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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 30 

DAYS AFTER PUBLICATION OF THIS FINAL RULE IN THE FEDERAL 

REGISTER OR DECEMBER 31, 2010, WHICHEVER IS EARLIER]. The 

incorporation by reference of certain publications listed 

in the rule is approved by the Director of Federal Register 
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as of [INSERT THE DATE 30 DAYS AFTER PUBLICATION OF THIS 

FINAL RULE IN THE FEDERAL REGISTER OR DECEMBER 31, 2010, 

WHICHEVER IS EARLIER]. 

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 INFORMATION CONTACT: Carole Cook, Climate 

Change Division, Office of Atmospheric Programs (MC-6207J), 

Environmental Protection Agency, 1200 Pennsylvania Ave., 
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NW, Washington, DC 20460; telephone number: (202) 343-

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

GHGReportingRule@epa.gov. For technical 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”). This final rule 

affects owners or operators of petroleum and natural gas 

systems. Regulated categories and entities may include 

those listed in Table 1 of this preamble: 

Table 1. Examples of Affected Entities by Category 

Source Category NAICS Examples of affected facilities 

Petroleum and 

Natural Gas 

Systems 

486210 Pipeline transportation of natural gas. 

221210 Natural gas distribution facilities. 

211 Extractors of crude petroleum and 

natural gas. 

211112 Natural gas liquid extraction 

facilities. 

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. 
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Although Table 1 of this preamble lists the types of 

facilities of which EPA is aware that could be potentially 

affected by this action, other types of facilities not 

listed in the table could also be 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 
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given reporter. Similarly, not all listed subparts are 

relevant for all reporters. 

Table 2. Source Categories and Relevant Subparts 

Source 

Category

Other subparts recommended for review to determine 

applicability

Petroleum 

and Natural 

Gas Systems 

40 CFR part 98, subpart C: General Stationary 

Fuel Combustion Sources

40 CFR part 98, subpart Y: Petroleum 

Refineries 

40 CFR part 98, subpart MM: Suppliers of 

Petroleum Products 

40 CFR part 98, subpart NN: Suppliers of 

Natural Gas and Natural Gas Liquids 

40 CFR part 98, subpart PP: Suppliers of 

Carbon Dioxide 

40 CFR part 98, subpart RR: Injection and 

Geologic Sequestration of Carbon Dioxide 

(proposed) 

What is the effective date? The final rule is 

effective on [INSERT THE DATE 30 DAYS AFTER PUBLICATION OF 

THIS FINAL RULE IN THE FEDERAL REGISTER OR DECEMBER 31, 

2010, WHICHEVER IS EARLIER]. Section 553(d) of the 

Administrative Procedure Act (APA), 5 U.S.C. Chapter 5, 
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generally provides that rules may not take effect earlier 

than 30 days after they are published in the Federal 

Register. EPA is issuing this final rule under section 

307(d)(1) of the Clean Air Act, which states: “The 

provisions of section 553 through 557 . . . of Title 5 

shall not, except as expressly provided in this section, 

apply to actions to which this subsection applies.” Thus, 

section 553(d) of the APA does not apply to this rule. EPA 

is nevertheless acting consistently with the purposes 

underlying APA section 553(d) in making this rule effective 

on [INSERT THE DATE 30 DAYS AFTER PUBLICATION OF THIS FINAL 

RULE IN THE FEDERAL REGISTER OR DECEMBER 31, 2010, 

WHICHEVER IS EARLIER]. Section 5 U.S.C. 553(d)(3) allows 

an effective date less than 30 days after publication “as 

otherwise provided by the agency for good cause found and 

published with the rule.” As explained below, EPA finds 

that there is good cause for this rule to become effective 

on or before December 31, 2010, even if this results in an 

effective date fewer than 30 days from date of publication 

in the Federal Register. 

While this action is being signed prior to December 1, 

2010, there is likely to be a significant delay in the 

publication of this rule as it contains complex diagrams, 

equations, and charts, and is relatively long in length. 
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As an example, EPA signed a shorter technical amendments 

package related to the same underlying reporting rule on 

October 7, 2010, and it was not published until October 28, 

2010, 75 FR 66434, three weeks later. 

The purpose of the 30-day waiting period prescribed in 

5 U.S.C. 553(d) is to give affected parties a reasonable 

time to adjust their behavior and prepare before the final 

rule takes effect. Where, as here, the final rule will be 

signed and made available on the EPA website more than 30 

days before the effective date, but where the publication 

is likely to be delayed due to the complexity and length of 

the rule, that purpose is still met. Moreover, for 

specified emission sources for certain industry segments, 

EPA has made available the optional use of best available 

monitoring methods (BAMM) during the 2011 calendar year. 

For these circumstances, facilities covered by this rule 

may use BAMM for any parameter for which it is not 

reasonably feasible to acquire, install, or operate a 

required piece of monitoring equipment in a facility, or to 

procure measurement services from necessary providers. 

This will provide facilities a substantial additional 

period to adjust their behavior to the requirements of the 

final rule. Accordingly, we find good cause exists to make 
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this rule effective on or before December 31, 2010, 

consistent with the purposes of 5 U.S.C. 553(d)(3)1. 

Judicial Review. 

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 

 

1

 We recognize that this rule could be published at least 30 days before 

December 31, 2010, which would negate the need for this good cause 

finding, and we plan to request expedited publication of this rule in 

order to decrease the likelihood of a printing delay. However, as we 

cannot know the date of publication in advance of signing this rule, we 

are proceeding with this good cause finding for an effective date on or 

before December 31, 2010. 
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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 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. 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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cf cubic feet 

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 

HHV high heat value 

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 
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N2O nitrous oxide 

NAESB North American Energy Standards Board 

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 

SBA Small Business Administration 

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 
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II. Reporting Requirements for Petroleum and Natural Gas 

Systems 

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 

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 

A. Organization of this Preamble

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. 
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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. Additional 

responses to significant comments can be found in the 

document Mandatory Greenhouse Gas Reporting Rule: EPA’s 

Response to Public Comments, Subpart W: Petroleum and 

Natural Gas Systems. 

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. 

B. Background on the Final Rule

This action finalizes monitoring and reporting 

requirements for petroleum and natural gas systems. 

On April 12, 2010, EPA proposed subpart W—Petroleum 

and Natural Gas Systems, amending 40 CFR part 98 (i.e., the 
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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 GHG Reporting 

Program, which became effective on December 29, 2009, 

includes reporting requirements for facilities and 

suppliers in 32 source categories. EPA established this 

program in response to the fiscal year 2008 Consolidated 

Appropriations Act2

. This Act 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 

 

2

 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. 

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

Stat. 3034-3408). 
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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 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 GHG 

emissions. As stated earlier in this section, this rule 

was proposed by EPA on April 12, 2010. One public hearing 

was held in April 2010, and the 60-day public comment 

period ended June 11, 2010. 

C. Legal Authority

EPA is promulgating 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), 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 as the Administrator requests for 

the purposes of carrying out any provision of the CAA. EPA 
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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 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 petroleum 

and natural gas systems proposal (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 CAA to collect 

emissions information from offshore petroleum and natural 

gas platforms including those located in areas of the 

Central and Western Gulf of Mexico as identified in CAA 

section 328(b). This final action does not regulate GHG 

emissions; rather it gathers information to inform EPA’s 
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evaluation of various CAA provisions. Moreover, EPA’s 

authority under CAA section 114 is broad, and extends to 

any person “who the Administrator believes may have 

information necessary for the purposes” of carrying out the 

CAA, even if that person is not subject to the CAA. 

Indeed, by specifically authorizing EPA to collect 

information from both persons subject to any requirement of 

the CAA, as well as any person who the Administrator 

believes may have necessary information, Congress clearly 

intended that EPA could gather information from a person 

not otherwise subject to CAA requirements. EPA is 

comprehensively considering how to address climate change 

under the CAA, including both regulatory and 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 
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reporting of GHGs including carbon dioxide (CO2), methane 

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

perfluorocarbons (PFCs), sulfur hexafluoride (SF6), and 

other fluorinated compounds (e.g., hydrofluoroethers 

(HFEs)). 

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 

required by facilities subject to subpart W included in 

this action, see Section II.D 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) that 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 

comments on the proposal, and is in the process of 
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considering these comments. A final rule and determination 

will be issued before any data are 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 of subpart A, referenced in 40 CFR 

98.2(a)(2), to add 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 are 

required to report under 40 CFR part 98, subpart W. 

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 Part 98 to 

clarify that it includes the territorial seas. Other 

facilities located offshore of the United States covered by 
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the GHG Reporting Program at 40 CFR part 98 may also be 

affected by this change in the definition of United States. 

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 and the Clean Air Act, 

328(a)(4)(A). These revisions are necessary to ensure that 

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

the Outer Continental Shelf, as defined in 43 U.S.C. §1331, 

and that otherwise meet the applicability criteria of the 

rule are required to report. 

Incorporation by Reference (IBR). In the April 2010 

proposal, EPA proposed to amend 40 CFR 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 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; 
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and the Energy Information Administration Oil and Gas Field 

Code Master List. 

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: 

 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 via 

walkways, storage tanks associated with the platform 

structure, and floating production and storage 

offloading equipment (FPSO). This source category 

does not include reporting of emissions from offshore 

drilling and, exploration that is not conducted on 

production platforms. 

 Onshore petroleum and natural gas production. Onshore 

petroleum and natural gas production means all 

equipment on a well pad or associated with a well pad 

(including compressors, generators, or storage 

facilities), and portable non-self-propelled equipment 

on a well pad or associated with a well pad (including 

well drilling and completion equipment, workover 

equipment, gravity separation equipment, auxiliary 

non-transportation-related equipment, and leased, 

rented or contracted equipment) used in the 

production, extraction, recovery, lifting, 

stabilization, separation or treating of petroleum 

and/or natural gas (including condensate). This 

equipment also includes associated storage or 

measurement vessels and all enhanced oil recovery 

(EOR) operations using CO2, and all petroleum and 

natural gas production located on islands, artificial 
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islands, or structures connected by a causeway to 

land, an island, or artificial island. 

 Onshore natural gas processing. Natural gas 

processing means facilities that separate and recovers 

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

gases and liquids from a stream of produced natural 

gas using 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. This segment also 

includes all residue gas compression equipment owned 

or operated by the natural gas processing facility, 

whether inside or outside the processing facility 

fence. This source category does not include 

reporting of emissions from gathering lines and 

boosting stations. This source category includes: (1) 

all processing facilities that fractionate and (2) 

those that do not fractionate with throughput of 25 

MMscf per day or greater. 

 Onshore natural gas transmission compression. Onshore 

natural gas transmission compression includes any 

stationary 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 stations may 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 onshore 

natural gas processing segment and are excluded from 

this segment. This source category also does not 

include reporting of emissions from gathering lines 

and boosting stations – these sources are currently 

not covered by subpart W. 

 Underground natural gas storage. Underground natural 

gas storage includes subsurface storage, including 

depleted gas or oil reservoirs and salt dome caverns 

that store 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 
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compression, dehydration and flow measurement, and 

excluding transmission pipelines); and all the 

wellheads connected to the compression units located 

at the facility that inject natural gas into and 

remove natural gas from the underground reservoirs. 

 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 

transmission pipelines or intrastate transmission 

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 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 - these sources are not 

covered by subpart W. 

Facilities from the following segments: (1) Offshore 

petroleum and natural gas production, (2) onshore natural 

gas processing, (3) onshore natural gas transmission 

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

storage, and (6) LNG import and export equipment, that 
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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. Facilities assessing 

their applicability in the onshore petroleum and natural 

gas production segment (as defined in 40 CFR 98.238), must 

include only emissions from equipment, as specified in 40 

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

ton CO2e threshold and thus are required to report their GHG 

emissions. Facilities assessing their applicability in the 

onshore natural gas distribution industry segment (as 

defined in 40 CFR 98.238), must include only emissions from 

equipment as specified 40 CFR 98.232(i) 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 must assess applicability based on all 

source categories for which methods are provided in the GHG 

Reporting Program. 

GHGs to Report. Facilities must report: 

 Carbon dioxide (CO2) and methane (CH4) emissions from 

equipment leaks and vents.

 CO2, CH4, and nitrous oxide (N2O) from combustion. 

 CO2, CH4, and nitrous oxide (N2O) emissions from 

combustion at flares. 

Reporting Threshold. Facilities that contain petroleum 

and natural gas systems that meet the requirements of 40 
25 of 287 

CFR 98.2(a)(2) are to report GHG emissions under subpart W. 

For applying the threshold defined in 40 CFR 98.2(a)(2), an 

onshore petroleum and natural gas production facility will 

consider emissions only from equipment specified in 40 CFR 

98.232(c). For applying the threshold defined in 40 CFR 

98.2(a)(2), a natural gas distribution facility shall 

consider emissions only from equipment specified in 40 CFR 

98.232(i). 

GHG Emissions Calculation and Monitoring. The 

petroleum and natural gas source category consists of 

several segments (e.g., onshore petroleum and natural gas 

production, natural gas processing). Within those 

segments, there are different types of emissions sources, 

some of which appear in multiple segments (e.g., pneumatic 

devices, blowdown vents, etc.). Subpart W provides 

methodologies for calculating emissions from each source 

type. Although the rule, in some cases, allows reporters 

the flexibility to choose from more than one method for 

calculating emissions from a specific source type, 

reporters must keep record in their monitoring plans as 

outlined in 40 CFR 98.3(g) of this chapter. Table 3 of 

this preamble summarizes those source types and indicates 

their applicable segments. Reporters of an industry segment 

as defined by 40 CFR 98.230 would report emissions under 
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subpart W only from the corresponding source types listed 

for that particular industry segment as defined in 40 CFR 

98.232. For example, an onshore natural gas transmission 

compression reporter as defined by 40 CFR 98.230(a)(4) 

would report emissions under subpart W only for sources 

defined in 40 CFR 98.232(e). The text following the table 

summarizes 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, that for specified time periods during 

the 2011 data collection year, reporters may use best 

available monitoring methods for certain emissions sources 

in lieu of the methods prescribed for specific sources 

below. This is intended to give reporters flexibility as 

they revise procedures and contractual arrangements during 

early implementation of the rule. 

Table 3. Summary of Source Types in Each Industry Segment 

Source Type 

Offshore 

Producti

on 

Onshore 

Product

ion 

Natural 

Gas 

Processing 

Natural 

Gas 

Transmi

ssion 

Compres

sion 

Undergr

ound 

Storage 

LNG 

Storage 

LNG 

Import 

and 

Export 

Equipmen

t 

Distribu

tion 

Natural gas 

pneumatic 

device 

venting 

X X X

Natural gas 

driven 

pneumatic 

pump 

venting 

X

Acid gas X X
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Source Type 

Offshore 

Producti

on 

Onshore 

Product

ion 

Natural 

Gas 

Processing 

Natural 

Gas 

Transmi

ssion 

Compres

sion 

Undergr

ound 

Storage 

LNG 

Storage 

LNG 

Import 

and 

Export 

Equipmen

t 

Distribu

tion 

removal 

vent stack 

Dehydrator 

vent stacks 

X X

Well 

venting for 

liquids 

unloading 

X

Gas well 

venting 

during well 

completions 

and 

workovers 

with 

hydraulic 

fracturing 

X

Gas well 

venting 

during well 

completions 

and 

workovers 

without 

hydraulic 

fracturing 

X

Blowdown 

vent stacks 

X X X X

Onshore 

production 

storage 

tanks 

X

Transmissio

n storage 

tanks 

X

Well 

testing 

venting and 

flaring 

X

Associated 

gas venting 

and flaring 

X

Flare 

stacks 

X X

Centrifugal 

compressor 

venting 

X X X X X X

Reciprocati

ng 

compressor 

rod packing 

venting 

X X X X X X

Other 

emissions 

from 

equipment 

X X X X X X X
28 of 287 

Source Type 

Offshore 

Producti

on 

Onshore 

Product

ion 

Natural 

Gas 

Processing 

Natural 

Gas 

Transmi

ssion 

Compres

sion 

Undergr

ound 

Storage 

LNG 

Storage 

LNG 

Import 

and 

Export 

Equipmen

t 

Distribu

tion 

leaks 

Population 

Count and 

Emissions 

Factor 

X X X X X

Vented, 

Equipment 

Leaks and 

Flare 

Emissions 

Identified 

in BOEMRE 

GOADS Study 

X 

Enhanced 

Oil 

Recovery 

hydrocarbon 

liquids 

dissolved 

CO2 

X

Enhanced 

Oil 

Recovery 

injection 

pump 

blowdown 

X

Onshore 

Petroleum 

and Natural 

Gas 

Production 

and Natural 

Gas 

Distributio

n 

Combustion 

Emissions 

X X

2. Summary of Methodologies for Each Source Type in Table 

3 of this preamble.

 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-3, and W-4 of subpart W. 

Onshore petroleum and natural gas production reporters 

must complete a total count of pneumatic devices any 
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time within the first three calendar years. A 

reporter must report pneumatic device emissions 

annually. For any years where activity data (count of 

pneumatic devices) is incomplete, use best available 

data or engineering estimates to calculate pneumatic 

device emissions. 

 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 of subpart W. 

 Acid gas removal (AGR) vents: Calculate CO2 emissions 

using one of the following calculation methodologies: 

– Use CEMS as specified under subpart C of this 

section. If CEMS is not operated or maintained, a 

CEMS may be installed. 

– Use metered flow and volume weighted CO2 content of 

the vent stack gas. The approaches available to 

measure the volume weighted CO2 content include 

using a continuous gas analyzer or sampling the gas 

quarterly. 

– Use metered flow of the inlet natural gas and volume 

weighted CO2 content of the natural gas flowing into 

and out of the AGR unit. The approaches available 

to measure the volume weighted CO2 content include 

using a continuous gas analyzer or sampling the gas 

quarterly. 

– Use a process simulator that uses the Peng-Robinson 

equation of state and speciates CO2 emissions. 

 Dehydrator vents. Calculate CH4 and CO2 emissions 

using the following calculation methodologies: 

– For glycol dehydrators with a throughput greater 

than or equal to 0.4 million standard cubic feet per 

day, use a software program such as GRI GlyCalc or 

AspenTech HYSYS® for example, to calculate 

emissions. The software program must determine the 

equilibrium coefficient using the Peng-Robinson 

equation of state, speciates CH4 and CO2 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. 

– 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 
30 of 287 

emission factor to calculate CO2 and CH4 emissions. 

There are separate emission factors for dehydrator 

units with a gas assist pump. 

– 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, and the time between desiccant refilling. 

 Well venting for liquids unloading: Calculate CO2 and 

CH4 emissions using either of the following calculation 

methodologies (the same methodology must be used for 

the entire duration of the calendar year). 

– Determine the average gas flow for the duration of 

the liquids unloading 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. 

– 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 

following methodologies to determine the flow rate of 

the gas. 

– Determine the flow rate of vented gas from 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 2 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 
31 of 287 

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 

2-year period. Separate equations are provided for 

sonic and sub-sonic flow. 

 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 for each well. 

