Monitoring Methods (described 

later in this preamble) would provide reporters additional 

time to modify contractual arrangements with service 

providers. The decision to retain the reporting 

requirements for portable equipment GHG emissions was based 

on EPA’s analysis of the contribution to GHG emissions, 

both combustion and process, from portable equipment in 

onshore production. It is estimated that portable non 

: EPA disagrees with commenters and has 

finalized the reporting requirements for GHG emissions from 

portable non-self propelled equipment in subpart W, 

including emissions from drilling rigs, dehydrators, 

compressors, electrical generators, steam boilers, and 

heaters with external combustion heat duty above five 

mmBtu/hour. 
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self-propelled equipment is responsible for over 45 percent

of total emissions from onshore petroleum and natural gas 

production (Please see Docket EPA-HQ-OAR-2009-0923 for the 

complete analysis). While EPA is not excluding portable 

equipment, for certain emissions sources, EPA agrees with 

comments that alternative methodologies are appropriate and 

viable for collecting these data. EPA has conducted an 

extensive review of the emissions contribution relative to 

reporting burden and is modifying the final rule to exempt

external combustion equipment that fall below a minimum 

heat input of 5 mmBtu/hr. (Please see Docket EPA-HQ-OAR2009-0923 for a full report of the analysis). Equipment 

that fall below the specified mmBtu level would not have to 

conduct monitoring for combustion emissions, and would only 

be required to report activity data. 

Monitoring, QA/QC, and Calculating Emissions

Comment: EPA received numerous comments on the use of 

the optical gas imaging instrument for detecting GHG 

emissions from equipment leaks. Several commenters 

expressed support for the use of optical gas imaging 

instruments prescribed in the rule, stating that using this 

equipment would result in cost savings to industry as it 

would reduce burden and time by quick survey of all 

emissions sources at one time. In addition, several 
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commenters specifically requested that EPA also allow the 

use of organic vapor analyzers (OVA), toxic vapor analyzers 

(TVA) and infrared laser beam illuminated instruments as 

alternative technologies to the optical gas imaging 

instruments proposed for emissions detection. 

Response: EPA has evaluated alternative methods for 

detection of equipment leaks for their viability and 

comparative accuracy to the optical gas imaging instrument 

in the proposed rule. We agreed with commenters and have 

modified the final rule to include the options to use 

OVA/TVA devices or infrared laser beam illuminated 

instruments for leak detection for all emissions sources 

across all industry segments with the exception of 

inaccessible sources. We are still requiring that

inaccessible sources use optical gas imaging instruments 

due to potential safety and cost concerns related to leak 

detection of sources that cannot be physically accessed

from a fixed, supportive surface with a hand held leak 

detection device such as OVA/TVA, or which do not have a 

reflective background for an IR laser detection device. 

While EPA has determined that the methodologies in this 

rule are viable and appropriate for collecting this type of 

GHG data, EPA will continue to evaluate other potential 
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methods for detecting methane emissions in the petroleum 

and natural gas sector3. 

Comment: Numerous commenters disagreed with EPA’s

assessment of the feasibility of conducting one measurement 

for each reciprocating or centrifugal compressor in each of 

the operational modes (operating, standby depressurized, 

not operating/pressurized) that would occur during a 

calendar year. Commenters specifically stated that common 

industry practice is to have a compressor in operating mode 

for several years before it is taken offline for routine 

maintenance and servicing, thereby taking a compressor 

offline for the sole purpose of measurement as prescribed 

in the rule would result in undue burden to the industry 

and result in additional GHG emissions. 

Response

 

3 While this activity is in a nascent stage, EPA is conducting ongoing 

research on experimental mobile monitoring methods to locate and 

quantify equipment leak emissions from petroleum and natural gas 

fields. In addition to increasing our knowledge about emissions from 

equipment leaks from petroleum and natural gas fields, if this proves 

to be a robust method, it could be one viable alternative for measuring 

emissions and EPA would consider a rulemaking to add it as an 

acceptable method to this subpart.

: EPA did not intend for compressors to be 

taken offline in order for reporters to collect the data 

required under subpart W and has clarified the final rule 

to allow reporters to conduct an annual measurement of each 

compressor in the mode as it exists at the time the annual 

measurement is taken. EPA requires the development of 
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emission factors from these measurements that reporters 

must apply appropriately to all compressors for the total 

time each compressor is operated in each mode. However, 

EPA requires that each compressor must be measured at least 

once during every three year period in the “not operating 

and depressurized” mode without blind flanges in place. 

Blind flanges are flat plates inserted between flanges on a 

valve or piping connection to assure absolute isolation of 

the equipment from process fluids, and hence, compromise 

through valve leakage measurement. Isolation valve leakage 

through the compressor blowdown vent must be measured 

before blind flanges are installed. 

Commenters suggested to EPA that based on their 

operational experience, 3 years is an appropriate maximum 

operational time period during which compressors will be 

shutdown for maintenance at least once, and therefore 

operators would not need to shutdown compressors 

specifically for the purposes of monitoring. Accordingly, 

EPA is requiring reporters to schedule the measurement of 

compressors in the not operating and depressurized mode at 

any one time during a consecutive three year time period. 

Comment: EPA received a broad range of comments that

the methodologies for calculating GHG emissions in subpart 

W for specific emissions sources were too burdensome. Some 
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commenters stated that quarterly sampling of produced 

natural gas to determine gas composition was overly 

burdensome and not necessary since produced gas composition 

does not change significantly from one quarter to the next. 

Other commenters suggested that requiring component counts 

for calculating equipment leaks for the onshore petroleum 

and natural gas industry segment was too onerous and time 

intensive since a reporter may have hundreds of wells 

across a large geographical area, and they currently do not 

have an inventory of all the components, such as valves, 

connectors and flanges, associated with their equipment. 

Several commenters stated that the number of tanks and 

dehydrators in the onshore petroleum and natural gas 

industry segment would be very burdensome to estimate 

emissions from using engineering equations. For example 

each tank would be required to obtain a sample analysis of 

low pressure separator oil for doing the engineering 

calculations. Finally, several commenters stated that the 

number of pneumatic devices and pneumatic pumps would 

require extensive time to determine the manufacturer model 

of each device in their facilities, and then estimate 

emissions based on manufacturer data.

Lastly, commenters noted that compressor emissions 

measurement and compressor throughput flow was too 
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burdensome, since many compressors would require the 

installation of expensive permanent meters. 

Response:

 Individual component counts and population based 

emissions factors for onshore petroleum and natural 

gas production have been replaced with major equipment 

counts and default average component counts per 

primary equipment. Identification of primary 

equipment (dehydrators, compressors, heaters, etc.) 

will result in significantly less burden to reporters 

than counting each component (valve, flange, openended line, etc.).

EPA considered all of these comments, and 

performed extensive evaluation of the methodologies for 

calculating GHG emissions for each emissions source under 

each industry segment. EPA compared alternative 

methodologies that, when performed, would result in reduced 

burden on industry while maintaining the necessary quality 

of data to inform policy. (Please see Docket EPA-HQ-OAR2009-0923 for a full report of the analysis).

Specifically, certain methodologies for specific emissions 

sources allowed for alternative methods that would reduce 

burden and maintain data quality. As a result, EPA 

determined that the following rule modifications would 

reduce burden while sustaining the necessary quality of 

data:

 Quarterly sampling of gas composition has been 

replaced by an annual sampling. Most producers would 

have this information already for transaction 

processing.
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 For onshore petroleum and natural gas production, for 

separators and well production with less than 10 

barrels per day throughput and glycol dehydrators with 

less than 0.4 million standard cubic feet per day 

throughput, reporters will use emissions factors to 

determine emissions. Blowdown emissions from 

equipment vessel chambers totaling less than 5000 

cubic feet are not required to be reported. For more 

information, please see “Equipment Threshold for 

Tanks,” “Equipment Threshold for Dehydrators,” and 

“Equipment Threshold for Blowdowns” under EPA-HQ-OAR2009-0923. 

 For all pneumatic devices and pneumatic pumps in 

onshore petroleum and natural gas production and all 

pneumatic devices in onshore natural gas transmission 

compression facilities and underground natural gas 

storage facilities, reporters will utilize population 

emissions factors instead of engineering estimates.

 The final rule has clarified that emissions from 

centrifugal and reciprocating compressors do not 

require the installation of a permanent flow meter; 

use of a portable meter and port are acceptable. In 

addition, compressor throughput flow meters are not 

required; estimates of compressor flow will be 

sufficient for EPA’s requirements.

Data Reporting Requirements 

Comment: Numerous commenters stated that there would 

be insufficient time, leak detection and measurement 

equipment, or service providers available to fully comply 

with subpart W reporting requirements. In particular, 

numerous onshore petroleum and natural gas production 

commenters expressed concern with the ability to gather 

data from geographically dispersed emissions sources 

starting January 1, 2011. Also numerous commenters from 

the natural gas processing and natural gas transmission 

industry segments expressed their concern with their 
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ability to comply with monitoring requirements, such as 

installing necessary measurement ports or meters for 

measurement. 

Response

Best available monitoring methods are available for

three specific instances as well as providing a catch-all 

provision in the case of unanticipated issues or 

circumstances. In each category EPA determined the 

affected sources, reporting requirements and the time 

period necessary for owners or operators to implement the 

requirements of the rule. In all cases, the owner or 

operator must use the equations and methods set forth in 

: As described below, EPA determined that for 

specified emissions sources for certain industry segments, 

some reporters may need more time to comply with the 

monitoring and QA/QC requirements of this subpart by 

January 1, 2011. EPA carefully considered each source and 

the reporting compliance requirements and determined for 

which monitoring requirements it is appropriate to allow 

the use of best available monitoring methods, for how long 

the use of best available monitoring methods will be 

applicable, and under what circumstances these methods are 

reasonable. EPA has extensively detailed when and how 

reporters may use best available monitoring methods below

and in §98.234(f) of the rule. 
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§98.233, but may use best available monitoring methods to 

estimate the parameters in the equations as specified in 

the sections below.

EPA also carefully considered the timing for allowing 

application of best available monitoring methods. EPA 

determined the time duration for specified sources for 

which reporting entities may apply best available 

monitoring methods without a petition, and those for which 

reporting entities must request the use of best available 

monitoring methods. Based on EPA’s experience in 

implementing the 2009 final rule and those BAMM provisions, 

EPA made the source specific determinations for subpart W 

as outlined below. 

Well-related Emissions Reporting. Subpart W requires the 

monitoring of well-related emissions sources for which the 

owner or operator must collect data during the actual event 

(for example, a well completion or workover conducted on a 

specific day in January 2011) and for which it may not be 

possible to collect or reproduce data after the event is 

over. EPA recognizes that in these cases, owners or 

operators may need to coordinate and possibly modify 

contracts, leases or other arrangements with service 

providers in order to gather data and thus it may not be 

possible for owners or operators to begin gathering well-
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related emissions data as of January 1, 2011. For these 

sources EPA will allow the use of best available monitoring 

methods through June 30, 2010 to allow reporters sufficient 

time to meet the requirements of the rule.

 Elligible Sources. There are three well-related 

sources for which subpart W requires emissions data 

collection at the time of the emissions event rather 

than at the reporter’s discretion during a calendar 

year and for which use of best available monitoring 

methods will be allowed. These sources are as 

follows: 

 Gas well workovers using hydraulic fracture in 

paragraph §98.233 (g)

 Gas well completions using hydraulic fracture in 

paragraph §98.233 (g)

 Well testing/flaring in paragraph §98.233 (l)

As a significant portion of well drilling activities 

are conducted by third-party service providers, it may take 

owners or operators additional time to finalize 

arrangements with their service providers or modify 

existing contracts, leases or other arrangements such that 

said service providers will provide data to owners or 

operators. Based on this, EPA concluded that it may not be 

possible for some owners or operators to begin gathering 

well-related emissions data as of January 1, 2011. 

 Reporting Requirements. For the sources listed above, 

an owner or operator must use the equations prescribed 

in §98.233(g) and §98.233(l) but may use best 

available monitoring methods to estimate any of the 

parameters. Best available monitoring methods may be:
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 Monitoring methods currently used by the facility 

that do not meet the specifications of this 

subpart. 

 Supplier data.

 Engineering calculations. 

 Other owner or operator records.

 Authorization to Use Best Available Monitoring 

Methods. All owners or operators may use best 

available monitoring methods for these sources between 

January 1, 2011 and June 30, 2011. Owners or 

operators do not have to submit a request to EPA for 

the initial six months. Owners or operators will have 

between the time this rule is signed by the 

Administrator until June 30, 2011 to make any 

necessary arrangements with service providers and 

other relevant organizations in order for the owner or 

operator to gather all necessary data to comply with 

subpart W. As this is approximately eight months 

time, starting July 1, 2011, EPA expects that owners 

or operators will have made arrangements or modified 

contracts with service providers, such as drilling 

companies, as necessary to comply fully with subpart W 

for these sources.

 Requests for Extension in 2011. If additional time is 

necessary beyond June 30, 2011, an owner or operator 

must request an extension for use of best available 

monitoring methods by February 28, 2011. EPA will not 

consider a company-wide or basin-wide extension of 

best available monitoring methods for an owner or 

operator’s emissions reporting requirements for 

§98.233(g) and §98.233(l). In order to receive an 

extension for a time period between July 1, 2011 and 

December 31, 2011, owners and operators must provide 

the following information for each source covered 

under §98.232 (c)(6), §98.232 (c)(8), and §98.232 

(c)(12):

 A list of the specific emissions sources within 

the owner or operator’s facility for which the 

owner or operator is requesting an extension of 

best available monitoring methods.

 A description of the specific requirements in 

§98.233(g) and §98.233(l) which the owner or 

operator cannot meet in 2011, including a 

detailed explanation as to why the requirements 

can not be met. 
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 Supporting documentation such as the date of and 

copies of correspondence to service providers or 

other relevant entities whereby the owner or 

operator clearly requests that said service 

providers or other relevant entities provide 

required data. 

 Correspondence from specific service providers or 

other relevant entities to the owner or operator, 

whereby the service provider states that it is 

unable to provide the necessary data or services 

requested by the owner or operator that would 

enable the owner or operator to comply with 

subpart W reporting requirements. EPA will not 

consider a request for extension of best 

available monitoring methods if the service 

provider requests a contract modification to 

collect this data and the owner or operator 

refuses to do so. 

 A detailed explanation and supporting 

documentation of how and when the owner or 

operator will receive the required data and/or 

services to comply with subpart W reporting 

requirements.

The Administrator reserves the right to require additional 

documentation.

EPA does not anticipate extending the use of best 

available monitoring methods beyond 2011 as approximately

fourteen months will have passed since the Administrator’s 

signature; however, under extreme and unique circumstances, 

which include safety, a requirement being technically 

infeasible or counter to other local, State or Federal 

regulations, EPA may consider granting a further extension. 

Any such request must be received by June 30, 2011. The 

owner or operator must provide the following information in 

a request for the use of best available monitoring methods 
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beyond 2011 for sources covered under §98.232 (c)(6), 

§98.232 (c)(8), and §98.232 (c)(12) for beyond 2011: 

 A list of the specific emissions sources within 

the owner or operator’s facility for which the 

owner or operator is requesting an extension of 

best available monitoring methods.

 A description of the specific requirements in 

§98.233(g) and §98.233(l) which the owner or 

operator cannot meet, including a detailed 

explanation as to why the requirements cannot be 

met. 

 Detailed outline of the unique circumstances 

necessitating an extension, including specific 

data collection issues that do not meet safety 

regulations, technical infeasibility or specific 

laws or regulations that conflict with data 

collection for §98.232 (c)(6), §98.232 (c)(8), 

and §98.232 (c)(12). The owner or operator must 

consider all data collection options as outlined 

in the rule for a specific emissions source 

before claiming that a specific safety, technical 

or legal barrier exists. For example, if 

measuring an open-ended line on a rooftop does 

not meet safety regulations, companies must 

consider the use of portable meters using a port 

at ground-level. 

 A detailed explanation and supporting 

documentation of how and when the owner or 

operator will receive the required data and/or 

services to comply with subpart W reporting 

requirements in the future. 

The Administrator reserves the right to require additional 

documentation.

It is the responsibility of the owner or operator to meet 

the reporting requirements of this rule. Accordingly, it 

is up to the owner or operator to best determine how they 

can obtain the necessary data to timely and fully comply. 

Stipulated Activity Data Collection. Several sources 

require the collection of activity data such as cumulative 
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run time or a cumulative throughput volume to a piece of 

equipment starting January 1, 2011. Based on industry 

comments, EPA recognizes that it may not be feasible for an 

owner or operator to gather these data across all of their 

facilities as data collection in some cases must begin on 

January 1, 2011. EPA has decided to allow reporters to use 

best available monitoring methods to estimate specific 

activity parameters used in the equations and methods 

outlined in §98.233 for the first six months of 2011. EPA 

will allow the use of best available monitoring methods for 

emissions sources for which the owner or operator must 

collect activity data sometime between January 1, 2011 and 

June 30, 2011 and the owner or operator can not reproduce 

or replicate after this time period. As owners or 

operators will have approximately eight months from the 

time of Administrator signature to June 30, 2011 to develop 

systems to collect these data, EPA does not anticipate 

approving best available monitoring methods for collecting 

activity data after June 30, 2011.

 Eligible Sources. Owners and operators may use best 

available monitoring methods only for the sources 

listed below:

 Cumulative hours of venting, days, or times of 

operation in paragraphs §98.233(e), §98.233(f), 

§98.233(g), §98.233(h), §98.233(l), §98.233(o), 

§98.233(p), §98.233(q), and §98.233(r).
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 Number of blowdowns, completions, workovers, or 

other events §98.233(f), §98.233(g), §98.233(h), 

§98.233(i), and §98.233(w).

 Cumulative volume produced, volume input or 

output, or volume of fuel used in paragraphs 

§98.233(d), (e), (j), (k), (l), (m), (n), (x), 

(y), and (z).

Reporting Requirements. For the parameters listed 

above, owners and operators must use the 

equations prescribed in §98.233 but may use best 

available monitoring methods to estimate the 

stipulated activity parameters. Best available 

monitoring methods are:

 Monitoring methods currently used by the facility 

that do not meet the specifications of this 

subpart. 

 Supplier data.

 Engineering calculations.

 Other owner or operator records.

 Authorization to Use Best Available Monitoring 

Methods. All owners and operators may use best 

available monitoring methods for the parameters listed 

above between January 1, 2011 and June 30, 2011. 

Owners or operators do not have to submit a request to 

EPA for the initial six months. As owners and 

operators will have approximately eight months from 

Administrator signature to June 30, 2011, to prepare 

for the data collection requirements for the above 

sources, EPA expects that all owners or operators 

should have had adequate time to comply with the data 

collection requirements outlined in this subpart and 

therefore not need the use of best available 

monitoring methods after June 30, 2011. 

 Requests for Extension in 2011. Only under extreme 

circumstances, which include safety, a requirement 

being technically infeasible or counter to other 

local, State or Federal regulations, will EPA consider 

extending the use of best available monitoring methods 

for the collection of activity data through the end of 

2011.

Owners or operators may submit a request for an 

extension through the end of 2011. These requests 
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must be received by February 28, 2011 and include the 

following:

 A list of specific source categories and 

parameters for which the owner or operator is 

seeking use of best available monitoring methods.

 A description of the specific requirements in 

§98.233(e), §98.233(f), §98.233(g), §98.233(h), 

§98.233(i), §98.233(j), §98.233(k), §98.233(l), 

§98.233(m), §98.233(n), §98.233(o), §98.233(p), 

§98.233(q), §98.233(r), §98.233(w), §98.233(x), 

§98.233(y), and §98.233(z) which the owner or 

operator cannot meet, including a detailed 

explanation as to why the requirements can not be 

met.

 Detailed outline of the unique circumstances 

necessitating an extension, including data 

collection methods that do not meet safety 

regulations, technical infeasibility or specific 

laws or regulations that conflict with the 

specific sources in this section. The owner or 

operator must consider all data collection 

options as outlined in the rule for a specific 

emissions source before claiming that a specific 

safety, technical or legal barrier exists. 

 A detailed explanation and supporting 

documentation of how and when the owner or 

operator will receive, for example, the services 

or equipment to comply with subpart W reporting 

requirements.

The Administrator reserves the right to require additional 

documentation.

 Requests for Extension beyond 2011. As approximately

fourteen months will have passed between the 

Administrator’s signature and December 31, 2011, EPA 

does not anticipate approving requests for best 

available monitoring methods beyond 2011 for the 

sources listed above; however, under extreme and 

unique circumstances, which include safety, a 

requirement being technically infeasible or counter to 

other local, State or Federal regulations, it may 

consider granting a further extension. Any such 

requests for extensions beyond 2011 must be received 

by June 30, 2011 and include the following: 
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 A list of specific source categories and 

parameters for which the owner or operator is 

seeking use of best available monitoring methods.

 A description of the specific requirements in 

§98.233(e), §98.233(f), §98.233(g), §98.233(h), 

§98.233(i), §98.233(j), §98.233(k), §98.233(l), 

§98.233(m), §98.233(n), §98.233(o), §98.233(p), 

§98.233(q), §98.233(r), §98.233(w), §98.233(x), 

§98.233(y), and §98.233(z) which the owner or 

operator cannot meet, including a detailed 

explanation as to why the requirements can not be 

met.

 Detailed outline of the unique circumstances 

necessitating an extension, including data 

collection methodologies that do not meet safety 

regulations, technical infeasibility or specific 

laws or regulations that conflict with sources 

outlined in this section. The owner or operator 

must consider all data collection options as 

outlined in the rule for a specific emissions 

source before claiming that a specific safety, 

technical or legal barrier exists. 

 A detailed explanation and supporting 

documentation of how and when the owner or 

operator will receive, for example, the services 

or equipment to comply with subpart W reporting 

requirements.

The Administrator reserves the right to require additional 

documentation.

Acquisition and implementation of leak detection and 

monitoring equipment or services. Based on industry 

comments, EPA understands that it may not be feasible for 

all owners or operators to acquire required leak detection 

and/or measurement equipment or hire a service provider in 

time to conduct the activities necessary to complete leak 

detection and measurement requirements under subpart W 

within the 2011 calendar year. EPA will consider the use 
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of best available monitoring methods for sources requiring 

leak detection and/or measurement based on evidence 

provided by the owners or operators demonstrating that they 

have made all efforts but cannot obtain the necessary 

equipment or services in time to complete subpart W 

reporting in 2011.

 Eligible Sources. With application approval from the 

Administrator, owners and operators may use best 

available monitoring methods only for the sources 

listed below:

 Reciprocating compressor rod packing vents for 

facilities downstream of onshore petroleum and 

natural gas production (i.e., natural gas 

processing, natural gas transmission compression, 

underground natural gas storage, LNG storage, and 

LNG import and export equipment) in paragraph 

§98.233(p).

 Centrifugal compressor wet seal oil degassing 

venting for facilities downstream of petroleum 

and natural gas production in paragraph 

§98.233(o).

 Acid gas removal vents in paragraph §98.233(d)

 Equipment leaks in facilities downstream of 

onshore petroleum and natural gas production in 

paragraph §98.233(q).

 Transmission storage tanks in paragraph 

§98.233(k).

 Reporting Requirements. For the sources listed above, 

if approved by the Administrator, the owner or 

operator may use best available monitoring methods to 

estimate emissions and/or the number of leaking 

components, and any throughputs, volumes, or owner or 

operator maintenance records in place of the required 

monitoring methods outlined for parameters in §98.233. 

These best available monitoring methods are:
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 Monitoring methods currently used by the facility 

that do not meet the specifications of this 

subpart. 

 Supplier data.

 Engineering calculations. 

 Other owner or operator records.

 Authorization to Use Best Available Monitoring 

Methods. Because leak detection and/or measurement 

surveys are one-time actions that can be conducted at 

any time during the year, by February 28, 2011, 

reporters must submit an application seeking approval 

for the use of best available monitoring methods. 

Upon approval by the Administrator, EPA may allow the 

use of best available monitoring methods for up to the 

entire 2011 calendar year. An owner or operator must 

submit this request no later than February 28, 2011 

and include, at a minimum:

 A list of specific source categories and 

parameters for which the owner or operator is 

seeking use of best available monitoring methods.

 A description of the specific requirements in 

§98.233(d), §98.233(k), §98.233(o), §98.233(p), 

and §98.233(q) which the owner or operator cannot 

meet and an explanation of how the owner or 

operator has diligently tried and why it cannot 

meet the requirements.

 Certification that the owner or operator does not 

already own relevant detection or measurement 

equipment.

 Documentation that at least four service 

providers that provide leak detection and 

measurement services relevant to subpart W will 

not supply their service to the owner or operator 

in time to meet subpart W reporting requirements 

for 2011. The documentation must demonstrate 

that the owner or operator made all reasonable 

efforts to obtain the service necessary to comply 

with subpart W reporting requirements in 2011. 

EPA recognizes that some owners or operators may 

choose to conduct their own leak detection and 

measurement activities and therefore purchase 

equipment for that purpose. It is the owner or 

operator’s responsibility to purchase all 
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necessary equipment in time to meet 2011 

reporting requirements. If relevant equipment 

vendors can not deliver hardware in time for an 

owner or operator to meet subpart W requirements, 

the owner or operator must attempt to use outside 

service providers, as stipulated above, prior to 

seeking a request for best available monitoring 

methodology extension. 

 A detailed explanation and supporting 

documentation of how and when the owner or 

operator will receive the services or equipment 

to comply with subpart W reporting requirements

in 2012.