 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 isolation 

valves. Total physical volume of less than 50 cubic 

feet between isolation valves of process vessels, 

piping, and equipment do not have to be reported. The 

total volume contained between isolation valves, which 

can be determined using an engineering equation based 

on best available data, 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 GHG volumes at standard conditions 

and GHG emissions using the concentration of CH4 and 

CO2 in the applicable stream. Reporters may use the 

same calculated volumes in subsequent years if the 

hardware has not changed. For process vessels 

blowndown to a flare, calculate the volume of 

emissions the same as 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 emissions using one of the following calculation 

methodologies: 

– For tanks with separator throughput greater than or 

equal to 10 barrels per day, use a software program, 

such as AspenTECH® or API 4697 E&P Tank for example, 

that uses the Peng-Robinson equation of state, 

models flashing emissions, and speciates CH4 and CO2

emissions from tanks. The low pressure separator 
32 of 287 

oil composition and Reid vapor pressure can be 

determined using the default values within the 

software program, or using a representative sample 

analysis. 

– Alternatively, for tanks with separator throughput 

greater than or equal to 10 barrels per day, you may 

assume all of the CH4 and CO2 in the low pressure 

separator oil is emitted. The low pressure 

separator oil composition shall be determined using 

an appropriate sample analysis, or default oil 

compositions in software programs. 

– For wells with oil production greater than or equal 

to 10 barrels per day that flow directly to a tank 

without going through a separator, calculate 

emissions by using an appropriate sample analysis 

and assuming all of the CH4 and CO2 are emitted. 

– For separator throughput or wells flowing directly 

to tanks with throughput less than 10 barrels per 

day, use a population emission factor together with 

the flow rate. 

– Account for occurrences when the separator dump 

valve is improperly open and bypassing gas to the 

tank through the liquid, by determining the number 

of hours the dump valve is open and scaling 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 as follows: (1) Assume 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 and (2) 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. 

 Transmission storage tanks. For transmission storage 

tanks, once per calendar year reporters must monitor 

the tank vapor vent stack using an optical gas imaging 

instrument, to view the emissions for 5 minutes. 

Alternatively, the scrubber dump valves can be 

monitored with an acoustic leak detector. If the vent 

stack emits continuously over that time period, then 

the reporter must use either a meter or an acoustic 

leak detection device to measure the flow rate of the 
33 of 287 

vent to determine emissions. This will quantify tank 

emissions resulting from malfunctioning scrubber dump 

valves. 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. 

 Well testing venting and flaring. Calculate CH4, CO2, 

and N2O emissions from well testing venting and flaring 

by multiplying available data from production records 

on the gas-to-oil ratio for produced hydrocarbon 

liquids, by the flow rate (in barrels of oil per day) 

of the well being tested, by the number of days in the 

calendar year the well is tested. If gas-to-oil 

ratios are not available, use a sample analysis to 

determine gas-to-oil ratios. For the calculated 

testing gas volume that is flared, use the method set 

forth for flare stacks to estimate the emissions. 

 Associated gas venting and flaring. Calculate CH4, CO2,

and N2O emissions from associated gas venting and 

flaring by multiplying available data from production 

records on the gas-to-oil ratio for produced 

hydrocarbon liquids, by the volume of liquids produced 

in the calendar year. The gas-to-oil ratios can be 

determined by the use of a representative gas-to-oil 

ratio of wells in the same field. If gas-to-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, CO2, and N2O 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. 

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. 
34 of 287 

Calculate N2O from flare stacks using the methodology 

set forth for in 40 CFR 98.233(z). 

 Centrifugal compressor 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 the 

appropriate emission factors. 

― Calculate CH4 and CO2 emissions from wet seal and dry 

seal centrifugal compressor blowdown vents, wet seal 

degassing, and unit isolation valves for wet seal 

and dry seal compressors (see Table 4 of this 

preamble) found in onshore natural gas processing, 

onshore natural gas transmission compression, 

underground natural gas storage, LNG storage, and 

LNG import and export equipment by: 

– Measuring venting from blowdown vents 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 these sources 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 a measurement of each 

compressor in the not operating, depressurized mode 

at least once every three calendar years. Please 

see Compressor Modes and Threshold, Docket EPA-HQOAR-2009-0923. 
35 of 287 

Table 4. Summary of Emission Factor Categories for 

Centrifugal Compressor Venting. 

Component 

Operating Mode 

Operating Not Operating – 

Depressurized 

Blowdown Vent 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 

and natural gas production by counting the total 

population of reciprocating compressors and 

multiplying it by the emission factors provided in 40 

CFR 98.233(p)(10). Calculate CH4 and CO2 emissions for 

reciprocating compressor blowdown valves, rod packing, 

and unit isolation valves (see Table 5 of this 

preamble) from onshore natural gas processing, onshore 

natural gas transmission compression, underground 

natural gas storage, LNG storage, and LNG import and 

export equipment by: 

– Measuring venting from blowdown vents when the 

compressor is found in operating and standby 

pressurized modes using a meter. 

– 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 and 

quantified 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. For through-valve leakage to 

open ended vents, such as unit isolation valves on 

not operating depressurized compressors, acoustic 

leak detection devices may also be used. 

If these sources 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 
36 of 287 

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 a 

measurement of each compressor, and measure the 

compressor in the mode as it 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 

least one time every 3 calendar years. Please see 

“Compressor Modes and Threshold” Docket EPA-HQ-OAR2009-0923. 

Table 5. Summary of Emission Factor Categories for 

Reciprocating Compressor Venting. 

Component 

Operating Mode 

Operating Standby 

Pressurized 

Not Operating –

Depressurized 

Blowdown Vent 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 (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 optical gas imaging instrument. The method 

must be used for all sources that cannot be 

monitored without elevating personnel more than 2 

meters above a support surface. 

– 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, W3, W-4, W-5, W-6, and W-7 of subpart W. Tubing 
37 of 287 

systems less than 0.5 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. 

– 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 during the last 

leak survey in a calendar year continues to emit 

until the end of the calendar year.. 

 Population count and emission factor. Calculate CH4

and CO2 emissions from the sources listed in 40 CFR 

98.233(r). 

– 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 of subpart 

W. The most recent gas composition that is 

representative of the field must be used to 

determine the percent of the leaked gas that is CH4

and CO2. 

– For underground natural gas storage, the emission 

factors in Table W-4 of subpart W 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. 
38 of 287 

– 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 of subpart W will be used to account for 

equipment leaks in underground meter and regulation 

stations, pipelines, and service lines. 

 Offshore production. Calculate CO2 and CH4 emissions 

from offshore petroleum and natural gas production 

facilities using the methods outlined by BOEMRE3 

Gulfwide Emissions Inventory Study, herein after 

referred to as “GOADS.” Offshore production facilities 

are not required to report portable emissions to EPA. 

– Offshore production facilities reporting under the 

BOEMRE GOADS program must report where available the 

same annual emissions as calculated by BOEMRE using 

activity data submitted by platform operators in the 

latest GOADS study calculated by BOEMRE’s data base 

management system. For the 2011 calendar year, 

offshore production facilities currently under the 

GOADS program must report the latest published 

emissions from the GOADS study for platforms in 

service in the GOADS study year. In subsequent 

calendar years when BOEMRE publishes an updated 

GOADS study, reporters shall report emissions based 

on that latest GOADS study. For each calendar year 

that does not overlap with the GOADS publication of 

a new study, reports for platforms operating in the 

current year that were also operating in the last 

published GOADS study should be adjusted based on 

the operating time for each platform relative to the 

operating time in the previous reporting period. 

 

3

 The Bureau of Ocean Energy Management, Regulation, and Enforcement 

(BOEMRE) was formerly known as Minerals Management Service (MMS) 
39 of 287 

– For offshore production facilities that do not 

report under the BOEMRE GOADS program (non-GOADS 

reporters), monthly activity data from applicable 

offshore production facilities must be collected for 

the first calendar year in accordance with the 

latest GOADS program instructions. Calculation of 

GHG emissions must be performed using the latest 

GOADS program emission factors and methodologies as 

outlined in the latest published GOADS study. In 

subsequent calendar years, facilities not under 

GOADS jurisdiction must follow the data collection 

cycle as required in the GOADS program by collecting 

new monthly activity data, estimating GHG emissions 

using the latest GOADS program emission factors and 

methodologies and report those emissions to EPA. 

For each calendar year that does not overlap with a 

new GOADS study publication, offshore production 

facilities not reporting under the BOEMRE GOADS 

program must report the last reported emissions data 

with emissions adjusted based on the operating time 

for each platform relative to operating time in the 

previous reporting period. Thus, these facilities 

will gather data and estimate updated emissions on 

the same cycle as facilities reporting to the GOADS 

program. 

– For either first or subsequent year reporting, 

platforms either within or outside of GOADS 

jurisdiction that were not covered in the previous 

GOADS data collection cycle shall collect monthly 

activity data from platform sources in accordance 

with the latest GOADS program instructions and 

calculate GHG emissions using the latest GOADS 

program emission factors and methodologies. 

– If BOEMRE discontinues or delays their GOADS survey 

by more than 4 years, then offshore production 

facilities shall collect monthly activity data every 

4 years from platform sources in accordance with the 

latest published version of the GOADS program 

instructions, and annual GHG emissions shall be 

calculated using latest GOADS program emission 

factors and methodologies. 

– Offshore production facilities subject to subpart W 

must report stationary combustion emissions under 

subpart C of part 98. 
40 of 287 

– All Offshore production facilities, whether out of 

or under the jurisdiction of BOEMRE GOADS program 

are to adhere to the monitoring and QA/QC 

requirements in the applicable BOEMRE regulations. 

 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 hydrocarbons beyond storage per barrel of produced 

liquid hydrocarbons. 

 EOR injection pump blowdown. Calculate CO2 emissions 

from enhanced oil recovery critical phase CO2 injection 

pump blowdowns by calculating the volume of gascontaining structures between isolation valves, 

including piping. Use engineering estimates and best 

available data to determine the volume of gascontaining structures between isolation valves. The 

volumes calculated may be used in subsequent years if 

the hardware has not changed. 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 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 and 

natural gas distribution combustion emissions. 

Calculate CO2, CH4 and N2O combustion emissions from 

stationary and portable combustion equipment in 

onshore petroleum and natural gas production and 

stationary combustion equipment in natural gas 

distribution using the following methods: 

– 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 subpart C. 

– Following the methodologies in 40 CFR 98.233(z), if 

the fuel combusted is field gas or a combination of 

field gas or process vent gas and one or more fuels 

listed in Table C-1 of subpart C, then use the 
41 of 287 

volume of fuel and the composition of the fuel to 

calculate CO2 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 by installing a permanent 

flow meter or use engineering calculations. 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. 

– Emissions from external fuel combustion sources with 

a rated heat capacity less than or equal to 5 

mmBtu/hour do not have to be reported. Only activity 

data (unit count by type of unit) for such sources 

is to be reported. 

– Calculate N2O 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 of subpart C if possible. If the 

fuel is field gas or process vent gas, a default 

high heat value is provided. If another fuel, not 

covered by Table C-1 of subpart C or field gas or 

process vent 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 

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

subpart W. 

Definitions. EPA added definitions that are specific 

to subpart W to 40 CFR 98.238 to avoid any confusion with 

the definitions found in 40 CFR 98.6. For compliance with 

subpart W, the subpart W specific definitions apply instead 

of any of the same definitions also found in subpart A. 

We are including a definition of the term “Offshore” 

in 40 CFR 98.238 to fully identify those petroleum and 

natural gas production platforms, secondary platforms and 

associated storage tanks covered by this rule. 

We are also including two distinctive definitions of 

facility for onshore petroleum and natural gas production 

and for 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 

industry (e.g., onshore natural gas processing, onshore 

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 

the scope of reporting and responsible reporting entities. 

However, in onshore petroleum and natural gas production 

and natural gas distribution such distinctions are more 
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challenging. As explained in the April 2010 proposal, EPA 

evaluated existing definitions used under current 

regulations and determined that it was necessary to provide 

a unique definition of facility for each of these two 

segments in order to ensure that the reporting delineation 

is clear, avoid double counting, and ensure appropriate 

emissions coverage. For more information please see the 

preamble for the April 2010 proposal (75 FR 18608) and the 

Greenhouse Gas Emissions from Petroleum and Natural Gas 

Industry: Background Technical Support Document (EPA-HQOAR-2009-0923). 

These definitions are intended only for purposes of 

subpart W and are not intended to affect to definition of a 

facility as it might be applied in any other context of the 

Clean Air Act. 

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 

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, 
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the ownership is clear to one company, and reporting at 

this level is consistent with 40 CFR part 98. 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 

percent 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 40 CFR 98.238. Where 

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

basin, then all onshore petroleum and natural gas 

production equipment associated with all wells that the 

person or entity owns or operates in the basin would be 

considered one facility. In the April 2010 proposal, EPA 

evaluated at least two available industry recognized 

definitions that identify hydrocarbon basins: one from the 

United States Geological Survey (USGS) and the other from 

the American Association of Petroleum Geologists. Basins 
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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. 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 natural gas production 

wells and CO2 EOR operations continue to 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 percent GHG emissions coverage of this industry segment. 

Finally, in this final action, EPA has replaced the 

term “fugitive emissions” with “equipment leaks.” This 

change was made to ensure consistency with the terminology 
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in the Alternative Work Practice to Detect Leaks from 

Equipment for 40 CFR parts 60, 63, and 65. 

E. Summary of Major Changes and Clarifications Since 

Proposal 

The major changes and clarifications in subpart W 

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 

organized following the different sections of the subpart W 

regulatory text. 

1. Definition of the Source Category

 EPA revised the definition for onshore natural gas 

processing and onshore petroleum and natural gas 

production to exclude gathering lines and boosting 

stations from the source category. 

 EPA revised the definition of onshore petroleum and 

natural gas production to include equipment on a well 

pad or associated with a well pad, due to the growing 

industry practice of multi-well pads, where equipment 

may serve one well on a pad or several wells on a pad. 

 EPA has revised the definition of natural gas 

processing to clarify that this industry segment 

includes (1) all processing facilities that 

fractionate and (2) those that do not fractionate with 

throughput of 25 MMscf per day or greater. 

 EPA has revised the definition for the natural gas 

processing industry segment by removing the term 

“plant” from the segment name to ensure consistency 
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with terminology used by other industry segment 

definitions. 

 EPA clarified that meters and regulators in the 

natural gas distribution industry segment do not 

include customer meters. 

 

2. Reporting Threshold.

 EPA is amending the reporting threshold language in 

subpart W to clarify that onshore petroleum and 

natural gas production facilities and onshore natural 

gas distribution facilities must report emissions only 

from sources specified in subpart W. This amendment 

was necessary to clearly define what emissions sources 

are to be included for considering the threshold in 

determining applicability for these two industry 

segments because they each have a different definition 

of the term “facility” than what is defined in the 

general provisions of part 98. 

3. GHGs to Report. 

 EPA removed the reporting requirements for produced 

water from coal bed methane (CBM) and enhanced oil 

recovery (EOR) operations. 

4. 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 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 gas 

imaging instrument. 

 For applicable industry segments (onshore natural gas 

processing, onshore natural gas transmission 

compression, underground natural gas storage, LNG 

storage and LNG import and export equipment), EPA 
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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, EPA requires reporters to conduct at least 

one measurement of each compressor in the not 

operating, depressurized mode during every 3-year 

period. Commenters suggested to EPA that based on 

their operational experience, 3 years is an 

appropriate maximum time period during which 

compressors will be shutdown at least once for routine 

maintenance, such that 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. Also see “Compressor Modes 

and Threshold ” Docket EPA-HQ-OAR-2009-0923 

 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 requiring individual counts for all 

components to determine populations to which to 

apply component emission factors 

– As compressors in onshore petroleum and natural gas 

production are small in size, EPA is allowing the 

use of emission factors for calculating GHG 

emissions from centrifugal and reciprocating 

compressors in onshore petroleum and natural gas 

production rather than conducting an annual 

measurement of each compressor in the mode in which 

it is found. 

– EPA is allowing onshore petroleum and natural gas 

production reporters to complete a total count of 

pneumatic devices any time within the first three 

calendar years. A reporter must report pneumatic 

device emissions annually. For any years where 

activity data (count of pneumatic devices) is 

incomplete, use best available data or engineering 

estimates to calculate pneumatic device emissions. 

– For collecting gas composition data for produced 

natural gas, EPA is allowing reporters to use 
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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 receiving oil from separators or 

directly from wells with less than 10 barrels per 

day throughput; onshore petroleum and natural gas 

production and onshore natural gas processing 

dehydrators with less than 0.4 million standard 

cubic feet per day throughput; 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. 

– For both the onshore petroleum and natural gas 

production industry segment and the natural gas 

distribution industry segment, external fuel 

combustion emissions from portable or stationary 

equipment with rated heat capacity less than or 

equal to 5 mmBtu/hr, only activity data must be 

reported. 

– Blowdown emissions from equipment vessel chambers 

totaling less than 50 cubic feet are not required to 

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. In 

addition, through-valve leakage to open ended vents, 

such as unit isolation valves on not operating 

depressurized compressors and blowdown valves on 

pressurized compressors, may be measured using 

acoustic leak detection devices. 

 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). 

 For transmission storage tanks, EPA is allowing 

reporters to use an acoustic leak detection device to 

monitor leakage through compressor scrubber dump 

valves into the tank. 
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5. Applicability. 

To assist reporters in determining applicability, EPA 

is planning to develop screening tools to assist in the 

determination of which entities may potentially be required 

to report under subpart W of 40 CFR part 98. 

F. Summary of Comments and Responses

This section contains a brief summary of major 

comments and responses. EPA received many comments on this 

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 this preamble. 

1. Definition of the Source Category

Comment: Numerous commenters objected to the 

inclusion of gathering lines and booster stations in the 

natural gas processing industry segment 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 
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gathering lines and boosting stations that typically are 

associated with a single natural gas processing facility, 

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 natural gas processing facility , to a scenario 

where a single company owns the wells, a second distinct 

company (or multiple companies) own the gathering lines, 

and a third distinct company may own the natural gas 

processing facility. The commenter further explained that 

these scenarios are further complicated because the 

variations in gas flow 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 facility. 

Finally, a number of commenters requested that the 

gathering lines and boosting stations be excluded from the 

natural gas processing industry segment 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 
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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 similar 

comments raised to ensure an effective coverage of 

emissions from this source, and is considering the most 

appropriate mechanism for future actions to address the 

collection of 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 
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segment have been refined to make clear what emissions are 

to be reported for this industry segment. 

Comment: Commenters noted that many facilities would 

fall under more than one industry segment in a calendar 

year and requested clarification as to which industry 

segment such a facility would be required to report under. 

In addition some commenters noted that they have equipment 

from multiple industry segments located in the same 

physical space. 

Response: EPA has reviewed these comments and has 

addressed them. Please see response to comment EPA-HQ-OAR2009-0923-1024-14 in the Mandatory Greenhouse Gas Reporting 

Rule: EPA’s Response to Public Comments. 

2. 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, 

commenters stated that the reporting of emissions from 

portable equipment will only marginally increase coverage 
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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: 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 rated heat capacity above 

5 mmBtu/hour. 