The Administrator reserves the right to require additional 

documentation.

 Requests for Extension. As owners and operators will 

have had approximately fourteen months since the date 

of the Administrator’s signature and December 31, 

2011, EPA does not anticipate extending best available 

monitoring methods beyond 2011; however, under extreme 

and unique circumstances, which include safety, a 

requirement being technically infeasible or counter to 

other local, State or Federal regulations, EPA may 

consider granting a further extension. Any such 

request for extensions beyond 2011 must be received by 

June 30, 2011 and include the following: 

 A list of specific source categories and 

parameters for which the owner or operator is 

seeking use of best available monitoring methods.

 A description of the specific requirements in 

§98.233(d), §98.233(k), §98.233(o), §98.233(p), 

and §98.233(q) of the unique circumstances 

necessitating an extension, including specific 

data collection methodologies that do not meet 

safety regulations, technical infeasibility or 

specific laws or regulations that conflict with 

sources outlined in this section. The owner or 

operator must consider all data collection 

options as outlined in the rule for a specific 

emissions source before claiming that a specific 

safety, technical or legal barrier exists. 

 Detailed explanation and supporting documentation 

of how and when the owner or operator will 
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receive the services or equipment to comply with 

subpart W reporting requirements.

The Administrator reserves the right to require additional 

documentation.

Other Sources

 Requests for 2011: Emissions sources not covered 

above are under operational control of the owner or 

operator, require one time data collection at any 

point during the calendar year and do not require leak 

detection or measurement equipment. For these 

reasons, for the sources not covered above, EPA does 

not anticipate the need for best available monitoring 

methods; however, EPA reserves the right to review 

such requests submitted by February 28, 2011 and 

consider approval of the use of best available 

monitoring methods for 2011 under unique and extreme 

circumstances which include safety, a requirement 

being technically infeasible or counter to other 

local, State or Federal regulations. Requests for the 

use of best available monitoring methods for sources 

not covered above must include:

 A list of specific source categories and 

parameters for which the owner or operator is 

seeking use of best available monitoring methods.

 Detailed outline of the unique circumstances 

necessitating an extension, which must include 

data collection methodologies that do not meet 

safety regulations, technical infeasibility or 

specific laws or regulations that conflict with 

specific sources for which owners or operators 

are requesting best available monitoring methods. 

The owner or operator must consider all data 

collection options as outlined in the rule for a 

specific emissions source before claiming that a 

specific safety, technical or legal barrier 

exists. 

 A detailed explanation and supporting 

documentation of how and when the owner or 

operator will receive the services or equipment 

to comply with subpart W reporting requirements 

in 2012. 
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The Administrator reserves the right to require additional 

documentation.

 Requests beyond 2011: For sources not covered above, 

EPA does not anticipate the need for best available 

monitoring methods beyond 2011; however, EPA reserves 

the right to review such requests submitted by June 

30, 2011 and consider approval of the use of best 

available monitoring methods for 2012 under unique and 

extreme circumstances which include safety, a 

requirement being technically infeasible or counter to 

other local, State or Federal regulations. Requests 

for the use of best available monitoring methods for 

sources not covered above must include:

 A list of specific source categories and 

parameters for which the owner or operator is 

seeking use of best available monitoring methods.

 Detailed outline of the unique circumstances 

necessitating an extension, which must include 

data collection methodologies that do not meet 

safety regulations, technical infeasibility or 

specific laws or regulations that conflict with 

specific sources for which owners or operators 

are requesting best available monitoring methods. 

The owner or operator must consider all data 

collection options as outlined in the rule for a 

specific emissions source before claiming that a 

specific safety, technical or legal barrier 

exists. 

 A detailed explanation and supporting 

documentation of how and when the owner or 

operator will receive the services or equipment 

to comply with subpart W reporting requirements. 

The Administrator reserves the right to require additional 

documentation.

5. Legal Authority

Comment: Several commenters asserted that EPA is 

over-reaching its CAA 114 authority. These commenters 

specifically stated that CAA 114 does not authorize EPA to 
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require indefinite and sweeping monitoring, recordkeeping, 

and reporting from the facilities covered by proposed 

Subpart W. On the other hand, several commenters asserted 

that the proposal was within EPA’s authority under the CAA. 

Response: As explained in section I. C. of this 

preamble, section I. C and Q of the 2009 final rule 

preamble (74 FR 56260), and the Mandatory Greenhouse Gas 

Reporting Rule: EPA’s Response to Public Comments, Volume 

9, Legal Issues (EPA-HQ-OAR-2008-0508), EPA is promulgating 

this rule under its existing CAA authority provided in CAA 

section 114. EPA disagrees with the commenters that it 

does not have statutory authority to require monitoring, 

reporting and recordkeeping from facilities in the 

petroleum and natural gas systems source category. The 

Administrator may gather information under CAA section 114, 

as long as that information is for purposes of carrying out 

any provision of the CAA. For example, section 103 of the 

CAA authorizes EPA to establish a national research and 

development program, including non-regulatory approaches 

and technologies, for the prevention and control of air 

pollution, including GHGs. The data collected under this 

rule will also inform EPA’s implementation of CAA section 

103(g) regarding improvement in sector based non-regulatory 

strategies and technologies for preventing or reducing air 
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pollutants. For more information about EPA’s legal 

authority please see the sections and documents noted 

above. 

Designated Representative

Comment: Several commenters stated that EPA lacked the 

authority to require facilities to collect data on 

equipment and activities that may be operated or provided 

by a third party service provider and then require a 

designated representative to certify those emissions data. 

Other commenters supported the inclusion of emissions data 

from equipment operated by third party service providers by 

stating that these emissions are critical to ensuring that 

facilities with different operational structures have 

equitable coverage in a reporting program and that a 

complete profile of emissions from the production sector is 

obtained.

Response: As explained in section V of the preamble of 

the 2009 final rule, all reporters must select a designated 

representative (DR) who is responsible for certifying, 

signing, and submitting all submissions to EPA. This 

provision provides flexibility to the owners and operators 

to choose any individual, employee or non-employee, to 

represent them, while ensuring EPA has one accountable 

point of contact. As explained in the final rule, the high 
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level of public interest in the data collected, as well as 

its importance to future policy, warrants establishment of 

a high standard for data quality and consistency and high 

level of accountability for reported data. The DR 

provisions and certification requirements help ensure the 

standard for high quality data and consistency is met. The 

DR provisions are crafted similarly to the provisions of 

the Acid Rain Program (ARP), 40 CFR Part 72 and EPA has 

found that this approach provides a high degree of both 

data quality and consistency and accountability. 

Similar comments were made about the data coming from 

multiple owners and operators and the concerns about the 

certification of those data upon promulgation of the ARP

and the 2009 final GHG reporting rule to which we 

responded, and which responses are summarized. We have 

attempted to provide maximum flexibility while ensuring 

accountability. For integrity of the program, one 

representative of the owners and operators must report for 

important reasons. Doing so ensures the accountability of 

owners or operators by, inter alia, reducing the likelihood

of inconsistent submissions by a facility. Interposing 

another person or party between the facility and the Agency 

would dilute the DR’s responsibility and in effect create 

multiple DRs for the facility. Additionally, leaving the 
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ultimate responsibility of submission with the designated 

representative has the salutary effect of clarifying that 

the DR should be aware of all submissions and should 

inquire of the persons with personal knowledge of the 

information in those submissions. The DR has the 

flexibility to delegate duties, such as the preparation of 

submissions, but retains the ultimate responsibility to 

sign and certify all submissions. See, 58 FR 3590, 3598 

(Jan. 11, 1993). Furthermore, while the DR or his 

delegatee may need to acquire necessary reporting 

information from a third party, the DR must make the 

appropriate inquiries and certification when reporting; 

ultimate responsibility rests and must necessarily rest on 

him or her. The DR may provide in contracts, leases, or 

other agreements with third parties that true, accurate, 

and correct reporting information must be provided to the 

DR in a timely fashion. If the third party fails to 

provide timely, true, accurate, or correct information to 

the DR , then the DR has recourse contractually, or 

otherwise, on the third party. Finally, in recognition of 

their potential need to adjust contracts, leases, or 

agreements accordingly, additional flexibility has been 

provided in the rule to allow facilities to utilize best 

available monitoring methods for a limited period. For 
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more information see section V of the 2009 final rule (74 

FR 56260) and the Mandatory Greenhouse Gas Reporting Rule: 

EPA’s Response to Public Comments, Volume 11, Designated 

Representative and Data Collection, Reporting, Management 

and Dissemination (EPA-HQ-OAR-2008-0508). 

Applicability

Comment: Multiple commenters requested that EPA 

develop a set of screening tools to assist in the 

determination of which entities would be required to report 

under subpart W of 40 CFR part 98. 

Response: Similar to what EPA has already provided

for other subparts of the Mandatory Reporting Program to 

help reporters assess their applicability to the GHG 

reporting program4

 

4 http://www.epa.gov/climatechange/emissions/GHG-calculator/index.html

, EPA plans to develop voluntary screening 

tools for each petroleum and natural gas industry segment. 

EPA anticipates that such tools would be based on easily 

determined inputs such as major equipment or operational 

counts. While the tools would be designed to provide help 

to potential reporters for complying with the rule, 

compliance with all Federal, State, and Local laws and 

regulations remain the sole responsibility of each facility 

owner or operator subject to those laws and regulations. 

The tools would be a guide to determine those facilities 
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that are clearly well below the reporting threshold, those 

clearly above, and those close to the threshold who will 

need to collect further data to make a proper 

determination. 

III. Economic Impacts of the Rule 

This section of the preamble summarizes the costs and 

economic impacts of the final rulemaking, including the 

estimated costs and benefits of the rule, and the estimated 

economic impacts on affected facilities, including 

estimated impacts on small entities. Complete details of 

the economic impacts of the final rule can be found in the 

Economic Impact Analysis (EIA) in the rulemaking docket 

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

This section also contains a brief summary of major 

comments and responses on the economic impacts of the rule. 

EPA received a number of comments on the estimated 

compliance costs as well as other comments covering a 

variety of topics. Responses to significant comments can 

be found in “Mandatory Greenhouse Gas Reporting Program: 

EPA’s Response to Public Comments, Cost and Economic 

Impacts of the Rule.” 

A. How were compliance costs estimated?

1. Summary of Method Used to Estimate Compliance Costs of 

the Final Rule
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EPA estimated costs for each affected petroleum and 

natural gas industry facility to comply with subpart W. 

These estimates capture the costs associated with 

monitoring and reporting both equipment leaks and vented 

emissions and incremental combustion-related emissions.5

Staff activities and associated labor costs may also 

vary over time. In particular, start-up activities, such 

as the installation of ports for compressors to allow for 

spot measurements, results in notably higher costs in the 

 

EPA based the estimates on the number of labor hours to 

perform specific activities, the cost of labor, and the 

cost of monitoring equipment.

The costs of complying with the rule will vary from 

one petroleum and gas industry segment and facility to 

another, depending on factors such as the types of 

emissions, the number of affected sources at the facility, 

existing maintenance practices, monitoring, recordkeeping, 

and reporting activities at the facility. The costs 

include expenditures related to monitoring, recording, and 

reporting process emissions and, as relevant, emissions 

from stationary combustion. 

 

5 Reporting entities that equal or exceed the Subpart W threshold for 

equipment leak and vented emissions must report combustion emissions 

under Subpart C, except for onshore production, which must report 

combustion emissions under Subpart W. Incremental combustion emissions 

refer to those from entities that did not trigger the Subpart C 

threshold in the absence of Subpart W. 
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first year. Costs would also vary over time when sitespecific emissions factors are developed every two or three 

years. Thus, EPA developed cost estimates for year one, 

which includes start-up and first-time reporting, and for 

subsequent year reporting.

EPA estimated annual costs in 2006 dollars using the 

2006 population of emitting sources. In addition, the 

agency estimated costs on a per entity basis and weighted 

them by the number of entities affected at the 25,000 

metric tons CO2

Next, 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 data that are already being collected 

e threshold. 

To develop compliance cost estimates, EPA gathered

existing data from EPA studies and publications, industry 

trade associations and publicly available data sources 

(e.g., labor rates from the Bureau of Labor Statistics) to 

characterize the processes, sources, segments, facilities, 

and companies/entities affected. EPA also considered cost 

data submitted in public comments on the proposed rule. 
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for reasons not associated with the rule (to allow only the 

incremental costs to be estimated). 

Labor Costs

 Developing a plan: reporting entity management, legal, 

and technical staff hours to determine applicability 

to the rule, organize training on rule requirements, 

identify staffing assignments, train staff, schedule 

activities as required below.

. The costs of complying with and 

administering this rule include time of managers, 

technical, operational and administrative staff in the 

private sector. Staff hours were estimated for activities, 

including:

 Setting up records: technical and field staff hours to 

develop data collection sheets and analytical model 

equations or linkages to input data into software 

programs.

 Collecting field data: technical and field staff hours 

to collect necessary site-specific data and input that 

data into the analytical input tables.

 Monitoring: staff hours to procure, install, operate 

and maintain emissions monitoring equipment, 

instruments and engineering analysis systems.

 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.

 Recordkeeping: 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.

 Reporting: management and staff hours to organize 

data, perform quality assurance/quality control, 

inform key management personnel, and report it to EPA 

through electronic systems.
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Estimates of labor hours were based on economic 

analyses 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. See the Economic Impact 

Analysis for the Mandatory Reporting of Greenhouse Gas 

Emissions under subpart W Final Rule (EPA-HQ-OAR-2009-0923) 

for a detailed discussion about the engineering analysis 

used to develop these estimates. In addition, the 

Greenhouse Gas Emissions from the Petroleum and Natural Gas 

Industry: Background TSD (EPA-HQ-OAR-2009-0923-0027) 

provides a discussion of the applicable engineering 

estimating and measurement technologies and any existing 

programs and practices.

EPA monetized the labor hours using wage rates from 

the Bureau of Labor Statistics (BLS). The agency also 

adjusted the wage rates to account for overhead. 

Equipment Costs. Equipment costs include both the 

initial purchase price of monitoring equipment and 

installation cost. 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 
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vent is inaccessible. Based on expert judgment, the 

engineering cost 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 5-year cost recovery period at a rate of 

seven percent. Not all segments require monitoring 

equipment capital expenditures but those that do are 

clearly documented in the Economic Impact Analysis.

Incremental Combustion Costs.

The costs to monitor and report incremental 

combustion-related emissions were estimated based on the 

approach used under 40 CFR Part 98, Subpart C.

 EPA estimated the costs 

to monitor and report incremental combustion emissions, 

which are combustion-related emissions from entities that 

did not trigger the Subpart C threshold in the absence of 

Subpart W. As discussed above, reporting entities that 

equal or exceed the Subpart W threshold must report 

combustion emissions following the methods under Subpart C, 

except for onshore production, which must report combustion 

emissions following the methods under Subpart W.

6

 

6 40 CFR Part 98 uses the IPCC Tier concept to estimate combustions emissions 

(74 FR 56260, October 30, 2009). See EPA-HQ-OAR-2008-0508-0004, U.S. EPA, 

Technical Support Document for Stationary Fuel Combustion Emissions: Proposed 

Rule for Mandatory Reporting of Greenhouse Gases, January 30, 2009, for more 

information about the IPCC Tier methodology (pgs 10-15).

 
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Specifically, EPA applied the Tier 1 methodology to 

estimate the costs to monitor combustion emissions that 

became subject to reporting as a result of this final 

action. The Tier 1 approach bases estimates on a fuelspecific default CO2

EPA based this conclusion on three considerations for 

applicability of the Tier 2 methodology and higher, as 

specified in Subpart C, to the petroleum and natural gas 

industry: (1) availability of high heating values (HHVs) 

for the fuels combusted at the frequency required by the 

Tier 2 methodology, (2) the maximum rated heat input 

capacity of the equipment, and (3) the type of fuel being 

combusted. First, in order to be required to use a Tier 2, 

units must have a rated heat input capacity less than or 

equal to 250 MMBtu/hr, combust a fuel found in Table C-1, 

and sample the HHV of the fuel consumed at the required 

frequency in Part 98.34(a). It was determined that this 

minimum required sampling frequency is not currently 

emission factor, a default high heating 

value of the fuel, and the annual fuel consumption from 

company records. EPA determined that entities that need to 

report incremental combustion-related emissions, as defined 

above, would use the Tier 1 method as set forth in Subpart 

C; these entities would likely not meet the requirements 

for the Tier 2 or higher methods. 
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carried out at these smaller units and therefore these 

units would not be required to use Tier 2 or higher. These 

units will generally follow Tier 1. 

Second, Tier 3 and Tier 4 methodologies generally 

apply to equipment with a maximum rated heat input capacity 

greater than 250 MMBtu/hr. A 250 MMBtu/hr rating means that 

the emissions from that individual unit alone will be 

greater than 25,000 metric tons CO2

Third, the predominant fuels used in the petroleum and 

natural gas industry are produced natural gas, pipeline 

quality natural gas, distillate fuel, and any products 

recovered from equipment leaks and vents. Of these fuels, 

equipment using pipeline quality natural gas, distillate 

fuel, or products recovered from equipment leaks and vents 

are required to use Tier 2 or higher. As described above, 

if the unit has a rated heat-input less than or equal to 

250 MMBtu/hr, then the unit probably does not currently 

receive HHV at the required frequency for a Tier 2 and 

could use a Tier 1. If the unit has a maximum rated heat 

input capacity greater than 250 MMBtu/hr, then as just 

e; these emissions would 

be subject to reporting under Subpart C even in the absence 

of Subpart W and therefore would not fall in the category 

of incremental combustion emissions considered in this 

analysis. 
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noted, emissions from a unit of this size would already be 

subject to reporting and would not be included in the 

incremental combustion emissions category considered in 

this analysis. Finally, the use of produced natural gas is 

predominant in onshore petroleum and natural gas 

production. Under the final rule, reporters are allowed to 

use methods similar to Tier 1 for all combustion emissions 

sources that use produced natural gas. In sum, the use of 

Tier 1 costs for incremental combustion is a reasonable 

assumption.

Reporting Determination Costs

EPA received many comments on the method used to 

estimate the rule’s compliance costs. Nearly all of these 

comments focused on both the methodology and the resulting 

cost estimates. Therefore, a summary of these comments and 

EPA’s response is presented in the next section, III.B.2, 

“What are the costs of the rule?” For the detailed 

. Facilities will have 

to estimate their emissions to determine whether they 

exceed the reporting threshold. The costs for making a 

reporting determination includes primarily the use of 

screening tools, which EPA plans to develop. The costs 

also account for cases in which preliminary monitoring is 

also required to make a reporting determination.

2. Summary of Comments and Responses
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responses to all comments received, see “Mandatory 

Greenhouse Gas Reporting Rule: EPA’s Response to Public 

Comments, Subpart W: Petroleum and Natural Gas Systems.” 

Table W-6 of this preamble presents the types of 

emissions covered under this final 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 $40.1 million, and the total 

national annualized cost for subsequent years is $15.1 

million (2006$). Of these costs, roughly 30 percent fall 

upon the onshore production segment in the first year, 

while about 38 percent fall upon the gas transmission 

segment. Offshore production, which is largely covered by 

the Bureau of Ocean Energy Management, Regulation, and 

Enforcement (formerly MMS) Gulfwide Emissions Inventory

study data, is estimated to incur approximately 0.7 percent 

of costs every three or four years; other segments 

incurring relatively large shares of costs in subsequent 

years are gas transmission (37.8 percent), onshore 

production (33.9 percent) and gas processing (12.0 

percent). The reporting of incremental combustion related 

B. What are the costs of the rule?

1. Summary of Costs
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emission for all segments of the petroleum and natural gas 

industry is estimated to cost $3.3 million in both the 

first year and in the subsequent years.

The reporting threshold 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-7 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 using 

25,000 metric tons CO2

Subpart W–

equivalent as the datum. 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 Impact 

Analysis for the final rule. 

TABLE W-6 NATIONAL COST ESTIMATES FOR PETROLEUM AND 

NATURAL GAS SYSTEMS (2006$)

First Year Subsequent Years
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Petroleum 

and 

Natural 

Gas 

systems

2006$ 

Million

Million 

MtCO2

2006 

e $/ton

2006$ 

Million

Million 

MtCO2

2006 

e $/ton

Equipment 

Leaks and 

Vented 

Emissions

40.1 253.9 $0.16 $15.1 253.9 $0.06 

Combustion 

Emissions

3.3 83.5 $0.04 $3.3 83.5 $0.04 

Total 

Emissions

43.4 337.4 $0.13 $18.4 337.4 $0.05 

TABLE W-7. THRESHOLD COST-EFFECTIVENESS ANALYSIS 

(SUBSEQUENT YEAR, 2006$)

Threshold 

(metric 

tons 

CO2

Facilit

ies 

Require

d to 

e) Report

Total 

Costs1

Downstream 

Emissions 

Reported 

(MtCO

 

(million 

$2006) 2

Percentage 

of Total 

Downstream 

Emissions 

Reported

e/

year)

Average 

Reporting 

Cost ($/Mt)

Increm

ental 

Cost 

($/Mt) 2

1,000 12,622 $71.60 391 99% $0.18 $0.99 

10,000 4,400 $29.48 362 91% $0.08 $0.44 

25,000 2,786 $18.43 337 85% $0.05 $0.00 

100,000 1,062 $9.61 273 69% $0.04 

($0.14

)

1

Excludes determination costs for non-reporters. 

2

Cost per metric ton relative to the selected option. 

2. Summary of Comments and Responses

Overview. EPA received extensive comments on the 

methodology and cost data presented in the Economic Impact 

Analysis for the proposal (EPA-HQ-OAR-2009-0923-0020). The 

comments can be sorted into two major categories: 1)

comments on the costs for facilities to make a reporting 

determination and 2) comments on cost estimates of labor 
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and equipment for certain industry segments to monitor and 

report emissions. 

Reporting Determination. 

EPA agrees with commenters that the EIA would better 

reflect the rule’s total economic burden by including all 

reporting determination costs. While EPA’s compliance cost 

estimates accounted for the reporting determination burden 

in the proposal, it did not include the determination 

burden for non-reporters. Therefore, EPA has estimated the 

burden for reporting determinations made by non-reporters 

and included it in the EIA for the final rule. EPA based 

this estimate on the assumption that non-reporters will use 

a screening tool, which EPA intends to provide to 

Commenters stated that EPA’s 

analysis underestimated the true compliance burden by 

omitting the costs for facilities to make a reporting 

determination—i.e., estimate annual emissions to determine 

whether they meet the reporting threshold. These 

commenters recommended that EPA account for reporting 

determination costs incurred by both facilities that report 

as well as non-reporters, i.e., those that monitor 

emissions but do not meet the reporting threshold. As 

discussed in preamble section II.F.6, the commenters also 

recommended that EPA develop screening tools to reduce the 

burden for facilities to make a reporting determination. 
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facilitate reporting determinations. The estimated total 

cost for all non-reporters to make a reporting 

determination is about $18.4 million, which accounts for 

use of the screening tool and, if required, the cost to 

conduct preliminary screening; section 4 of the EIA 

provides a complete discussion of the basis for this 

estimate. In addition, as discussed in preamble section 

II.F.6, EPA plans to develop screening tools to facilitate 

reporting determinations. EPA expects this to minimize 

burden by allowing facilities to enter basic activity data, 

such as well count and drilling activity, into the tool to 

roughly assess whether they meet the threshold.

Labor and Equipment Costs

In development of this rule and in response to 

comments, EPA collected and evaluated cost data from 

. Many commenters disagreed 

with EPA’s cost estimates in particular segments and 

presented alternative estimates that in some cases differed 

from the agency’s estimates by orders of magnitude. Many 

of the comments suggested that EPA’s estimates of labor 

costs (e.g., number of labor hours required to collect 

field data, to use equipment and engineering analysis 

systems to measure emissions, and to manage the emissions 

data) and equipment costs (e.g., purchase of flow meters) 

were too low. 
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multiple sources, closely reviewed the input received 

through public comments, and weighed the analysis prepared 

against this input. While EPA has adjusted its estimates 

in response to some of the comments, EPA concludes that its 

methodology and final cost estimates appropriately account 

for the compliance burden under this rule. EPA determined 

that the commenters’ alternative estimates are much higher 

than the agency’s because of assumptions and 

interpretations that were inconsistent with EPA’s intent; 

the alternative estimates were also based on higher-cost, 

optional monitoring methods. 

EPA summarizes below the key assumptions, 

misinterpretations, and use of higher-cost, optional 

methods and the resulting costs estimates that differed 

most from EPA’s estimates. These comments were concentrated 

in three industry segments: 1) onshore production, 2) 

natural gas processing, and 3) natural gas distribution 

segments. 

Onshore Production

Comment: Commenters stated that EPA’s estimated 

compliance costs for the onshore petroleum and natural gas 

production segment were too low. Overall, the commenters 

concluded that EPA should reassess the analysis of entities 
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covered by the rule, the assumptions underlying the cost 

estimates, and reduce the monitoring and reporting burden.

One commenter provided detailed, alternative cost 

estimates and concluded that costs could be as high as $1.8 

billion for the onshore production segment in the first 

year, which is notably higher than EPA’s proposal estimate 

of $30.4 million for this segment. The basis for the 

commenter’s cost analysis was an estimate of the number of 

sources in the onshore production segment subject to 

monitoring. Specifically, the commenter assumed that 

because the proposed rule would cover about 80 percent of 

emissions from the petroleum and gas industry, 

approximately 80 percent of the sites and equipment at each 

onshore production facility would be subject to the rule. 