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 

self-propelled equipment is responsible for over 45 percent 

of total emissions from onshore petroleum and natural gas 
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production. Please see “Portable Combustion Emissions” 

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 modified the final rule to simplify the 

requirements for external combustion equipment that fall 

below a rated heat capacity of 5 mmBtu/hr for the onshore 

petroleum and natural gas industry segment and the natural 

gas distribution industry segment. Please see “Portable 

Combustion Emissions” Docket EPA-HQ-OAR-2009-0923 and 

“Equipment Threshold for Small Combustion Units” Docket 

EPA-HQ-OAR-2009-0923 for the analysis. Equipment that 

fall below the specified mmBtu level for the applicable 

industry segments would not have to conduct monitoring for 

combustion emissions, and would only be required to report 

activity data which would be total number of external fuel 

combustion units with a rated heat capacity of equal to or 

less than 5 mmBtu/hr by type of unit. 

3. Monitoring, QA/QC, and Calculating Emissions

Comment: EPA received numerous comments on the use of 

the optical gas imaging instrument for detecting GHG 
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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 

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. EPA agrees with commenters and has 

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. EPA is still requiring that 

reporters use optical gas imaging instruments for 

inaccessible sources due to potential safety and cost 

concerns related to leak detection of sources that cannot 

be physically accessed from a fixed, supportive surface 
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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 methods for detecting methane 

emissions in the petroleum and natural gas sector4. 

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 pressurized, not 

operating/depressurized) 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. 

 

4

 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 approach, 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. 
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Response: 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 

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 3-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, when the compressor 

is in the not operating and depressurized mode, 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 
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specifically for the purposes of monitoring to gather 

measurements at this frequency. Accordingly, EPA is 

requiring reporters to schedule the measurement of 

compressors in the not operating and depressurized mode at 

least once during each consecutive 3- 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 

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 
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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 

burdensome, since many compressors would require the 

installation of expensive permanent meters. 

Response: 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 “Alternative 

Methodologies” Docket EPA-HQ-OAR-2009-0923 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: 
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 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.). 

 Quarterly sampling of gas composition has been 

replaced with using your most recent representative 

gas analysis. Most onshore petroleum and natural gas 

producers would have this information already for 

transaction processing. 

 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 50 cubic 

feet are not required to be reported. For more 

information, the following documents; “Equipment 

Threshold for Tanks,” “Equipment Threshold for 

Dehydrators,” and “Equipment Threshold for Blowdowns” 

can be found in docket EPA-HQ-OAR-2009-0923. 

 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 component 

counts and population emissions factors instead of 

engineering estimates. Note that onshore petroleum and 

natural gas production reporters must complete a total 

count of pneumatic devices any time within the first 

three calendar years. A reporter must report pneumatic 

device emissions annually. For any years where 

activity data (count of pneumatic devices) is 

incomplete, use best available data or engineering 

estimates to calculate pneumatic device emissions. 

 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, through-valve leakage to open ended vents, 

such as unit isolation valves on not operating 
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depressurized compressors and blowdown valves on 

pressurized compressors, may be measured using 

acoustic leak detection devices. In addition, 

compressor throughput flow meters are not required; 

estimates of compressor flow will be sufficient for 

EPA’s requirements. 

4. 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 onshore natural gas processing and onshore natural gas 

transmission industry segments expressed their concern with 

their ability to comply with monitoring requirements, such 

as installing necessary measurement ports or meters for 

measurement. 

Response: 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 than by 

January 1, 2011. EPA carefully considered each source and 

the reporting compliance requirements and determined for 
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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 

specified in the following sections and in 40 CFR 98.234(f) 

of the rule. 

Best available monitoring methods are any of the 

following methods: monitoring methods currently used by the 

facility that do not meet the specifications of a relevant 

subpart; supplier data; engineering calculations; or other 

company records. 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 calculation methods set 

forth in 40 CFR 98.233, but may use best available 

monitoring methods to estimate the parameters in the 

equations as specified in the following sections.
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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. If the reporter anticipates the 

potential need for best available monitoring for sources 

for which they need to petition EPA and the situation is 

unresolved at the time of the deadline, reporters should 

submit written notice of this potential situation to EPA by 

the specified deadline for requests to be considered. EPA 

reserves the right to review petitions after the deadline 

but will only consider and approve late petitions which 

demonstrate extreme or unusual circumstances. 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 in the following 

sections. 

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 
65 of 287 

be possible to collect or reproduce data after the event is 

over. EPA recognizes that a significant portion of welldrilling activities are conducted by third-party service 

providers and 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-related emissions data as 

of January 1, 2011. For these sources EPA will allow the 

use of best available monitoring methods through June 30, 

2011 to allow reporters sufficient time to meet the 

requirements of the rule. 

 Eligible 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 40 CFR 98.233 (g) 

– Gas well completions using hydraulic fracture in 

paragraph 40 CFR 98.233 (g) 

– Well testing/flaring in paragraph 40 CFR 98.233 (l) 

 

 Reporting Requirements. For the eligible sources 

listed, an owner or operator must use the equations 

prescribed in 40 CFR 98.233(g) and 40 CFR 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 

from 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 April 30, 2011. 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 40 CFR 98.232(c)(6), 40 CFR 

98.232(c)(8), and 40 CFR 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 40 CFR 

98.233(g) and 40 CFR 98.233(l) that the owner or 

operator cannot meet in 2011, including a detailed 

explanation as to why the requirements cannot be 

met. 

– 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 
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providers or other relevant entities provide 

required data. 

– Demonstrate that it is not possible to obtain the 

necessary information, service or hardware which may 

include providing 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. 

– 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, or 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 September 30, 2011. 

The owner or operator must provide the following 

information in a request for the use of best available 

monitoring methods beyond 2011 for sources covered under 40 

CFR 98.232 (c)(6), 40 CFR 98.232 (c)(8), and 40 CFR 98.232 

(c)(12) for beyond 2011: 
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– 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 40 CFR 

98.233(g) and 40 CFR 98.233(l) that 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 40 CFR 98.232 (c)(6), 40 CFR 98.232 

(c)(8), and 40 CFR 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 

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 
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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 40 CFR 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 cannot reproduce or 

replicate the data 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), (f), (g), (h), 

(l), (o), (p), (q), (r) of 40 CFR part 98. 

– Number of blowdowns, completions, workovers, or 

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

(i), and (w) of 40 CFR part 98. 

– 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) of 

40 CFR part 98. 
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 Reporting Requirements. For the sources eligible for 

best available monitoring methods applicable to 

stipulated activity data, , owners and operators must 

use the equations prescribed in 40 CFR 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 sources eligible 

for best available monitoring methods applicable to 

stipulated activity data 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 eligible 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 for this information 

after June 30, 2011. 

 Requests for Extension in 2011. Only under extreme 

circumstances, which include safety, or 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 

must be received by April 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. 
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– A description of the specific requirements in 

paragraphs §98.233(e), (f), (g), (h), (i), (j), (k), 

(l), (m), (n), (o), (p), (q), (r), (w), (x), (y), 

and (z) of 40 CFR Part 98 that 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 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 of the preamble. 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 

applicable stipulated activity data sources eligible 

for best available monitoring methods; 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 September 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 

paragraphs §98.233(e), (f), (g), (h), (i), (j), (k), 

(l), (m), (n), (o), (p), (q), (r), (w), (x), (y), 

and (z) of 40 CFR Part 98 that the owner or operator 
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cannot meet, including a detailed explanation as to 

why the requirements cannot 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 of the preamble. 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 

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 
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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., onshore natural gas 

processing, onshore natural gas transmission 

compression, underground natural gas storage, LNG 

storage, and LNG import and export equipment) in 40 

CFR 98.233(p). 

– Centrifugal compressor wet seal oil degassing 

venting for facilities downstream of petroleum and 

natural gas production in 40 CFR 98.233(o). 

– Acid gas removal vents in 40 CFR 98.233(d) 

– Equipment leaks in facilities downstream of onshore 

petroleum and natural gas production in 40 CFR 

98.233(q). 

– Transmission storage tanks in 40 CFR 98.233(k). 

 Reporting Requirements. For the sources eligible for 

best available monitoring methods applicable to 

acquisition and implementation of leak detection and 

monitoring equipment or services, , 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 maintenance records in place 

of the required monitoring methods outlined for 

parameters in 40 CFR 98.233. These 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. Because leak detection and/or measurement 
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surveys are one-time actions that can be conducted at 

any time during the year, by April 30, 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 April 30, 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 40 CFR 

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

98.233(q) that 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 which demonstrates that the owner or 

operator made all reasonable efforts to obtain the 

service necessary to comply with subpart W reporting 

requirements in 2011, including evidence of specific 

service or equipment providers contacted and why 

services could not be obtained during 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 necessary equipment 

in time to meet 2011 reporting requirements. If 

relevant equipment vendors cannot 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, 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. 
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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, or 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 

September 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 40 CFR 

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

98.233(q) for which extension is being requested and 

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 of the preamble. 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 receive the 

services or equipment to comply with subpart W 

reporting requirements. 

The Administrator reserves the right to require 

additional documentation. 

Unique or Extreme Circumstances

 Requests for 2011: Emissions sources not covered 

under the previous three categories of BAMM are under 

operational control of the owner or operator, require 

one time data collection at any point during the 
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calendar year and do not require leak detection or 

measurement equipment. For these reasons, for the 

sources not covered under the previous three 

categories of BAMM, EPA does not anticipate the need 

for best available monitoring methods; however, EPA 

will review all requests submitted by April 30, 2011 

and consider approval of the use of best available 

monitoring methods for 2011 under unique and extreme 

circumstances, which include safety, or 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 under the previous three 

categories of BAMM 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. 

The Administrator reserves the right to require 

additional documentation. 

 Requests beyond 2011: For sources not covered in the 

previous three categories of BAMM, EPA does not 

anticipate the need for best available monitoring 

methods beyond 2011; however, EPA will review such 

requests submitted by September 30, 2011 and consider 

approval of the use of best available monitoring 

methods for 2012 under unique and extreme 

circumstances, which include safety, or a requirement 

being technically infeasible or counter to other 
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local, State, or Federal regulations. Requests for 

the use of best available monitoring methods for 

sources not covered in the previous three categories 

of BAMM, 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 section 114 does not authorize 

EPA to 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. 
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Response: As explained in Section I.C. of this 

preamble, Section I.C and Q of the 2009 final Part 98 

preamble (74 FR 56260), and the document Mandatory 

Greenhouse Gas Reporting Rule: EPA’s Response to Public 

Comments, Volume 9, Legal Issues (EPA-HQ-OAR-2008-0508), 

EPA is promulgating subpart W 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, CAA section 103 authorizes EPA to establish a 

national research and development program, including nonregulatory 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 pollutants. For more 

information about EPA’s legal authority please see the 

related sections and documents in the preamble for subpart 

W. 
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6. 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 Part 98 (74 FR 56355), 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 nonemployee, to represent them, while ensuring EPA has one 

accountable point of contact. As explained in the preamble 

to the final Part 98, the high level of public interest in 

the data collected, as well as its importance to future 

policy, warrants establishment of a high standard for data 
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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 for 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 

ultimate responsibility of submission with the designated 

representative has the salutary effect of clarifying that 
81 of 287 

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, 

January 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 more information, see Section V of the 

preamble to the 2009 final Part 98 (74 FR 56260) and the 
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document 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). 

7. 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 Greenhouse Gas Reporting Program 

to help reporters assess the applicability of the 

Greenhouse Gas Reporting Program5 to their facilities, EPA 

plans to develop voluntary screening tools for the 

petroleum and natural gas source category. 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 that are clearly well 

 

5

 http://www.epa.gov/climatechange/emissions/GHG-calculator/index.html 
83 of 287 

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 subpart W rulemaking, 

including the estimated costs and benefits of subpart W, 

and the estimated economic impacts on affected facilities, 

including estimated impacts on small entities. Complete 

details of the economic impacts of the final subpart W 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, Docket EPA-HQ-OAR-2008-0508. 

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.6

 

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 

and 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. 

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, result in notably higher costs in the 

 

6

 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 and LDCs, 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 2 or 3 

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 CO2e 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. 

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 
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for reasons not associated with the rule (to allow only the 

incremental costs to be estimated). 

Labor Costs. The costs of complying with and 

administering this rule include time of managers, and of 

technical, operational and administrative staff in the 

private sector. Staff hours were estimated for activities, 

including: 

 Developing a plan: reporting entity management, legal, 

and technical staff hours to determine applicability 

of the rule, organize training on rule requirements, 

identify staffing assignments, train staff, and 

schedule activities as required below. 

 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) 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 
88 of 287 

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. 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 earlier in this section, reporting 

entities that equal or exceed the subpart W threshold must 

report combustion emissions following the methods under 

subpart C, except for onshore production entities that 

consume field gas or process vent gas and LDCs, which must 

report combustion emissions following the methods under 

subpart W. 

For purposes of cost estimation, EPA determined that 

under the final rule, entities that need to report 

incremental combustion-related emissions, as previously 

defined, would likely use either the Tier 1 calculation 
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methodology as set forth in subpart C or the calculation 

methodology as set forth in subpart W (40 CFR 98.233(z)). 

EPA determined that the entities reporting incremental 

emissions under subpart C would likely not meet the 

requirements for Tier 2 or higher methods. However, as 

these entities will be reporting combustion emissions under 

subpart C (except onshore production and LDCs), if a 

facility did meet the requirements for a tier other than 

Tier 1, the facility would have to use the required method, 

as specified in subpart C. 

Given that the combustion methodology in 40 CFR 

98.233(z) is similar to the Tier 1 calculation methodology, 

EPA estimated the costs to monitor and report incremental 

combustion-related emissions based on the approach used 

under 40 CFR part 98, subpart C.7

 Specifically, EPA applied 

the Tier 1 calculation 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 fuel-specific default CO2

emission factor, a default high heating value of the fuel, 

and the annual fuel consumption from company records. 

 

7

 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). 
90 of 287 

EPA based its conclusion that entities would likely 

report incremental combustion emissions using the Tier 1 

method on three considerations for applicability of the 

Tier 2 calculation 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 

calculation methodology, (2) the maximum rated heat 

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

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

analysis, units must have a rated heat capacity less than 

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

of subpart C, and sample the HHV of the fuel consumed at 

the required frequency in 40 CFR 98.34(a). It was 

determined that this minimum required sampling frequency is 

not currently carried out at these smaller units and 

therefore these units would not be required to use Tier 2 

methodology. These units will generally follow Tier 1 

methodology. 

Second, Tier 3 and Tier 4 calculation methodologies 

generally apply to equipment with a maximum rated heat 

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 CO2e; these 
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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. 

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. The use of 

produced natural gas is predominant in onshore petroleum 

and natural gas production. Under the final rule for 

subpart W, reporters in this segment are allowed to use 

methods similar to Tier 1 for all combustion emissions 

sources that use produced natural gas. 

In the remaining segments, equipment using produced 

natural gas or products recovered from equipment leaks and 

vents are normally required to use Tier 2 methodology or 

higher. However, as described previously, if the unit has 

a rated heat capacity 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 analysis and could use 

a Tier 1 analysis instead. If the unit has a maximum rated 

heat capacity greater than 250 mmBtu/hr, then as just 

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

subject to reporting under subpart C and would not be 
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included in the incremental combustion emissions category 

considered in this analysis. In sum, the use of Tier 1 

methodology for incremental combustion is a reasonable 

assumption for costing the subpart W rule. 

Reporting Determination Costs. 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

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 of this 

preamble, Section III.B.2, What are the costs of the rule? 

For the detailed responses to all comments received, see 

Mandatory Greenhouse Gas Reporting Rule: EPA’s Response to 

Public Comments, Subpart W: Petroleum and Natural Gas 

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

B. What are the costs of the rule?

1. Summary of Costs
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Table 6 of this preamble presents for each segment the 

total costs and costs per ton in the first year and 

subsequent years as well as the annualized costs. EPA 

estimates that the total private sector cost in the first 

year is about $62 million and about $19 million for 

subsequent years; the annualized cost over a 20-year time 

period is about $21 million (3 percent discount rate) and 

$22 million (7 percent discount rate) (2006$). Of these 

costs, EPA estimates roughly $40 million to report process 

emissions in the first year and about $15 million in 

subsequent years. In addition, EPA estimates approximately 

$3 million to report incremental combustion related 

emissions 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 7a and Table 7b of 

this preamble provide 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 per 
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metric ton of emissions reported. The incremental cost is 

calculated as the additional (incremental) cost per metric 

ton using 25,000 metric tons CO2 equivalent as the baseline. 

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 subpart W. 

Table 6 National Cost Estimates for Petroleum and Natural 

Gas Systems (2006$)1

 First Year Subsequent Year 

Annualized 

Cost (3%)2 

($Million)

Annualized 

Cost (7%)3

($Million) Segment 

National 

Cost 

($Million)

Cost 

($/metr

ic ton)

National 

Cost 

($Millio

n)

Cost 

($/metr

ic ton)

Processin

g 8.13 0.26 2.10 0.07 2.43 2.57 

Transmiss

ion 16.87 0.40 6.49 0.15 7.02 7.26 

Undergrou

nd 

Storage 2.73 0.35 1.02 0.13 1.10 1.14 

LNG 

Storage 0.70 0.41 0.26 0.15 0.28 0.29 

LNG 

import/ex

port 0.14 0.44 0.03 0.09 0.04 0.04 

LDC 3.31 0.15 1.35 0.06 1.47 1.52 

Onshore 

Productio

n 26.58 0.12 7.54 0.03 8.61 9.05 

Offshore 

Productio

n 3.33 0.65 0.24 0.05 0.42 0.49 

TOTAL (8 

Segments) 61.78 0.18 19.01 0.06 21.36 22.34 

1 Includes determination costs for non-reporters. These estimates are 

conservative and should be viewed as an upper-bound because the 

determination costs were applied at the facility-level rather than the 

company-level. For example, for offshore production, determination 
95 of 287 

costs were applied to each of the approximately 3,000 platforms in the 

Gulf of Mexico rather than the 86 operators in that region. See the 

memo, “Estimates of Determination Costs,” in the docket for complete 

details and additional determination cost estimates (EPA-HQ-OAR-2009-

0923). 

2 The cost to report annualized over 20 years at 3 percent (see 

additional details in section 5 of the EIA for the final rule). 

3 The cost to report annualized over 20 years at 7 percent (see 

additional details in section 5 of the EIA for the final rule). 

Table 7a. Threshold Cost-effectiveness Analysis (First 

Year, 2006$) 

Threshold 

(metric 

tons 

CO2e) 

Facilit

ies 

Require

d to 

Report 

Total 

Costs1

 

(million 

$2006) 

Downstream 

Emissions 

Reported 

(MtCO2e/ 

year) 

Percentage 

of Total 

Downstream 

Emissions 

Reported 

Average 

Reporting 

Cost 

($/Mt)1

Increm

ental 

Cost 

($/Mt)

1,2

1,000 12,622 $148.67 391 99% $0.38 $1.62

10,000 4,400 $79.01 362 91% $0.22 $0.69

25,000 2,786 $61.78 337 85% $0.18 $0.00

100,000 1,062 $44.32 273 69% $0.16 ($0.27)

1

Includes determination costs for non-reporters. The upper-bound first 

year determination cost estimates for each threshold are as follows: 

1,000 metric tons CO2e = $12.3 million; 10,000 metric tons CO2e = $17.4 

million; 25,000 metric tons CO2e = $18.4 million; and 100,000 metric 

tons CO2e = $19.3 million. As noted in previous table, these estimates 

are conservative. See the memo, “Estimates of Determination Costs,” in 

the docket for complete details and additional determination cost 

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

2

Cost per metric ton relative to the selected option (25,000 MT 

threshold). 