The commenter therefore concluded that the rule would cover 

80 percent of the 823,000 wells in the nation, or about 

667,000 wells, which exceeds EPA’s estimated coverage of 

about 467,000 wells, plus sources at non-well sites.7

The commenter also presented a breakdown of the labor 

and equipment costs, such as labor wages and time spent on 

 In 

particular, the commenter said that counting components to 

estimate emissions from equipment leaks would be onerous. 

 

7 Commenter estimated 823,000 wells based on a “US Energy Information 

Administration’s 2008 report,” but did not provide any other citation 

information. 
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sampling activities. Sampling activities accounted for a 

notable fraction of the commenter’s estimates. For 

example, the commenter estimated costs for sampling 

activity to determine the composition of produced natural 

gas and low pressure separator oil and to analyze all tanks 

for hydrocarbon liquids and produced water. 

In addition, data management software constituted a 

substantial fraction of the commenter’s total cost 

estimate. The commenter stated that individual reporters 

would spend between $100,000 and $850,000 for data 

management software, which totals to approximately $123 

million to $1 billion for the entire segment.

EPA has carefully reviewed these comments and 

disagrees that the agency’s cost estimates should be orders 

of magnitude higher. 

First, EPA disagrees with the commenter’s estimate of 

the number of sources subject to reporting because it 

incorrectly assumed that the proposed rule covered 80 

percent of all wells in the United States. The commenter’s 

assumption that each reporter would need to monitor 80 

percent of its wells in order to report about 80 percent of 

its emissions implies that the type and quantity of 

emissions from each well are identical. This assumption, 

which resulted in much more labor and complex monitoring 
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than required under the proposal, is incorrect. The 

quantity and type of emissions from wells are variable; 

therefore, monitoring 80 percent of the wells does not 

necessarily account for 80 percent of emissions. Moreover, 

the final rule targets only those wells that have the 

highest emissions. Based on its threshold analysis, EPA 

estimates that approximately 60 percent of the wells are 

subject to the monitoring requirements, not 80 percent. 

EPA conducted the threshold analysis using actual data 

available through the commercial database from HPDI LLC, 

which collects these data primarily from individual 

petroleum and natural gas producing States that require 

petroleum and natural gas producing companies to report 

field data. The HPDI database includes operator well count. 

In most cases, HPDI provides data for each well on the 

production of petroleum and natural gas by operator and 

basin; some data are listed by property, which is a 

collection of wells. EPA developed a reasonable estimate 

of the emissions per well by apportioning the national 

emissions from each emissions source type to each of the 

wells based on the contribution of petroleum and natural

gas production from each well to the national total. This 

analysis suggests that approximately 60 percent of the 

wells are covered by the reporters, not 80 percent. 
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The commenter’s analysis of the onshore production 

burden also incorrectly assumed that the rule required all 

onshore production reporters to spend up to $1 billion on 

data management software. EPA disagrees with this 

assumption for two key reasons. First, EPA notes that the 

rule does not require reporters to purchase data collection 

software. It is at the reporters’ discretion to do so. 

Second, although the commenter did not provide any 

information about the software represented in its analysis 

(except for cost), a system in the price range assumed by 

the commenter is usually customized to accommodate data 

needs that extend far beyond the scope of this rule. For 

example, such systems are typically tailored to an 

individual facility and used to simultaneously manage, 

among other things, criteria pollutants under the CAA, 

water discharge and permit data under the Clean Water Act, 

employee accident and injury reporting under Occupational 

Safety and Health Administration requirements, and onsite 

hazardous and non-hazardous solid waste information for the 

Resource Conservation and Recovery Act. In contrast, even 

the largest of reporters under this final action will be 

able to use standard spreadsheets or databases to collect 

the emissions data and perform calculations at a facility 

level. Spreadsheet software can store and manipulate tens 
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of thousands of data points, and database software can 

store hundreds of thousands of data points. In short, 

spreadsheet and database software systems are capable of 

managing far more data than will be necessary for even the 

largest onshore production reporter under Subpart W. 

Accordingly, EPA accounted for data management costs by 

factoring in estimates of labor to set up spreadsheets and 

other archiving and recordkeeping activities, as well as 

equipment costs like file cabinets and external hard 

drives; see the EIA for a complete discussion. 

 Another assumption contributing to the commenters’ 

high cost estimates concerned the extent of sampling 

required. For example, commenters assumed that reporters 

would need to sample produced natural gas. EPA disagrees in 

part because it expects reporters to already have this 

information and would therefore not need to sample. In 

particular, producers conduct composition analysis of 

produced natural gas in order to pay royalties and taxes; 

they could use these data to estimate the percentage of 

GHGs instead of analyzing additional samples. 

The commenters also assumed that sampling would be 

required for tanks and dehydrators, which resulted in cost 

estimates significantly higher than EPA’s. Although not 

explicitly stated in the proposal, EPA did not intend for 
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reporters to sample either the low pressure separator oil 

associated with tanks or natural gas going to dehydrators. 

Therefore, EPA has clarified the final rule to allow 

reporters that use the engineering modeling software to 

rely on the software’s default values. 

In addition, commenters also assumed that produced 

water and hydrocarbon liquids produced from all reporting 

wells in the country would have to be sampled to determine 

and report CO2

Finally, in response to comments about the costs to 

count all components to determine equipment leaks, EPA has 

revised the rule to require reporters to count only major 

equipment (see preamble section II.E). EPA expects this 

revision to reduce the reporters’ burden because in many 

cases they already have an inventory of the major equipment 

at each well site. 

content; this assumption resulted in a large 

sampling cost. However, EPA never intended for reporters 

to sample produced water and hydrocarbon liquids from all 

wells but instead targeted EOR operations. Therefore, EPA 

clarified in this final action that the sampling 

requirement for hydrocarbon liquids applies only to EOR 

operations; EPA also clarified in the final rule that 

reporting from produced water emissions sources is not 

required.
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For the detailed responses to all of the comments 

received about the costs for onshore production, see 

“Mandatory Greenhouse Gas Reporting Rule: EPA’s Response to 

Public Comments, Subpart W: Petroleum and Natural Gas 

Systems.”

Natural Gas Processing

Comment: Commenters stated that EPA’s estimated 

compliance costs for the natural gas processing segment 

were too low. They recommended that EPA reassess the costs 

for the processing segment and simplify the reporting 

requirements. In particular, one commenter estimated 

compliance costs at $4.5 billion for the processing 

segment. Of the $4.5 billion, the commenter attributed 

$3.9 billion to monitoring activities at gathering lines 

and boosting stations. The commenter attributed the 

remainder of its estimate to processing plants. 

Response: Based on its thorough review of the 

comments, EPA determined that the commenter’s estimates for 

processing plants were higher in part because it made 

assumptions that were inconsistent with EPA’s intent. 

Specifically, it assumed higher-cost, optional monitoring 

methods for processing plants in its analysis. However, 

EPA agrees with the commenter that the agency’s analysis 

partly underestimated the costs at processing plants to 
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place meters on acid gas removal units. Likewise, EPA 

agrees that the agency’s analysis did not accurately 

account for the compliance costs for gathering lines and 

boosting stations in the processing segment. 

In the case of processing plants, the commenter 

assumed that the rule would require reporters to install 

permanent flow meters, at an assumed cost of $100,000 per 

meter, to measure emissions from compressor venting. 

However, the rule does not require this and allows 

installation of a port for using a temporary insertion flow 

meter for an annual one-time estimate of vented emissions. 

Temporary flow meters are a significantly cheaper option 

than permanent meters. Based on current market data, EPA 

estimated approximately $1,000 for each installation of a 

temporary meter port for reciprocating compressors; about 

$5,000 for centrifugal compressors; and about $800 in 

capital costs for a reporter’s hotwire anemometer.8

In addition, EPA considered and responded to the 

commenter’s assumption about the burden to install 

permanent outflow meters at acid gas removal (AGR) vents. 

 

Reporters will only need to purchase one hotwire anemometer 

per facility; the hotwire anemometer can be used to measure 

the flow rate at multiple comressors at the facility.

 

8 For example, see Global Water Instrumentation Inc., at 

http://www.globalw.com/products/407119.html
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EPA incorrectly assumed that outlet meters were already 

installed at most sites. Specifically, EPA determined upon 

further analysis that the flow rates at the inlet and 

outlet streams for an acid gas removal unit are roughly 

similar. EPA therefore adjusted the calculation method in 

the final rule to allow the use of flow rate at the inlet 

or outlet, where available, based on its assumption that 

the outlet flow is the same as the inlet flow. In 

addition, if equipment to measure the flow rate, such as 

CEMS or a meter on the vent stack of the acid gas removal 

unit, is not available, the final rule allows reporters to 

use engineering estimates of flow rate of natural gas into 

the AGR. Therefore, the cost analysis in the final EIA is 

consistent with the monitoring requirements by not 

accounting for the cost to meter flow rates.

Finally, EPA used data about the number of gathering 

lines and boosting stations presented by the commenter as a 

basis to modify the rule requirements. EPA agrees that its 

EIA did not accurately reflect the number of gathering 

lines and boosting stations that would have been subject to 

the rule. The costs for gathering lines and boosting 

stations is not relevant to this analysis, however, because 

they are not covered under the final rule. Instead, EPA 

will continue to evaluate options for obtaining emissions 
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data from gathering lines and boosting stations in a way 

that maximizes data quality while minimizing industry 

burden; see preamble section II.F.1 for further discussion.

Natural Gas Distribution

Comment: Commenters stated that EPA’s estimated 

compliance costs for the natural gas distribution segment 

were too low by orders of magnitude. For example, one 

commenter estimated approximately $11.3 billion for all 

reporters in the natural gas distribution segment to comply 

with the rule. A large fraction of this estimate was based 

on the commenter’s assumption that the leak detection 

requirements applied to customer meters, i.e., industrial, 

commercial, and residential meters. The commenter did not, 

however, provide adequate information about the basis for 

the remainder of its cost estimate. In particular, the 

commenter stated that in addition to the costs of using an 

infrared camera, each LDC would spend on average about $41 

million annually to comply with the rule, but did not 

specify any compliance activities that accounted for the 

$41 million.

Response: EPA has carefully reviewed these comments 

and disagrees that the agency’s cost estimates should be 

orders of magnitude higher. EPA has determined that 

commenters’ interpretations of the proposed rule were 
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inconsistent with the Agency’s intent and accounted for the 

discrepancies between the estimates. 

EPA disagrees with the commenter’s cost estimate 

because it is based on an incorrect assumption about the 

number of meters subject to leak detection requirements. 

The commenter assumed that the proposed rule required leak 

detection and emissions estimates for customer meters, 

i.e., industrial, commercial, and residential meters; the 

commenter estimated reporters would spend approximately 

$5.4 billion to monitor these meters. EPA never intended 

to require reporting for customer meters, which would 

involve a major cost and have minimal effect on the quality 

of emissions estimates. EPA has therefore clarified the 

final rule to note that sources subject to reporting in the 

natural gas distribution segment do not include customer 

meters for natural gas. 

In addition, EPA has responded to the commenter’s 

recommendation to reduce the compliance costs by 

simplifying the requirements for optical gas imaging 

equipment equipment, e.g., infrared cameras. As discussed 

previously in preamble section II.E, this final action 

provides more flexibility and further reduces the 

compliance cost by allowing facilities to use alternative 

leak detection equipment.
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Finally, the commenter did not identify the monitoring 

activities and assumptions comprising its estimate of $5.9 

billion to comply with leak detection requirements. The 

commenter noted that it obtained the estimate from an 

informal survey of its members but did not provide 

sufficient information or documentation substantiating what 

was included in this estimate. The commenter also noted 

that this estimate did not include the costs to use 

infrared cameras; a separate estimate was given for this 

and discussed in the previous paragraph. EPA is not aware 

of requirements other than those the commenter accounted 

for in the estimates based on infrared cameras and 

therefore did not change its cost estimate.

C. What are the economic impacts of the rule?

1. Summary of Economic Impacts 

EPA prepared an economic impact analysis to evaluate 

the impacts of the rule on affected small to large 

reporting entities. In evaluating the various reporting 

options considered, EPA conducted a cost-effectiveness 

analysis, comparing the cost per metric ton of GHG 

emissions across reporting options. EPA used this 

information to identify the preferred options described in 

the final rule.
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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.9

These low average cost-to-sales ratios indicate that 

the final 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. Consistent with 

the agency’s guidelines for economic analyses, EPA used the 

engineering cost estimates to measure the social cost of 

the rule, rather than modeling market responses and using 

The national 

costs of the rule are notable 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. 

 

9 Note: Before totaling the industry compliance costs, EPA estimated 

costs for each of the industry segments. EPA then summed the costs for 

each segment cost at the NAICS level for this screening assessment.
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the resulting measures of social cost.10

NAICS

 Table W-8 of this 

preamble summarizes cost-to-sales ratios for affected 

industries. 

TABLE W-8. ESTIMATED COST-TO-SALES RATIOS FOR AFFECTED 

ENTITIES (Year 1) 

NAICS 

Description

MRR Segments 

Included

Average 

Cost Per 

Entity 

($1,000/en

tity)

Average 

Entity 

Cost-toSales 

Ratio1

211

Crude 

Petroleum and 

Natural Gas 

Extraction

Onshore Production, 

Offshore Production, 

Processing $17.1 0.08%

486210

Pipeline 

Transportatio

n of Natural 

Gas

Transmission, 

Underground Storage, 

LNG Storage, and LNG 

Import Terminals $15.7 0.08%

221210 Natural Gas 

Distribution Distribution $13.9 0.06%

1 

While EPA received a substantial number of comments on 

the estimated costs for reporters to comply with the rule, 

there were minimal additional comments on the economic 

impacts, such as changes in production or effects on small 

entities in particular. As discussed in the previous 

section, commenters said that EPA underestimated the 

compliance costs and recommended that EPA carefully review 

the economic impact analysis. See the previous section for 

a summary; the response to comments document, “Mandatory 

Greenhouse Gas Reporting Rule: EPA’s Response to Public 

This ratio reflects first year costs. Subsequent year costs will be 

slightly lower because they do not include initial start-up activities.

2. Summary of Comments and Responses

 

10 Guidelines for Preparing Economic Analyses (EPA, 2002, p.124-125)
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Comments, Subpart W: Petroleum and Natural Gas Systems,” 

provides detailed comments.

As discussed previously, EPA collected and evaluated 

cost data from multiple sources, thoroughly reviewed the 

input received through public comments, and weighed the 

analysis prepared for the proposal against this input. EPA 

has determined that this analysis provides a reasonable 

characterization of costs and that the documentation 

provides adequate explanation of how the costs were 

estimated. 

EPA has determined the selected threshold maximizes 

the rule coverage with 85 percent of U.S. GHG emissions 

from the industry segments reported by approximately 2,786 

reporters, while keeping reporting burden to a minimum. 

Furthermore, many industry stakeholders that EPA met with 

expressed support for a 25,000 metric ton CO

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

1. Summary of Impacts on Small Businesses

As required by the RFA and Small Business Regulatory 

Enforcement and Fairness ACT (SBREFA), EPA assessed the 

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.) 

2e threshold 
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because it sufficiently captures the majority of GHG 

emissions in the United States., while excluding most of 

the smaller facilities and sources. In response to the 

comments EPA received about the monitoring and reporting 

requirements in specific source categories, EPA 

incorporated changes that reduce burden on reporters while 

maximizing emissions coverage. 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 

industry 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.11

 

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

continues to be the preferred quantitative metric for economic impact 

screening analysis.

 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 
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industries. The results of the screening assessment are 

shown in Table W-9 of this preamble. 
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TABLE W-9. ESTIMATED COST-TO-SALES RATIOS FOR FIRST YEAR COSTS BY INDUSTRY AND ENTERPRISE SIZEa

SBA Size 

Standard 

(effective 

March 11, 

2008)

Average 

Cost Per 

Entity 

($1,000/

entity)

All 

Enterprises

Owned by Enterprises with:

Industry NAICS

NAICS 

Description

1 to 20 

Employees

20 to 99 

Employees

100 to 

499 

Employees

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 

Extraction

500 $17.1 0.08% 1.32% 0.11% 0.05% 0.02% 0.47% 0.03% 0.02%

Onshore 

natural gas 

processing; 

onshore 

natural gas 

transmission; 

underground 

natural gas 

storage

486210 Pipeline 

Transportat

ion of 

Natural Gas

b $15.7 0.08% 0.12% 0.40% 0.24% c 0.10% c c

Natural gas 

distribution

221210 Natural Gas 

Distribution

500 $13.9 0.06% 0.27% 0.03% 0.06% 0.11% 0.07% 0.02% 0.03%

a The Census Bureau defines an enterprise as a business organization consisting of one or more domestic establishments that were specified under common ownership or 

control. The enterprise and the establishment are the same for single-establishment firms. Each multi-establishment company forms one enterprise—the enterprise 

employment and annual payroll are summed from the associated establishments. Enterprise size designations are determined by the summed employment of all associated 

establishments.

Since the SBA’s business size definitions (http://www.sba.gov/size) apply to an establishment’s ultimate parent company, EPA assumes in this analysis that the 

enterprise definition above is consistent with the concept of ultimate parent company that is typically used for Small Business Regulatory Enforcement Fairness Act 

(SBREFA) screening analyses.

b The SBA size standard for NAICS 486210 is $7 million in average annual receipts.

c The U.S. Census Bureau has missing data for this employee range; some estimates were possible using partial data. The receipts for these categories underestimate

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

percent for establishments owned by small businesses that 

EPA considers most likely to be covered by the reporting 

program. The only exception is the ratio for enterprises 

with 1-20 employees for crude petroleum and natural gas 

extraction, which is greater than 1 percent but less than 2 

percent. While a majority of the enterprises in the 

petroleum and natural gas industry fall in the 1-20 

employee range, most of the production, and therefore 

emissions, comes from large corporations. In most cases, 

the smaller enterprises have very small operations (such as 

a single family owning a few production wells) that are 

highly unlikely to cross the 25,000 metric tons CO2e 

reporting threshold. 

In other cases, a small enterprise (less than 20 

employee) may own large operations but conduct nearly all 

of its operations through service providers. Such 

enterprises, however, tend to have higher annual revenues 

than those with small operations. In addition, these 

enterprises constitute a small fraction of the over 19,000 

enterprises in the less than 20 employee category subject 

to this final rule.
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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 

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 

reasonable balance of direct measurement, engineering 

estimation, and emission factors based monitoring methods 

to quantify emissions, which provides flexibility to 

entities and helps minimize reporting costs. 
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2. Summary of Comments and Responses

Comment: Some commenters noted concerns about the 

rule’s impact on small businesses, in particular that small 

businesses would have to apply the monitoring methods 

specified in the rule to determine whether they have to 

report under the rule. One commenter recommended that EPA 

redo its analysis of the rule’s impacts on small businesses 

using “more accurate economic impact data,” but did not 

appear to include or identify alternative data sources for 

such an analysis. See the response to comments document, 

“Mandatory Greenhouse Gas Reporting Rule: EPA’s Response to 

Public Comments, Subpart W: Petroleum and Natural Gas 

Systems,” for the detailed comments.

Response: EPA has assessed the economic impact of the 

final rule on small entities and concluded that this action 

will not have a significant economic impact on a 

substantial number of small entities. While the commenter 

did not provide details in its recommendation that EPA redo 

the small business analysis using “more accurate economic 

impact data,” EPA acknowledges the importance of using the 

best available economic data. Accordingly, EPA analyzed 

the economic impact on small entities using the revised 

cost estimates discussed in this section and in the EIA. 
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These cost estimates were the same order of magnitude as 

those estimated under the proposal; the estimates also 

reflected improvements made in response to comments as well 

as changes to the monitoring requirements in the final 

rule. 

In addition, EPA’s assessment of the economic impacts 

on small entities continued to rely on data from the 

Statistics of U.S. Businesses, a well-known database that 

provides national information on the distribution of 

economic variables by the size of entity. As noted in the 

EIA, these data were developed in cooperation with, and 

partially funded by, the Office of Advocacy of the Small 

Business Administration. Complete documentation of this 

analysis can be found in section 5.2 of the EIA for the 

final rule.

Finally, in response to concerns about the cost to 

make a reporting determination, EPA intends to provide 

screening tools. As discussed above, these tools will aid 

small businesses and other potential reporters to determine 

whether or not they have to report.

The response to comments document, “Mandatory 

Greenhouse Gas Reporting Rule: EPA’s Response to Public 

Comments, Subpart W: Petroleum and Natural Gas Systems,” 
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presents the detailed comments and responses related to the 

rule’s impact on small businesses. 

A mandatory reporting system for petroleum and natural 

gas systems will benefit policymakers and 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 

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

EPA examined the potential benefits of the final 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 

monetize. Instead of a quantitative analysis of the 

benefits, EPA conducted a systematic literature review of 

existing studies including government, consulting, and 

scholarly reports. 
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consumption habits based on the GHG emissions of producers. 

Facility-specific emissions data will also aid local, 

state, and national policymakers as they evaluate and 

consider future climate change policy decisions.

The benefits of mandatory reporting of petroleum and 

natural gas systems GHG emissions to government also 

include enhancing existing programs, such as the Natural 

Gas STAR Program, and provide significant economic and 

environmental benefits. Through the Natural Gas STAR 

Program, EPA has identified over 120 proven, cost effective 

technologies and practices to reduce emissions of methane—

the primary constituent of natural gas—from operations in 

all of the major industry sectors—production, gathering and 

processing, transmission, and distribution. The final 

reporting rule will increase knowledge of the location and 

magnitude of significant methane emissions sources in the 

petroleum and natural 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 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 
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emissions. Such monitoring allows for inclusion of 

standardized GHG data into environmental management 

systems, providing the necessary information to achieve and 

disseminate their environmental achievements. 

Standardization will also be a benefit to industry. 

Once facilities invest in the institutional knowledge and 

systems to report emissions, the cost of monitoring should 

fall and the accuracy of the accounting should improve. A 

standardized reporting program will also allow for 

facilities to benchmark themselves against similar 

facilities to understand better their relative standing 

within their industry. 

The EIA for this final rule as well as the RIA for 40 

CFR Part 98 summarize the anticipated benefits, 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 Review

A. Executive Order 12866: Regulatory Planning and Review
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Under Executive Order (EO) 12866 (58 FR 51735, October 

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

because it raises novel legal or policy issues arising out 

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

principles set forth in the EO. Accordingly, EPA submitted 

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

for review under EO 12866

B. Paperwork Reduction Act

The information collection requirements in this final 

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

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 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 

. The Information Collection 

Request (ICR) document prepared by EPA has been assigned 

EPA ICR number 2376.02. 
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that influence GHG emission rates and actions that 

facilities are already taking to reduce emissions. 

Additionally, EPA will be able to track the trend of 

emissions from facilities within the petroleum and natural 

gas industry over time, particularly in response to 

policies and potential regulations. The data collected by 

this 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.

The projected cost and hour burden for non-federal 

respondents is $27.7 million and 396,474 hours per year.

The estimated average burden per response is 90.71 hours; 

the frequency of response is annual for all respondents 

that must comply with the final rule’s reporting 

requirements; and the estimated average number of likely 

respondents per year is 2,786. The cost burden to 

respondents resulting from the collection of information 
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includes the total capital cost annualized over the 

equipment’s expected useful life (averaging $0.74 million), 

a total operation and maintenance component (averaging $1.7 

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

$25.3 million per year)12

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. When this ICR is approved by OMB, 

. 

Burden is defined at 5 CFR 1320.3(b). These cost 

numbers differ from those shown elsewhere in the EIA for 

these subparts because the information collection request 

(ICR) costs represent the average cost over the first three 

years of the rule, but costs are reported elsewhere in the 

EIA for the subparts for the first year of the rule and for 

subsequent years of the rule. In addition, the ICR focuses 

on respondent burden, while the EIA includes both national 

compliance costs and the burden for EPA to implement the 

rule.

 

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

those shown elsewhere in the Economic Analysis because the ICR costs 

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

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

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

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

the Economic Analysis includes EPA Agency costs.
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the Agency will publish a technical amendment to 40 CFR 

part 9 in the Federal Register to display the OMB control 

number for the approved information collection requirements 

contained in this final rule.

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 final 

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

small business as defined by the Small Business 

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

governmental jurisdiction that is a government of a city, 

county, town, school district or special district with a 

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

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

independently owned and operated and is not dominant in its 

field.
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After considering the economic impacts of this final 

action 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 final 

rule include small businesses in the petroleum and gas 

industry, small governmental jurisdictions and small nonprofits. EPA has determined that some small businesses 

will be affected because their production processes emit 

GHGs exceeding the reporting threshold.

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 final 

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 
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businesses covered by the reporting program. Although the 

costs to receipts for entities in onshore production with 

1-20 employees is slightly over 1 percent, most of these 

facilities would likely not exceed the 25,000 mtCO2

EPA also concluded that the final rulemaking would not 

affect a small organization that is any not-for-profit 

enterprise, which is independently owned and operated and 

is not dominant in its field. Specifically, the data 

listing entities in each segment of the petroleum and 

natural gas industry did not include any non-profit 

entities.

e 

threshold, a threshold supported by many stakeholders as 

one that sufficiently captures the majority of GHG 

emissions while excluding small facilities. Further, these 

sales tests examine the average establishment’s total 

annualized mandatory reporting costs to the average 

establishment receipts for enterprises within several 

employment categories. The average entity costs used to 

compute the sales test are the same across all of these 

enterprise size categories. As a result, the sales-test 

will overstate the cost-to-receipt ratio for establishments 

owned by small businesses, because the reporting costs are 

likely lower than average entity estimates provided by the 

engineering cost analysis.
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In addition, EPA determined that the final rulemaking 

would not have a significant impact on small governmental 

jurisdictions. EPA determined that one segment of the 

petroleum and natural gas industry might include small 

governments affected by the final rulemaking. A comparison 

of the compliance costs to the revenue of potentially 

affected small governmental jurisdictions revealed that the 

costs of the rule are less than 1 percent of revenues. 

Although this final 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 final rule on small entities. For example, EPA 

determined appropriate thresholds that reduce the number of 

small businesses reporting. In addition, EPA allows 

different monitoring methods for different emissions 

sources, requiring direct measurement only for selected 

sources. Also, EPA intends to provide a screening tool 

that will help small businesses make a reporting 

determination with minimal burden (see preamble Section 

II.F.6). Finally, EPA is establishing 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 
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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 final 

rule. EPA 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 final rule or provide suggestions to EPA about the 

types of compliance assistance that would be useful to 

small businesses. EPA intends to develop a range of 

compliance assistance tools and materials and conduct 

extensive outreach for the final rule. 

EPA has therefore concluded that this final action

will not have a significant economic impact on a 

substantial number of small entities. 
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D. Unfunded Mandates Reform Act (UMRA)

This 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 sector in any one year. EPA estimated the cost to 

individual facilities that may have to report to this final 

rule using actual facility characteristics such as 

throughput and size. EPA also determined the costs to nonreporters for determination to report. The sum of these 

costs for the entire industry has been estimated to be less 

than $100 million. Thus, this rule is not subject to the 

requirements of sections 202 or 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. Based on EPA’s analysis of the rule’s 

impact on small entities, the Agency determined that natural 

gas distribution is the only industry segment that would 

potentially have small governments affected by the rule. In 

this segment, however, the facilities owned or operated by 

small governments are expected to be too small to trigger the 

25,000 metric tons CO2e reporting threshold.

E. Executive Order 13132: Federalism
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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. 

EPA has concluded that this action may have tribal 

implications. However, it will neither impose substantial 

direct compliance costs on tribal governments, nor preempt 

Tribal law. EPA conducted an analysis to determine 

potential impact of this action on tribes that own or 

operate petroleum and natural gas systems (EPA-HQ-OAR-2009-

0923-XXX). First, EPA analyzed a comprehensive listing of 

all operators of petroleum and natural gas systems in the 

United States in conducting the threshold analysis. In a 

separate analysis, EPA researched additional available data 

F. Executive Order 13175: Consultation and Coordination 

with Indian Tribal Governments
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to determine which tribal entities may own or operate 

petroleum and natural gas systems that could be impacted by 

this final action. As a result of those analysis, EPA found 

one tribe that may potentially be impacted by this final 

action. Finally, during the comment period for the April 

2010 proposal, EPA received comment from one tribe, 

Southern Ute, which were specific to the proposed reporting 

methodologies. 

As further discussed in the 2009 final rule that 

established the Greenhouse Gas reporting program, EPA 

believes that there are minimal impacts to tribes. Tribes 

could be required to submit an annual GHG report for any 

facility they own or operate that is subject to the rule. 

Landfills and stationary combustion equipment are the types 

of facilities owned or operated by tribes that would most 

likely trigger applicability. Tribes that own or operate 

large industrial emission sources such as cement plants, 

coal mines, or oil and gas operations could also be 

required to report emissions under this rulemaking. It 

should be noted that the owner or operator of any privately 

owned sources located on a reservation would be required to 

report for any applicable facility. The rule would apply to 

all types of stationary combustion equipment (except for 

emergency generators and portable equipment) if the 
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aggregate maximum rated heat input capacity of all 

stationary fuel combustion units at a facility is 30 

million British thermal units per hour (mmBtu/hr) or 

greater, and the facility emits 25,000 metric tons of CO2e 

or more per year from all stationary fuel combustion 

sources. 

EPA sought opportunities to provide information to 

tribal governments and representatives during rule 

development. As stated in Section F: Executive Order 13175: 

Consultation and Coordination with Indian Tribal 

Governments of 40 CFR part 98, and in consultation with 

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

plan for the Greenhouse Gas Reporting Rule included tribes. 

EPA conducted several conference calls with Tribal 

organizations during the proposal phase of the mandatory 

reporting rule. 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 The Climate Registry (TCR). 

In addition, EPA prepared a short article on the GHG 

Reporting Program that appeared on the front page of a 

Tribal newsletter—Tribal Air News—that was distributed to 

EPA/OAQPS’s network of Tribal organizations. EPA gave a 
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presentation on various climate efforts, including the 

Greenhouse Gas Reporting Program, at the National Tribal 

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

In addition, EPA distributed copies of a short information 

sheet 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 

final rule. It was posted on the Greenhouse Gas Reporting 

Program website and published in the Tribal Air Newsletter. 

As required by section 7(a), EPA’s Tribal Consultation 

Official has certified that the requirements of the 

Executive Order have been met in a meaningful and timely 

manner. A copy of the certification is included in the 

docket for this action.

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 

G. Executive Order 13045: Protection of Children from 

Environmental Health Risks and Safety Risks
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influence the regulation. This action is not subject to EO 

13045 because it does not establish an environmental 

standard intended to mitigate health or safety risks.

H. Executive Order 13211: Actions that Significantly 

Affect Energy Supply, Distribution, or Use

This final 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, EPA 

has concluded that this final rule is not likely to have 

any adverse energy effects. This final rule relates to 

monitoring, reporting and recordkeeping at petroleum and 

gas facilities that emit over 25,000 mtCO2

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, 

e and does not 

impact energy supply, distribution or use. Therefore, EPA 

concludes that this final rule is not likely to have any 

adverse effects on energy supply, distribution, or use. 

I. National Technology Transfer and Advancement Act
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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 

final rule. Instead, EPA reviewed existing rules for 

source categories and voluntary greenhouse gas programs and 

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. 
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By incorporating voluntary consensus standards into 

this final 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 final 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. 

K. Congressional Review Act 
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The Congressional Review Act, 5 U.S.C. 801 et seq., as 

added by the Small Business Regulatory Enforcement Fairness 

Act of 1996 (SBREFA), generally provides that before a rule 

may take effect, the agency promulgating the rule must 

submit a rule report, which includes a copy of the rule, to 

each House of the Congress and to the Comptroller General 

of the United States. EPA will submit a report containing 

this rule and other required information to the U.S. 

Senate, the U.S. House of Representatives, and the 

Comptroller General of the U.S. prior to publication of the 

rule in the Federal Register. A major rule cannot take 

effect until 60 days after it is published in the Federal 

Register. This action is not a “major rule” as defined by 

5 U.S.C. 804(2). This rule will be effective [INSERT THE 

DATE 60 DAYS AFTER PUBLICATION IN THE FEDERAL REGISTER].
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List of Subjects in 40 CFR Part 98

Environmental protection, Administrative practice and 

procedure, Greenhouse gases, Incorporation by reference, 

Suppliers, Reporting and recordkeeping requirements.

Lisa P. Jackson, 

Administrator.

Dated:
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For the reasons stated in the preamble, title 40, 

chapter I, of the Code of Federal Regulations is amended as 

follows: 

PART 98–[AMENDED]

1. The authority citation for part 98 continues to 

read as follows:

Authority: 42 U.S.C. 7401-7671q.

Subpart A—[Amended]

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

introductory text, (a)(1)introductory text and (a)(2)

introductory text to read as follows:

(1) A facility that contains any source category that 

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

starting in 2010. For these facilities, the annual GHG 

§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:
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report must cover stationary fuel combustion sources 

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

and all applicable source categories listed in Table A-3 

and Table A-4 of this subpart. For these facilities, the 

annual GHG report shall not cover onshore petroleum and 

natural gas production as defined in §98.232(c) except as 

specified in subpart RR.

* * * * *

(2) A facility that contains any source category that 

is listed in Table A-4 of this subpart that emits 25,000 

metric tons CO2e or more per year in combined emissions from 

stationary fuel combustion units, miscellaneous uses of 

carbonate, and all applicable source categories that are 

listed in Table A-3 and Table A-4 of this subpart. For 

these facilities, the annual GHG report must cover 

stationary fuel combustion sources (subpart C), 

miscellaneous use of carbonates (subpart U), and all 

applicable source categories listed in Table A-3 and Table 

A-4 of this subpart. Onshore petroleum and natural gas 

production facilities must report emissions only from 

sources specified in §98.232(c).

* * * * *
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3. Table A-4 of subpart A is amended by adding 

“Petroleum and Natural Gas Systems (subpart W)” at the end 

of the table to read as follows:

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

Source Categoriesa Applicable in 2010 and Future Years

* * * * * * *

Additional Source Categoriesa Applicable in 2011 and Future Years

Petroleum and Natural Gas Systems (subpart W)

a Source categories are defined in each applicable subpart.

* * * * *

4. 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.

* * * * *
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Air injected flare means a flare in which air is blown 

into the base of a flare stack to induce complete 

combustion of gas.

* * * * *

Blowdown vent stack emissions mean natural gas and/or 

CO2 released due to maintenance and/or blowdown operations 

including 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 an 

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 or CO2 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 or CO2 from escaping 

to the atmosphere.
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Centrifugal compressor dry seal emissions mean natural 

gas or CO2 released from a dry seal vent pipe and/or the 

seal face around the rotating shaft where it exits one or 

both ends of the compressor case.

Centrifugal compressor wet seal degassing vent 

emissions means emissions that occur when the high-pressure 

oil barriers for centrifugal compressors are depressurized 

to release absorbed natural gas or CO2. 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. 

* * * * *

Dehydrator means a device in which a liquid absorbent 

(including 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 and 

CO2 released from a natural gas dehydrator system absorbent 

(typically glycol) reboiler or regenerator to the 
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atmosphere or a flare, including stripping natural gas and 

motive natural gas used in absorbent circulation pumps.

* * * * *

De-methanizer means the natural gas processing unit 

that separates methane rich residue gas from the heavier 

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 or absorption. Desiccants include activated 

alumina, pelletized calcium chloride, lithium chloride and 

granular silica gel material. Wet natural gas is passed 

through a bed of the granular or pelletized solid adsorbent 

or absorbent in these dehydrators. As the wet gas contacts 

the surface of the particles of desiccant material, water 

is adsorbed on the surface or absorbed and dissolves the 

surface of these desiccant particles. Passing through the 

entire desiccant bed, almost all of the water is adsorbed 

onto or absorbed into the desiccant material, leaving the 

dry gas to exit the contactor.

* * * * *

Gas conditions mean the actual temperature, volume, 

and pressure of a gas sample. 
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* * * * *

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, continuous 

bleed 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 continuously (bleeds) to the atmosphere at a 

rate in excess of six standard cubic feet per hour. 

Intermittent Bleed Pneumatic Devices mean automated 

flow control devices powered by pressurized natural gas and 

used for maintaining a process condition such as liquid 

level, pressure, delta-pressure and temperature. These are 

snap-acting or throttling devices which discharge the full 

volume of the actuator intermittently when control action 

is necessary, but does not bleed continuously.

* * * * *

Low-Bleed Pneumatic Devices mean automated flow 

control devices powered by pressurized natural gas and used 
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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 

continuously (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.

* * * * *

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.

* * * * *

Reciprocating compressor means a piece of equipment 

that increases the pressure of a process natural gas or CO2

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 
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reciprocating compressor piston rod to create a seal 

limiting the amount of compressed natural gas or CO2 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.

* * * * *

Sales oil means produced crude oil or condensate 

measured at the production lease automatic custody transfer 

(LACT) meter or custody transfer tank gauge.

* * * * *

Sour natural gas means natural gas that contains 

significant concentrations of hydrogen sulfide (H2S)and/or 

carbon dioxide (CO2) 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.

* * * * *
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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 

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 process designed flow to the atmosphere through 

seals or vent pipes, equipment blowdown for maintenance, 
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and direct venting of gas used to power equipment (such as 

pneumatic devices).

* * * * *

Well completions means the 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, steps which may vent 

produced gas to the atmosphere via an open pit or tank. 

Well completion also involves connecting the well bore to 

the reservoir, which may include treating the formation or 

installing tubing, packer(s), or lifting equipment, steps 

which do not significantly vent natural gas to the 

atmosphere. This process may also include high-rate 

flowback of injected gas, water, oil, and sand used to 

fracture or re-fracture and prop open new fractures in 

existing lower permeability gas reservoirs, steps which may 

vent large quantities of produced gas to the atmosphere.

Well workover means the process(es) of performing one 

or more of a variety of remedial operations on producing 

petroleum and natural gas wells to try to increase 

production. This process also includes high-rate flowback

of injected gas, water, oil, and sand used to re-fracture 

and prop-open new fractures in existing low permeability 
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gas reservoirs, steps which may vent large quantities of 

produced gas to the atmosphere.

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. Wellhead 

equipment includes all equipment, permanent and portable, 

located on the improved land area (i.e. well pad) 

surrounding one or multiple wellheads.

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.”

5. Section 98.7 is amended by adding paragraphs (p), 

(q), and (r) to read as follows:

§98.7 What standardized methods are incorporated by 

reference into this part?

* * * * *

(p) The following material is available for purchase 

from the American Association of Petroleum Geologists, 1444 

South Boulder Avenue, Tulsa, Oklahoma 74119, (918) 584-

2555, http://www.aapg.org.
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(1) Geologic Note: AAPG-CSD Geologic Provinces Code 

Map: AAPG Bulletin, Prepared by Richard F. Meyer, Laure G. 

Wallace, and Fred J. Wagner, Jr., Volume 75, Number 10 

(October 1991), pages 1644-1651, IBR approved for §98.238.

(2) Alaska Geological Province Boundary Map, Compiled 

by the American Association of Petroleum Geologists 

Committee on Statistics of Drilling in cooperation with the 

USGS, 1978, IBR approved for §98.238.

(q) The following material is available from the 

Energy Information Administration (EIA), 1000 Independence 

Ave., SW, Washington, DC 20585, (202) 586-8800, 

http://www.eia.doe.gov/pub/oil_gas/natural_gas/data_publica

tions/field_code_master_list/current/pdf/fcml_all.pdf.

(1) Oil and Gas Field Code Master List 2008, 

DOE/EIA0370(08), January 2009, IBR approved for §98.238.

(2) [Reserved]

(r) The following material is available from the United 

States Environmental Protection Agency, Air Docket, EPA 

Docket Center, Public Reading Room, EPA West Building, Room 

3334, 1301 Constitution Avenue., NW., Washington, DC 20004. 

http://www.regulations.gov.

(1) Year 2005 Gulfwide Emission Inventory Study, OCS 

Study MMS 2007-067, December 2007, IBR approved for 

§98.232(b)and §98.233(s).
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(2) [Reserved]
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6. Add subpart W to read as follows:

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.

§98.230 Definition of the source category

(1) 

. 

(a) This source category consists of the following:

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 

processes and/or transfers such hydrocarbons to storage, 

transport vessels, or onshore. In addition, offshore 

production includes secondary platform structures connected 
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to the platform structure via causeways or walkways, 

storage tanks associated with the platform structure and 

floating production storage and offloading equipment

(FPSO).

(2) Onshore petroleum and natural gas production. 

Onshore petroleum and natural gas production equipment

means all structures associated with wells (including 

compressors, generators, or storage facilities), and 

portable non-self-propelled equipment (including 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 enhanced 

oil recovery (EOR) operations using CO2

(3) 

, 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. 

Onshore natural gas processing plants. Natural 

gas processing plants are designed to separate and recover 

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

and liquids from a stream of produced natural gas through 
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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. This source 

category also includes all residue gas compression 

equipment owned or operated by the natural gas processing 

plant, whether inside or outside the processing plant 

fence.

(4) Onshore natural gas transmission compression. 

Onshore natural gas transmission compression means any 

fixed combination of compressors that move natural gas at 

elevated pressure from production fields or natural gas 

processing facilities, in transmission pipelines, to 

natural gas distribution pipelines, or into storage. In 

addition, transmission compressor station includes 

equipment for liquids separation, natural gas dehydration, 

and tanks for the storage of water and hydrocarbon liquids. 

Residue (sales) gas compression operated by Natural Gas 

Processing Facilities are included in the processing 

category and excluded from this category.
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(5) Underground natural gas storage. Underground 

natural gas storage means subsurface storage, including 

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 compression, 

dehydration and flow measurement, and excluding 

transmission pipelines); and all the wellheads connected to 

the compression units located at the facility.

(6) Liquefied natural gas (LNG) storage

(7) 

. 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.

LNG import and export equipment. LNG import 

equipment means all onshore or offshore equipment that 

receives imported LNG via ship 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 
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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 the distribution pipelines (not 

interstate pipelines or intrastate pipelines) and metering 

and regulating at city gate stations that physically 

deliver natural gas to end users. This category excludes

all customer meters and the infrastructure and pipelines 

delivering natural gas directly to major industrial users 

and "farm taps" upstream of the local distribution company 

inlet.

(b) [RESERVED]

§98.231 Reporting threshold

(c) For applying the threshold defined in 

§98.2(a)(2), natural gas processing plants must also 

.

(a) You must report GHG emissions under this subpart

if your facility contains petroleum and natural gas systems 

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

(b) For applying the threshold defined in 

§98.2(a)(2), an onshore petroleum and natural gas 

production facility shall consider emissions only from the 

equipment specified in 98.232(c). 
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include owned or operated residue gas compression 

equipment.

§98.232 GHGs to report. 

(a) You must report CO2, CH4, and N2O emissions from 

each industry segment specified in paragraph (b) through 

(i) of this section, CO2, CH4, and N2O emissions from each 

flare as specified in paragraph (j) of this section, and 

stationary combustion emissions as applicable as specified 

in paragraph (k) if this section.

(b) For offshore petroleum and natural gas 

production, report CO2 and CH4 emissions from all 

“stationary fugitive” and “stationary vented” source as 

identified in the United States Department of the Interior, 

Minerals Management Service (MMS), Gulf of Mexico OCS 

Region, Year 2005 Gulfwide Emission Inventory Study, OCS 

Study MMS 2007-067, December 2007,(incorporated by 

reference, see §98.7).

(c) For onshore petroleum and natural gas production, 

report CO2, CH4 and N2

(4) Well venting for liquids unloading.

O emissions from the following source 

types:

(1) Natural gas pneumatic device venting.

(2) [Reserved]

(3) Natural gas driven pneumatic pump venting.
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(5) Gas well venting during well completions without

hydraulic fracturing.

(6) Gas well venting during well completions with 

hydraulic fracturing.

(7) Gas well venting during well workovers without 

hydraulic fracturing.

(8) Gas well venting during well workovers with 

hydraulic fracturing.

(9) Flare stack emissions.

(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) [Reserved]

(16) EOR injection pump blowdown.

(17) Acid gas removal vent stack.

(18) EOR hydrocarbon liquids dissolved CO2

(21) Equipment leaks from valves, connectors, open 

ended lines, pressure relief valves, pumps, flanges, and 

other equipment leak sources (such as instruments, loading 

.

(19) Centrifugal compressor wet seal degassing 

venting.

(20) [Reserved]
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arms, pressure relief valves, stuffing boxes, compressor 

seals, dump lever arms, and breather caps).

(22) You must use the methods in subpart W and report 

CO2, CH4, and N2O from combustion emissions from stationary 

and portable equipment that cannot move on roadways under 

its own power and drive train, and that are located at an 

onshore production wellhead. Stationary and portable 

equipment are well drilling and completion equipment,

workover equipment, dehydrators, compressors, electrical 

generators, steam boilers, and heaters. 

(d) For onshore natural gas processing, report CO2 and 

CH4

(e) For onshore natural gas transmission compression, 

report CO

emissions from the following sources:

(1) Reciprocating compressor rod packing venting.

(2) Centrifugal compressor wet seal degassing 

venting.

(3) Blowdown vent stacks.

(4) Dehydrator vent stacks.

(5) Acid gas removal vent stack.

(6) Flare stack emissions.

(7) Equipment leaks from: valves, connectors, open 

ended lines, pressure relief valves, meters, and 

centrifugal compressor dry seals.

2 and CH4 emissions from the following sources:
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(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 device venting.

(6) [Reserved]

(7) Equipment leaks 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 CO2

and CH4

(g) For LNG storage, report CO

emissions from the following sources:

(1) Reciprocating compressor rod packing venting.

(2) Centrifugal compressor wet seal degassing 

venting.

(3) Natural gas pneumatic device venting.

(4) [Reserved]

(5) Equipment leaks from connectors, block valves, 

control valves, compressor blowdown valves, pressure relief 

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

ended lines. 

2 and CH4 emissions from 

the following sources:
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(1) Reciprocating compressor rod packing venting.

(2) Centrifugal compressor wet seal degassing 

venting.

(3) Equipment leaks from valves; pump seals; 

connectors; vapor recovery compressors, and other equipment 

leak sources.

(h) LNG import and export equipment, report CO2 and 

CH4 emissions from the following sources: 

(1) Reciprocating compressor rod packing venting.

(2) Centrifugal compressor wet seal degassing 

venting.

(3) Blowdown vent stacks.

(4) Equipment leaks from valves, pump seals, 

connectors, vapor recovery compressors, and other equipment 

leak sources.

(i) For natural gas distribution, report emissions 

from the following sources: 

(1) Above ground meters and regulators at custody 

transfer city gate stations, including equipment leaks 

from connectors, block valves, control valves, pressure 

relief valves, orifice meters, other meters, regulators, 

and open ended lines. Customer meters are excluded.
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(2) Above ground meters and regulators at non-custody 

transfer city gate stations, including station equipment 

leaks. Customer meters are excluded.

(3) Below ground meters and regulators and vault 

equipment leaks. Customer meters are excluded.

(4) Pipeline main equipment leaks.

(5) Service line equipment leaks.

(j) All applicable industry segments must report the 

CO2, CH4, and N2O emissions from each flare. 

(k) External fuel combustion sources with a rated 

heat input capacity equal to or less than 5 mmBtu/hr do not 

need to report combustion emissions. All applicable 

industry segments 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. Onshore 

petroleum and natural gas production must report stationary 

and portable combustion emissions as specified in paragraph 

(c) of this section under this subpart. 

(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.
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(a) Natural gas pneumatic device venting

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

. Calculate 

emissions from continuous high bleed, continuous low bleed, 

and intermittent bleed natural gas pneumatic devices using 

Equation W-1 of this section. 

(Eq. W-1)

Where:

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

CO2e per year at standard conditions from a 

natural gas pneumatic device vent, for GHG i.

Count = Total number of continuous high bleed, 

continuous low bleed, or intermittent bleed 

natural gas pneumatic devices of each type.

EF = Population emission factors for natural gas 

pneumatic device venting listed in Tables W1A, 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; 0.000410 for CH4, and 0.00005357 for 

CO2.

24 * 365 = Conversion to yearly emissions estimate.

(b) [Reserved]

(c) Natural gas driven pneumatic pump venting. 

Calculate emissions from natural gas driven pneumatic pump 

venting using Equation W-2 of this section. 
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* * * * 24*365 Masss,i = Count EF GHGi Convi (Eq. W-2)

Where:

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

CO2e per year at standard conditions from all 

natural gas pneumatic pump venting, for GHG i.

Count = Total number of natural gas pneumatic pumps.

EF = Population emission factors for natural gas 

pneumatic pump venting listed in Tables W-1A 

of this subpart for onshore petroleum and 

natural gas production.

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

natural gas.

Convi = Conversion from standard cubic feet to metric 

tons CO2e; 0.000410 for CH4, and 0.00005357 for 

CO2.

24 * 365 = Conversion to yearly emissions estimate.

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

(including processes such as amine, membrane, molecular 

sieve or other absorbents and adsorbents), calculate 

emissions for CO2 only (not CH4

(1) 

) vented directly to the 

atmosphere or through a flare, engine (e.g. permeate from a 

membrane or de-adsorbed gas from a pressure swing adsorber 

used as fuel supplement), or sulfur recovery plant using 

any of the calculation methodologies described in paragraph 

(d) of this section.

Calculation Methodology 1. If you operate and 

maintain a CEMS that measures CO2 emissions according to 

subpart C of this part, you must calculate CO2 emissions 

under this subpart by following the Tier 4 Calculation 
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Methodology and all associated requirements for Tier 4 in 

subpart C of this part (General Stationary Fuel Combustion 

Sources). If CEMS and/or volumetric flow rate monitor are 

not available, you may install a CEMS that complies with 

the Tier 4 Calculation Methodology in subpart C of this 

part (General Stationary Fuel Combustion).

(2) Calculation Methodology 2. If CEMS is not 

available, use the CO2 composition and annual volume of vent 

stack gas to calculate emissions using Equation W-3 of this 

section.

Ea,CO2 = VS * VolCO2 (Eq. W-3)

Where:

Ea,CO2 = Annual volumetric CO2 emissions at actual 

condition, in cubic feet per year.

VS = Total annual volume of vent stack gas flowing 

out of the AGR unit in cubic feet per year at 

ambient condition as determined by flow meter 

using methods set forth in §98.234(b) or 

engineering calculation and process knowledge 

using best available data.

VolCO2 = Volume fraction of CO2 content in vent gas out 

of the AGR unit as determined in (d)(5) of 

this section.