TABLE 7b. Threshold Cost-Effectiveness Analysis 

(Subsequent Year, 2006$) 

Threshold 

(metric 

tons 

CO2e) 

Facilit

ies 

Require

d to 

Report 

Total 

Costs1

 

(million 

$2006) 

Downstream 

Emissions 

Reported 

(MtCO2e/ 

year) 

Percentage 

of Total 

Downstream 

Emissions 

Reported 

Average 

Reporting 

Cost ($/Mt) 1

Increm

ental 

Cost 

($/Mt)

1,2

1,000 12,622 $73.44 391 99% $0.19 $1.02 

10,000 4,400 $30.51 362 91% $0.08 $0.46 

25,000 2,786 $19.01 337 85% $0.06 $0.00 

100,000 1,062 $9.77 273 69% $0.04 

($0.14

) 

1

Includes determination costs for non-reporters. The upper-bound 

determination costs in subsequent years for each threshold are as 

follows: 1,000 metric tons CO2e = $1.8 million; 10,000 metric tons CO2e 

= $1.0 million; 25,000 metric tons CO2e = $0.6 million; and 100,000 
96 of 287 

metric tons CO2e = $0.2 million. As noted in previous table, these 

estimates are conservative. See the memo, “Estimates of Determination 

Costs,” in the docket for complete details and additional determination 

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

2

Cost per metric ton relative to the selected option (25,000 MT 

threshold). 

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 proposed subpart W (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 and equipment for certain industry 

segments to monitor and report emissions. 

Reporting Determination. 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 Section II.F.6 of this preamble, the 
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commenters also recommended that EPA develop screening 

tools to reduce the burden for facilities to make a 

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 

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 further screening; Section 4 of the EIA provides a 

complete discussion of the basis for this estimate.8

 EPA 

expects use of the screening tool to minimize burden by 

 

8

 These estimates are conservative and should be viewed as an upperbound because the determination costs were applied at the facilitylevel rather than the company-level. For example, for offshore 

production, determination costs were applied to each of the 

approximately 3,000 platforms in the Gulf of Mexico rather than the 86 

operators in that region. See the memo, “Estimates of Determination 

Costs,” in the docket for complete details and additional determination 

cost estimates (EPA-HQ-OAR-2009-0923). 
98 of 287 

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. Facilities for 

which the tool estimates emissions well below the threshold 

will generally not need to conduct further screening. 

Facilities for which the tool estimates emissions near the 

threshold will generally conduct additional screening, and 

this is reflected in the cost estimates. 

Labor and Equipment Costs. 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. 

In development of this rule and in response to 

comments, EPA collected and evaluated cost data from 

multiple sources, closely reviewed the input received 

through public comments, and weighed the analysis prepared 

against this input. EPA also carefully weighed the burden 

of incrementally more comprehensive methods of measuring 
99 of 287 

and calculating emissions against the increase in coverage 

and accuracy, and in some cases revised or clarified the 

measurement and calculation requirements. EPA has thus 

adjusted both the rule requirements and its cost estimates 

in response to comments, and concludes that its methodology 

and final cost estimates appropriately account for the 

compliance burden under this final rule. EPA determined 

that the commenters’ alternative estimates are much higher 

than the agency’s because of assumptions and 

interpretations that were either inconsistent with EPA’s 

original intent (and which EPA has now clarified) or 

requirements that have been revised; in some cases, the 

alternative estimates were also based on higher-cost, 

optional monitoring methods. 

EPA summarizes below the key assumptions, revisions, 

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. 

3. Onshore Production

Comment: Commenters stated that EPA’s estimated 

compliance costs for the onshore petroleum and natural gas 
100 of 287 

production segment were too low. Overall, the commenters 

concluded that EPA should reassess the analysis of entities 

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 commenter made 

various assumptions that differed from EPA’s analysis and 

accounted for the difference in the cost estimates. One 

source of the difference stemmed from the 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.9

 In 

 

9

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

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

information. 
101 of 287 

particular, the commenter said that counting components to 

estimate emissions from equipment leaks would be onerous. 

Additional differences in the commenter’s and EPA’s 

estimates resulted from differences in the assumptions 

about labor wages and time spent sampling. For example, 

the commenter presented a breakdown of the labor and 

equipment costs, such as labor wages and time spent on 

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 true costs will be substantially higher 

than those estimated by the agency. 

First, EPA disagrees with the commenter’s estimate of 

the number of sources subject to reporting because it 
102 of 287 

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 

than required under the proposal, is incorrect. The 

quantity and type of emissions from wells are variable; in 

fact, it is not necessary to monitor 80 percent of wells to 

account for 80 percent of emissions and neither the 

proposed nor final rules would require such a large 

percentage of wells to be covered. Because the final rule 

tends to target those wells that have the higher emissions, 

based on its threshold analysis, EPA estimates that 

approximately 60 percent of the wells are subject to the 

monitoring requirements, and that these wells will account 

for about 85 percent of total GHG emissions from this 

segment. 

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 
103 of 287 

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 owned or operated by entities that would trigger 

the reporting threshold, not 80 percent. 

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. EPA notes that the rule does not require 

reporters to purchase data collection software. It is at 

the reporters’ discretion to do so. 

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 
104 of 287 

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 nonhazardous 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 

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 
105 of 287 

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 proposed subpart W, EPA did not 

intend for 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 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 
106 of 287 

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. 

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 Section II.E of this preamble). 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. 

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

4. 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 
107 of 287 

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 facilities. 

Response: Based on its thorough review of the 

comments, EPA determined that the commenter’s estimates for 

processing facilities 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 facilities in its analysis. 

However, EPA agrees with the commenter that the agency’s 

analysis partly underestimated the costs at processing 

facilities to 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 facilities, 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 
108 of 287 

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.10 

Reporters will only need to purchase one hotwire anemometer 

per facility; the hotwire anemometer can be used to measure 

the flow rate at multiple compressors at the facility. 

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. 

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 

 

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

http://www.globalw.com/products/407119.html 
109 of 287 

the AGR. These revised requirements are reflected in the 

cost analysis in the final EIA. 

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 for the proposed rule did not accurately reflect the 

number of gathering lines and boosting stations that would 

have been subject to the rule. EPA has dropped the 

requirement for reporting on gathering lines and boosting 

stations from the final rule, so these costs are not 

included in the analysis. Instead, EPA will continue to 

evaluate options for obtaining emissions data from 

gathering lines and boosting stations in a way that 

maximizes data quality while balancing industry burden; see 

Section II.F.1 of this preamble for further discussion. 

5. 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, 
110 of 287 

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 

optical gas imaging instrument, 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 

inconsistent with the Agency’s intent and this likely 

accounted for the discrepancies between the estimates. 

EPA disagrees with the commenter’s cost estimate 

because it is based on the assumption that customer meters 

are subject to leak detection requirements. The commenter 

assumed that the proposed rule required leak detection and 

emissions estimates for all 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 
111 of 287 

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 

instrument equipment, e.g., allowing alternatives to 

infrared cameras in some situations. As discussed 

previously in Section II.E of this preamble, this final 

action provides more flexibility and further reduces the 

compliance cost by allowing facilities to use alternative 

leak detection equipment. 

The commenter did not identify the monitoring 

activities and assumptions underlying 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. Because EPA has accounted 

for the two primary issues raised by the commenter 

(monitoring of customer meters and allowable leak detection 

equipment), EPA did not change its cost estimate to reflect 

the much higher costs estimated by the commenter. 
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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 and large 

reporting entities. 

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.11 The 

national costs of the rule are notable because there are a 

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

low. Average cost-to-sales ratios for establishments in 

the affected NAICS codes for all segments is less than 1 

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

petroleum and natural gas segment. 

These low average cost-to-sales ratios indicate that 

the final rule is unlikely to result in significant changes 

in firms’ production decisions or other behavioral changes 

that would result in significant changes in prices or 

quantities in affected markets. Given that prices and 

 

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

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

each segment at the NAICS level for this screening assessment. 
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quantities are unlikely to change significantly, and 

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 resulting measures of social 

cost.12 Table 8 of this preamble summarizes cost-to-sales 

ratios for affected industries. 

Table 8. Estimated Cost-to-sales Ratios for Affected 

Entities (Year 1) 

NAICS 

NAICS 

Description MRR Segments Included 

Average 

Cost Per 

Entity 

($1,000/ent

ity) 

Average 

Entity 

Cost-toSales 

Ratioa

211 

Crude 

Petroleum and 

Natural Gas 

Extraction 

Onshore Production, 

Offshore Production, 

Processing $17.1 0.08% 

486210 

Pipeline 

Transportation 

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% 

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

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

2. Summary of Comments and Responses

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 of this preamble, commenters said that EPA 

 

12 Guidelines for Preparing Economic Analyses (EPA, 2002, p.124-125) 
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underestimated the compliance costs and recommended that 

EPA carefully review the economic impact analysis. See the 

previous section of this preamble for a summary; the 

response to comments document, Mandatory Greenhouse Gas 

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

W: Petroleum and Natural Gas Systems, provides detailed 

comments. 

As discussed in Section III.B.2 of this preamble, 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 economic impacts and that the documentation provides 

adequate explanation of how the costs and impacts were 

estimated. 

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.) 
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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 CO2e threshold 

because it sufficiently captures the majority of GHG 

emissions in the United States, while excluding many 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 

maintaining a high level of 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.13 The cost-to-sales ratios were 

 

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

continues to be the preferred quantitative metric for economic impact 

screening analysis. 
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constructed at the establishment level (average reporting 

program costs per establishment/average establishment 

receipts) for several business size ranges. This allowed 

EPA to account for receipt differences between 

establishments owned by large and small businesses and 

differences in small business definitions across affected 

industries. The results of the screening assessment are 

shown in Table 9 of this preamble. 
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TABLE 9. Estimated Cost-to-Sales Ratios, Sales Receipts ($Million), And Number of EstabFirst Year Costs by Industry and Enterprise Sizea

SBA Size 

Standard in 

num of 

employees 

(effective 

March 11, 

2008)

Average 

Cost Per 

Entity 

($1,000/

entity) 

All 

Enterprises 

Owned by Enterpri

Industry NAICS 

NAICS 

Description

1 to 20 

Employees 

20 to 99 

Employees

100 to 

499 

Employees

< 500 

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% 0.47% 

$160,879 

d

$7,573 $6,790 $9,609 $23,972 

7,629e 5,836 456 292 6,584 

Onshore 

natural gas processing; onshore natural gas transmission; underground natural gas storage 

486210 Pipeline 

Transportation of Natural Gas 

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

$35,897d $1,035 $106c $394c $2,566 

1,936e 81 27 61 36 

Natural gas 

distribution 

221210 Natural Gas 

Distribution

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

$67,275d $2,524 $4,642 $2,878 $13,127 

2,897e 483 86 131 700 

a The Census Bureau defines an enterprise as a business organization consisting of one or more domestic establishments that were specified control. The enterprise and the establishment are the same for single-establishment firms. Each multi-establishment company forms one enteremployment and annual payroll are summed from the associated establishments. Enterprise size designations are determined by the summed emplestablishments.  Since the SBA’s business size definitions (http://www.sba.gov/size) apply to an establishment’s ultimate parent company, EPA assumes in thenterprise definition above is consistent with the concept of ultimate parent company that is typically used for Small Business Regulatory (SBREFA) screening analyses. b The SBA size standard for NAICS 486210 is $7 million in average annual receipts. 
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c The U.S. Census Bureau has missing data for this employee range; some estimates were possible using partial data. The receipts for these true value. d This row presents total annual sales receipts ($Million)for establishments in each enterprise category. Source: U.S. Census Bureau e This row presents total number of establishments in each enterprise category. Source: U.S. Census Bureau
119 of 287 

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. It is important to note that this analysis does 

not screen out entities that would be below the reporting 

threshold. Based on further analysis of production data in 

HPDI, EPA estimates that in most cases, the smaller 

enterprises have very small operations (such as a single 

family owning a few production wells) that are unlikely to 

cross the 25,000 metric tons CO2e reporting threshold. 

In other cases, a small enterprise (less than 20 

employees) may own large operations but conduct nearly all 

of its operations through service providers, so that it has 

few employees of its own. Such enterprises, however, tend 

to have higher annual revenues than those with small 

operations and therefore have lower cost-to-sales ratios. 

The review of production data by operator in HPDI shows a 
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ratio of less than one percent for the operators expected 

to meet the reporting threshold. 

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. That is, the analysis assumes that each 

establishment is a unique enterprise. To the extent that a 

single parent may own multiple establishments, the small 

entity impacts could be lower. 

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 
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emissions to report. The Agency also established 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. 

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 

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 
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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 of the preamble 

and in the EIA. 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 in 

determining whether or not they have to report. 
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The response to comments document, Mandatory 

Greenhouse Gas Reporting Rule: EPA’s Response to Public 

Comments, Subpart W: Petroleum and Natural Gas Systems, 

presents the detailed comments and responses related to the 

rule’s impact on small businesses. 

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

EPA examined the potential benefits of the final 

subpart W. The benefits of a reporting system are based on 

their relevance to policy making, transparency, and market 

efficiency. Benefits are very difficult to quantify and 

monetize. Instead of a quantitative analysis of the 

benefits, EPA conducted a systematic literature review of 

existing studies including government, consulting, and 

scholarly reports. 

A mandatory reporting system for petroleum and natural 

gas systems will benefit policymakers and the public by 

increased availability of facility emissions data. Public 

data on emissions allows for accountability of emitters to 

the public. Citizens, community groups, and labor unions 

have made use of data from Pollutant Release and Transfer 

Registers to negotiate directly with emitters to lower 

emissions, circumventing greater government regulation. 

Publicly available emissions data also will allow 

individuals to alter their consumption habits based on the 
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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 that provide significant 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 subpart W will increase 

knowledge of the location and magnitude of significant 

methane emissions sources in the petroleum and natural gas 

industry, which can result in improvements in these 

technologies and the identification of new emissions 

reducing technologies. 

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 justify 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. The Information Collection 

Request (ICR) document prepared by EPA has been assigned 

EPA ICR number 2376.02. 

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 
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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)14. 

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. 

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, 

 

14 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 that 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 9 of this preamble, 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. It is 

important to note that this analysis does not screen out 

entities that would be below the reporting threshold. 

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 

mtCO2e threshold, a threshold supported by many stakeholders 

as one that sufficiently captures the majority of GHG 

emissions while excluding small facilities. 

EPA also concluded that the final rulemaking would not 

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

enterprise that 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. 

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. 
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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 (see Section II.F.6 of this preamble). 

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 

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 
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businesses on the EPA GHG reporting rule website, 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. 

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 non-
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reporters 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

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

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

this action. 

F. Executive Order 13175: Consultation and Coordination 

with Indian Tribal Governments

EPA has concluded that this action may have tribal 

implications. However, it will neither impose substantial 

direct compliance costs on tribal governments, nor preempt 

Tribal law. 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 

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. 
136 of 287 

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. 

Specifically, tribes that own or operate oil and gas 

operations could 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. 

EPA sought opportunities to provide information to tribal 

governments and representatives during rule development. As 

stated in IV.F of this preamble, 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 Part 98. 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). 
137 of 287 

In addition, EPA prepared a short article on the 

Greenhouse Gas 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 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-HQOAR-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 Part 98. 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. 

G. Executive Order 13045: Protection of Children from 

Environmental Health Risks and Safety Risks
138 of 287 

This action is not subject to EO 13045 because it does 

not establish an environmental standard intended to 

mitigate health or safety risks. Also, this is not an 

economically significant rule under EO 12866, and thus EO 

13045 does not apply. 

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 mtCO2e 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

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 
139 of 287 

impractical. Voluntary consensus standards are technical 

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

sampling procedures, and business practices) that are 

developed or adopted by voluntary consensus standards 

bodies. NTTAA directs EPA to provide Congress, through 

OMB, explanations when the Agency decides not to use 

available and applicable voluntary consensus standards. 

This rulemaking involves technical standards. EPA 

provides the flexibility to use any one of the voluntary 

consensus standards from at least seven different voluntary 

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 
140 of 287 

flow; and methods to gauge and measure petroleum and 

petroleum products. 

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 12898 (59 FR 7629, February 16, 1994) 

establishes Federal executive policy on environmental 

justice. Its main provision directs Federal agencies, to 

the greatest extent practicable and permitted by law, to 

make environmental justice part of their mission by 

identifying and addressing, as appropriate, 

disproportionately high and adverse human health or 

environmental effects of their programs, policies, and 

activities on minority populations and low-income 

populations in the United States. 

EPA has determined that this 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 
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to human health or the environment because it is a rule 

addressing information collection and reporting procedures. 

K. Congressional Review Act 

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 30 DAYS AFTER PUBLICATION OF THIS FINAL RULE IN THE 

FEDERAL REGISTER OR DECEMBER 31, 2010, WHICHEVER IS 

EARLIER]. 
Mandatory Reporting of Greenhouse Gases: 

Petroleum and Natural Gas Systems 

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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. 

Dated: 

 

Lisa P. Jackson, 

Administrator. 
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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 the 

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

§98.2 Who must report?

(a) The GHG reporting requirements and related 

monitoring, recordkeeping, and reporting requirements of 

this part apply to the owners and operators of any facility 

that is located in the United States or under or attached 

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

1331) and that meets the requirements of either paragraph 

(a)(1), (a)(2), or (a)(3) of this section; and any supplier 

that meets the requirements of paragraph (a)(4) of this 

section: 

 

* * * * * 
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3. Section 98.6 is amended by adding the following 

definitions in alphabetical order and revising the 

definition of “United States” to read as follows: 

§98.6 Definitions.

Absorbent circulation pump means a pump commonly 

powered by natural gas pressure that circulates the 

absorbent liquid between the absorbent regenerator and 

natural gas contactor. 

* * * * * 

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. 

* * * * * 
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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. 

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. 
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* * * * * 

Continuous bleed means a continuous flow of pneumatic 

supply gas to the process measurement device (e.g. level 

control, temperature control, pressure control) where the 

supply gas pressure is modulated by the process condition, 

and then flows to the valve controller where the signal is 

compared with the process set-point to adjust gas pressure 

in the valve actuator. 

* * * * * 

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 emissions means natural gas and CO2

released from a natural gas dehydrator system absorbent 

(typically glycol) reboiler or regenerator to the 

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. 

* * * * * 
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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. 

* * * * * 

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. 

* * * * * 
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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 that 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 6 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 that 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 

for maintaining a process condition such as liquid level, 

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

power stream that is regulated by the process condition 

flows to a valve actuator controller where it vents 
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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. §1331, 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 

reciprocating compressor piston rod to create a seal 

limiting the amount of compressed natural gas or CO2 that 

escapes to the atmosphere. 
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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. 

* * * * * 

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 
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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. 

* * * * * 

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 

that do not significantly vent natural gas to the 

atmosphere. This process may also include high-rate 
152 of 287 

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

fracture or re-fracture and prop open new fractures in 

existing lower permeability gas reservoirs, steps that 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 proppant used to refracture and prop-open new fractures in existing low 

permeability gas reservoirs, steps that 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.” 
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4. Section 98.7 is amended by reserving paragraphs 

(n) and (o), and by adding paragraphs (p) and q) to read as 

follows: 

§98.7 What standardized methods are incorporated by 

reference into this part?