(3) Calculation Methodology 3. If the CO2 composition 

and annual volume of vent stack gas is not known, use the 

inlet or outlet gas flow rate of the acid gas removal unit 

to calculate emissions for CO2 using Equation W-4 of this 

section.
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Ea,CO2 = V * (VolI - VolO) (Eq. W-4)

Where:

Ea,CO2 = Annual volumetric CO2 emissions at actual 

condition, in cubic feet per year.

V = Total annual volume of natural gas flow 

through the AGR unit in cubic feet per year at 

actual condition as determined using methods 

specified in paragraph (d)(4) of this section.

VolI = Volume fraction of CO2 content in natural gas 

into the AGR unit as determined in 

paragraph(d)(6) of this section.

VolO = Volume fraction of CO2

(4) Record the gas flow rate of the inlet and outlet 

natural gas stream of an AGR unit using a meter according 

to methods set forth in §98.234(b). If you do not have a 

continuous flow meter, either install a continuous flow 

meter or use an engineering calculation to determine the 

flow rate.

(5) If continuous gas analyzer is not available, 

either install a continuous gas analyzer or take quarterly 

gas samples from the vent gas stream to determine Vol

content in natural gas 

out of the AGR unit as determined in 

paragraph(d)(7) of this section.

CO2

(6) If a continuous gas analyzer is installed on the 

inlet gas stream, then the continuous gas analyzer results 

must be used. If continuous gas analyzer is not available, 

either install a continuous gas analyzer or take quarterly 

according to methods set forth in §98.234(b).
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gas samples from the inlet gas stream to determine VolI 

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

(7) Determine volume fraction of CO2 content in 

natural gas out of the AGR unit using one of the methods 

specified in paragraph(d)(7). 

(i) If a continuous gas analyzer is installed on the

outlet gas stream, then the continuous gas analyzer results 

must be used. If a continuous gas analyzer is not 

available, you may install a continuous gas analyzer. 

(ii) If a continuous gas analyzer is not available or 

installed, quarterly gas samples may be taken from the 

outlet gas stream to determine VolO according to methods set 

forth in §98.234(b).

(iii) Use sales line quality specification for CO2 in 

natural gas.

(8) Calculate CO2 volumetric emissions at standard 

conditions using calculations in paragraph (t) of this 

section.

(9) Mass CO2 emissions shall be calculated from 

volumetric CO2

(e) 

emissions using calculations in paragraph (v) 

of this section.

Dehydrator vent stacks. For dehydrator vent 

stacks, calculate annual CH4 and CO2 emissions using 
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calculation methodologies described in paragraphs (e)(1) or 

(e)(2) of this section.

(1) Calculation Methodology 1. Calculate annual mass 

emissions from dehydrator vent stacks with throughput 

greater than or equal to 0.4 million standard cubic feet 

per day using a software program, such as AspenTech HYSYS® 

or GRI-GLYCalc, that uses the Peng-Robinson equation of 

state to calculate the equilibrium coefficient, speciates 

CH4 and CO2 emissions from dehydrators, and has provisions 

to include regenerator control devices, a separator flash 

tank, stripping gas and a gas injection pump or gas assist 

pump. A minimum of the following parameters determined by 

engineering estimate based on best available data must be 

used to characterize emissions from dehydrators:

(i) Feed natural gas flow rate.

(ii) Feed natural gas water content.

(iii) Outlet natural gas water content.

(iv) Absorbent circulation pump type (natural gas 

pneumatic/ air pneumatic/ electric). 

(v) Absorbent circulation rate.

(vi) Absorbent type: including triethylene glycol 

(TEG), diethylene glycol (DEG) or ethylene glycol (EG).

(vii) Use of stripping natural gas.
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(viii) Use of flash tank separator (and disposition 

of recovered gas).

(ix) Hours operated.

(x) Wet natural gas temperature and pressure.

(xi) Wet natural gas composition. Determine this 

parameter by selecting one of the methods described under

paragraph (e)(2)(xi) of this section.

(A) Use the wet natural gas composition as defined in 

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

(B) If wet natural gas composition cannot be 

determined using paragraph (u)(2)(i) of this section, 

select a representative analysis.

(C) You may use an appropriate standard method 

published by a consensus-based standards organization if 

such a method exists or you may use an industry standard 

practice as specified in §98.234 (b)(1) to sample and 

analyze wet natural gas composition.

(D) If only composition data for dry natural gas is 

available, assume the wet natural gas is saturated. 

(2) Calculation Methodology 2. Calculate annual CH4

and CO2 emissions from glycol dehydrators with throughput 

less than 0.4 million cubic feet per day using Equation W-5

of this section:
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* *1000 E , EF Count s i= i (Eq. W-5)

Where:

Es,i = Annual total volumetric GHG emissions (either CO2 

or CH4) at standard conditions in cubic feet.

EFi = Population emission factors for glycol 

dehydrators in thousand standard cubic feet per 

dehydrator per year. Use 73.4 for CH4 and 3.21 for 

CO2. 

Count = Total number of glycol dehydrators with 

throughput less than 0.4 million cubic feet. 

1000 = Conversion of EFi

(5) Dehydrators that use desiccant shall calculate 

emissions from the amount of gas vented from the vessel 

in thousand standard cubic to 

cubic feet. 

(3) Determine if dehydrator unit has vapor recovery. 

Adjust the emissions estimated in paragraphs (e)(1) or 

(e)(2) downward by the magnitude of emissions captured.

(4) Calculate annual emissions from dehydrator vent 

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

follows:

(A) Use the dehydrator vent stack volume and gas 

composition as determined in paragraphs (e)(1) and (e)(2) 

of this section.

(B) 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.
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every time it is depressurized for the desiccant refilling 

process using Equation W-6 of this section. 

Es,n = (H*D2*P*P2*%G*365days/yr) (Eq. W-6)

(4*P1*T*1,000cf/Mcf*100)

Where:

Es,n = Annual natural gas emissions at standard 

conditions in cubic feet. 

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).

100 = Conversion of %G to fraction

(6) 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 one of the calculation methodologies 

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

section. 

Calculation Methodology 1. For one well of each 

unique well tubing diameter and producing horizon/formation 

combination in each gas producing field (see §98.238 for 
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the definition of Field) where gas wells are vented to the 

atmosphere to expel liquids accumulated in the tubing, a 

recording flow meter shall be installed on the vent line 

used to vent gas from the well (e.g. on the vent line off 

the wellhead separator or atmospheric storage tank) 

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

emissions from well venting for liquids unloading using 

Equation W-7 of this section.

= ∑∑

h t

Ea,n Th,t *FRh,t (Eq. W-7)

Where: 

Ea,n = Annual natural gas emissions at actual conditions 

in cubic feet. 

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

from all wells of the same tubing diameter and 

producing horizon/formation combination during 

the year.

FRh,t

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

calculated for each unique tubing diameter and producing 

horizon/formation combination in each producing field by 

averaging the recorded flow rates for the recorded time of 

one representative well venting to the atmosphere. 

= Average flow rate in cubic feet per hour of the 

measured well venting, under actual conditions as 

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

section.

(i) Determine the well vent average flow rate as 

specified under paragraph (f)(1)(i) of this section.
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(B) This average flow rate is applied to all wells in 

the field that have the same tubing diameter and producing 

horizon/formation combination, for the number of hours of 

venting these wells.

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

calendar year for each reporting field and horizon starting 

the first calendar year of data collection. 

(ii) Calculate natural gas volumetric emissions at 

standard conditions using calculations in paragraph (t) of 

this section.

(2) Calculation Methodology 2. Calculate emissions 

from each well venting for liquids unloading using Equation 

W-8 of this section.

Ea,n = {(0.37×10-3

)*CD2*WD*SP*NV}+{SFR*(HR-1.0)*Z}(Eq. W-8)

Where:

Ea,n = Annual natural gas emissions at actual 

conditions, in cubic feet/year. 

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

pounds per square feet)

CD = Casing diameter (inches).

WD = Well depth to first producing horizon (feet).

SP = Shut-in pressure (psia).

NV = Number of vents per year.

SFR = Average sales flow rate of gas well in cubic 

feet per hour.

HR = Hours that the well was left open to the 

atmosphere during unloading. 
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1.0 = Hours for average well to blowdown casing 

volume at shut-in pressure.

Z = If HR is less than 1.0 then Z is equal to 0. 

If HR is greater than or equal to 1.0 then Z 

is equal to 1.

(i) Calculate natural gas volumetric emissions at 

standard conditions using calculations in paragraph (t) of 

this section.

(3) Calculation Methodology 3. Calculate emissions 

from each well venting to the atmosphere for liquids 

unloading with plunger lift assist using Equation W-9 of 

this section.

Ea,n = {(0.37×10-3

)*TD2*WD*SP*NV}+{SFR*(HR-0.5)*Z} (Eq. W-9)

Where:

Ea,n = Annual natural gas emissions at actual 

conditions, in cubic feet/year. 

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

pounds per square feet)

TD = Tubing diameter (inches).

WD = Tubing depth (feet).

SP = Sales line pressure (psia).

NV = Number of vents per year.

SFR = Average sales flow rate of gas well in cubic 

feet per hour.

HR = Hours that the well was left open to the 

atmosphere during unloading. 

0.5 = Hours for average well to blowdown tubing 

volume at sales line pressure.
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Z = If HR is less than 0.5 then Z is equal to 0. 

If HR is greater than or equal to 0.5 then Z 

is equal to 1.

(i) Calculate natural gas volumetric emissions at 

standard conditions using calculations in paragraph (t) of 

this section. 

(4) Both CH4 and CO2 volumetric and mass emissions 

shall be calculated from volumetric natural gas emissions 

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

section.

(g) Gas well venting during completions and workovers 

from hydraulic fracturing. Calculate emissions from gas 

well venting during completions involving hydraulic 

fracturing in new wells and well workovers using Equation 

W-10 of this section. 

Ea,n = T * FR (Eq. W-10)

Where:

Ea,n

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

atmosphere or to a flare during well completions and 

= Annual emissions in cubic feet at actual 

conditions from gas well venting during 

completions following hydraulic fracturing 

T = Cumulative amount of time in hours of all well 

completion venting in a field during the year.

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

actual conditions, as required in paragraph 

(g)(1) of this section.
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workovers from hydraulic fracturing shall be determined 

using either of the calculation methodologies described in 

this paragraph (g)(1).

(i) Calculation Methodology 1

(ii) 

. 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, ahead of a flare 

if used, to measure the backflow venting event according to 

methods set forth in §98.234(b). 

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

venting to the atmosphere or a flare is determined from the 

flow recording over the period of backflow venting. 

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

completions in the field and to all well workovers in the 

field for the number of hours of venting these wells. 

(C) New flow rates for completions and workovers are 

calculated every other calendar year for each reporting 

field and horizon starting in the first calendar year of 

data collection. 

Calculation Methodology 2. For one well 

completion in each gas producing field and for one well 

workover in each gas producing field, record the well 

flowing pressure upstream(and downstream in subsonic flow)

of a well choke according to methods set forth in 
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§98.234(b) to calculate intermittent well flow rate of gas 

during venting to the atmosphere or a flare. Calculate 

emissions using Equation W-11 for subsonic flow or Equation 

W-12 for sonic flow:

































− 













 =

1.758

1

2

1.515

1

2 35.3* * 3430* * P

P

P

P

FR A T (W-11)

Where:

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

subsonic flow conditions, in cubic feet per 

second.

A = Cross sectional area of orifice (m2).

P1 = Upstream pressure (Pa).

T = Upstream temperature (K).

P2 = Downstream pressure (Pa).

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

35.3 = Conversion from m3 to ft3

FR = 35.3* A* 187.08*T

.

(W-12)

Where:

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

sonic flow conditions, in cubic feet per 

second.

A = Cross sectional area of orifice (m2).

T = Upstream temperature (K).

187.08 = Constant with units of m2/sec2 * K.

35.3 = Conversion from m3 to ft3

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

venting across the choke is calculated for one well 

completion in each field and for one well workover in each 

field by averaging the gas flow rates during venting to the 

atmosphere or a flare. 

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

completions in the field and to all well workovers in the 

field for the number of hours of venting these wells. 

(C) New flow rates for completions and workovers are 

calculated every other calendar year for each reporting 

field and horizon starting in the first calendar year of 

data collection. 

(2) Calculate natural gas volumetric emissions at 

standard conditions using calculations in paragraph (t) of 

this section.

(3) Both CH4 and CO2

(4) Calculate annual emissions from gas well venting 

during well completions and workovers from hydraulic 

fracturing to flares as follows:

volumetric and mass emissions 

shall be calculated from volumetric natural gas emissions 

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

section.
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(i) Use the gas well venting volume during well 

completions and workovers as determined in paragraph (g) of 

this section.

(ii) Use the calculation methodology of flare stacks 

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

venting during well completions and workovers using 

hydraulic fracturing emissions from the flare.

(h) Gas well venting during completions and workovers 

without hydraulic fracturing

Ea,n = V * T

. Calculate emissions from 

each gas well venting during well completions and workovers 

not involving hydraulic fracturing using Equation W-13 of 

this section:

(Eq. W-13)

Where:

Ea,n = Annual natural gas emissions in cubic feet at 

actual conditions from gas well venting during 

well completions or workovers without hydraulic 

fracturing. 

V = Average daily gas production rate in cubic feet 

per minute. This is the total annual gas 

production volume divided by total number of 

minutes the well is producing to the sales line.

T = Cumulative amount of time of well venting in 

minutes during the year.

(1) Calculate natural gas volumetric emissions at 

standard conditions using calculations in paragraph (t) of 

this section. 
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(2) 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.

(3) Calculate annual emissions from gas well venting 

during well completions and workovers not involving 

hydraulic fracturing to flares as follows:

(i) Use the gas well venting volume during well 

completions and workovers as determined in paragraph (h) of 

this section.

(ii) Use the calculation methodology of flare stacks 

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

venting during well completions and workovers emissions 

without hydraulic fracturing from the flare.

(i) Blowdown vent stacks

(1) Calculate the total volume (including pipelines, 

compressor case or cylinders, manifolds, suction and 

discharge bottles and vessels) between isolation valves 

. Calculate blowdown vent 

stack emissions from depressurizing equipment to the 

atmosphere (excluding depressurizing to a flare, overpressure relief, operating pressure control venting and 

blowdown of non-GHG gases; desiccant dehydrator blowdown 

venting before reloading is covered in §98.233(e)(5)) as 

follows: 
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determined by engineering estimate based on best available 

data.

(2) If the total volume between isolation valves is 

greater than or equal to 5000 standard cubic feet, retain 

logs of the number of blowdowns for each equipment type 

(including but not limited to compressors, vessels, 

pipelines, headers, fractionators, and tanks). Blowdown 

volumes smaller than 5000 standard cubic feet are exempt 

from reporting under paragraph (i) of this section.

(3) Calculate the total annual venting emissions for 

each equipment type using Equation W-14 of this section:

( )

( ) 













 −















+

+ = V C

T P

T P

E N V v

a s

s a

s n v *

459.67

459.67 , * (Eq. W-14)

Where:

Es,n = Annual natural gas venting emissions at standard 

conditions from blowdowns in cubic feet.

N = Number of repetitive blowdowns for each equipment 

type of a unique volume in calendar year.

Vv = Total volume of blowdown equipment chambers 

(including pipelines, compressors and vessels) 

between isolation valves in cubic feet.

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

purged or zero if the equipment is purged using 

non-GHG gases.

Ts = Temperature at standard conditions (oF).

Ta = Temperature at actual conditions in the blowdown 

equipment chamber (o

F).
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Ps = Absolute pressure at standard conditions (psia).

Pa = Absolute pressure at actual conditions in the 

blowdown equipment chamber (psia).

(4) Calculate both CH4 and CO2 mass emissions from 

volumetric natural gas emissions using calculations in 

paragraph (v) of this section.

(5) Calculate total annual venting emissions for all 

blowdown vent stacks by adding all standard volumetric and 

mass emissions determined in Equation W-14 and paragraph 

(i)(4) of this section, respectively.

(j) Onshore production storage tanks. For emissions 

from atmospheric pressure fixed roof storage tanks 

receiving produced liquids from onshore petroleum and 

natural gas production facilities (including stationary 

liquid storage not owned or operated by the reporter), 

calculate annual CH4 and CO2

(1) 

emissions using any of the 

calculation methodologies described in paragraph (j) of 

this section. 

Calculation Methodology 1. For separators with 

oil throughput greater than or equal to 10 barrels per day. 

Calculate annual CH4 and CO2 emissions from onshore 

production storage tanks using operating conditions in the 

last wellhead gas-liquid separator before liquid transfer 

to storage tanks. Calculate flashing emissions with a 

software program, such as AspenTech HYSYS® or API 4697 E&P 
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Tank, that uses the Peng-Robinson equation of state, models 

flashing emissions, and speciates CH4 and CO2

(B) If separator oil composition and Reid vapor 

pressure data are available through your previous analysis,

emissions that 

will result when the oil from the separator enters an 

atmospheric pressure storage tank. A minimum of the 

following parameters determined for typical operating 

conditions over the year by engineering estimate and 

process knowledge based on best available data must be used 

to characterize emissions from liquid transferred to tanks.

(i) Separator temperature.

(ii) Separator pressure.

(iii) Sales oil or stabilized oil API gravity. 

(iv) Sales oil or stabilized oil production rate.

(vi) Ambient air temperature.

(vii) Ambient air pressure.

(viii) Separator oil composition and Reid vapor 

pressure. If this data is not available, determine these 

parameters by selecting one of the methods described under 

paragraph (j)(1)(viii) of this section.

(A) If separator oil composition and Reid vapor 

pressure data are provided with the software program, 

select the default values which most closely match your 

separator pressure first, and API gravity secondarily.
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select the latest available analysis that is representative 

of produced crude oil or condensate from the field. 

(C) Analyze a representative sample of separator oil 

in each field for oil composition and Reid vapor pressure 

using an appropriate standard method published by a 

consensus-based standards organization.

(2) Calculation Methodology 2. Calculate annual CH4

and CO2 emissions from onshore production storage tanks for 

wellhead gas-liquid separators with oil throughput greater 

than or equal to 10 barrels per day by assuming that all of 

the CH4 and CO2 in solution at separator temperature and 

pressure is emitted from oil sent to storage tanks. You may 

use an appropriate standard method published by a 

consensus-based standards organization if such a method 

exists or you may use an industry standard practice as 

described in §98.234(b)(1) to sample and analyze separator 

oil composition at separator pressure and temperature.

(3) Calculation Methodology 3. For wells with oil 

production greater than or equal to 10 barrels per day that 

flow directly to atmospheric storage tanks without passing 

through a wellhead separator, calculate CH4 and CO2

emissions by either of the methods in paragraph (j)(3) of 

this section:
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(i) If well production oil and gas compositions are 

available through your previous analysis, select the latest 

available analysis that is representative of produced oil 

and gas from the field and assume all of the CH4 and CO2 in 

both oil and gas are emitted from the tank.

(ii) If well production oil and gas compositions are 

not available, use default oil and gas compositions in 

software programs, such as API 4697 E&P Tank, that most 

closely match your well production gas/oil ratio and API 

gravity.

(4) Calculation Methodology 4. For wells with oil 

production greater than or equal to 10 barrels per day that 

flow to a separator not at the well pad, calculate CH4 and 

CO2 emissions by either of the methods in paragraph (j)(4)

of this section:

(i) If well production oil and gas compositions are 

available through your previous analysis, select the latest 

available analysis that is representative of oil at 

separator pressure determined by best available data and 

assume all of the CH4 and CO2

(ii) If well production oil composition is not 

available, use default oil composition in software 

programs, such as API 4697 E&P Tank, that most closely 

in the oil is emitted from the 

tank.
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match your well production API gravity and pressure in the 

off-well pad separator determined by best available data. 

Assume all of the CH4 and CO2 in the oil phase is emitted 

from the tank.

(iii) Assume all of the flash gas from the default 

flash data is emitted from the tank for flare emissions 

calculation in paragraph (j)(7) of this section.

(5) Calculation Methodology 5. Calculate annual CH4

and CO2

E EF Count s i i

* , =

emissions from onshore production tanks based on 

well head gas-liquid separators and wells flowing off the 

well pad without passing through a gas-liquid separator 

with crude oil of less than 45° API gravity and throughput 

less than 10 barrels per day using Equation W-15 of this 

section:

(Eq. W-15)

Where:

Es,i = Annual total volumetric GHG emissions (either CO2 

or CH4) at standard conditions in cubic feet.

EFi = Populations emission factor for separators and 

wells in thousand standard cubic feet per 

separator or well per year, 16.1 for CH4 and 0.707 

for CO2.

Count = Total number of separators and wells with crude 

oil of less than 45° API gravity throughput less 

than 10 barrels per day.
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(6) Determine if the storage tank receiving your 

separator oil has a vapor recovery system. (i) Adjust the 

emissions estimated in paragraphs (j)(1) through (j)(5) of 

this section downward by the magnitude of emissions 

recovered using a vapor recovery system as determined by 

engineering estimate based on best available data.

(ii) [Reserved]

(7) Determine if the storage tank receiving your 

separator oil is vented to flare(s).

(i) Use your separator flash gas 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 your 

contribution to storage tank emissions from the flare.

(8) Calculate emissions from occurrences of well pad 

gas-liquid separator liquid dump valves not closing during 

the calendar year by using Equation W-16.

( ) ( ( )) Es i= CFn En Tn + Et −Tn * * * 8760 , (Eq. W-16)

Where:

Es,i = Annual total volumetric GHG emissions at 

standard conditions from each storage tank in 

cubic feet.

En = Storage tank emissions as determined in 

calculation methods 1, 2, or 5 (with wellhead 

separators) of this section during time Tn in 

cubic feet per hour. 
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Tn = Total time the dump valve is not closing 

properly in the calendar year in hours. Tn is 

estimated by maintenance or operations records 

(records) such that when a record shows the 

valve to be open improperly, it is assumed the 

valve was open for the entire time period 

preceding the record starting at either the 

beginning of the calendar year or the previous 

record showing it closed properly within the 

calendar year. If a subsequent record shows it 

is closing properly, then assume from that time 

forward the valve closed properly until either 

the next record of it not closing properly or, 

if there is no subsequent record, the end of the 

calendar year. 

CFn = Correction factor for tank emissions for time 

period Tn is 3.87 for sales oil less than 45 API 

gravity. Correction factor for tank emissions 

for time period Tn is 5.37 for sales oil equal 

to or greater than 45 API gravity. Correction 

factor for tank emissions for time period Tn is 

1.0 for periods when the dump valve is closed.

Et = Storage tank emissions as determined in 

calculation methods 1, 2, or 3 of this section 

at maintenance or operations during the time the 

dump valve is closing properly (ie.8760-Tn) in 

cubic feet per hour. 

(k) Transmission storage tanks

(1) Monitor the tank vapor vent stack annually for 

emissions using an optical gas imaging instrument according 

to methods set forth in §98.234(a)(1) for a duration of 5 

. For condensate 

storage tanks, either water or hydrocarbon, without vapor 

recovery or thermal control devices in onshore natural gas 

transmission compression facilities calculate annual 

emissions from compressor scrubber dump valve leakage as 

follows: 
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minutes. Or you may annually monitor leakage through 

compressor scrubber dump valve(s) into the tank using an 

acoustic detection device according to methods set forth in 

§98.234(a)(5).

(2) If the tank vapors are continuous for 5 minutes, 

or the acoustic detection device detects a leak, then use 

one of the following two methods in paragraph (k)(2) of 

this section to quantify emissions: 

(i) Use a meter, such as a turbine meter, to estimate 

tank vapor volumes according to methods set forth in 

§98.234(b). If you do not have a continuous flow 

measurement device, you may install a flow measuring device 

on the tank vapor vent stack.

(ii) Use an acoustic detection device on each scrubber 

dump valve connected to the tank according to the method 

set forth in §98.234(a)(5).

(iii) Use the appropriate gas composition in 

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

(3) If the leaking dump valve(s) is fixed following 

leak detection, the annual emissions shall be calculated 

from the beginning of the calendar year to the time the 

valve(s) is repaired.

(4) Calculate emissions from storage tanks to flares 

as follows:
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(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.

Ea,n = GOR * FR*D

Calculate well 

testing venting and flaring emissions as follows:

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

hydrocarbon production from each well tested.

(2) If GOR cannot be determined from your available 

data, then you must measure quantities reported in §98.233 

according to one of the two procedures in paragraph (l)(2) 

of this section to determine GOR:

(i) You may use an appropriate standard method 

published by a consensus-based standards organization if 

such a method exists.

(ii) Or you may use an industry standard practice as 

described in §98.234(b)(1).

(3) Estimate venting emissions using Equation W-17 of 

this section.

(Eq. W-17)

Where:
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Ea,n = Annual volumetric natural gas emissions from well 

testing in cubic feet under actual conditions.

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

of oil; oil here refers to hydrocarbon liquids 

produced of all API gravities.

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

being tested.

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

tested.

(4) Calculate natural gas volumetric emissions at 

standard conditions using calculations in paragraph (t) of 

this section.

(5) Calculate both CH4 and CO2

(m) 

volumetric and mass 

emissions from volumetric natural gas emissions using 

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

(6) 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.

Associated gas venting and flaring. Calculate 

associated gas venting and flaring emissions not in 

conjunction with well testing (refer to paragraph (l) of 

this section) as follows:
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(1) Determine the GOR ratio of the hydrocarbon 

production from each well whose associated natural gas is 

vented or flared. If GOR from each well is not available, 

the GOR from a cluster of wells in the same field shall be 

used. 

(2) If GOR cannot be determined from your available 

data, then use one of the two procedures in paragraph 

(m)(2) of this section to determine GOR:

(i) You may use an appropriate standard method 

published by a consensus-based standards organization if 

such a method exists.

(ii) Or you may use an industry standard practice as 

described in §98.234(b)(1).

(3) Estimate venting emissions using Equation W-18 of 

this section.

Ea,n = GOR * V (Eq. W-18)

Where:

Ea,n = Annual volumetric natural gas emissions from 

associated gas venting under actual conditions, 

in cubic feet.

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

of oil; oil here refers to hydrocarbon liquids 

produced of all API gravities.

V = Total volume of oil produced in barrels in the 

calendar year.
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(4) Calculate natural gas volumetric emissions at 

standard conditions using calculations in paragraph (t) of 

this section.

(5) Calculate both CH4 and CO2 volumetric and mass 

emissions from volumetric natural gas emissions using 

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

(6) 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 (4) 

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 stack emissions. 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 

install a flow measuring device on the flare or use 

engineering calculations based on process knowledge, 

company records, and best available data. 
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(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) For onshore natural gas production, determine 

natural gas composition using (u)(2)(i) of this section.

(ii) For onshore natural gas processing, when the 

stream going to flare is natural gas, use the GHG mole 

percent in feed natural gas for all streams upstream of the 

de-methanizer or dew point control, and GHG mole percent in 

facility specific residue gas to transmission pipeline 

systems for all emissions sources downstream of the demethanizer overhead or dew point control for onshore 

natural gas processing facilities.

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

hydrocarbon product stream, such as ethane, propane, 

butane, pentane-plus and mixed light hydrocarbons, then use 

a representative composition from the source for the stream 

determined by engineering calculation based on process 

knowledge and best available data.
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(3) Determine flare combustion efficiency from 

manufacturer. If not available, assume that flare 

combustion efficiency is 98 percent.

(4) Calculate GHG volumetric emissions at actual 

conditions using Equations W-19, W-20, and W-21 of this 

section.

( ) , 4 * 4 *(1 ) a CH Va X CH E un − combusted = −η (Eq. W-19)

( ) a,CO2 Va * X CO2 E un − combusted = (Eq. W-20)

( ) = ∑

j

a CO Va Yj Rj E combusted * * * , 2 η (Eq. W-21)

Where:

Ea,CH4(un-combusted) = Contribution of annual un-combusted 

CH4 emissions from flare stack in 

cubic feet, under actual conditions.

Ea,CO2(un-combusted) = Contribution of annual un-combusted 

CO2 emissions from flare stack in 

cubic feet, under actual conditions.

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

emissions from flare stack in cubic 

feet, under actual conditions.

Va = Volume of gas sent to flare in cubic 

feet, during the year.

η = Fraction of gas combusted by a burning 

flare (default is 0.98). For gas sent 

to an unlit flare, η is zero.XCH4 = 

Mole fraction of CH4 in gas to the 

flare.

XCO2 = Mole fraction of CO2 in gas to the 

flare.

Yj = Mole fraction of gas hydrocarbon 

constituents j (such as methane, 

ethane, propane, butane, and pentanesplus).
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Rj = Number of carbon atoms in the gas 

hydrocarbon constituent j: 1 for 

methane, 2 for ethane, 3 for propane, 

4 for butane, and 5 for pentanes 

plus).

(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 total annual emission from flare stacks 

using Equation W-40 in paragraph (z) of this section.

(8) Calculate N2O emissions from flare stacks using 

Equation W-39 in paragraph (z) of this section.

(9) The flare emissions determined under paragraph 

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

calculated and reported under other paragraphs of this 

section to avoid double counting of these emissions. 

(o) Centrifugal compressor venting

(1) For each centrifugal compressor covered by 

§98.232 (d)(2), (e)(2), (f)(2), (g)(2), and (h)(2) 

determine the volume of vapors from wet seal oil degassing 

tank sent to an atmospheric vent or flare, using a 

temporary or permanent flow meter such as a vane anemometer 

. Calculate 

emissions from centrifugal compressor vents as follows: 
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according to methods set forth in §98.234(b), and the steps 

listed in paragraphs (o)(2) through (o)(8) of this section. 

If you do not have a permanent flow meter, you may install 

a permanent flow meter on the wet seal oil degassing tank 

vent.

(i) Estimate annual emissions using the flow meter 

measurement and Equation W-22 of this section.

* * *(1 ) Es,i

= MT T Mi − B (Eq. W-22)

Where:

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

emissions at standard conditions, as specified in 

paragraphs (o)(3)(i) through (iv) of this section 

in cubic feet.

MT = Meter reading of gas emissions in standard cubic 

feet per hour.

T = Total time the compressor associated with the wet 

seal(s) is operational in the calendar year in 

hours.

Mi

(2) You must conduct an annual measurement for each 

compressor, except as specified in paragraph (o)(4) of this 

section. Measure emissions from all vents (including 

emissions manifolded to common vents) including unit 

= Mole fraction of GHG i in the degassing vent gas; 

use the appropriate gas compositions in paragraph 

(u)(2) of this section.

B = Fraction of operating time that centrifugal 

compressor wet seal degassing vent gas is sent to 

vapor recovery or fuel gas as determined by 

keeping logs of the number of operating hours for 

the vapor recovery system and the time that vent 

gas is directed to the fuel gas system or sales.
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isolation valves and blowdown vents using a temporary meter 

such as a vane anemometer or a permanent meter such as an 

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

If you do not have a flow meter, you may install a port for 

insertion of a temporary meter, or a permanent flow meter,

on the vents. For blowdown vents, you can use one of the 

following end of pipe methods: calibrated bagging or high 

volume sampler according to methods set forth in §98.234 

(c) and §98.234(d), respectively. For through-valve 

leakage to open ended vents, such as unit isolation valves 

on shutdown, depressurized compressors and blowdown valves 

on pressurized compressors, you may use an acoustic 

detection device according to methods set forth in 

§98.234(a). Record the vent type and the mode of the 

compressor, during the annual measurement as follows:

(i) Operating mode, blowdown vents. 

(ii) Operating mode, wet seal oil degassing vents.

(iii) Not operating, depressurized mode, unit 

isolation valves, without blind flanges, leakage through 

open blowdown vent.

(3) Each compressor must be measured at least once in 

any three consecutive calendar years, in each mode in 

paragraphs (o)(3)(i) through (o)(3)(iii) of this section.
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(4) You must combine emissions separately from 

paragraph (o)(3)(i) of this section for blowndown vents, 

measured in the operating or standby, pressurized mode, and 

from paragraph (o)(3)(iii) of this section for unit 

isolation valve leakage in shutdown, depressurized mode.

(5) You must combine emissions from paragraph 

(o)(3)(ii) for seal oil degassing vent in the operating 

mode.

(6) You shall use the flow meter readings at standard 

conditions for all vented sources calculated in paragraph 

(o)(1), (o)(2), (o)(3), (o)(4), (o)(5), (o)(6), and (o)(7) 

of this section to develop for each reporter the three 

emission factors using Equation W-23 of this section. The 

emission factors must be calculated annually. You must use

all measurements from the current calendar year and the 

preceding two calendar years, totaling three consecutive 

calendar years of measurements in paragraph (o)(4) of this 

section.

= ∑ m

m

m Count

MT EF (Eq. W-23)

Where:

EFm = Reporter emission factors for compressor in the 

three modes i (operating blowdown vent, operating 

wet seal oil degassing vent, and not operating, 

depressurized) in cubic feet per hour.
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MTm = Meter readings from all centrifugal compressor 

vents in each mode in (o)(3)(i) through 

(o)(3)(iii) of this section in cubic feet per 

hour.

Countm

= ∑

i

Es i EFi Ti GHGi* * ,

= Total number of compressors measured from 

paragraphs (o)(3)(i) through (o)(3)(iii) of this 

section.

(7) Calculate emissions from each centrifugal 

compressor, with wet or dry seals, using Equation W-24 of 

this section.

(Eq. W-24)

Where:

Es,i = Annual total volumetric GHG emissions at 

standard conditions from each centrifugal 

compressor in cubic feet.

EFm = Reporter emission factor for each mode i, in 

cubic feet per hour, from Eq. W-23 of this 

section.

Tm = Total time in hours per year the compressor was 

in each mode of Eq. W-23 of this section, with 

operating blowdown vent time including time in 

standby, depressurized mode.

GHGi = For 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 (a)(3) through 

(a)(8),GHGi

Es i Count EFi* , =

equals 1.

(8) Onshore petroleum and natural gas production

shall calculate emissions from centrifugal compressor wet 

seal oil degassing vents as follows:

(Eq. W-25)

Where:
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Es,i = Annual total volumetric GHG emissions at 

standard conditions from centrifugal compressor 

wet seals in cubic feet.

Count = Total number of centrifugal compressors for the 

reporter.

EFi = Emission factor for GHG i. Use 12 thousand 

standard cubic feet per year per compressor for 

CH4 and 530 thousand standard cubic feet per 

year per compressor for CO2.

(9) Calculate both CH4 and CO2 mass emissions from 

volumetric emissions using calculations in paragraph (v) of 

this section.

(10) Calculate emissions from seal oil degassing vent 

vapors to flares as follows:

(i) Use the seal oil 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.

(p) Reciprocating compressor venting

(1) For each reciprocating compressor rod packing vent 

covered in §98.232 (d)(1), (e)(1), (f)(1), (g)(1), and 

(h)(1) using a meter flow measurement according to methods 

set forth in §98.234(b) and Equation W-26 of this section.

. Calculate 

emissions from all reciprocating compressor vents as 

follows:
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Es i MT T Mi* * , = (Eq. W-26)

Where:

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

emissions at standard conditions, as specified in 

paragraphs (p)(4)(i) through (v) of this section 

in cubic feet.

MT = Meter volumetric reading of gas emissions 

standard cubic feet per hour.

T = Total time the compressor associated with the 

venting is operational in the calendar year in 

hours.

Mi

(ii) Use a temporary meter such as a vane anemometer 

or a permanent meter such as an orifice meter to measure 

emissions from all vents (including emissions manifolded to 

a common vent) including rod packing vents, unit isolation 

valve vents, and blowdown vents according to methods set 

= Mole fraction 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 vents using 

one of the following end of pipe methods: calibrated 

bagging or high volume sampler according to methods set 

forth in §98.234 (c) and §98.234(d), respectively.
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forth in §98.234(b). If you do not have a permanent flow 

meter, you may install a port for insertion of a temporary 

meter or a permanent flow meter on the vents. For throughvalve leakage to open ended vents, such as unit isolation 

valves on shutdown, depressurized compressors and blowdown 

valves on pressurized compressors, you may use an acoustic 

detection device according to methods set forth in 

§98.234(a).

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

line use the following method to measure emissions:

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

to conduct annual leak detection of equipment leaks from 

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

compressor crank case breather cap or other vent with a 

closed distance piece.

(ii) Measure emissions found in paragraph (p)(3)(i) 

of this section using a appropriate meter, or calibrated 

bag, or high volume sampler according to methods set forth 

in §98.234(b), (c), and (d), respectively.

(4) You must conduct an annual measurement for each 

compressor, except as specified in paragraph (p)(5) of this 

section. Record the vent type and the mode of the 

compressor during the annual measurement as follows:
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(i) Operating and standby pressurized mode, blowdown 

vent not manifolded to rod packing vents. 

(ii) Operating mode, rod packing emissions from 

paragraphs(p)(2) or (p)(3) of this section.

(iii) Not operating, depressurized mode, unit 

isolation valves, without blind flanges, leakage through 

open blowdown vent.

(5) Each compressor must be measured at least once in 

any three consecutive calendar years, in each mode in 

paragraphs (p)(4)(i) through (iii) of this section.

(6) You must combine emissions separately from 

paragraph (p)(4)(i) of this section for blowndown vents, 

measured in the operating and standby pressurized modes, 

and from (p)(4)(iii) for unit isolation valve leakage in 

shutdown depressurized mode.

(7) You must combine emissions separately from 

paragraph (p)(4)(ii) for rod packing in operating mode and 

in standby pressurized mode.

(8) You shall use the meter readings at standard 

conditions for all vented sources calculated in paragraph 

(p)(1), (p)(2), (p)(3), (p)(4), (p)(5), (p)(6), and (p)(7) 

of this section to develop for each reporter the three 

emission factors using Equation W-27 of this section. The 

emission factors must be calculated annually. You must use 
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all measurements from the current calendar year and the 

preceding two calendar years, totaling three consecutive 

calendar years of measurements in paragraph (p)(5) of this 

section.

= ∑ m

m

m Count

MT EF (Eq. W-27)

Where:

EFm = Reporter emission factor for compressor in the 

three modes i (operating and standby pressurized, 

operating mode rod packing, and not operating, 

depressurized) in cubic feet per hour.

MTm = Meter readings from all reciprocating compressor 

vents in each mode in paragraphs(p)(4)(i) through 

(p)(4)(iii) of this section in cubic feet per 

hour.

Countm

= ∑

i

Es i EFi Ti GHGi* * ,

= Total number of compressors measured from 

paragraphs (p)(4)(i) through (p)(4)(iii) of this 

section.

(9) Calculate emissions from each compressor using 

Equation W-28 of this section.

(Eq. W-28)

Where:

Es,i = Annual total volumetric GHG emissions at 

standard conditions from each compressor in 

cubic feet.

EFm = Reporter emission factor for each mode i, in 

cubic feet per hour, from Eq. W-27 of this 

section.

Tm = Total time in hours per year the compressor was 

in each mode of Eq. W-27 of this section.
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GHGi = For 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 (a)(3) through 

(a)(8),GHGi

Es i Count EFi* , =

equals 1.

(10) Onshore petroleum and natural gas production 

shall calculate emissions from reciprocating compressor rod 

packing venting as follows:

(Eq. W-29)

Where:

Es,i = Annual total volumetric GHG emissions at 

standard conditions from reciprocating 

compressor rod packings in cubic feet.

Count = Total number of reciprocating compressors for 

the reporter.

EFi = Emission factor for GHG i. Use 9.48 thousand 

standard cubic feet per year per compressor for 

CH4 and 0.527 thousand standard cubic feet per 

year per compressor for CO2.

(11) Estimate CH4 and CO2

(q) 

volumetric and mass 

emissions from volumetric natural gas emissions using the 

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

Leak detection and leaker emission factors. You 

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

leak detection(s) of equipment leaks from all sources 

listed in §98.232(d)(7), (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 
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gas content less than 10 percent CH4 plus CO2

Es i EFs GHGi Counts Ts * * * , =

by weight do 

not need to be reported. Tubing systems equal to or less 

than one half inch diameter are exempt from the 

requirements of paragraph (q) of this section and do not 

need to be reported. If equipment leaks are detected for 

sources listed in this paragraph, calculate emissions using 

Equation W-30 of this section for each source with 

equipment leaks. 

(Eq. W-30)

Where:

Es,i = Annual total volumetric GHG emissions at 

standard conditions from each equipment leak 

source in cubic feet.

EFs = 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 GHGi, CH4 or CO2, in the total 

hydrocarbon of the feed natural gas; for other 

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

(a)(8), GHGi equals 1 for CH4 and 1.1 × 10-2 for 

CO2. 

Counts = Total number of this type of emission source 

found to be leaking during Ts

T

.

s = The total time the component was found leaking 

and operational, in hours. If one leak detection 

survey is conducted, assume the component was 

leaking for the entire calendar year. If 

multiple leak detection surveys are conducted, 

assume that the component found to be leaking 

has been leaking since the previous survey or 

the beginning of the calendar year. For the last 

leak detection survey in the calendar year, 
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assume that all leaking components continue to 

leak until the end of the calendar year. 

(1) You must select to conduct either one leak 

detection survey in a calendar year or multiple complete 

leak detection surveys in a calendar year. The number of 

leak detection surveys selected must be conducted during 

the calendar year.

(2) Calculate GHG mass emissions in carbon dioxide 

equivalent at standard conditions using calculations in 

paragraph (v) of this section.

(3) Onshore natural gas processing facilities shall 

use the appropriate default leaker emission factors listed 

in Table W-2 of this subpart for equipment leaks detected 

from valves, connectors, open ended lines, pressure relief 

valves, and meters.

(4) Onshore natural gas transmission compression 

facilities shall use the appropriate default leaker 

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

equipment leaks detected from connectors, block valves,

control valves, compressor blowdown valves, pressure relief 

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

ended lines. 

(5) 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 
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equipment leaks detected from connectors, block valves,

control valves, compressor blowdown valves, pressure relief 

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

ended lines.

(6) LNG storage facilities shall use the appropriate 

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

subpart for equipment leaks detected from valves, pump 

seals, connectors, and other.

(7) LNG import and export facilities shall use the 

appropriate default leaker emission factors listed in Table 

W-6 of this subpart for equipment leaks detected from 

valves, pump seals, connectors, and other.

(8) Natural gas distribution facilities for above 

ground meters and regulators at city gate stations at 

custody transfer, shall use the appropriate default leaker 

emission factors listed in Table W-7 of this subpart for 

equipment leak detected from connectors, block valves,

control valves, pressure relief valves, orifice meters,

other meters, regulators, and open ended lines.

(r) Population count and emission factors. This 

paragraph applies to emissions sources listed in §98.232 

(c)(1), (c)(3), (c)(21), (e)(5), (f)(3), (f)(5), (g)(1), 

(g)(2), (h)(1), (h)(2), (i)(2), (i)(3), (i)(4) and (i)(5), 

on streams with gas content greater than 10 percent CH4 
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plus CO2 by weight. Emissions sources in streams with gas 

content less than 10 percent CH4 plus CO2

Es i Counts EFs GHGi Ts * * * , =

by weight do not 

need to be reported. Tubing systems equal or less than one 

half inch diameter are exempt from the requirements of 

paragraph (r) of this section and do not need to be 

reported. Calculate emissions from all sources listed in 

this paragraph using Equation W-31 of this section.

(Eq. W-31)

Where:

Es,i = Annual volumetric GHG emissions at standard 

conditions from each equipment leak source in 

cubic feet.

Counts = Total number of this type of emission source at 

the facility. Average component counts are 

provided by major equipment piece in Table W-1B 

and Table W-1C. Use average component counts as 

appropriate for operations in Eastern and 

Western U.S., according to Table W-1D.

EFs = Population emission factor for the specific 

source, s listed in Table W-1A and Table W-3 

through Table W-7 of this subpart. Use 

appropriate population emission factor for 

operations in Eastern and Western U.S., 

according to Table W-1D. EF for non-custody 

transfer city gate stations is determined in Eq. 

W-32.

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 (a)(3) 

through (a)(8),GHGi equals 1 for CH4 and 1.1 ×

10-2 for CO2.
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Ts = Total time the specific source s associated with 

the equipment leak emission was operational in 

the calendar 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-1A of this subpart for 

equipment leaks from valves, connectors, open ended lines,

pressure relief valves, pump, flanges, and other. Where 

components are in multi-phase service, use the gas service 

emissions factors if one of the phases is gas. Where 

facilities conduct EOR operations the emissions factor 

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

of gases, including recycle CO2 stream. The component count 

can be determined using either of the methodologies 

described in this paragraph (r)(2). The same methodology 

must be used for the entire calendar year.

(i) Component Count Methodology 1. For all onshore 

natural gas and oil production operations in the facility 

perform the following activities;

(A) Count all major equipment listed in Table W-1B 

and Table W-1C.
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(B) Multiply major equipment counts by the average 

component counts listed in Table W-1B and W-1C for onshore 

natural gas production and onshore oil production 

respectively. Use the appropriate factor in Table W-1A for 

operations in Eastern and Western U.S. according to the 

mapping in Table W-1D.

(ii) Component Count Methodology 2. Count each 

component individually for the facility. Use the 

appropriate factor in Table W-1A for operations in Eastern 

and Western U.S. according to the mapping in Table W-1D.

(3) Underground natural gas storage facilities for 

storage wellheads shall use the appropriate default 

population emission factors listed in Table W-4 of this 

subpart for equipment leak from connectors, valves,

pressure relief valves, and open ended lines.

(4) LNG storage facilities shall use the appropriate 

default population emission factors listed in Table W-5 of 

this subpart for equipment leak from vapor recovery 

compressors.

(5) LNG import and export facilities shall use the 

appropriate default population emission factor listed in 

Table W-6 of this subpart for equipment leak from vapor 

recovery compressors.
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(6) Natural gas distribution facilities shall use the 

appropriate emission factors as described in paragraph 

(r)(6) of this section.

(i) Below grade meters and regulators; mains; and 

services, shall use the appropriate default population 

emission factors listed in Table W-7 of this subpart. 

(ii) Above grade meters and regulators at city gate 

stations not at custody transfer as listed in 

§98.232(i)(2), shall use the total volumetric GHG emissions 

at standard conditions for all equipment leak sources 

calculated in paragraph (q)(8) of this section to develop 

facility emission factors using Equation W-32 of this 

section. The calculated facility emission factor from 

Equation W-32 of this section shall be used in Equation W31 of this section.

Count

E

EF s,i = ∑ (Eq. W-32)

Where:

EF = Facility emission factor for a meter at above 

grade M&R at city gate stations not at custody 

transfer in cubic feet per meter per year.

Es,i = Annual volumetric GHG emissions at standard 

condition from all equipment leak sources at all 

above grade M&R city gate stations at custody 

transfer, from paragraph (q)(8) of this section.

Count = Total number of meter runs at all above grade M&R 

city gate stations at custody transfer.
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(s) Offshore petroleum and natural gas production 

facilities.

(ii) In subsequent calendar years when MMS publishes 

an updated Gulfwide Air Emissions Inventory study, 

reporters shall report emissions based on the latest MMS 

GOADS/DBMS methodology.

 Report GHG emissions from all “stationary 

fugitive” and “stationary vented” sources for each platform 

as identified in the United States Department of the 

Interior, Minerals Management Service (MMS), Gulf of Mexico 

OCS Region, Year 2005 Gulfwide Emission Inventory Study, 

OCS Study MMS 2007-067, December 2007, (incorporated by 

reference, see §98.7).

(1) MMS Gulfwide Emissions Inventory Study Reporters. 

Offshore production facilities reporting under the MMS 

Gulfwide Emissions Inventory Study (referred to as GOADS, 

although GOADS is an emissions activity database) will 

report where available the same annual emissions as 

calculated by MMS using activity data submitted by platform 

operators in the latest Gulfwide Offshore Activity Data 

System (GOADS) program and emissions calculated by MMS’s 

Data Base Management System (DBMS).

(i) For 2011 calendar year, report the latest 

published emissions from MMS GOADS/DBMS methodology for 

platforms in service in the GOADS/DBMS study year. 
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(iii) For each calendar year that does not overlap 

with the MMS publication of a new study, report for 

platforms operating in the current year that were operating 

in the last published MMS Gulfwide Air Emissions study, 

adjusted based on the operating time for each platform 

relative to the latest published MMS study.

(2) Non-MMS GOADS Reporters. Offshore production 

facilities that do not report under the MMS GOADS program 

shall collect monthly activity data from platform sources 

for the first calendar year in accordance with the latest 

MMS GOADS program instructions and calculate GHG emissions 

using the latest MMS GOADS program emission factors and 

methodologies. 

(i) In subsequent calendar years, facilities not 

under GOADS jurisdiction shall follow the data collection 

cycle as required in the MMS Gulfwide Air Emissions Study 

by collecting new monthly activity data, estimating GHG 

emissions using the latest MMS GOADS program emission 

factors and methodologies and report those emissions.

(ii) For each calendar year that does not overlap 

with a new MMS GOADS study publication, report the last 

reported emissions data with emissions adjusted based on 

the operating time for each platform relative to operating 

time in the latest MMS published study.
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(3) For either first or subsequent year reporting, 

platforms either within or outside of MMS GOADS 

jurisdiction that were not covered in the previous MMS data 

collection cycle shall collect monthly activity data from 

platform sources in accordance with the latest MMS GOADS 

program instructions and calculate GHG emissions using the 

latest MMS GOADS program emission factors and 

methodologies. 

(4) 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 published version of the MMS 

GOADS program instructions, beginning in the year that the 

GOADS survey would have been conducted, and annual GHG 

emissions shall be calculated using latest MMS GOADS 

program emission factors and methodologies.

(t) Volumetric emissions

(1) Calculate natural gas volumetric emissions at 

standard conditions by converting actual temperature and 

pressure of natural gas emissions to standard temperature 

. Calculate volumetric 

emissions at standard conditions as specified in paragraphs 

(t)(1) or (2) of this section determined by engineering 

estimate based on best available data unless otherwise 

specified. 
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and pressure of natural gas using Equation W-33 of this 

section. 

( )

( ) a a

a n s a

s n T P

E T P

E

459.67 *

, * 459.67 *

, +

+ = (Eq. W-33)

Where:

Es,n = Natural gas volumetric emissions at standard 

temperature and pressure (STP) conditions in 

cubic feet.

Ea,n = Natural gas volumetric emissions at actual 

conditions in cubic feet.

Ts = Temperature at standard conditions. (oF).

Ta = Temperature at actual emission conditions. (o

F).

Ps = Absolute pressure at standard conditions (psia).

Pa

( )

( ) a s

a i s a

s i T P

E T P

E

459.67 *

, * 459.97 *

, +

+ =

 = Absolute pressure at actual conditions (psia).

(2) Calculate GHG volumetric emissions at standard 

conditions by converting actual temperature and pressure of 

GHG emissions to standard temperature and pressure using 

Equation W-34 of this section. 