* * * * * 

(n) [Reserved] 

(o) [Reserved] 

(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. 

(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, 
154 of 287 

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] 

5. Table A-4 to subpart A is amended by adding an 

entry for “Petroleum and Natural Gas Systems (subpart W)” 

at the end of the table to read as follows: 

Table A-4 to 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.

6. Add subpart W – Petroleum and Natural Gas Systems 

to read as follows: 
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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. 

(a) This source category consists of the following 

industry segments: 

(1) Offshore petroleum and natural gas production. 

Offshore petroleum and natural gas production is any 

platform structure, affixed temporarily or permanently to 

offshore submerged lands, that houses equipment to extract 

hydrocarbons from the ocean or lake floor and that 

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 via walkways, storage tanks 

associated with the platform structure and floating 

production and storage offloading equipment (FPSO). This 

source category does not include reporting of emissions 
156 of 287 

from offshore drilling and exploration that is not 

conducted on production platforms. 

(2) Onshore petroleum and natural gas production. 

Onshore petroleum and natural gas production means all 

equipment on a well pad or associated with a well pad 

(including compressors, generators, or storage facilities), 

and portable non-self-propelled equipment on a well pad or 

associated with a well pad (including well drilling and 

completion equipment, workover equipment, gravity 

separation equipment, auxiliary non-transportation-related 

equipment, and leased, rented or contracted equipment) used 

in the production, extraction, recovery, lifting, 

stabilization, separation or treating of petroleum and/or 

natural gas (including condensate). This equipment also 

includes associated storage or measurement vessels and all 

enhanced oil recovery (EOR) operations using CO2, and all 

petroleum and natural gas production located on islands, 

artificial islands, or structures connected by a causeway 

to land, an island, or artificial island. 

(3) Onshore natural gas processing. Natural gas 

processing separates and recovers natural gas liquids 

(NGLs) and/or other non-methane gases and liquids from a 

stream of produced natural gas using equipment performing 

one or more of the following processes: oil and condensate 
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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. This segment also includes all 

residue gas compression equipment owned or operated by the 

natural gas processing facility, whether inside or outside 

the processing facility fence. This source category does 

not include reporting of emissions from gathering lines and 

boosting stations. This source category includes: 

(i) All processing facilities that fractionate. 

(ii) All processing facilities that do not 

fractionate with throughput of 25 MMscf per day or greater. 

(4) Onshore natural gas transmission compression. 

Onshore natural gas transmission compression means any 

stationary combination of compressors that move natural gas 

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 may 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 onshore natural gas 

processing segment and are excluded from this segment. 
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This source category also does not include reporting of 

emissions from gathering lines and boosting stations – 

these sources are currently not covered by subpart W. 

(5) Underground natural gas storage. Underground 

natural gas storage means subsurface storage, including 

depleted gas or oil reservoirs and salt dome caverns that 

store 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 that inject and recover natural gas into and 

from the underground reservoirs. 

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

means onshore LNG storage vessels located above ground, 

equipment for liquefying natural gas, compressors to 

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

vaporization units for re-gasification of the liquefied 

natural gas. 

(7) LNG import and export equipment. LNG import 

equipment means all onshore or offshore equipment that 

receives imported LNG via ocean transport, stores LNG, re-
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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. 

(8) Natural gas distribution. Natural gas 

distribution means the distribution pipelines (not 

interstate transmission pipelines or intrastate 

transmission 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 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. 

(b) [Reserved] 

§98.231 Reporting threshold.

(a) You must report GHG emissions under this subpart 

if your facility contains petroleum and natural gas systems 
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and the facility meets the requirements of §98.2(a)(2). 

Facilities must report emissions from the onshore petroleum 

and natural gas production industry segment only if 

emission sources specified in paragraph §98.232(c) emit 

25,000 metric tons of CO2 equivalent or more per year. 

Facilities must report emissions from the natural gas 

distribution industry segment only if emission sources 

specified in paragraph §98.232(i) emit 25,000 metric tons 

of CO2 equivalent or more per year. 

 (b) For applying the threshold defined in 

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

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 and portable combustion emissions as applicable 

as specified in paragraph (k) of this section. 

(b) For offshore petroleum and natural gas 

production, report CO2, CH4, and N2O emissions from equipment 

leaks, vented emission, and flare emission source types as 
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identified in the data collection and emissions estimation 

study conducted by BOEMRE in compliance with 30 CFR 250.302 

through 304. Offshore platforms do not need to report 

portable emissions. 

(c) For an onshore petroleum and natural gas 

production facility, report CO2, CH4, and N2O emissions from 

only the following source types on a well pad or associated 

with a well pad: 

(1) Natural gas pneumatic device venting. 

(2) [Reserved] 

(3) Natural gas driven pneumatic pump venting. 

(4) Well venting for liquids unloading. 

(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 vented emissions from produced 

hydrocarbons. 

(11) Reciprocating compressor rod packing venting. 
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(12) Well testing venting and flaring. 

(13) Associated gas venting and flaring from produced 

hydrocarbons. 

(14) Dehydrator vents. 

(15) [Reserved] 

(16) EOR injection pump blowdown. 

(17) Acid gas removal vents. 

(18) EOR hydrocarbon liquids dissolved CO2. 

(19) Centrifugal compressor venting. 

(20) [Reserved] 

(21) Equipment leaks from valves, connectors, open 

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

other equipment leak sources (such as instruments, loading 

arms, stuffing boxes, compressor seals, dump lever arms, 

and breather caps). 

(22) You must use the methods in §98.233(z) and 

report under this subpart the emissions of CO2, CH4, and N2O 

from stationary or portable fuel combustion equipment that 

cannot move on roadways under its own power and drive 

train, and that are located at an onshore production well 

pad. Stationary or portable equipment are the following 

equipment which are integral to the extraction, processing 

or movement of oil or natural gas: well drilling and 

completion equipment, workover equipment, natural gas 
163 of 287 

dehydrators, natural gas compressors, electrical 

generators, steam boilers, and process heaters. 

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

CH4 emissions from the following sources: 

(1) Reciprocating compressor rod packing venting. 

(2) Centrifugal compressor venting. 

(3) Blowdown vent stacks. 

(4) Dehydrator vents. 

(5) Acid gas removal vents. 

(6) Flare stack emissions. 

(7) Equipment leaks from valves, connectors, open 

ended lines, pressure relief valves, and meters. 

(e) For onshore natural gas transmission compression, 

report CO2 and CH4 emissions from the following sources: 

(1) Reciprocating compressor rod packing venting. 

(2) Centrifugal compressor venting. 

(3) Transmission storage tanks. 

(4) Blowdown vent stacks. 

(5) Natural gas pneumatic device venting. 

(6) [Reserved] 

(7) Equipment leaks from valves, connectors, open 

ended lines, pressure relief valves, and meters. 

(f) For underground natural gas storage, report CO2

and CH4 emissions from the following sources: 
164 of 287 

(1) Reciprocating compressor rod packing venting. 

(2) Centrifugal compressor venting. 

(3) Natural gas pneumatic device venting. 

(4) [Reserved] 

(5) Equipment leaks from valves, connectors, open 

ended lines, pressure relief valves, and meters. 

(g) For LNG storage, report CO2 and CH4 emissions from 

the following sources: 

(1) Reciprocating compressor rod packing venting. 

(2) Centrifugal compressor 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 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: 
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(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, regulators, and open ended 

lines. Customer meters are excluded. 

(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. 

(6) Report under subpart W of this part the emissions 

of CO2, CH4, and N2O emissions from stationary fuel 

combustion sources following the methods in §98.233(z). 

(j) All applicable industry segments must report the 

CO2, CH4, and N2O emissions from each flare. 

(k) Report under subpart C of this part (General 

Stationary Fuel Combustion Sources) the emissions of CO2, 

CH4, and N2O from each stationary fuel combustion unit by 

following the requirements of subpart C. Onshore petroleum 

and natural gas production facilities must report 

stationary and portable combustion emissions as specified 

in paragraph (c) of this section. Natural gas distribution 
166 of 287 

facilities must report stationary combustion emissions as 

specified in paragraph (i) of this section. 

(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. You must calculate and 

report the annual GHG emissions as prescribed in this 

section. For actual conditions, reporters must use average 

atmospheric conditions or typical operating conditions as 

applicable to the respective monitoring methods in this 

section. 

(a) Natural gas pneumatic device venting. Calculate 

CH4 and CO2 emissions from continuous high bleed, continuous 

low bleed, and intermittent bleed natural gas pneumatic 

devices using Equation W-1 of this section. 

* * * * 24*365 Masss,i  Count EF GHGi Convi (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 as 
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determined in paragraph (a)(1) of this 

section. 

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 compression, 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. 

 (1) For onshore petroleum and natural gas production, 

provide the total number of continuous high bleed, 

continuous low bleed, or intermittent bleed natural gas 

pneumatic devices of each type as follows: 

(i) In the first calendar year, for the total number 

of each type, you may count the total of each type, or 

count any percentage number of each type plus an 

engineering estimate based on best available data of the 

number not counted. 

(ii) In the second consecutive year, for the total 

number of each type, you may count the total of each type, 

or count any percentage number of each type plus an 
168 of 287 

engineering estimate based on best available data of the 

number not counted. 

(iii) In the third consecutive calendar year, 

complete the count of all pneumatic devices, including any 

changes to equipment counted in prior years. 

(iv) For the calendar year immediately following the 

third consecutive calendar year, and for calendar years 

thereafter, facilities must update the total count of 

pneumatic devices and adjust accordingly to reflect any 

modifications due to changes in equipment. 

(2) For onshore natural gas transmission compression 

and underground natural gas storage, all natural gas 

pneumatic devices must be counted in the first year and 

updated every calendar year. 

(b) [Reserved] 

(c) Natural gas driven pneumatic pump venting. 

Calculate CH4 and CO2 emissions from natural gas driven 

pneumatic pump venting using Equation W-2 of this section. 

Natural gas driven pneumatic pumps covered in paragraph (e) 

of this section do not have to report emissions under 

paragraph (c) of this section. 

* * * * 24*365 Masss,i  Count EF GHGi Convi (Eq. W-2) 

Where: 
169 of 287 

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) vents. For AGR vent 

(including processes such as amine, membrane, molecular 

sieve or other absorbents and adsorbents), calculate 

emissions for CO2 only (not CH4) vented directly to the 

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

membrane or de-adsorbed gas from a pressure swing adsorber 

used as fuel supplement), or sulfur recovery plant using 

any of the calculation methodologies described in paragraph 

(d) of this section. 

(1) 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 

Methodology and all associated requirements for Tier 4 in 

subpart C of this part (General Stationary Fuel Combustion 
170 of 287 

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 

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 

conditions, in cubic feet per year. 

VS = Total annual volume of vent gas flowing out of 

the AGR unit in cubic feet per year at actual 

conditions as determined by flow meter using 

methods set forth in §98.234(b). 

VolCO2 = Volume fraction of CO2 content in vent gas out 

of the AGR unit as determined in (d)(6) of 

this section. 

(3) Calculation Methodology 3. If using CEMS or vent 

meter is not an option, 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. 

       Ea,CO2  V   * V * VolI VolO

* VolI VolO (Eq. W-4) 

Where: 
171 of 287 

Ea,CO2 = Annual volumetric CO2 emissions at actual 

condition, in cubic feet per year. 

V = Total annual volume of natural gas flow into 

or out of the AGR unit in cubic feet per year 

at actual condition as determined using 

methods specified in paragraph (d)(5) of this 

section. 

α = Factor is 1 if the outlet stream flow is 

measured. Factor is 0 if the inlet stream 

flow is measured. 

VolI = Volume fraction of CO2 content in natural gas 

into the AGR unit as determined in paragraph 

(d)(7) of this section. 

VolO = Volume fraction of CO2 content in natural gas 

out of the AGR unit as determined in paragraph 

(d)(8) of this section. 

(4) Calculation Methodology 4. Calculate emissions 

using any standard simulation software packages, such as 

AspenTech HYSYS® and API 4679 AMINECalc, that uses the PengRobinson equation of state, and speciates CO2 emissions. A 

minimum of the following determined for typical operating 

conditions over the calendar year by engineering estimate 

and process knowledge based on best available data must be 

used to characterize emissions: 

(i) Natural gas feed temperature, pressure, and flow 

rate. 

(ii) Acid gas content of feed natural gas. 

(iii) Acid gas content of outlet natural gas. 

(iv) Unit operating hours, excluding downtime for 

maintenance or standby. 
172 of 287 

(v) Exit temperature of natural gas. 

(vi) Solvent pressure, temperature, circulation rate, 

and weight. 

(5) 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. 

(6) If continuous gas analyzer is not available on 

the vent stack, either install a continuous gas analyzer or 

take quarterly gas samples from the vent gas stream to 

determine VolCO2 according to methods set forth in 

§98.234(b). 

(7) 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 

gas samples from the inlet gas stream to determine VolI 

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

(8) Determine volume fraction of CO2 content in 

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

specified in paragraph (d)(8) of this section. 
173 of 287 

(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. 

(9) Calculate CO2 volumetric emissions at standard 

conditions using calculations in paragraph (t) of this 

section. 

(10) Mass CO2 emissions shall be calculated from 

volumetric CO2 emissions using calculations in paragraph (v) 

of this section. 

(11) Determine if emissions from the AGR unit are 

recovered and transferred outside the facility. Adjust the 

emission estimated in paragraphs (d)(1) through (d)(10) of 

this section downward by the magnitude of emission 

recovered and transferred outside the facility. 

(e) Dehydrator vents. For dehydrator vents, 

calculate annual CH4, CO2 and N2O (when flared) emissions 
174 of 287 

using calculation methodologies described in paragraphs 

(e)(1) or (e)(2) of this section. 

(1) Calculation Methodology 1. Calculate annual mass 

emissions from dehydrator vents with throughput greater 

than or equal to 0.4 million standard cubic feet per day 

using a software program, such as AspenTech HYSYS® or GRIGLYCalc, 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. 
175 of 287 

(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: 
176 of 287 

* *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 74.5 for CH4 and 

3.26 for CO2 at 68°F and 14.7 psia or 73.4 for 

CH4 and 3.21 for CO2 at 60°F and 14.7 psia. 

Count = Total number of glycol dehydrators with 

throughput less than 0.4 million cubic feet. 

1000 = Conversion of EFi 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) of this section downward by the magnitude of 

emissions captured. 

(4) Calculate annual emissions from dehydrator vents 

to flares or regenerator fire-box/fire tubes as follows: 

(A) Use the dehydrator vent 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 emissions from the flare or regenerator combustion gas 

vent. 
177 of 287 

(5) Dehydrators that use desiccant shall calculate 

emissions from the amount of gas vented from the vessel 

every time it is depressurized for the desiccant refilling 

process using Equation W-6 of this section. Desiccant 

dehydrators covered in (e)(5) of this section do not have 

to report emissions under (i) 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. Calculate 

CO2 and CH4 emissions from well venting for liquids 
178 of 287 

unloading using one of the calculation methodologies 

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

section. 

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

unique well tubing diameter and producing horizon/formation 

combination in each gas producing field (see §98.238 for 

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 (t) 

and producing horizon (h)/formation combination 

during the year. 

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

measured well venting for the duration of the 

liquids unloading, under actual conditions as 

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

section. 
179 of 287 

(i) Determine the well vent average flow rate as 

specified under paragraph (f)(1)(i) of this section. 

(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. 

(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: 
180 of 287 

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. 

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. 

(ii) [Reserved] 

(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: 
181 of 287 

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 to plunger bumper (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. 

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. 

(ii) [Reserved] 

(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 CH4, CO2 and N2O (when 

flared) annual emissions from gas well venting during 

completions involving hydraulic fracturing in wells and 
182 of 287 

well workovers using Equation W-10 of this section. Both CH4

and CO2 volumetric and mass emissions shall be calculated 

from volumetric total gas emissions using calculations in 

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

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

Where: 

Ea,n = Annual volumetric total gas emissions in cubic 

feet at standard 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 

reporting. 

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

actual conditions, converted to standard 

conditions, as required in paragraph (g)(1) of 

this section. 

EnF = Volume of CO2 or N2 injected gas in cubic feet at 

standard conditions that was injected into the 

reservoir during an energized fracture job. If 

the fracture process did not inject gas into the 

reservoir, then EnF is 0. If injected gas is CO2

then EnF is 0. 

SG = Volume of natural gas in cubic feet at standard 

conditions that was recovered into a sales 

pipeline. If no gas was recovered for sales, SG 

is 0. 

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

atmosphere or to a flare during well completions and 

workovers from hydraulic fracturing shall be determined 
183 of 287 

using either of the calculation methodologies described in 

this paragraph (g)(1) of this section. 

(i) Calculation Methodology 1. For one well 

completion in each gas producing field and for one well 

workover in each gas producing field, a recording flow 

meter (digital or analog) 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 routed to 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 producing field and to all well 

workovers in the producing field for the total number of 

hours of venting of each of these wells. 

(C) New flow rates for completions and workovers are 

measured every other calendar year for each reporting gas 

producing field and gas producing geologic horizon in each 

gas producing field starting in the first calendar year of 

data collection. 

(D) Calculate total volumetric flow rate at standard 

conditions using calculations in paragraph (t) of this 

section. 
184 of 287 

(ii) Calculation Methodology 2. For one well 

completion in each gas producing field and for one well 

workover in each gas producing field, record the well 

flowing pressure upstream(and downstream in subsonic flow) 

of a well choke according to methods set forth in 

§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 of this section for subsonic 

flow or Equation W-12 of this section for sonic flow: 































  













  

1.758

1

2

1.515

1

5 2 1.27 10 * * 3430* * P

P

P

P FR A Tu (Eq. W-11) 

Where: 

FR = Average flow rate in cubic feet per hour, 

under subsonic flow conditions. 

A = Cross sectional area of orifice (m2). 

P1 = Upstream pressure (psia). 

Tu = Upstream temperature (degrees Kelvin). 

P2 = Downstream pressure (psia). 

3430 = Constant with units of m2

/(sec2 * K). 

1.27*105

 = Conversion from m3/second to ft3/hour. 

FR A Tu 1.27 10 * * 187.08* 5   (Eq. W-12) 

Where: 

FR = Average flow rate in cubic feet per hour, 

under sonic flow conditions. 
185 of 287 

A = Cross sectional area of orifice (m2). 

Tu = Upstream temperature (degrees Kelvin). 

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

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

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

venting across the choke is calculated for one well 

completion in each gas producing field and for one well 

workover in each gas producing field by averaging the gas 

flow rates during venting to the atmosphere or routing to a 

flare. 

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

completions in the gas producing field and to all well 

workovers in the gas producing field for the total number 

of hours of venting of each of these wells. 

(C) Flow rates for completions and workovers in each 

field shall be calculated once every two years for each 

reporting gas producing field and geologic horizon in each 

gas producing field starting in the first calendar year of 

data collection. 

(D) Calculate total volumetric flow rate at standard 

conditions using calculations in paragraph (t) of this 

section. 

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

reservoir during energized hydraulic fractures will be 
186 of 287 

measured using an appropriate meter as described in 

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

for the energized fracture job. 

(i) Calculate gas volume at standard conditions using 

calculations in paragraph (t) of this section. 

(ii) [Reserved] 

(3) The volume of recovered completion gas sent to a 

sales line will be measured using existing company records. 

If data does not exist on sales gas, then an appropriate 

meter as described in 98.234(b) may be used. 

(i) Calculate gas volume at standard conditions using 

calculations in paragraph (t) of this section. 

(ii) [Reserved] 

(4) Both CH4 and CO2 volumetric and mass emissions 

shall be calculated from volumetric total emissions using 

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

(5) Determine if the well completion or workover from 

hydraulic fracturing recovered gas with purpose designed 

equipment that separates saleable gas from the backflow, 

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

completion). 
187 of 287 

(i) Use the factor SG in Equation W-10 of this 

section, to adjust the emissions estimated in paragraphs 

(g)(1) through (g)(4) of this section by the magnitude of 

emissions captured using reduced emission completions as 

determined by engineering estimate based on best available 

data. 

(ii) [Reserved] 

(6) Calculate annual emissions from gas well venting 

during well completions and workovers from hydraulic 

fracturing to flares as follows: 

(i) Use the total 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. This 

adjustment to emissions from completions using flaring 

versus completions without flaring accounts for the 

conversion of CH4 to CO2 in the flare. 

(h) Gas well venting during completions and workovers 

without hydraulic fracturing. Calculate CH4, CO2 and N2O 

(when flared) emissions from each gas well venting during 

well completions and workovers not involving hydraulic 
188 of 287 

fracturing and well workovers not involving hydraulic 

fracturing using Equation W-13 of this section: 

  

f

Ea n Nwo EFwo Vf Tf* , (Eq. W-13) 

Where: 

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

actual conditions from gas well venting during 

well completions and workovers without hydraulic 

fracturing. 

Nwo = Number of workovers per field not involving 

hydraulic fracturing in the reporting year. 

EFwo = Emission Factor for non-hydraulic fracture well 

workover venting in actual cubic feet per 

workover. EFwo = 2,454 standard cubic feet per 

well workover without hydraulic fracturing. 

f = Total number of well completions without 

hydraulic fracturing in a field. 

Vf = Average daily gas production rate in cubic feet 

per hour of each well completion without 

hydraulic fracturing. This is the total annual 

gas production volume divided by total number of 

hours the wells produced to the sales line. For 

completed wells that have not established a 

production rate, you may use the average flow 

rate from the first 30 days of production. In the 

event that the well is completed less than 30 

days from the end of the calendar year, the first 

30 days of the production straddling the current 

and following calendar years shall be used. 

Tf = Time each well completion without hydraulic 

fracturing was venting in hours during the year. 

 (1) Calculate natural gas volumetric emissions at 

standard conditions using calculations in paragraph (t) of 

this section. 
189 of 287 

(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. Calculate CO2 and CH4

blowdown vent stack emissions from depressurizing equipment 

to the atmosphere (excluding depressurizing to a flare, 

over-pressure relief, operating pressure control venting 

and blowdown of non-GHG gases; desiccant dehydrator 

blowdown venting before reloading is covered in paragraph 

(e)(5) of this section) as follows: 

(1) Calculate the total volume (including pipelines, 

compressor case or cylinders, manifolds, suction bottles, 

discharge bottles, and vessels) between isolation valves 
190 of 287 

determined by engineering estimate based on best available 

data. 

(2) If the total volume between isolation valves is 

greater than or equal to 50 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 50 standard cubic feet are exempt from 

reporting under paragraph (i) of this section. 

(3) Calculate the total annual venting emissions for 

each equipment type using 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 (o

F). 

Ta = Temperature at actual conditions in the blowdown 

equipment chamber (o

F). 

Ps = Absolute pressure at standard conditions (psia). 
191 of 287 

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. 

(j) Onshore production storage tanks. Calculate CH4, 

CO2 and N2O (when flared) emissions from atmospheric 

pressure fixed roof storage tanks receiving hydrocarbon 

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 emissions using any of the calculation methodologies 

described in this paragraph (j). 

(1) 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 

Tank, that uses the Peng-Robinson equation of state, models 
192 of 287 

flashing emissions, and speciates CH4 and CO2 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. 

(v) Ambient air temperature. 

(vi) Ambient air pressure. 

(vii) 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 default data are provided with the software 

program, select the default values that most closely match 

your separator pressure first, and API gravity secondarily. 

(B) If separator oil composition and Reid vapor 

pressure data are available through your previous analysis, 
193 of 287 

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: 
194 of 287 

(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 and assume all of the CH4 and CO2 in both oil and 

gas are emitted from the tank. 

(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 in the oil is emitted from the 

tank. 

(ii) If well production oil composition is not 

available, use default oil composition in software 
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programs, such as API 4697 E&P Tank, that most closely 

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. 

(5) Calculation Methodology 5. For well pad gasliquid separators and for wells flowing off a well pad 

without passing through a gas-liquid separator with 

throughput less than 10 barrels per day use Equation W-15 

of this section: 

E EF Count s i i* ,  (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, for crude oil use 

4.3 for CH4 and 2.9 for CO2 at 68°F and 14.7 

psia, and for gas condensate use 17.8 for CH4

and 2.9 for CO2 at 68°F and 14.7 psia. 

Count = Total number of separators and wells with 

throughput less than 10 barrels per day. 

(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 
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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 sent 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 of this section. 

     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 Methodologies 1, 2, or 5 in 

paragraphs (j)(1) through (j)(5) of this section 

(with wellhead separators) during time Tn in 

cubic feet per hour. 

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 
197 of 287 

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 crude oil production. 

Correction factor for tank emissions for time 

period Tn is 5.37 for gas condensate production. 

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 Methodologies 1, 2, or 3 in 

paragraphs (j)(1) through (j)(5) of this section 

at maintenance or operations during the time the 

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

cubic feet per hour. 

(9) Calculate both CH4 and CO2 mass emissions from 

volumetric natural gas emissions using calculations in 

paragraph (v) of this section. 

(k) Transmission storage tanks. For condensate 

storage tanks, either water or hydrocarbon, without vapor 

recovery or thermal control devices in onshore natural gas 

transmission compression facilities calculate CH4, CO2 and 

N2O (when flared) annual emissions from compressor scrubber 

dump valve leakage as follows: 

(1) Monitor the tank vapor vent stack annually for 

emissions using an optical gas imaging instrument according 
198 of 287 

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

minutes. Or you may annually monitor leakage through 

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

acoustic leak detection device according to methods set 

forth in §98.234(a)(5). 

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

or the acoustic leak 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 leak 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. 
199 of 287 

(4) Calculate emissions from storage tanks to flares 

as follows: 

(i) Use the storage tank emissions volume and gas 

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

section or with an acoustic leak detection device in 

paragraphs (k)(1) through (k)(3) of this section. 

(ii) Use the calculation methodology of flare stacks 

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

emissions from the flare. 

(l) Well testing venting and flaring. Calculate CH4, 

CO2 and N2O (when flared) 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 this 

section 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). 
200 of 287 

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

this section. 

Ea,n  GOR * FR*D (Eq. W-17) 

Where: 

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 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. 
201 of 287 

(ii) Use the calculation methodology of flare stacks 

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

emissions from the flare. 

(m) Associated gas venting and flaring. Calculate 

CH4, CO2 and N2O (when flared) associated gas venting and 

flaring emissions not in conjunction with well testing 

(refer to paragraph (l): Well testing venting and flaring 

of this section) as follows: 

(1) Determine the GOR of the hydrocarbon production 

from each well whose associated natural gas is vented or 

flared. If GOR from each well is not available, the GOR 

from a cluster of wells in the same 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). 

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

this section. 

Ea,n  GOR * V (Eq. W-18) 
202 of 287 

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 = Volume of oil produced in barrels in the calendar 

year during which associated gas was vented or 

flared. 

(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 CO2, CH4, and 

N2O emissions from a flare stack as follows: 
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(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 all of the flare gas 

is not measured by the existing flow measurement device, 

then the flow not measured can be estimated using 

engineering calculations based on best available data or 

company records. 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. 

(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 
204 of 287 

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. 

(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   (Eq. W-19) 

  a,CO2 Va * X CO2 E un  combusted  (Eq. W-20) 

   

j

a CO Va Yj Rj E , 2 combusted  * * * (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. 
205 of 287 

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 

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) 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 

by summing Equation W-40, Equation W-19, Equation W-20 and 

Equation W-21 of this section. 

(8) Calculate N2O emissions from flare stacks using 

Equation W-40 in paragraph (z) of this section. 
206 of 287 

(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. Calculate CH4, 

CO2 and N2O (when flared) emissions from both wet seal and 

dry seal centrifugal compressor vents as follows: 

(1) For each centrifugal compressor covered by 

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

conduct an annual measurement in the operating mode in 

which it is found. Measure emissions from all vents 

(including emissions manifolded to common vents) including 

wet seal oil degassing vents, unit isolation valve vents, 

and blowdown valve vents. Record emissions from the 

following vent types in the specified compressor modes 

during the annual measurement. 

(i) Operating mode, blowdown valve leakage through 

the blowdown vent, wet seal and dry seal compressors. 

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

(iii) Not operating, depressurized mode, unit 

isolation valve leakage through open blowdown vent, without 

blind flanges, wet seal and dry seal compressors. 

(A) For the not operating, depressurized mode, each 

compressor must be measured at least once in any three 
207 of 287 

consecutive calendar years. If a compressor is not 

operated and has blind flanges in place throughout the 3 

year period, measurement is not required in this mode. If 

the compressor is in standby depressurized mode without 

blind flanges in place and is not operated throughout the 3 

year period, it must be measured in the standby 

depressurized mode. 

(2) For wet seal oil degassing vents, determine vapor 

volumes sent to an atmospheric vent or flare, using a 

temporary meter such as a vane anemometer or permanent flow 

meter according to 98.234(b) 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. 

(3) For blowdown valve leakage and unit isolation 

valve leakage to open ended vents, you can use one of the 

following 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, such 

as isolation valves, you may use an acoustic leak detection 

device according to methods set forth in §98.234(a). 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. 
208 of 287 

(4) Estimate annual emissions using the flow 

measurement and Equation W-22 of this section. 

* * *(1 ) Es,i,m MTm Tm Mi,m  Bm (Eq. W-22) 

Where: 

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

emissions at standard conditions, in cubic feet. 

MTm = Measured gas emissions in standard cubic feet per 

hour. 

Tm = Total time the compressor is in the mode for 

which Es,i is being calculated, in the calendar 

year in hours. 

Mi,m = Mole fraction of GHG i in the vent gas; use the 

appropriate gas compositions in paragraph (u)(2) 

of this section. 

Bm = Fraction of operating time that the 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. 

(5) Calculate annual emissions from each centrifugal 

compressor using Equation W-23 of this section. 



m

Es,i EFm *Tm *GHGi (Eq. W-23) 

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 m, in 

cubic feet per hour, from Equation W-24 of this 

section as calculated in paragraph 6. 
209 of 287 

Tm = Total time in hours per year the compressor was 

in each mode, as listed in paragraph (o)(1)(i) 

through (o)(1)(iii). 

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)(4) through 

(a)(8),GHGi equals 1. 

(6) You shall use the flow measurements of operating 

mode wet seal oil degassing vent, operating mode blowdown 

valve vent and not operating depressurized mode isolation 

valve vent for all the reporter’s compressor modes not 

measured in the calendar year to develop the following 

emission factors using Equation W-24 of this section for 

each emission source and mode as listed in paragraph 

(o)(1)(i) through (o)(1)(iii). 

  m

m

m Count

MT EF (Eq. W-24) 

Where: 

EFm = Reporter emission factors for compressor in the 

three modes m (as listed in paragraph (o)(1)(i) 

through (o)(1)(iii)) in cubic feet per hour. 

MTm = Flow Measurements from all centrifugal compressor 

vents in each mode in (o)(1)(i) through 

(o)(1)(iii) of this section in cubic feet per 

hour. 

Countm = Total number of compressors measured. 

m = Compressor mode as listed in paragraph (o)(1)(i) 

through (o)(1)(iii). 

 (i) The emission factors must be calculated 

annually. You must use all measurements from the current 
210 of 287 

calendar year and the preceding two calendar years, 

totaling three consecutive calendar years of measurements 

in paragraph (o)(6) of this section. 

(ii) [Reserved] 

(7) Onshore petroleum and natural gas production 

shall calculate emissions from centrifugal compressor wet 

seal oil degassing vents as follows: 

Es i Count EFi* ,  (Eq. W-25) 

Where: 

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 12.2 million 

standard cubic feet per year per compressor for 

CH4 and 538 thousand standard cubic feet per year 

per compressor for CO2 at 68°F and 14.7 psia or 

12 million standard cubic feet per year per 

compressor for CH4 and 530 thousand standard 

cubic feet per year per compressor for CO2 at 

60°F and 14.7 psia. 

(8) Calculate both CH4 and CO2 mass emissions from 

volumetric emissions using calculations in paragraph (v) of 

this section. 

(9) Calculate emissions from seal oil degassing vent 

vapors to flares as follows: 
211 of 287 

(i) Use the seal oil degassing vent vapor volume and 

gas composition as determined in paragraphs (o)(5) 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. Calculate CH4

and CO2 emissions from all reciprocating compressor vents as 

follows. For each reciprocating compressor covered in 

§98.232(d)(1), (e)(1), (f)(1), (g)(1), and (h)(1) you must 

conduct an annual measurement for each compressor in the 

mode in which it is found during the annual measurement, 

except as specified in paragraph (p)(9) of this section. 

Measure emissions from (including emissions manifolded to 

common vents) reciprocating rod packing vents, unit 

isolation valve vents, and blowdown valve vents. Record 

emissions from the following vent types in the specified 

compressor modes during the annual measurement as follows: 

(1) Operating or standby pressurized mode, blowdown 

vent leakage through the blowdown vent stack. 

(2) Operating mode, reciprocating rod packing 

emissions. 
212 of 287 

(3) Not operating, depressurized mode, unit isolation 

valve leakage through the blowdown vent stack, without 

blind flanges. 

(i) For the not operating, depressurized mode, each 

compressor must be measured at least once in any three 

consecutive calendar years if this mode is not found in the 

annual measurement. If a compressor is not operated and 

has blind flanges in place throughout the 3 year period, 

measurement is not required in this mode. If the 

compressor is in standby depressurized mode without blind 

flanges in place and is not operated throughout the 3 year 

period, it must be measured in the standby depressurized 

mode. 

(ii) [Reserved] 

(4) If reciprocating rod packing and blowdown vent 

are connected to an open-ended vent line 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 

either calibrated bagging or high volume sampler according 

to methods set forth in §98.234 (c) and §98.234(d), 

respectively. 
213 of 287 

(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 and unit 

isolation valve leakage through blowdown vents according to 

methods set 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 through-valve leakage to open ended vents, such 

as unit isolation valves on not operating, depressurized 

compressors and blowdown valves on pressurized compressors, 

you may use an acoustic detection device according to 

methods set forth in §98.234(a). 

(5) If reciprocating rod packing is not equipped with 

a vent line use the following method to calculate 

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)(5)(i) 

of this section using an appropriate meter, or calibrated 
214 of 287 

bag, or high volume sampler according to methods set forth 

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

(6) Estimate annual emissions using the flow 

measurement and Equation W-26 of this section. 

Es,i,m MTm Tm Mi,m  * * (Eq. W-26) 

Where: 

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

emissions at standard conditions, in cubic feet. 

MTm = Measured gas emissions in standard cubic feet per 

hour. 

Tm = Total time the compressor is in the mode for 

which Es,i,m is being calculated, in the calendar 

year in hours. 

Mi,m = Mole fraction of GHG i in gas; use the 

appropriate gas compositions in paragraph (u)(2) 

of this section. 

(7) Calculate annual emissions from each 

reciprocating compressor using Equation W-27 of this 

section. 



m

Es,i EFm *Tm *GHGi (Eq. W-27) 

Where: 

Es,i = Annual total volumetric GHG emissions at 

standard conditions from each reciprocating 

compressor in cubic feet. 

EFm = Reporter emission factor for each mode, m, in 

cubic feet per hour, from Equation W-28 of this 

section as calculated in paragraph (p)(7)(i) of 

this section. 
215 of 287 

Tm = Total time in hours per year the compressor was 

in each mode, m, as listed in paragraph (p)(1) 

through (p)(3). 

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)(4) through 

(a)(8), GHGi equals 1. 

m = Compressor mode as listed in paragraph (p)(1) 

through (p)(3). 

(i) You shall use the flow meter readings from 

measurements of operating and standby pressurized blowdown 

vent, operating mode vents, not operating depressurized 

isolation valve vent for all the reporter’s compressor 

modes not measured in the calendar year to develop the 

following emission factors using Equation W-28 of this 

section for each mode as listed in paragraph (p)(1) through 

(p)(3). 

 m

m

m Count

MT EF (Eq. W-28) 

Where: 

EFm = Reporter emission factors for compressor in the 

three modes, m, in cubic feet per hour. 

MTm = Meter readings from all reciprocating compressor 

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

hour. 

Countm = Total number of compressors measured in each 

mode, m. 

m = Compressor mode as listed in paragraph (p)(1) 

through (p)(3). 
216 of 287 

(A) You must combine emissions for blowndown vents, 

measured in the operating and standby pressurized modes. 

(B) 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. 

(ii) [Reserved] 

(8) Determine if the reciprocating compressor vent 

vapors are sent to a vapor recovery system. 

(i) Adjust the emissions estimated in paragraphs 

(p)(7) 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] 

(9) Onshore petroleum and natural gas production 

shall calculate emissions from reciprocating compressors as 

follows: 

Es i Count EFi* ,  (Eq. W-29) 

Where: 

Es,i = Annual total volumetric GHG emissions at 

standard conditions from reciprocating 

compressors in cubic feet. 
217 of 287 

Count = Total number of reciprocating compressors for 

the reporter. 

EFi = Emission factor for GHG i. Use 9.63 thousand 

standard cubic feet per year per compressor for 

CH4 and 0.535 thousand standard cubic feet per 

year per compressor for CO2 at 68°F and 14.7 psia 

or 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. at 60°F and 14.7 psia. 

(10) Estimate CH4 and CO2 volumetric and mass 

emissions from volumetric natural gas emissions using the 

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

(q) Leak detection and leaker emission factors. You 

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

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 

gas content less than 10 percent CH4 plus CO2 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 this paragraph (q) and do not need to be 

reported. If equipment leaks are detected for sources 

listed in this paragraph (q), calculate emissions using 

Equation W-30 of this section for each source with 

equipment leaks. 
218 of 287 

 xEs,i GHGi* EFs *Tx (Eq. W-30) 

Where: 

Es,i = Annual total volumetric GHG emissions at 

standard conditions from each equipment leak 

source in cubic feet. 

x = Total number of this type of emissions source 

found to be leaking during Tx. 

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)(4) through 

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

CO2. 

Tx = 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, 

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. 
219 of 287 

(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 valves, connectors, open 

ended lines, pressure relief valves, and meters. 

(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 

equipment leaks detected from valves, connectors, open 

ended lines, pressure relief valves, and meters. 

(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 
220 of 287 

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, 

regulators, and open ended lines. 