(Eq. W-34)

Where:

Es,i = GHG i volumetric emissions at standard 

temperature and pressure (STP) conditions in 

cubic feet.

Ea,i = GHG i volumetric emissions at actual conditions 

in cubic feet.

Ts = Temperature at standard conditions. (o

F).

Ta = Temperature at actual emission conditions. (o

P

F).

s = Absolute pressure at standard conditions (psia).
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Pa = Absolute pressure at actual conditions (psia).

(u) GHG volumetric emissions. Calculate GHG 

volumetric emissions at standard conditions as specified in 

paragraphs (u)(1) and (2) of this section determined by 

engineering estimate based on best available data unless 

otherwise specified.

(1) Estimate CH4 and CO2

Es,i =Es,n * Mi

emissions from natural gas 

emissions using Equation W-35 of this section.

(Eq. W-35)

Where:

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

standard conditions in cubic feet.

Es,n = Natural gas volumetric emissions at standard 

conditions in cubic feet.

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

(2) For Equation W-35 of this section, the mole 

fraction, Mi

(i) GHG mole fraction in produced natural gas for 

onshore petroleum and natural gas production facilities. 

If you have a continuous gas composition analyzer for 

produced natural gas, you must use these values for 

determining the mole fraction. If you do not have a 

, shall be the annual average mole fraction for 

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

(vii) of this section.
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continuous gas composition analyzer, then you must use your 

annual average gas composition based on available sample 

analysis.

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

emissions sources upstream of the de-methanizer and GHG 

mole fraction 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 for determining the mole 

fraction. If you do not have a continuous gas composition 

analyzer, then annual samples must be taken according to 

methods set forth in §98.234(b).

(iii) GHG mole fraction in transmission pipeline 

natural gas that passes through the facility for onshore 

natural gas transmission compression facilities. 

(iv) GHG mole fraction in natural gas stored in 

underground natural gas storage facilities. 

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

storage facilities. 

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

import and export facilities. 
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(vii) GHG mole fraction in local distribution 

pipeline natural gas that passes through the facility for 

natural gas distribution facilities. 

(v) GHG mass emissions

3

, , * * * 10− Masss i = Es i ρi GWP

. Calculate GHG mass emissions 

in carbon dioxide equivalent at standard conditions by 

converting the GHG volumetric emissions into mass emissions 

using Equation W-36 of this section.

(Eq. W-36)

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

ρ i

) volumetric emissions at 

standard conditions, in cubic feet.

= 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 pipelines, manifolds and vessels) between 

isolation valves.

(2) Retain logs of the number of blowdowns per 

calendar year.

(3) Calculate the total annual venting emissions 

using Equation W-37 of this section:
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3

, * * * *10− Massc i= N Vv Rc GHGi (Eq. W-37)

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 the 

calendar year.

Vv = Total volume in cubic feet of blowdown equipment 

chambers (including pipelines, manifolds and 

vessels) between isolation valves.

Rc = Density of critical phase EOR injection gas in 

kg/ft3. You may use an appropriate standard 

method published by a consensus-based standards 

organization if such a method exists or you may 

use an industry standard practice to determine 

density of super critical EOR injection gas.

GHGi = Mass fraction of GHGi in critical phase 

injection gas.

1 × 10-3 = Conversion factor from kilograms to metric tons.

(x) EOR hydrocarbon liquids dissolved CO2. Calculate 

dissolved CO2 in hydrocarbon liquids produced through EOR 

operations as follows:

(1) Determine the amount of CO2 retained in 

hydrocarbon liquids after flashing in tankage at STP 

conditions. Annual 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 annual analysis for the calendar 

year.
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(2) Estimate emissions using Equation W-38 of this 

section.

Masss,CO2 = Shl * Vhl (Eq. W-38)

Where:

Masss,CO2 = Annual CO2 emissions from CO2 retained in 

hydrocarbon liquids produced through EOR 

operations 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 

at the EOR operations in barrels in the 

calendar year.

(y) [Reserved]

(z) Onshore petroleum and natural gas production 

combustion emissions.

(2) If the fuel combusted in the stationary or 

portable equipment is not found in Table C-1 and is not a 

blend containing only fuels listed in Table C-1, and you 

are not consuming field gas, you must follow the Tier 3 or 

 Calculate combustion-related 

emissions from stationary and portable equipment as 

follows:

(1) If the fuel combusted in the stationary or 

portable equipment is listed in Table C-1, or is a blend of 

fuels listed in Table C-1, use the Tier 1 methodology 

described in subpart C of this part (General Stationary 

Fuel Combustion Sources).
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Tier 4 method in paragraphs §§98.33(b)(3)or 98.33(b)(4) of 

this part, as applicable. 

(3) For fuel combustion units that combust field gas, 

or any blend of field gas and fuels listed in Table C-1, 

calculate combustion emissions as follows: 

(i) If you have a continuous flow meter on the 

combustion unit, you must use the measured flow volumes to 

calculate the total flow of gas to the unit. If you do not 

have a permanent flow meter on the combustion unit, you may 

install a permanent flow meter on the combustion unit, or 

use company records or engineering calculations based on 

best available data to estimate volumetric unit gas flow. 

(ii) If you have a continuous gas composition 

analyzer on fuel to the combustion unit, you must use these 

compositions for determining the concentration of gas 

hydrocarbon constituent in the flow of gas to the unit. If 

you do not have a continuous gas composition analyzer on 

gas to the combustion unit, you must use the appropriate 

gas compositions for each stream of hydrocarbons going to 

the combustion unit as specified in paragraph (u)(2)(i) of 

this section.

(iii) Calculate GHG volumetric emissions at actual 

conditions using Equations W-39 of this section.
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= ∑

j

Ea CO Va Yj Rj* * , 2

(Eq. W-39)

Where:

Ea,CO2 = Contribution of annual emissions from 

portable or stationary fuel combustion 

sources in cubic feet, under actual 

conditions.

Va = Volume of gas sent to combustion unit 

in cubic feet, during the year.

Yj = Concentration of gas hydrocarbon 

constituents j (such as methane, 

ethane, propane, butane, and pentanes 

plus).

Rj = Number of carbon atoms in the gas 

hydrocarbon constituent j; 1 for 

methane, 2 for ethane, 3 for propane, 

4 for butane, and 5 for pentanes 

plus).

(5) External fuel combustion sources with a rated 

heat input capacity equal to or less than 5 mmBtu/hr do not 

need to report combustion emissions. You must report the 

type of fuel combustion unit and the number of each type.

(6) Calculate GHG volumetric emissions at standard 

conditions using calculations in paragraph (t) of this 

section.

(7) Calculate both combustion-related CH4 and CO2 mass 

emissions from volumetric CH4 and CO2 emissions using 

calculation in paragraph (v) of this section.
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(8) Calculate N2

(Eq. W-40)

Where:

N

O mass emissions using Equation W-40

of this section.

2O = Annual N2O emissions from the 

combustion of a particular type of 

fuel (metric tons).

Fuel = Mass or volume of the fuel combusted 

(mass or volume per year, choose 

appropriately to be consistent with 

the units of HHV).

HHV = High heat value of the fuel from 

paragraphs (z)(8)(i),(z)(8)(ii) or 

(z)(8)(iii) of this section (units 

must be consistent with Fuel).

EF = Use 1.0 × 10-4 kg N2O/mmBtu.

1 × 10-3 = Conversion factor from kilograms to 

metric tons.

(i) For fuels listed in Table C-1 of subpart C, use 

the provided default HHV in the table.

(ii) For field gas, use 1.235 × 10-3 mmBtu/scf for 

HHV.

(iii) For fuels not listed in Table C-1 of subpart C 

and not field gas, you must use the methodology set forth 

in the Tier 2 methodology described in subpart C of this 

part to determine HHV.

N O = ( × )× Fuel × HHV × EF 3

2 1 10

§98.234 Monitoring and QA/QC requirements.
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(a) You must use any of the methods described as 

follows in this paragraph to conduct leak detection(s) of 

equipment leaks and through-valve leakage from all source 

types listed in §98.233(k), (o), (p) and (q) that occur 

during a calendar year, except as provided in paragraph 

(a)(4) of this section. 

(1) Optical gas imaging instrument. Use an optical 

gas imaging instrument for equipment leak detection in 

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

and (2) Alternative work practice for monitoring equipment 

leaks. Any emissions detected by the optical gas imaging 

instrument is a leak unless screened with Method 21 

monitoring, in which case 10,000 ppm or greater is 

designated a leak. In addition, you must operate the 

optical gas imaging instrument to image the source types 

required by this subpart in accordance with the instrument 

manufacturer’s operating parameters.

(2) Method 21. Use the equipment leak detection 

methods in 40 CFR part 60, Appendix A-7, Method 21. If 

using Method 21 monitoring, if an instrument reading of 

10,000 ppm or greater is measured, a leak is detected. 

Inaccessible emissions sources, as defined in 40 CFR part 

60, are not exempt from this subpart. Owners or operators 

must use alternative leak detection devices as described in 
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paragraph (a)(1)of this section to monitor inaccessible 

equipment leaks or vented emissions. 

(3) Infrared laser beam illuminated instrument. Use 

an infrared laser beam illuminated instrument for equipment 

leak detection. Any emissions detected by the infrared 

laser beam illuminated instrument is a leak unless screened 

with Method 21 monitoring, in which case 10,000 ppm or 

greater is designated a leak. In addition, you must 

operate the infrared laser beam illuminated instrument to 

detect the source types required by this subpart in 

accordance with the instrument manufacturer’s operating 

parameters.

(4) An optical gas imaging instrument must be used 

for all source types that are inaccessible and cannot be 

monitored without elevating the monitoring personnel more 

than 2 meters above a support surface. 

(5) Acoustic leak detection instrument. Use the 

acoustic leak detection instrument to detect through-valve 

leakage. The acoustic leak detection instrument must have 

instrument manufacturer’s calculation methods to quantify 

the through-valve leak. When using the acoustic leak 

detection instrument, if a leak of 3.1 scf per hour or 

greater is calculated, a leak is detected. In addition, you 

must operate the acoustic leak detection instrument to 
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monitor the source valves required by this subpart in 

accordance with the instrument manufacturer’s operating 

parameters.

(b) You must operate and calibrate all flow meters, 

composition analyzers and pressure gauges used to measure 

quantities reported in §98.233 according to the procedures 

in §98.3(i) and the procedures in paragraph (b) of this 

section. You may use an appropriate standard method 

published by a consensus-based standards organization if 

such a method exists or you may use an industry standard 

practice. Consensus-based standards organizations include, 

but are not limited to, the following: ASTM International, 

the American National Standards Institute (ANSI), the 

American Gas Association (AGA), the American Society of 

Mechanical Engineers (ASME), the American Petroleum 

Institute (API), and the North American Energy Standards 

Board (NAESB).

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

only where the emissions are at near-atmospheric pressures 

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

emissions, below the maximum temperature specified by the 

vent bag manufacturer, and the entire emissions volume can 

be encompassed for measurement. 
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(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

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

attachments available from the manufacturer, is not able to 

volumetric and mass emissions 

from volumetric natural gas emissions using the 

calculations in §98.233(u) and (v).

(d) Use a high volume sampler to measure emissions 

within the capacity of the instrument. 

(1) A technician following manufacturer instructions 

shall conduct measurements, including equipment 

manufacturer operating procedures and measurement 

methodologies relevant to using a high volume sampler, 

including positioning the instrument for complete capture 

of the equipment leak without creating backpressure on the 

source.
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capture all the emissions from the source then use antistatic 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

2 2 V 2bV b

a

V b

RT

p

m m + m − − − = α

by using 

calibrated gas samples and by following manufacturer’s 

instructions for calibration.

(e) Peng Robinson Equation of State means the 

equation of state defined by:

Where,

p = absolute pressure

R = universal gas constant

T = absolute temperature

Vm

c

c

p

R T

2 2 0.45724

= molar volume

a = 

b = 

c

c

p

0.7780RT
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α = ( )

2

2 1 0.37464 1.54226 0.26992 1 































+ + − − Tc

T

ω ω

ω = acentric factor of the species

Tc = critical temperature

Pc = critical pressure

(f) Special reporting provisions. 

(1) Best available monitoring methods.

(2) 

 EPA will 

allow owners or operators to use best available monitoring 

methods for parameters in §98.233 ‘‘Calculating GHG 

Emissions’’ as specified in paragraphs (f)(2), (f)(3), and 

(f)(4) of this section. The owner or operator must use the 

calculation methodologies and equations in §98.233 

‘‘Calculating GHG Emissions.’’ Best available monitoring 

methods means any of the following methods specified in 

paragraph(f)(1) of this section: 

(i) Monitoring methods currently used by the facility 

that do not meet the specifications of this subpart. 

(ii) Supplier data.

(iii) Engineering calculations. 

(iv) Other company records. 

Best available monitoring methods for wellrelated emissions. During January 1, 2011 through June 30, 

2011, owners or operators may use best available monitoring 

methods for any well-related data that cannot reasonably be 
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measured according to the monitoring and QA/QC requirements 

of this subpart, and only where required measurements 

cannot be duplicated due to technical limitations after 

June 30, 2011. These well-related sources are:

(i) §98.233 (g) Gas well venting during well 

completions and workovers with hydraulic fracturing.

(ii) §98.233 (l) Well testing venting and flaring.

(3) Best available monitoring methods for specified 

activity data

(iii) Cumulative volume produced, volume input or 

output, or volume of fuel used in paragraphs §98.233(d), 

(e), (j), (k), (l), (m), (n), (x), (y), and (z).

. During January 1, 2011 through June 30, 

2011, owners or operators may use best available monitoring 

methods for activity data as listed below that cannot 

reasonably be obtained according to the monitoring and 

QA/QC requirements of this subpart, specifically for events 

that generate data which can only be collected between 

January 1, 2011 and June 30, 2011 and cannot be duplicated 

after June 30, 2011. These sources are:

(i) Cumulative hours of venting, days, or times of 

operation in paragraphs §98.233(e), (f), (g), (h), (l), 

(o), (p), (q), and (r).

(ii) Number of blowdowns, completions, workovers, or 

other events §98.233(f), (g), (h), (i), and (w).
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(4) Best available monitoring methods for leak 

detection and measurement

(iv) Section 98.232 (d)(7), (e)(7), (f)(5), (g)(3), 

(h)(4), and (i)(1) equipment leak emissions from valves, 

connectors, open ended lines, pressure relief valves, block 

valves, control valves, compressor blowdown valves, orifice 

meters, other meters, regulators, vapor recovery 

compressors, centrifugal compressor dry seals, and/or other 

. The owner or operator may 

request use of best available monitoring methods between 

January 1, 2011 and December 31, 2011 for sources requiring 

leak detection and/or measurement. These sources include:

(i) Section 98.232 (d)(1), (e)(1), (f)(1), (g)(1), 

and (h)(1) reciprocating compressor rod packing venting in 

onshore natural gas processing, onshore natural gas 

transmission compression, underground natural gas storage, 

LNG storage, and LNG import and export equipment.

(ii) Section 98.232 (d)(2), (e)(2), (f)(2), (g)(2), 

and (h)(2) centrifugal compressor wet seal oil degassing 

venting in onshore natural gas processing, onshore natural 

gas transmission compression, underground natural gas 

storage, LNG storage, and LNG import and export equipment.

(iii) Section 98.232 (c)(17) and (d)(6) acid gas 

removal vent stacks in onshore petroleum and natural gas 

production and onshore natural gas processing.
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equipment leaks in onshore natural gas processing, onshore 

natural gas transmission compression, underground natural 

gas storage, LNG storage, LNG import and export equipment, 

and natural gas distribution.

(v) Section 98.232 (e)(3) condensate (oil and/or 

water) storage tanks in onshore natural gas transmission 

compression.

(5) Requests for the use of best available monitoring 

methods. The owner or operator may submit a request to the 

Administrator to use one or more best available monitoring 

methods.

(i) No request or approval by the Administrator is 

necessary to use best available monitoring methods between 

January 1, 2011 and June 30, 2011 for the sources outlined 

in paragraph §98.234(f)(2).

(ii) No request or approval by the Administrator is 

necessary to use best available monitoring methods between 

January 1, 2011 and June 30, 2011 for the sources outlined 

in paragraph §98.234(f)(3).

(iii) Owners or operators must submit a request and 

receive approval by the Administrator to use best available 

monitoring methods between January 1, 2011 and December 31, 

2011 for sources outlined in §98.234(f)(4).
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(A) Timing of request. The request to use best 

available monitoring methods for §98.234(f)(4) must be 

submitted to EPA no later than February 28, 2011. 

(B) Content of request

(4) A description of the specific actions the 

facility will take to obtain and/or install the equipment 

or obtain the monitoring service as soon as reasonably 

feasible and the expected date by which the equipment will 

be obtained and operating or service will be provided.

. Requests must contain the 

following information for §98.234(f)(4):

(1) A list of specific source types and specific 

equipment, monitoring instrumentation, and/or services for 

which the request is being made and the locations where 

each piece of monitoring instrumentation will be installed 

or monitoring service will be supplied.

(2) Identification of the specific rule requirements 

(by subpart, section, and paragraph numbers) for which the 

instrumentation or monitoring service is needed.

(3) Documentation of correspondences to and from at 

least four subpart W-relevant service providers 

demonstrating the request for services and responses 

stating the service provider will not provide necessary 

equipment or services in time to meet requirements in this 

subpart for 2011.
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(C) Approval criteria. To obtain approval, the owner 

or operator must demonstrate to the Administrator’s 

satisfaction that it does not own the required monitoring 

equipment, and it is not reasonably feasible to acquire, 

install, and operate a required piece of monitoring 

equipment or to obtain leak detection or measurement 

services in order to meet the requirements of this subpart 

for 2011.

(iv) EPA does not anticipate a need to approve the use 

of best available monitoring methods for sources not listed 

in §98.234 (f)(2), (f)(3), and (f)(4); however, EPA 

reserves the right to review such requests. 

(A) Timing of request. The request to use best 

available monitoring methods for §98.234(f)(4) must be 

submitted to EPA no later than February 28, 2011. 

(B) Content of request

(2) A description of the data collection 

methodologies that do not meet safety regulations, 

technical infeasibility, or specific laws or regulations 

that conflict with each specific source for which an owner 

. Requests must contain the 

following information:

(1) A list of specific source categories and 

parameters for which the owner or operator is seeking use 

of best available monitoring methods.
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or operator is requesting use of best available monitoring 

methodologies. 

(3) A detailed explanation and supporting 

documentation of how and when the owner or operator will 

receive the services or equipment to comply with all 

subpart W reporting requirements. 

(C) Approval criteria. To obtain approval, the owner 

or operator must demonstrate to the Administrator’s 

satisfaction that the owner or operator faces unique 

safety, technical or legal issues rendering them unable to 

meet the requirements of this subpart for 2011.

(6) Requests for extension of the use of best 

available monitoring methods through December 31, 2011 for 

sources in §98.234(f)(2). The owner or operator may submit 

a request to the Administrator to use one or more best 

available monitoring methods described in §98.234(f)(2)

beyond June 30, 2011. 

(i) Timing of request. The extension request must be 

submitted to EPA no later than February 28, 2011. 

(ii) Content of request

(A) A list of specific source types and specific 

equipment, monitoring instrumentation, contract 

modifications, and/or services for which the request is 

. Requests must contain the 

following information:
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being made and the locations where each piece of monitoring 

instrumentation will be installed, monitoring service will 

be supplied, or contracts will be modified. 

(B) Identification of the specific rule requirements 

(by subpart, section, and paragraph numbers) for which the 

instrumentation, contract modification, or monitoring 

service is needed. 

(C) A description and applicable correspondence 

outlining the diligent efforts of the owner or operator in 

obtaining the needed equipment or service and why they 

could not be obtained and installed in a period of time 

enabling completion of applicable requirements of this 

subpart within the 2011 calendar year. 

(D) If the reason for the extension is that the owner 

or operator cannot collect data from a service provider or 

relevant organization in order for the owner or operator to 

meet requirements of this subpart for the 2011 calendar 

year, the owner or operator must provide documentation of a 

good faith effort to obtain relevant data, including the 

modification of relevant contracts, leases or arrangements. 

The owner or operator must include correspondence to the 

service provider requesting relevant data and from the 

service provider or relevant organization stating that they 

will not provide relevant data, and documentation of why 
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the owner or operator could not collect the necessary data 

themselves or modify applicable contracts leases or 

arrangements by June 30, 2011. 

(E) A description of the specific actions the owner 

or operator will take to comply with monitoring 

requirements in 2012 and beyond.

(iii) Approval criteria. To obtain approval, the 

owner or operator must demonstrate to the Administrator’s 

satisfaction that it is not reasonably feasible to obtain 

the data necessary to meet the requirements of this subpart 

for the sources outlined in §98.234(f)(2) by June 30, 2011. 

(7) Requests for extension of the use of best 

available monitoring methods through December 31, 2011 for 

sources in §98.234(f)(3). The owner or operator may submit 

a request to the Administrator to use one or more best 

available monitoring methods described in §98.234(f)(3)

beyond June 30, 2011. 

(i) Timing of request. The extension request must be 

submitted to EPA no later than February 28, 2011. 

(ii) Content of request. Requests must contain the 

following information:

(A) A list of specific source types for which data 

collection could not be implemented.
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(B) Identification of the specific rule requirements 

(by subpart, section, and paragraph numbers) for which the 

data collection could not be implemented. 

(C) A description of the data collection 

methodologies that do not meet safety regulations, 

technical infeasibility, or specific laws or regulations 

that conflict with each specific source for which an owner 

or operator is requesting use of best available monitoring 

methodologies for which data collection could not be 

implemented in the 2011 calendar year.

(iii) Approval criteria

(8) 

. To obtain approval, the 

owner or operator must demonstrate to the Administrator’s 

satisfaction that it is not reasonably feasible to 

implement the data collection for the sources described in 

§98.234(f)(3) for the methods required in this subpart by 

July 1, 2011.

Requests for extension of the use of best 

available monitoring methods beyond 2011 for sources listed 

in §98.234(f)(2), (f)(3), (f)(4), (f)(5)(iv) and other 

sources in subpart W. EPA does not anticipate a need for 

approving the use of best available methods beyond December 

31, 2011, except in extreme circumstances which include 

safety, a requirement being technically infeasible or 

counter to other local, State or Federal regulations. 
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(i) Timing of request. The request to use best 

available monitoring methods for §98.234(f)(2), (f)(3), 

(f)(4), (f)(5)(iv) and sources not listed in §98.234(f)(2), 

(f)(3), (f)(4), (f)(5)(iv) must be submitted to EPA no

later than June 30, 2011. 

(ii) Content of request

(C) 

. Requests must contain the 

following information: 

(iii) A list of specific source categories and 

parameters for which the owner or operator is seeking use 

of best available monitoring methods.

(iv) A description of the data collection 

methodologies that do not meet safety regulations, 

technical infeasibility, or specific laws or regulations 

that conflict with each specific source for which an owner 

or operator is requesting use of best available monitoring 

methodologies. 

(v)A detailed explanation and supporting documentation 

of how and when the owner or operator will receive the 

services or equipment to comply with all subpart W 

reporting requirements. 

Approval criteria. To obtain approval, the owner 

or operator must demonstrate to the Administrator’s 

satisfaction that the owner or operator faces unique 
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safety, technical or legal issues rendering them unable to 

meet the requirements of this subpart.

§98.235 Procedures for estimating missing data.

A complete record of all estimated and/or measured 

parameters used in the GHG emissions calculations is 

required. If data are lost or an error occurs during 

annual emissions estimation or measurements, you must 

repeat the estimation or measurement activity for those 

sources as soon as possible, including in the subsequent 

calendar year if missing data are not discovered until 

after December 31 of the year in which data are collected, 

until valid data for reporting is obtained. Data developed 

and/or collected in a subsequent calendar 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 measurements 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 and 

related information as specified in this section.
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(a) Report annual emissions separately for each of 

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

(8) of this section in metric tons CO2e per year at standard 

conditions. For each segment, report emissions from each 

source type §98.232(a) in the aggregate, unless specified 

otherwise. For example, an onshore natural gas production 

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) [Reserved]

(c) For each aggregated source, report activity data 

and emissions (in metric tons CO2e per year at standard 

conditions) for each aggregated source type as follows:
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(1) For natural gas pneumatic devices (refer to 

§98.233, Equation W-1), report the following: 

(i) Count of natural gas pneumatic high bleed 

devices.

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

(iii) Count of natural gas pneumatic intermittent 

bleed devices. 

(iv) Report emissions collectively. 

(2) For natural gas driven pneumatic pumps (refer to 

§98.233, Equation W-2), report the following, 

(i) Count of natural gas driven pneumatic pumps.

(ii) Report emissions collectively. 

(3) For each acid gas removal unit (refer to §98.233, 

Equation W-3, and Equation W-4), report the following:

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

gas removal unit and/or total volume of natural gas flow 

out of the acid gas removal unit in cubic feet per year.

(ii) For method 1 and method 2, fraction of CO2 content 

in the vent from the acid gas removal unit (refer to 

§98.233(d)(1) or (d)(5)).

(iii) For method 3, volume fraction of CO2

(iii) Report emissions individually. 

content of 

natural gas into and out of the acid gas removal unit 

(refer to §98.233(d)(6) and (d)(7)).
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(4) For dehydrators, report the following:

(i) For each Glycol dehydrator with a throughput 

greater than or equal to 0.4 mmscfd (refer to 

§98.233(e)(1)), report the following: 

(A) Glycol dehydrator feed natural gas flow rate in 

mmscfd, determined by engineering estimate based on best 

available data.