(r) Population count and emission factors. This 

paragraph applies to emissions sources listed in §98.232 

(c)(21), (f)(5), (g)(3), (h)(4), (i)(2), (i)(3), (i)(4) and 

(i)(5), on streams with gas content greater than 10 percent 

CH4 plus CO2 by weight. Emissions sources in streams with 

gas content less than 10 percent CH4 plus CO2 by weight do 

not need to be reported. 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. 

Es i Counts EFs GHGi Ts * * * ,  (Eq. W-31) 

Where: 
221 of 287 

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 Tables W-1B 

and Table W-1C of this subpart. Use average 

component counts as appropriate for operations 

in Eastern and Western U.S., according to Table 

W-1D of this subpart. 

EFs = Population emission factor for the specific 

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

through Table W-7 of this subpart. Use 

appropriate population emission factor for 

operations in Eastern and Western U.S., 

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

non-custody transfer city gate stations is 

determined in Equation 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)(4) through 

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

CO2. 

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, 
222 of 287 

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

equipment and components associated with gas wells are 

considered gas service components in reference to Table 1-A 

of this subpart and major natural gas equipment in 

reference to Table W-1B of this subpart. Major equipment 

and components associated with crude oil wells are 

considered crude service components in reference to Table 

1-A of this subpart and major crude oil equipment in 

reference to Table W-1C of this subpart. Where facilities 

conduct EOR operations the emissions factor listed in Table 

W-1A of this subpart 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 

petroleum and natural gas production operations in the 

facility perform the following activities: 

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

and Table W-1C of this subpart. 

(B) Multiply major equipment counts by the average 

component counts listed in Table W-1B and W-1C of this 

subpart for onshore natural gas production and onshore oil 

production, respectively. Use the appropriate factor in 
223 of 287 

Table W-1A of this subpart for operations in Eastern and 

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

subpart. 

(ii) Component Count Methodology 2. Count each 

component individually for the facility. Use the 

appropriate factor in Table W-1A of this subpart for 

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

mapping in Table W-1D of this subpart. 

(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. 

(6) Natural gas distribution facilities shall use the 

appropriate emission factors as described in paragraph 

(r)(6) of this section. 
224 of 287 

(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) of this section. 

Count = Total number of meter runs at all above grade M&R 

city gate stations at custody transfer. 

(s) Offshore petroleum and natural gas production 

facilities. Report CO2, CH4, and N2O emissions for offshore 

petroleum and natural gas production from all equipment 
225 of 287 

leaks, vented emission, and flare emission source types as 

identified in the data collection and emissions estimation 

study conducted by BOEMRE in compliance with 30 CFR 250.302 

through 304. 

(1) Offshore production facilities under BOEMRE 

jurisdiction shall report the same annual emissions as 

calculated and reported by BOEMRE in data collection and 

emissions estimation study published by BOEMRE referenced 

in 30 CFR 250.302 through 304 (GOADS). 

(i) For any calendar year that does not overlap with 

the most recent BOEMRE emissions study publication year, 

report the most recent BOEMRE reported emissions data 

published by BOEMRE referenced in 30 CFR 250.302 through 

304 (GOADS). Adjust emissions based on the operating time 

for the facility relative to the operating time in the most 

recent BOEMRE published study. 

(ii) [Reserved] 

(2) Offshore production facilities that are not under 

BOEMRE jurisdiction shall use monitoring methods and 

calculation methodologies published by BOEMRE referenced in 

30 CFR 250.302 through 304 to calculate and report 

emissions (GOADS). 

(i) For any calendar year that does not overlap with 

the most recent BOEMRE emissions study publication, report 
226 of 287 

the most recent reported emissions data with emissions 

adjusted based on the operating time for the facility 

relative to operating time in the previous reporting 

period. 

(ii) [Reserved] 

(3) If BOEMRE discontinues or delays their data 

collection effort by more than 4 years, then offshore 

reporters shall once in every 4 years use the most recent 

BOEMRE data collection and emissions estimation methods to 

report emission from the facility sources. 

(4) For either first or subsequent year reporting, 

offshore facilities either within or outside of BOEMRE 

jurisdiction that were not covered in the previous BOEMRE 

data collection cycle shall use the most recent BOEMRE data 

collection and emissions estimation methods published by 

BOEMRE referenced in 30 CFR 250.302 through 304 to 

calculate and report emissions (GOADS) to report emissions. 

(t) Volumetric emissions. 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. 

(1) Calculate natural gas volumetric emissions at 

standard conditions by converting actual temperature and 
227 of 287 

pressure of natural gas emissions to standard temperature 

and pressure of natural gas using Equation W-33 of this 

section. 

 

  a s

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 (o

F). 

Ta = Temperature at actual emission conditions (oF). 

Ps = Absolute pressure at standard conditions (psia). 

Pa = 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. 

 

  a s

a i s a

s i

T P

E T P

E

459 .67 *

, * 459 .67 *

, 

 
228 of 287 

Ea,i = GHG i volumetric emissions at actual conditions 

in cubic feet. 

Ts = Temperature at standard conditions (oF). 

Ta = Temperature at actual emission conditions (oF). 

Ps = Absolute pressure at standard conditions (psia). 

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 emissions from natural gas 

emissions using Equation W-35 of this section. 

Es i Es n Mi * ,  , (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, shall be the annual average mole fraction for 

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

(vii) of this section. 
229 of 287 

(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 

continuous gas composition analyzer, then you must use your 

most recent gas composition based on available sample 

analysis of the field. 

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

emissions sources upstream of the de-methanizer or dew 

point control and GHG mole fraction in facility specific 

residue gas to transmission pipeline systems for all 

emissions sources downstream of the de-methanizer overhead 

or dew point control for onshore natural gas processing 

facilities. 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. 
230 of 287 

(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. 

(vii) GHG mole fraction in local distribution 

pipeline natural gas that passes through the facility for 

natural gas distribution facilities. 

(v) GHG mass emissions. Calculate GHG mass emissions 

in carbon dioxide equivalent at standard conditions by 

converting the GHG volumetric emissions into mass emissions 

using Equation W-36 of this section. 

3

, , * * * 10  Mass s i  Es i  i GWP (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) volumetric emissions at 

standard conditions, in cubic feet. 

 i = Density of GHG i. Use 0.0538 kg/ft3

 for CO2 and 

N2O, and 0.0196 kg/ft3

 for CH4 at 68°F and 14.7 

psia or 0.0530 kg/ft3

 for CO2 and N2O, and 0.0193 

kg/ft3

 for CH4 at 60°F and 14.7 psia . 

GWP = Global warming potential, 1 for CO2, 21 for CH4, 

and 310 for N2O. 

(w) EOR injection pump blowdown. Calculate CO2 pump 

blowdown emissions as follows: 
231 of 287 

(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: 

3

, * * * *10  Mass c 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. 
232 of 287 

(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. 

(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 and 

natural gas distribution combustion emissions. Calculate 
233 of 287 

CO2 CH4,and N2O combustion-related emissions from stationary 

or portable equipment as follows: 

(1) If the fuel combusted in the stationary or 

portable equipment is listed in Table C-1 of subpart C of 

this part, 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). If the fuel 

combusted is natural gas and is pipeline quality and has a 

minimum high heat value of 950 Btu per standard cubic foot, 

then the natural gas emission factor and high heat values 

listed in Tables C-1 and C-2 of this part may be used. 

(2) For fuel combustion units that combust field gas 

or process vent gas, or any blend of field gas or process 

vent gas and fuels listed in Table C-1 of subpart C of this 

part, 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 on heat duty or horsepower to estimate 

volumetric unit gas flow. 
234 of 287 

(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. 

 

j

Ea,CO2 Va *Yj* Rj

 (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). 

(3) External fuel combustion sources with a rated 

heat capacity equal to or less than 5 mmBtu/hr do not need 
235 of 287 

N O     Fuel  HHV  EF 3

2 1 10

to report combustion emissions. You must report the type 

and number of each external fuel combustion unit. 

(4) Calculate GHG volumetric emissions at standard 

conditions using calculations in paragraph (t) of this 

section. 

(5) Calculate both combustion-related CH4 and CO2 mass 

emissions from volumetric CH4 and CO2 emissions using 

calculation in paragraph (v) of this section. 

(6) Calculate N2O mass emissions using Equation W-40 

of this section. 

 (Eq. W-40) 

Where: 

N2O = 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 of 

this part, use the provided default HHV in the table. 
236 of 287 

(ii) For field gas or process vent gas, use 1.235 ×

10-3 mmBtu/scf for HHV. 

(iii) For fuels not listed in Table C-1 of subpart C 

of this part and not field gas or process vent gas, you 

must use the methodology set forth in the Tier 2 

methodology described in subpart C of this part to 

determine HHV. 

§98.234 Monitoring and QA/QC requirements.

The GHG emissions data for petroleum and natural gas 

emissions sources must be quality assured as applicable as 

specified in this section. Offshore petroleum and natural 

gas production facilities shall adhere to the monitoring 

and QA/QC requirements as set forth in 30 CFR 250. 

(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) of the Alternative work practice for monitoring 

equipment leaks. Any emissions detected by the optical gas 
237 of 287 

imaging instrument is a leak unless screened with Method 21 

(40 CFR part 60, appendix A-7) monitoring, in which case 

10,000 ppm or greater is designated a leak. In addition, 

you must operate the optical gas imaging instrument to 

image the source types required by this subpart in 

accordance with the instrument manufacturer’s operating 

parameters. 

(2) Method 21. Use the equipment leak detection 

methods in 40 CFR part 60, appendix A-7, Method 21. If 

using Method 21 monitoring, if an instrument reading of 

10,000 ppm or greater is measured, a leak is detected. 

Inaccessible emissions sources, as defined in 40 CFR part 

60, are not exempt from this subpart. Owners or operators 

must use alternative leak detection devices as described in 

paragraph(a)(1) 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 
238 of 287 

accordance with the instrument manufacturer’s operating 

parameters. 

(4) Optical gas imaging instrument. 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 device. Use the acoustic 

leak detection device to detect through-valve leakage. 

When using the acoustic leak detection device to quantify 

the through-valve leakage, you must use the instrument 

manufacturer’s calculation methods to quantify the throughvalve leak. When using the acoustic leak detection device, 

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

leak is detected. In addition, you must operate the 

acoustic leak detection device to monitor the source valves 

required by this subpart in accordance with the instrument 

manufacturer’s operating parameters. 

(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 
239 of 287 

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. 

(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). 
240 of 287 

(4) Estimate CH4 and CO2 volumetric and mass emissions 

from volumetric natural gas emissions using the 

calculations in §98.233(u) and (v). 

(d) Use a high volume sampler to measure emissions 

within the capacity of the instrument. 

(1) A technician following manufacturer instructions 

shall conduct measurements, including equipment 

manufacturer operating procedures and measurement 

methodologies relevant to using a high volume sampler, 

including positioning the instrument for complete capture 

of the equipment leak without creating backpressure on the 

source. 

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

attachments available from the manufacturer, is not able to 

capture all the emissions from the source then 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 by using 
241 of 287 

calibrated gas samples and by following manufacturer’s 

instructions for calibration. 

(e) Peng Robinson Equation of State means the 

equation of state defined by Equation W-41 of this section: 

2 2 V 2bV b

a

V b

RT

p

m m  m     

 (Eq. W-41) 

Where: 

p = Absolute pressure. 

R = Universal gas constant. 

T = Absolute temperature. 

Vm = Molar volume. 

 = c

c

p

R T

2 2 0.45724

 = c

c

p

0.7780RT

α =  

2

2 1 0.37464 1.54226 0.26992 1 































    Tc

T

 

Where: 

ω = Acentric factor of the species. 

Tc = Critical temperature. 

Pc = Critical pressure. 

(f) Special reporting provisions 
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(1) Best available monitoring methods. 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. If the reporter anticipates the potential 

need for best available monitoring for sources for which 

they need to petition EPA and the situation is unresolved 

at the time of the deadline, reporters should submit 

written notice of this potential situation to EPA by the 

specified deadline for requests to be considered. EPA 

reserves the right to review petitions after the deadline 

but will only consider and approve late petitions which 

demonstrate extreme or unusual circumstances. The 

Administrator reserves to right to request further 

information in regard to all petition requests. 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. 
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(2) 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 

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) Gas well venting during well completions and 

workovers with hydraulic fracturing as specified in 

§98.233(g). 

(ii) Well testing venting and flaring as specified in 

§98.233(l). 

(3) Best available monitoring methods for specified 

activity data. 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 that can be collected only between 

January 1, 2011 and June 30, 2011 and cannot be duplicated 

after June 30, 2011. These sources are: 
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(i) Cumulative hours of venting, days, or times of 

operation in §98.233(e), (f), (g), (h), (l), (o), (p), (q), 

and (r). 

(ii) Number of blowdowns, completions, workovers, or 

other events in §98.233(f), (g), (h), (i), and (w). 

(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). 

(4) Best available monitoring methods for leak 

detection and measurement. 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) 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 as 

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

(h)(1). 

(ii) 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 
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as specified in §98.232(d)(2), (e)(2), (f)(2), (g)(2), and 

(h)(2). 

(iii) Acid gas removal vent stacks in onshore 

petroleum and natural gas production and onshore natural 

gas processing as specified in §98.232(c)(17) and (d)(6). 

(iv) 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 

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 as specified in §98.232 

(d)(7), (e)(7), (f)(5), (g)(3), (h)(4), and (i)(1). 

(v) Condensate (oil and/or water) storage tanks in 

onshore natural gas transmission compression as specified 

in §98.232(e)(3). 

(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 
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January 1, 2011 and June 30, 2011 for the sources specified 

in paragraph (f)(2) of this section. 

(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 specified 

in paragraph (f)(3) of this section. 

(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 specified in paragraph (f)(4) of this 

section. 

(A) Timing of request. The request to use best 

available monitoring methods for paragraph (f)(4) of this 

section must be submitted to EPA no later than April 30, 

2011. 

(B) Content of request. Requests must contain the 

following information for sources listed in paragraph 

(f)(4) of this section: 

(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. 
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(2) Identification of the specific rule requirements 

(by subpart, section, and paragraph number) for which the 

instrumentation or monitoring service is needed. 

(3) Documentation which demonstrates that the owner 

or operator made all reasonable efforts to obtain the 

information, services or equipment necessary to comply with 

subpart W reporting requirements, including evidence of 

specific service or equipment providers contacted and why 

services or information could not be obtained during 2011. 

(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. 

(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 
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in paragraphs(f)(2), (f)(3), and (f)(4) of this section; 

however, EPA will review such requests if submitted in 

accordance with paragraph (f)(5)(iv)(A)-(C) of this 

section. 

(A) Timing of request. The request to use best 

available monitoring methods for sources not listed in 

paragraphs (f)(2), (f)(3), and (f)(4) of this section must 

be submitted to EPA no later than April 30, 2011. 

(B) Content of request. 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. 

(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 

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. 
249 of 287 

(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 paragraph (f)(2) of this section. The owner or 

operator may submit a request to the Administrator to use 

one or more best available monitoring methods described in 

paragraph (f)(2) of this section beyond June 30, 2011. 

(i) Timing of request. The extension request must be 

submitted to EPA no later than April 30, 2011. 

(ii) Content of request. Requests must contain the 

following information: 

(A) A list of specific source types and specific 

equipment, monitoring instrumentation, contract 

modifications, and/or services for which the request is 

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 number) for which the 
250 of 287 

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 demonstrate a good faith 

effort that it is not possible to obtain the necessary 

information, service or hardware which may include 

providing 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 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. 
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(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 specified in paragraph (f)(2) of this 

section by June 30, 2011. 

(7) Requests for extension of the use of best 

available monitoring methods through December 31, 2011 for 

sources in paragraph (f)(3) of this section. The owner or 

operator may submit a request to the Administrator to use 

one or more best available monitoring methods described in 

paragraph (f)(3) of this section beyond June 30, 2011. 

(i) Timing of request. The extension request must be 

submitted to EPA no later than April 30, 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. 

(B) Identification of the specific rule requirements 

(by subpart, section, and paragraph number) 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 
252 of 287 

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. 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 

paragraph (f)(3) of this section for the methods required 

in this subpart by June, 30, 2011. 

(8) Requests for extension of the use of best 

available monitoring methods beyond 2011 for sources listed 

in paragraphs (f)(2), (f)(3), (f)(4), (f)(5)(iv) of this 

section and other sources in this subpart. 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. 

(i) Timing of request. The request to use best 

available monitoring methods for paragraphs (f)(2), (f)(3), 

(f)(4), (f)(5)(iv) of this section and sources not listed 

in paragraphs (f)(2), (f)(3), (f)(4), (f)(5)(iv) of this 
253 of 287 

section must be submitted to EPA no later than September 

30, 2011. 

(ii) Content of request. 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 of 

this 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. 

§98.235 Procedures for estimating missing data.
254 of 287 

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. For missing data which 

are continuously monitored or measured, (for example flow 

meters), or for missing temperature or pressure data that 

are required under §98.236, the reporter may use best 

available data for use in emissions determinations. The 

reporter must record and report the basis for the best 

available data in these cases. 

§98.236 Data reporting requirements.
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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. 

(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) Offshore petroleum and natural gas production is 

not required to report activity data and emissions for each 
256 of 287 

aggregated source under §98.236 (c). Reporting requirements 

for offshore petroleum and natural gas production is set 

forth by BOEMRE in compliance with 30 CFR 250.302 through 

304. 

(c) For each aggregated source, unless otherwise 

specified, report activity data and emissions (in metric 

tons CO2e per year at standard conditions) for each 

aggregated source type as follows: 

(1) For natural gas pneumatic devices (refer to 

Equation W-1 of §98.233), report the following: 

(i) Actual count and estimated count separately of 

natural gas pneumatic high bleed devices as applicable. 

(ii) Actual count and estimated count separately of 

natural gas pneumatic low bleed devices as applicable. 

(iii) Actual count and estimated count separately of 

natural gas pneumatic intermittent bleed devices as 

applicable. 

(iv) Report emissions collectively. 

(2) For natural gas driven pneumatic pumps (refer to 

Equation W-2 of §98.233), report the following, 

(i) Count of natural gas driven pneumatic pumps. 

(ii) Report emissions collectively. 

(3) For each acid gas removal unit (refer to Equation 

W-3 and Equation W-4 of §98.233), report the following: 
257 of 287 

(i) Total throughput off the acid gas removal unit 

using a meter or engineering estimate based on process 

knowledge or best available data in million cubic feet per 

year. 

(ii) For Calculation Methodology 1 and Calculation 

Methodology 2 of §98.233(d), fraction of CO2 content in the 

vent from the acid gas removal unit (refer to 

§98.233(d)(6)). 

(iii) For Calculation Methodology 3 of §98.233(d), 

volume fraction of CO2 content of natural gas into and out 

of the acid gas removal unit (refer to §98.233(d)(7) and 

(d)(8)). 

(iv) Report emissions from the AGR unit recovered and 

transferred outside the facility. 

(v) Report emissions individually. 

(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. 
258 of 287 

(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. 

(ii) For all glycol dehydrators with a throughput 

less than 0.4 MMscfd (refer to §98.233, Equation W-5 of 

§98.233), report the following: 

(A) Count of glycol dehydrators. 

(B) Whether any vent gas controls are used (refer to 

§98.233(e)(3) and (e)(4)). 

(C) Report vent emissions collectively. 

(iii) For absorbent desiccant dehydrators (refer to 

Equation W-6 of §98.233), report the following: 

(A) Count of desiccant dehydrators. 