(B) Glycol dehydrator absorbent circulation pump 

type.

(C) Whether stripper gas is used in glycol 

dehydrator. 

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

dehydrator.

(E) Type of absorbent.

(F) Total time the glycol dehydrator is operating in 

hours.

(G) Temperature, in degrees Fahrenheit and pressure, 

in psig, of the wet natural gas.

(H) Concentration of CH4 and CO2 in natural gas.

(I) What vent gas controls are used (refer to 

§98.233(e)(3) and (e)(4)). 

(J) Report vent and flared emissions individually. 
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(ii) For all Glycol dehydrators with a throughput less 

than 0.4 mmscfd (refer to §98.233, Equation W-5), report 

the following:

(A) Count of glycol dehydrators.

(B) Whether any vent gas controls are used (refer to 

§98.233, paragraph (e)(3) and (e)(4)).

(C) Report vent and flared emissions collectively. 

(iii) For absorbent desiccant dehydrators (refer to 

§98.233, Equation W-6), report the following:

(A) Count of desiccant dehydrators.

(B) Report emissions collectively. 

(5) For well venting for liquids unloading (refer to 

§98.233, Equations W-7, W-8 and W-9), report the following 

by field:

(i) Count of wells vented to the atmosphere for 

liquids unloading.

(ii) Count of plunger lifts.

(iii) Collective number of unloadings vented to the 

atmosphere.

(iv) Average flow rate of the measured well venting in 

cubic feet per hour (refer to §98.233 (f)(1)(i)(A)).

(v) Average casing diameter in inches.

(vi) Report emissions collectively. 
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(6) For well completions and workovers, report the 

following for each field: 

(i) For gas well completions and workovers with 

hydraulic fracturing (refer to §98.233, Equation W-10):

(A) Total count of completions in calendar year.

(B) Average flow rate of the measured well completion 

venting in cubic feet per hour (refer to §98.233 Paragraph 

(g)(1)(i)(A) or (g)(1)(ii)(A)).

(C) Total count of workovers in calendar year.

(D) Average flow rate of the measured well workover 

venting in cubic feet per hour (refer to §98.233 

(g)(1)(i)(A) or (g)(1)(ii)(A)).

(E) Total number of days of gas venting to the 

atmosphere during backflow for completion. 

(F) Total number of days of gas venting to the 

atmosphere during backflow for workovers.

(G) Report number of completions and workovers 

employing reduced emissions completions and engineering 

estimate based on best available data of the amount of gas 

recovered to sales.

(H) Report vent and flared emissions collectively. 

(ii) For gas well completions and workovers without 

hydraulic fracturing (refer to §98.233, Equation W-13): 

(A) Total count of completions in calendar year.
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(B) Total count of workovers in calendar year.

(C) Total number of days of gas venting to the 

atmosphere during backflow for completion.

(D) Total number of days of gas venting to the 

atmosphere during backflow for workover.

(E) Report vent and flared emissions collectively.

(7) For each blowdown vent stack (refer to §98.233, 

Equation W-14), report the following:

(i) Total number of blowdowns per equipment type in 

calendar year. 

(ii) Report emissions collectively per equipment 

type. 

(8) For gas emitted from produced oil sent to 

atmospheric tanks: 

(i) For wellhead gas-liquid separator with oil 

throughput greater than or equal to 10 barrels per day, 

using methodology 1 and 2 (refer to §98.233(j)(1) and 

(j)(2)), report the following by field: 

(A) Number of wellhead separators sending oil to 

atmospheric tanks.

(B) Separator temperature, in degrees Fahrenheit, and 

pressure, in psig, ranges.

(C) Sales oil stabilized API gravity range, in 

degrees.
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(D) Count of stock tanks at well pads.

(E) Best estimate of count of stock tanks not at well 

pads receiving your oil.

(F) Total volume of oil from all wellhead separators 

sent to tank(s) in barrels per year.

(G) Count of tanks with emissions control measures, 

either vapor recovery system or flaring, for tanks at well 

pads.

(H) Best estimate of count of stock tanks assumed to 

have emissions control measures not at well pads, receiving 

your oil.

(F) Range of concentrations of flash gas, CH4 and CO2

(C) Total number of wells sending oil to separators 

off the well pads.

.

(G) Report emissions individually for methodology 1 

and 2. 

(ii) For wells with oil production greater than or 

equal to 10 barrels per day, using methodology 3 and 4 

(refer to §98.233, paragraph (j)(3) and (j)(4)), report the 

following by field: 

(A) Total volume of sales oil from all wells in 

barrels per year.

(B) Total number of wells sending oil directly to 

tanks.
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(D) Sales oil API gravity range for (B) and (C) of 

this section, in degrees. 

(E) Count of tanks on wellpads

(F) Count of tanks, both on and off well pads assumed 

to have emissions control measures: either vapor recovery 

system or flaring of tank vapors.

(G) Report emissions collectively for methodology 3 

and methodology 4. 

(iii)For wellhead gas-liquid separators and wells with 

throughput less than 10 barrels per day, using methodology 

5 (refer to §98.233, Equation W-15), report the following:

(A) Number of wellhead separators.

(B) Number of wells without wellhead separators.

(C) Total volume of oil production in barrels per 

year. 

(D) Best estimate of fraction of production sent to 

tanks with assumed control measures: either vapor recovery 

system or flaring of tank vapors.

(E) Count of stock tanks on well pads.

(F) Report CO2 and CH4 emissions collectively. 

(iv) If wellhead separator dump valve is functioning 

improperly during the calendar year (refer to §98.233, 

Equation W-16), report the following:
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(A) Count of wellhead separators that dump valve 

factor is applied. 

(9) For transmission tank emissions identified using 

optical gas imaging instrument per §98.234(a) (refer to 

§98.233, Paragraph (k)), report the following for each 

tank:

(i) Report emissions individually.

(10) For well testing (refer to §98.233, Equation W17), report the following for each field in the basin:

(i) Number of wells tested per field in calendar 

year.

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

(iii) Average number of days the well is tested.

(iv) Report emissions of the venting gas 

collectively.

(11) For associated natural gas venting (refer to 

§98.233, Equation W-18), report the following for each 

field in the basin:

(i) Number of wells venting or flaring associated 

natural gas in a calendar year.

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

(iii) Report emissions of the flaring gas 

collectively. 
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(12) For flare stacks (refer to §98.233, Equation W19, W-20 and W-21), report the following for each flare:

(i) Whether flare has a continuous flow monitor.

(ii) Volume of gas sent to flare in cubic feet per 

year.

(iii) Percent of gas sent to un-lit flare determined 

by engineering estimate and process knowledge based on best 

available data and operating records.

(iv) Whether flare has a continuous gas analyzer.

(v) Flare combustion efficiency. 

(vi) Report uncombusted and combusted CO2 and CH4 

emissions separately. 

(13) For each centrifugal compressor:

(i) For compressors with wet seals in operational 

mode (refer to §98.233, Equations W-22 through W-24), 

report the following for each degassing vent:

(A) Number of wet seals connected to the degassing 

vent.

(B) Fraction of vent gas recovered for fuel or sales

or flared.

(C) Annual throughput in million scf.

(D) Type of meters used for making measurements.
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(E) Reporter emission factor for wet seal oil 

degassing vents in cubic feet per hour (refer to §98.233, 

Equation W-23).

(F) Total time the compressor is operating in hours. 

(G) Report seal oil degassing vent emissions for 

compressors measured (refer to §98.233, Equation W-22) and 

for compressors not measured (refer to §98.233, Equation W23).

(ii) For wet and dry seal centrifugal compressors in 

operating and standby, pressurized mode, (refer to §98.233, 

Equations W-23 and W-24), report the following:

(A) Total time in hours the compressor is in 

operating mode.

(B) Total time in hours the compressor is in standby, 

pressurized mode. 

(c) Reporter emission factor for blowdown vents in 

cubic feed per hour (refer to §98.233, Equation W-23).

(D) Report blowdown vent emissions when operating and 

standby pressurized modes (refer to §98.233, Equation W23). 

(iii) For wet and dry seal centrifugal compressors in 

shutdown, depressurized mode (refer to §98.233, Equations 

W-23 and W-24), report the following:
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(A) Total time in hours the compressor is in 

shutdown, depressurized mode.

(B) Reporter emission factor for isolation valve 

emissions in shutdown, depressurized mode in cubic feet per 

hour (refer to §98.233, Equation W-23).

(C) Report the isolation valve leakage emissions in 

shutdown, depressurized mode in cubic feet per hour (refer 

to §98.233, Equation W-23). 

(iv) Report total annual compressor emissions from 

all modes of operation (refer to §98.233, Equation W-24).

(v) For centrifugal compressors in onshore petroleum 

and natural gas production (refer to §98.233, Equation W25), report the following:

(A) Count of compressors.

(B) Report emissions (refer to §98.233, Equation W25) collectively. 

(14) For reciprocating compressors:

(i) For reciprocating compressors rod packing 

emissions with or without a vent in operating mode, report 

the following:

(A) Annual throughput in million scf. 

(B) Total time in hours the reciprocating compressor 

is in operating mode.
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(C) Report rod packing emissions for compressors 

measured (refer to §98.233, Equation W-26) and for 

compressors not measured (refer to §98.233, Equation W-27).

(ii) For reciprocating compressors blowdown vents not 

manifold to rod packing vents, in operating and standby

pressurized mode (refer to §98.233, Equations W-27 and W28), report the following: 

(A) Total time in hours the compressor is in standby, 

pressurized mode. 

(B) Reporter emission factor for blowdown vents in 

cubic feet per hour (refer to §98.233, Equation W-27).

(C) Report blowdown vent emissions when in operating 

and standby pressurized modes (refer to §98.233, Equation 

W-28). 

(iii) For reciprocating compressors in shutdown, 

depressurized mode (refer to §98.233, Equations W-27 and W28), report the following:

(A) Total time the compressor is in shutdown, 

depressurized mode.

(B) Reporter emission factor for isolation valve 

emissions in shutdown, depressurized mode in cubic feet per 

hour (refer to §98.233, Equation W-27).

(C) Report the isolation valve leakage emissions in 

shutdown, depressurized mode. 
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(iv) Report total annual compressor emissions from 

all modes of operation (refer to §98.233, Equation W-28).

(v) For reciprocating compressors in onshore 

petroleum and natural gas production (refer to §98.233, 

Equation W-29), report the following:

(A) Count of compressors.

(B) Report emissions collectively. 

(15) For each equipment leak sources that uses 

emission factors for estimating emissions (refer to 

§98.233, paragraphs (q) and (r).

(i) For equipment leaks found in each leak survey 

(refer to §98.233(q)), report the following:

(A) Total count of leaks found in each complete 

survey listed by date of survey and each type of leak 

source for which there is a leaker emission factor in 

Tables W-2, W-3, W-4, W-5, W-6 and W-7.

(B) Concentration of CH4 and CO2 as described in 

§98.233, Equation W-30.

(C) Report CH4 and CO2 emissions (refer to §98.233, 

Equation W-30) collectively by equipment type.

(ii) For equipment leaks calculated using population 

counts and factors (refer to §98.233(r)), report the 

following:
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(A) For source categories §98.230 (a)(3), (a)(4), 

(a)(5), (a)(6), and (a)(7), total count for each type of 

leak source in Tables W-2, W-3, W-4, W-5 and W-6 for which 

there is a population emission factor, listed by major 

heading and component type.

(B) For onshore production (refer to §98.230 

paragraph (a)(2)), total count for low bleed, high bleed 

and intermittent bleed pneumatic devices and pneumatic 

pumps in Table W-1A, and each type of major equipment in 

Table W-1B, by field.

(C) Report CH4 and CO2

(iii) Number of blowdowns per year.

emissions (refer to §98.233, 

Equation W-30) collectively by equipment type.

(16) For Local Distribution Companies, report the 

following:

(i) Number of custody transfer gate stations.

(ii) Number of non-custody transfer gate stations.

(iii)Custody transfer gate station meter run leak 

factor (refer to §98.233, Equation W-32).

(17) For each EOR injection pump blowdown (refer to 

§98.233, Equation W-37), report the following:

(i) Pump capacity, in barrels per day.

(ii) Volume of critical phase gas between isolation 

valves.
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(iv) Critical phase EOR injection gas density.

(v) Report emissions collectively. 

(18) For hydrocarbon liquids dissolved CO2 for each 

field (refer to §98.233, Equation W-37), report the 

following:

(i) Volume of crude oil produced in barrels per year.

(ii) Amount of CO2 retained in hydrocarbon liquids in 

metric tons per barrel, under standard conditions. 

(iii) Report emissions individually.

(d) Report annual throughput as determined by 

engineering estimate based on best available data for each 

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

this section. 

(e) For offshore petroleum and natural gas production 

facilities, report the number of connected wells, and 

whether the wells are producing oil, gas, or both.

(f) Report emissions separately for portable 

equipment for the following source types: drilling rigs, 

dehydrators, compressors, electrical generators, steam 

boilers, and heaters. 

(1) Aggregate emissions by source type.

(2) Report count of each source type.

§98.237 Records that must be retained.
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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.

Acid Gas means hydrogen sulfide (H2S) and/or carbon 

dioxide (CO2) contaminants that are separated from sour 

natural gas by an acid gas removal unit.

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 
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amine solution) and released with methane and other light 

hydrocarbons to the atmosphere or a flare.

Basin means geologic provinces as defined by the 

American Association of Petroleum Geologists (AAPG) 

Geologic Note: AAPG-CSD Geologic Provinces Code Map: AAPG 

Bulletin, Prepared by Richard F. Meyer, Laure G. Wallace, 

and Fred J. Wagner, Jr., Volume 75, Number 10 (October 

1991) (incorporated by reference, see §98.7)and the Alaska 

Geological Province Boundary Map, Compiled by the American 

Association of Petroleum Geologists Committee on Statistics 

of Drilling in Cooperation with the USGS, 1978 

(incorporated by reference, see §98.7).

Component means 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.

Compressor means any machine for raising the pressure 

of a natural gas or CO2 by drawing in low pressure natural 

gas or CO2 and discharging significantly higher pressure 

natural gas or CO2.

Condensate means hydrocarbon and other liquid, 

including both water and hydrocarbon liquids, separated 

from natural gas that condenses due to changes in the 
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temperature, pressure, or both, and remains liquid at 

storage conditions. 

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 subpart, EOR applies to 

injection of critical phase or immiscible carbon dioxide 

into a crude oil reservoir to enhance the recovery of oil. 

Equipment leak means those emissions which could not 

reasonably pass through a stack, chimney, vent, or other 

functionally-equivalent opening.

Equipment leak detection means the process of 

identifying emissions from equipment, components, and other 

point sources.

Field means oil and gas fields identified in the 

United States as defined by the Energy Information 

Administration Oil and Gas Field Code Master List 2008, 

DOE/EIA 0370(08) (incorporated by reference, see §98.7).
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Flare stack emissions means CO2 and N2O from partial 

combustion of hydrocarbon gas sent to a flare plus CH4

emissions resulting from the incomplete combustion of 

hydrocarbon gas in flares.

Flare combustion efficiency means the fraction of 

hydrocarbon gas, on a volume or mole basis, that is 

combusted at the flare burner tip.

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 boil-off 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.

Natural gas 

Facility for purposes of this subpart and for subpart 

A with respect to natural gas distribution means the 

means a naturally occurring mixture of 

hydrocarbon gases found in geologic formations beneath the 

earth’s surface, of which its constituents include, but are 

not limited to, methane, heavier hydrocarbons and carbon 

dioxide. Natural gas for the purposes of subpart W is 

composed of a minimum high heat value of 910 Btu per 

standard cubic foot.
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distribution pipelines, metering stations, and regulating 

stations that are operated by and a Local Distribution

Company (LDC) that is regulated as a separate operating 

company by a public utility commission or that are operated 

as an independent municipally-owned distribution system.

Facility for purposes of this subpart and for subpart 

A with respect to onshore petroleum and natural gas 

production facility means all petroleum or natural gas 

equipment associated with all petroleum or natural gas 

production wells and CO2

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 

EOR operations that are under 

common ownership or common control including leased, 

rented, or contracted activities by an onshore petroleum 

and natural gas production owner or operator and that are 

located in a single hydrocarbon basin as defined in 

§98.238. Where a person or entity owns or operators more 

than one well in a basin, then all onshore petroleum and 

natural gas production equipment associated with all wells 

that the person or entity owns or operates in the basin 

would be considered one facility. 
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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 person or entity who holds the permit to 

operate petroleum and natural gas wells on the drilling 

permit or an operating permit where no drilling permit is 

issued, which operates an onshore petroleum and/or natural 

gas production facility (as described in §98.230(a)(2). 

Where petroleum and natural gas wells operate without a 

drilling or operating permit, the person or entity that 

pays the state or federal business income taxes is 

considered the owner or operator.

Operating pressure means the containment pressure that 

characterizes the normal state of gas or liquid inside a 

particular process, pipeline, vessel or tank.

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

increase flow of liquid streams in closed or open conduits.

Pump seals means any seal on a pump drive shaft used 

to keep methane and/or carbon dioxide containing light 

liquids from escaping the inside of a pump case to the 

atmosphere.

Pump seal emissions means hydrocarbon gas released 

from the seal face between the pump internal chamber and 

the atmosphere.
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Reservoir means a porous and permeable underground 

natural formation containing significant quantities of 

hydrocarbon liquids and/or gases. A reservoir is 

characterized by a single natural pressure system.

Separator means a vessel in which streams of multiple 

phases are gravity separated into individual streams of 

single phase.

Transmission pipeline means high pressure cross 

country pipeline transporting sellable quality natural gas 

from production or natural gas processing to natural gas 

distribution pressure let-down, metering, regulating 

stations where the natural gas is typically odorized before 

delivery to customers.

Turbine meter means a flow meter in which a gas or 

liquid flow rate through the calibrated tube spins a 

turbine from which the spin rate is detected and calibrated 

to measure the fluid flow rate.

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

FOR ONSHORE PRODUCTION

Onshore production Emission Factor 

(scf/hour/component)

Eastern U.S.

Population Emission Factors - All Components, 

Gas Service1

Valve 0.640

Connector 0.083

Open-ended Line 1.460

Pressure Relief Valve 0.970
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Low Continuous Bleed Pneumatic Device 

Vents 1.39 2

High Continuous Bleed Pneumatic Device 

Vents 37.3 2

Intermittent Bleed Pneumatic Device Vents 13.5 2

Pneumatic Pumps 10.3 3

Population Emission Factors - All Components, 

Light Crude Service4

Valve 0.04

Flange 0.002

Connector 0.01

Open-ended Line 0.04

Pump 0.01

Other 0.24 5

Population Emission Factors - All Components, 

Heavy Crude Service6

Valve 0.001

Flange 0.001

Connector (other) 0.0004

Open-ended Line 0.01

Other 0.003 5

Western U.S.

Population Emission Factors - All Components, 

Gas Service1

Valve 2.903

Connector 0.396

Open-ended Line 0.748

Pressure Relief Valve 4.631

Low Continuous Bleed Pneumatic Device 

Vents 1.39 2

High Continuous Bleed Pneumatic Device 

Vents 37.3 2

Intermittent Bleed Pneumatic Device Vents 13.5 2

Pneumatic Pumps 10.3 3

Population Emission Factors - All Components, 

Light Crude Service4

Valve 0.04

Flange 0.002

Connector 0.01

Open-ended Line 0.04

Pump 0.01

Other 0.24 5

Population Emission Factors - All Components, 

Heavy Crude Service6

Valve 0.001

Flange 0.001

Connector (other) 0.0004

Open-ended Line 0.01

Other 0.003 5

1 For multi-phase flow that includes gas, use the gas service emissions 
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TABLE W-1B OF SUBPART W–DEFAULT AVERAGE COMPONENT COUNTS FOR 

MAJOR NATURAL GAS PRODUCTION EQUIPMENT

Major Equipment Valves Connectors Open-ended 

Lines

Pressure 

relief 

valves

Eastern U.S.

Wellheads 8 38 0.5 0

Separators 1 6 0 0

Meters/piping 12 45 0 0

Compressors 12 57 0 0

In-line heaters 14 65 2 1

Dehydrators 24 90 2 2

Western U.S.

Wellheads 11 36 1 0

Separators 34 106 6 2

Meters/piping 14 51 1 1

Compressors 73 179 3 4

In-line heaters 14 65 2 1

Dehydrators 24 90 2 2

TABLE W-1C OF SUBPART W–DEFAULT AVERAGE COMPONENT COUNTS FOR 

MAJOR CRUDE OIL PRODUCTION EQUIPMENT

Major Equipment Valves Flanges Connecto

rs

Openended 

Lines

Other

Components

Eastern U.S.

Wellhead 5 10 4 0 1

Separator 6 12 10 0 0

Heater-treater 8 12 20 0 0

Header 5 10 4 0 0

Western U.S.

Wellhead 5 10 4 0 1

Separator 6 12 10 0 0

Heater-treater 8 12 20 0 0

Header 5 10 4 0 0

TABLE W-1D OF SUBPART W–DESIGNATION OF EASTERN AND WESTERN 

U.S.

Eastern U.S. Western U.S.

Connecticut Alabama

factors

2 Emission Factor is in units of "scf/hour/device"

3 Emission Factor is in units of "scf/hour/pump" 4 Hydrocarbon liquids greater than or equal to 20 ̊API are considered 

"light crude"

5 ”Others” category includes instruments, loading arms, pressure relief 

valves, stuffing boxes, compressor seals, dump lever arms, and vents.

6 Hydrocarbon liquids less than 20 ̊API are considered "heavy crude"
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Delaware Alaska

Florida Arizona

Georgia Arkansas

Illinois California

Indiana Colorado

Kentucky Hawaii

Maine Idaho

Maryland Iowa

Massachusetts Kansas

Michigan Louisiana

New Hampshire Minnesota

New Jersey Mississippi

New York Missouri

North Carolina Montana

Ohio Nebraska

Pennsylvania Nevada

Rhode Island New Mexico

South Carolina North Dakota

Tennessee Oklahoma

Vermont Oregon

Virginia South Dakota

West Virginia Texas

Wisconsin Utah

Washington

Wyoming

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

FACTORS FOR PROCESSING

Processing Emission Factor 

(scf/hour/component)

Leaker Emission Factors - Compressor Components, Gas Service

Valve 14.84

Connector 5.59

Open-Ended Line 17.27

Pressure Relief Valve 39.66

Meter 19.33

Leaker Emission Factors – Non-Compressor Components, Gas Service

Valve 6.42

Connector 5.71

Open-Ended Line 11.27

Pressure Relief Valve 2.01

Meter 2.93
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TABLE W-3 OF SUBPART W–DEFAULT METHANE EMISSION FACTORS FOR 

TRANSMISSION

Transmission Emission Factor 

(scf/hour/component)

Leaker Emission Factors - Compressor Components, Gas Service

Valve 14.84

Connector 5.59

Open-Ended Line 17.27

Pressure Relief Valve 39.66

Meter 19.33

Leaker Emission Factors – Non-Compressor Components, Gas Service

Valve 6.42

Connector 5.71

Open-Ended Line 11.27

Pressure Relief Valve 2.01

Meter 2.93

Population Emission Factors – Gas Service

Low Continuous Bleed Pneumatic Device 

Vents1 1.39

High Continuous Bleed Pneumatic Device 

Vents1 19.82

Intermittent Bleed Pneumatic Device 

Vents1 19.82 1 Emission Factor is in units of "scf/hour/device"

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

UNDERGROUND STORAGE

Underground Storage

Emission Factor 

(scf/hour/componen

t)

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 Continuous Bleed Pneumatic Device Vents 1.39 1
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Underground Storage

Emission Factor 

(scf/hour/componen

t)

Leaker Emission Factors - Storage Station, Gas Service

High Continuous Bleed Pneumatic Device Vents 19.82 1

Intermittent Bleed Pneumatic Device Vents 19.82 1

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

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

LIQUEFIED NATURAL GAS (LNG) STORAGE

LNG Storage

Emission Factor 

(scf/hour/compon

ent)

Leaker Emission Factors - LNG Storage Components, LNG Service

Valve 1.19

Pump Seal 4.00

Connector 0.34

Other 1.77 1

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/compone

nt)

Leaker Emission Factors - LNG Terminals Components, LNG Service

Valve 1.19

Pump Seal 4.00

Connector 0.34

Other 1.77 1

Population Emission Factors - LNG Terminals 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-7 OF SUBPART W–DEFAULT METHANE EMISSION FACTORS FOR 

DISTRIBUTION

Distribution Emission Factor 

(scf/hour/component)

Leaker Emission Factors - Above Grade M&R at City Gate Stations1

Components, Gas Service

Connector 1.69
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Distribution Emission Factor 

(scf/hour/component)

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&R2 Components, Gas Service3

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 Service4

Unprotected Steel 12.58

Protected Steel 0.35

Plastic 1.13

Cast Iron 27.25

Population Emission Factors - Distribution Services, Gas Service5

Unprotected Steel 0.19

Protected Steel 0.02

Plastic 0.001

Copper 0.03 1 City gate stations at custody transfer and excluding customer meters 2 Excluding customer meters 3 Emission Factor is in units of "scf/hour/station" 4 Emission Factor is in units of "scf/hour/mile" 5 Emission Factor is in units of “scf/hour/number of services”