(B) Report emissions collectively. 
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(5) For well venting for liquids unloading (refer to 

Equations W-7, W-8 and W-9 of §98.233), report the 

following by field: 

(i) Count of wells vented to the atmosphere for 

liquids unloading. 

(ii) Count of plunger lifts. 

(iii) Cumulative 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. 

(6) For well completions and workovers, report the 

following for each field: 

(i) For gas well completions and workovers with 

hydraulic fracturing (refer to Equation W-10 of §98.233): 

(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(g)(1)(i) 

or (g)(1)(ii)). 

(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) 

or (g)(1)(ii)). 
260 of 287 

(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 emissions collectively. Report 

flared emissions collectively. 

(ii) For gas well completions and workovers without 

hydraulic fracturing (refer to Equation W-13 of §98.233): 

(A) Total count of completions in calendar year. 

(B) Total count of workovers in calendar year. 

(C) Total number of days of gas venting to the 

atmosphere during backflow for completion. 

(D) Report vent emissions collectively. Report flared 

emissions collectively. 

(7) For each blowdown vent stack (refer to Equation 

W-14 of §98.233), report the following: 

(i) Total number of blowdowns per equipment type in 

calendar year. 

(ii) Report emissions collectively per equipment 

type. 
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(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 Calculation Methodology 1 and 2 of §98.233(j), report 

the following by field: 

(A) Number of wellhead separators sending oil to 

atmospheric tanks. 

(B) Estimated average separator temperature, in 

degrees Fahrenheit, and estimated average pressure, in 

psig. 

(C) Estimated average sales oil stabilized API 

gravity, in degrees. 

(D) Count of hydrocarbon 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. 
262 of 287 

(I) Range of concentrations of flash gas, CH4 and CO2. 

(J) Report emissions individually for Calculation 

Methodology 1 and 2 of §98.233(j). 

(ii) For wells with oil production greater than or 

equal to 10 barrels per day, using Calculation Methodology 

3 and 4 of §98.233(j), report the following by field: 

(A) Total volume of sales oil from all wells in 

barrels per year. 

(B) Total number of wells sending oil directly to 

tanks. 

(C) Total number of wells sending oil to separators 

off the well pads. 

(D) Sales oil API gravity range for (B) and (C) of 

this section, in degrees. 

(E) Count of hydrocarbon tanks on wellpads 

(F) Count of hydrocarbon 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 Calculation 

Methodology 3 and 4 of §98.233(j). 

(iii) For wellhead gas-liquid separators and wells 

with throughput less than 10 barrels per day, using 

Calculation Methodology 5 of §98.233(j) Equation W-15 of 

§98.233), report the following: 
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(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 hydrocarbon 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 Equation W-16 

of §98.233), report the following: 

(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(k)), or acoustic leak detection of scrubber dump 

valves report the following for each tank: 

(i) Report emissions individually. 

(ii) [Reserved] 

(10) For well testing (refer to Equation W-17 of 

§98.233), report the following for each basin: 

(i) Number of wells tested per basin in calendar 

year. 
264 of 287 

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

(iii) Average number of days the well is tested in a 

basin. 

(iv) Report emissions of the venting gas 

collectively. 

(11) For associated natural gas venting (refer to 

Equation W-18 of §98.233), report the following for each 

basin: 

(i) Number of wells venting or flaring associated 

natural gas in a calendar year. 

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

(iii) Report emissions of the flaring gas 

collectively. 

(12) For flare stacks (refer to Equation W-19, W-20, 

and W-21 of §98.233), 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. 
265 of 287 

(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 Equations W-22 through W-24 of §98.233), 

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, use an 

engineering calculation based on best available data. 

(D) Type of meters used for making measurements. 

(E) Reporter emission factor for wet seal oil 

degassing vents in cubic feet per hour (refer to Equation 

W-24 of §98.233). 

(F) Total time the compressor is operating in hours. 

(G) Report seal oil degassing vent emissions for 

compressors measured (refer to Equation W-22 of §98.233) 

and for compressors not measured (refer to Equation W-23 

and Equation W-24 of §98.233). 

(ii) For wet and dry seal centrifugal compressors in 

operating mode, (refer to Equations W-22 through W-24 of 

§98.233), report the following: 
266 of 287 

(A) Total time in hours the compressor is in 

operating mode. 

(B) Reporter emission factor for blowdown vents in 

cubic feet per hour (refer to Equation W-24 of §98.233). 

(C) Report blowdown vent emissions when in operating 

mode (refer to Equation W-23 and Equation W-24 of §98.233). 

(iii) For wet and dry seal centrifugal compressors in 

not operating, depressurized mode (refer to Equations W-22 

through W-24 of §98.233), report the following: 

(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 Equation W-24 of §98.233). 

(C) Report the isolation valve leakage emissions in 

not operating, depressurized mode in cubic feet per hour 

(refer to Equation W-23 and Equation W-24 of §98.233). 

(iv) Report total annual compressor emissions from 

all modes of operation (refer to Equation W-24 of §98.233). 

(v) For centrifugal compressors in onshore petroleum 

and natural gas production (refer to Equation W-25 of 

§98.233), report the following: 

(A) Count of compressors. 
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(B) Report emissions (refer to Equation W-25 of 

§98.233) 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, use an 

engineering calculation based on best available data. 

(B) Total time in hours the reciprocating compressor 

is in operating mode. 

(C) Report rod packing emissions for compressors 

measured (refer to Equation W-26 of §98.233) and for 

compressors not measured (refer to Equation W-27 and 

Equation W-28 of §98.233). 

(ii) For reciprocating compressors blowdown vents not 

manifold to rod packing vents, in operating and standby 

pressurized mode (refer to Equations W-26 through W-28 of 

§98.233), 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-28). 
268 of 287 

(C) Report blowdown vent emissions when in operating 

and standby pressurized modes (refer to Equation W-27 and 

Equation W-28 of §98.233). 

(iii) For reciprocating compressors in not operating, 

depressurized mode (refer to Equations W-26 through W-28 of 

§98.233), report the following: 

(A) Total time the compressor is in not operating, 

depressurized mode. 

(B) Reporter emission factor for isolation valve 

emissions in not operating, depressurized mode in cubic 

feet per hour (refer to Equation W-28 of §98.233). 

(C) Report the isolation valve leakage emissions in 

not operating, depressurized mode. 

(iv) Report total annual compressor emissions from all 

modes of operation (refer to Equation W-27 and Equation W28 of §98.233). 

(v) For reciprocating compressors in onshore 

petroleum and natural gas production (refer to Equation W29 of §98.233), 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(q) and (r). 
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(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 of this subpart. 

(B) Concentration of CH4 and CO2 as described in 

Equation W-30 of §98.233. 

(C) Report CH4 and CO2 emissions (refer to Equation W30 of §98.233) collectively by equipment type. 

(ii) For equipment leaks calculated using population 

counts and factors (refer to §98.233(r)), report the 

following: 

(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 of this 

subpart for which there is a population emission factor, 

listed by major heading and component type. 

(B) For onshore production (refer to §98.230 

paragraph (a)(2)), total count for each type of major 

equipment in Table W-1B and Table W-1C of this subpart, by 

field. 

(C) Report CH4 and CO2 emissions (refer to Equation W31 of §98.233) collectively by equipment type. 
270 of 287 

(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 Equation W-32 of §98.233). 

(iv) Number of below grade M&R stations with inlet 

pressure greater than 300 psig. 

(v) Number of below grade M&R stations with inlet 

pressure between 100 and 300 psig. 

(vi) Number of below grate M&R stations with inlet 

pressure less than 100 psig. 

(vii) Number of miles of unprotected steel 

distribution mains. 

(viii) Number of miles of protected steel distribution 

mains. 

(ix) Number of miles of plastic distribution mains. 

(x) Number of miles of cast iron distribution mains. 

(xi) Number of unprotected steel distribution 

services. 

(xii) Number of protected steel distribution services. 

(xiii) Number of plastic distribution services. 

(xiv) Number of copper distribution services. 
271 of 287 

(xv) Total emissions from each natural gas 

distribution facility. 

(17) For each EOR injection pump blowdown (refer to 

Equation W-37 of §98.233), report the following: 

(i) Pump capacity, in barrels per day. 

(ii) Volume of critical phase gas between isolation 

valves. 

(iii) Number of blowdowns per year. 

(iv) Critical phase EOR injection gas density. 

(v) Report emissions collectively. 

(18) For EOR hydrocarbon liquids dissolved CO2 for 

each field (refer to Equation W-38 of §98.233), 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. 

(19) For onshore petroleum and natural gas production 

and natural gas distribution combustion emissions, report 

the following: 

(i) Cumulative number of external fuel combustion 

units with a rated heat capacity equal to or less than 5 

mmBtu/hr, by type of unit. 
272 of 287 

(ii) Cumulative number of external fuel combustion 

units with a rated heat capacity larger than 5 mmBtu/hr, by 

type of unit. 

(iii) Cumulative emissions from external fuel 

combustion units with a rated heat capacity larger than 5 

mmBtu/hr, by type of unit. 

(iv) Cumulative volume of fuel combusted in external 

fuel combustion units with a rated heat capacity larger 

than 5 mmBtu/hr, by fuel type. 

(v) Cumulative number of all internal combustion 

units, by type of unit. 

(vi) Cumulative emissions from internal combustion 

units, by type of unit. 

(vii) Cumulative volume of fuel combusted in internal 

combustion units, by fuel type. 

(d) Report annual throughput as determined by 

engineering estimate based on best available data for each 

industry segment listed in paragraphs (a)(1) through (a)(8) 

of this section. 

 

§98.237 Records that must be retained.

Monitoring Plans, as described in §98.3(g)(5), must be 

completed by April 1, 2011. In addition to the information 
273 of 287 

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 in this section, 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 emissions mean the acid gas 

separated from the acid gas absorbing medium (e.g., an 
274 of 287 

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 
275 of 287 

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. 

External combustion means fired combustion in which 

the flame and products of combustion are separated from 

contact with the process fluid to which the energy is 

delivered. Process fluids may be air, hot water, or 

hydrocarbons. External combustion equipment may include 
276 of 287 

fired heaters, industrial boilers, and commercial and 

domestic combustion units. 

Facility with respect to natural gas distribution for 

purposes of this subpart and for subpart A means the 

collection of all distribution pipelines, metering 

stations, and regulating stations that are operated by a 

Local Distribution Company (LDC) that is regulated as a 

separate operating company by a public utility commission 

or that are operated as an independent municipally-owned 

distribution system. 

Facility with respect to onshore petroleum and natural 

gas production for purposes of this subpart and for subpart 

A means all petroleum or natural gas equipment on a well 

pad or associated with a well pad and CO2 EOR operations 

that are under common ownership or common control including 

leased, rented, or contracted activities by an onshore 

petroleum and natural gas production owner or operator and 

that are located in a single hydrocarbon basin as defined 

in §98.238. Where a person or entity owns or operates more 

than one well in a basin, then all onshore petroleum and 

natural gas production equipment associated with all wells 

that the person or entity owns or operates in the basin 

would be considered one facility. 
277 of 287 

Farm Taps are pressure regulation stations that 

deliver gas directly from transmission pipelines to 

generally rural customers. The gas may or may not be 

metered, but always does not pass through a city gate 

station. In some cases a nearby LDC may handle the billing 

of the gas to the customer(s). 

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). 

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. 

Gas well means a well completed for production of 

natural gas from one or more gas zones or reservoirs. Such 

wells contain no completions for the production of crude 

oil. 

Internal combustion means the combustion of a fuel 

that occurs with an oxidizer (usually air) in a combustion 
278 of 287 

chamber. In an internal combustion engine the expansion of 

the high-temperature and –pressure gases produced by 

combustion applies direct force to a component of the 

engine, such as pistons, turbine blades, or a nozzle. This 

force moves the component over a distance, generating 

useful mechanical energy. Internal combustion equipment may 

include gasoline and diesel industrial engines, natural 

gas-fired reciprocating engines, and gas turbines. 

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. 

Offshore means seaward of the terrestrial borders of 

the United States, including waters subject to the ebb and 

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

normally standing waters, and extending to the outer 

boundaries of the jurisdiction and control of the United 

States under the Outer Continental Shelf Lands Act. 

Oil well means a well completed for the production of 

crude oil from at least one oil zone or reservoir. 
279 of 287 

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. 
280 of 287 

Reservoir means a porous and permeable underground 

natural formation containing significant quantities of 

hydrocarbon liquids and/or gases. 

Residue Gas and Residue Gas Compression mean, 

respectively, production lease natural gas from which gas 

liquid products and, in some cases, non-hydrocarbon 

components have been extracted such that it meets the 

specifications set by a pipeline transmission company, 

and/or a distribution company; and the compressors operated 

by the processing facility, whether inside the processing 

facility boundary fence or outside the fence-line, that 

deliver the residue gas from the processing facility to a 

transmission pipeline. 

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 saleable 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 
281 of 287 

turbine from which the spin rate is detected and calibrated 

to measure the fluid flow rate. 

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, 

and direct venting of gas used to power equipment (such as 

pneumatic devices). 

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

FOR ONSHORE PETROLEUM AND NATURAL GAS PRODUCTION 

Onshore petroleum and natural gas production Emission Factor 

(scf/hour/component) 

Eastern U.S. 

Population Emission Factors - All Components, 

Gas Service1 

Valve 0.027

Connector 0.004

Open-ended Line 0.062

Pressure Relief Valve 0.041

Low Continuous Bleed Pneumatic Device 

Vents2 1.80

High Continuous Bleed Pneumatic Device 

Vents2 48.1

Intermittent Bleed Pneumatic Device Vents2 17.4

Pneumatic Pumps3 13.3

Population Emission Factors - All Components, 

Light Crude Service4 

Valve 0.04

Flange 0.002

Connector 0.005

Open-ended Line 0.04

Pump 0.01

Other5 0.23

Population Emission Factors - All Components, 

Heavy Crude Service6 

Valve 0.0004

Flange 0.0007

Connector (other) 0.0002
282 of 287 

TABLE W-1B OF SUBPART W–DEFAULT AVERAGE COMPONENT COUNTS FOR 

MAJOR ONSHORE 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 

Open-ended Line 0.004

Other5 0.002

Western U.S. 

Population Emission Factors - All Components, 

Gas Service1

Valve 0.123

Connector 0.017

Open-ended Line 0.032

Pressure Relief Valve 0.196

Low Continuous Bleed Pneumatic Device 

Vents2 1.80

High Continuous Bleed Pneumatic Device 

Vents2 48.1

Intermittent Bleed Pneumatic Device Vents2 17.4

Pneumatic Pumps3 13.3

Population Emission Factors - All Components, 

Light Crude Service4

Valve 0.04

Flange 0.002

Connector (other) 0.005

Open-ended Line 0.04

Pump 0.01

Other5 0.23

Population Emission Factors - All Components, 

Heavy Crude Service6

Valve 0.0004

Flange 0.0007

Connector (other) 0.0002

Open-ended Line 0.004

Other5 0.002 1

 For multi-phase flow that includes gas, use the gas service emissions 

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" 
283 of 287 

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 of Part 98 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 of Part 98 Designation Of Eastern 

And Western U.S.

Eastern U.S. Western U.S. 

Connecticut Alabama 

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 
284 of 287 

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 ONSHORE NATURAL GAS PROCESSING 

Onshore natural gas processing Emission Factor 

(scf/hour/component) 

Leaker Emission Factors - Compressor Components, Gas Service 

Valve1 15.07

Connector 5.68

Open-Ended Line 17.54

Pressure Relief Valve 40.27

Meter 19.63

Leaker Emission Factors – Non-Compressor Components, Gas Service 

Valve 6.52

Connector 5.80

Open-Ended Line 11.44

Pressure Relief Valve 2.04

Meter 2.98 1 Valves include control valves, block valves and regulator valves. 

TABLE W-3 OF SUBPART W–DEFAULT TOTAL HYDROCARBON EMISSION 

FACTORS FOR ONSHORE NATURAL GAS TRANSMISSION COMPRESSION 

Onshore natural gas transmission 

compression 

Emission Factor 

(scf/hour/component) 

Leaker Emission Factors - Compressor Components, Gas Service 

Valve1 15.07

Connector 5.68

Open-Ended Line 17.54

Pressure Relief Valve 40.27

Meter 19.63

Leaker Emission Factors – Non-Compressor Components, Gas Service 

Valve1 6.52
285 of 287 

Connector 5.80

Open-Ended Line 11.44

Pressure Relief Valve 2.04

Meter 2.98

Population Emission Factors – Gas Service 

Low Continuous Bleed Pneumatic Device 

Vents2 1.41

High Continuous Bleed Pneumatic Device 

Vents2 18.8

Intermittent Bleed Pneumatic Device 

Vents2 18.8 1

 Valves include control valves, block valves and regulator valves. 

2

 Emission Factor is in units of "scf/hour/device" 

TABLE W-4 OF SUBPART W–DEFAULT TOTAL HYDROCARBON EMISSION 

FACTORS FOR UNDERGROUND NATURAL GAS STORAGE 

Underground natural gas storage 

Emission Factor 

(scf/hour/componen

t) 

Leaker Emission Factors - Storage Station, Gas Service 

Valve1 15.07 

Connector 5.68 

Open-Ended Line 17.54 

Pressure Relief Valve 40.27 

Meter 19.63

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 Vents2 1.41

High Continuous Bleed Pneumatic Device Vents2 18.8

Intermittent Bleed Pneumatic Device Vents2 18.8 1

 Valves include control valves, block valves and regulator valves.

2

 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 1.21

Pump Seal 4.06
286 of 287 

Connector 0.35

Other1 1.80

Population Emission Factors - LNG Storage Compressor, Gas Service

Vapor Recovery Compressor2 4.23 1

 "other" equipment type should be applied for any equipment type other 

than connectors, pumps, or valves.

2

 Emission Factor is in units of "scf/hour/compressor" 

TABLE W-6 OF SUBPART W–DEFAULT METHANE EMISSION FACTORS FOR 

LNG IMPORT AND EXPORT EQUIPMENT 

LNG import and export equipment 

Emission Factor 

(scf/hour/compone

nt) 

Leaker Emission Factors - LNG Terminals Components, LNG Service

Valve 1.21

Pump Seal 4.06

Connector 0.35

Other1 1.80

Population Emission Factors - LNG Terminals Compressor, Gas Service

Vapor Recovery Compressor2 4.23 1

 "other" equipment type should be applied for any equipment type other 

than connectors, pumps, or valves.

2

 Emission Factor is in units of "scf/hour/compressor"

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

NATURAL GAS DISTRIBUTION 

Natural gas distribution Emission Factor 

(scf/hour/component) 

Leaker Emission Factors - Above Grade M&R at City Gate Stations1

Components, Gas Service 

Connector 1.72

Block Valve 0.566

Control Valve 9.48

Pressure Relief Valve 0.274

Orifice Meter 0.215

Regulator 0.784

Open-ended Line 26.533

Population Emission Factors - Below Grade M&R2 Components, Gas Service3

Below Grade M&R Station, Inlet Pressure > 300 

psig 1.32

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 
287 of 287 

Natural gas distribution Emission Factor 

(scf/hour/component) 

Unprotected Steel 12.77

Protected Steel 0.36

Plastic 1.15

Cast Iron 27.67

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”