Tuesday, 

November 30, 2010 

Part III 

Environmental 

Protection Agency 

40 CFR Part 98 

Mandatory Reporting of Greenhouse 

Gases: Petroleum and Natural Gas 

Systems; Final Rule 


srobinson on DSKHWCL6B1PROD with RULES2
74458 Federal Register / Vol. 75, No. 229 / Tuesday, November 30, 2010 / Rules and Regulations 

ENVIRONMENTAL PROTECTION 

AGENCY 

40 CFR Part 98 

[EPA–HQ–OAR–2009–0923; FRL–9226–1] 

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 

December 30, 2010. The incorporation 

by reference of certain publications 

listed in the rule is approved by the 

Director of the Federal Register as of 

December 30, 2010. 

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 http://www.regulations.gov Web 

site. 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 

http://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., 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 Web site http://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. 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

INFORMATION CONTACT section. 

Many facilities that are affected by the 

final rule have GHG emissions from 

multiple source categories listed in 40 

CFR part 98. Table 2 of this preamble 

has been developed as a guide to help 

potential reporters in the petroleum and 

natural gas industry affected by this 

action identify other source categories 

(by subpart) that they may need to: (1) 

Consider in their facility applicability 

determination, and (2) include in their 

reporting. Table 2 of this preamble 

identifies the subparts that are likely to 

be relevant to sources with petroleum 

and natural gas systems. The table 

should only be seen as a guide. 

Additional subparts in 40 CFR part 98 

may be relevant for a given reporter. 

Similarly, not all listed subparts are 

relevant for all reporters. 

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). 


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Federal Register / Vol. 75, No. 229 / Tuesday, November 30, 2010 / Rules and Regulations 74459 

1We 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. 

What is the effective date? The final 

rule is effective on December 30, 2010. 

Section 553(d) of the Administrative 

Procedure Act (APA), 5 U.S.C. Chapter 

5, 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 December 

30, 2010. 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. 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 Web site 

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 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 January 31, 2011. 

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 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 

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 

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 


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74460 Federal Register / Vol. 75, No. 229 / Tuesday, November 30, 2010 / Rules and Regulations 

2Consolidated 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). 

U.S. United States 

UMRA Unfunded Mandates Reform Act of 

1995 

U.S.C. United States Code 

USGS United States Geologic Society 

VOC volatile organic compound(s) 

WCI Western Climate Initiative 

Table of Contents 

I. Background 

A. Organization of this Preamble 

B. Background on the Final Rule 

C. Legal Authority 

II. Reporting Requirements for Petroleum and 

Natural Gas Systems 

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 Low-Income 

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. 

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 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 Act.2 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 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 nonregulatory 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 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 


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Federal Register / Vol. 75, No. 229 / Tuesday, November 30, 2010 / Rules and Regulations 74461 

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 

evaluation of various CAA provisions. 

Moreover, EPA’s authority under CAA 

section 114 is broad, and extends to any 

person ‘‘who the Administrator believes 

may have information necessary for the 

purposes’’ of carrying out the CAA, even 

if that person is not subject to the CAA. 

Indeed, by specifically authorizing EPA 

to collect information from both persons 

subject to any requirement of the CAA, 

as well as any person who the 

Administrator believes may have 

necessary information, Congress clearly 

intended that EPA could gather 

information from a person not otherwise 

subject to CAA requirements. EPA is 

comprehensively considering how to 

address climate change under the CAA, 

including both regulatory and nonregulatory options. The information 

from offshore platforms will inform our 

analyses, including options applicable 

to emissions of any offshore platforms 

that EPA is authorized to regulate under 

the CAA. 

II. Reporting Requirements for 

Petroleum and Natural Gas Systems 

A. Overview of Greenhouse Gas 

Reporting Program 

The GHG Reporting Program requires 

reporting of GHG emissions and other 

relevant information from certain source 

categories in the United States, as 

discussed in Section I.B. of this 

preamble. The rule requires annual 

reporting of GHGs including carbon 

dioxide (CO2), methane (CH4), nitrous 

oxide (N2O), hydrofluorocarbons 

(HFCs), perfluorocarbons (PFCs), sulfur 

hexafluoride (SF6), 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 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 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; 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-selfpropelled equipment on a well pad or 

associated with a well pad (including well 

drilling and completion equipment, 

workover equipment, gravity separation 

equipment, auxiliary non-transportationrelated equipment, and leased, rented or 

contracted equipment) used in the 

production, extraction, recovery, lifting, 

stabilization, separation or treating of 

petroleum and/or natural gas (including 

condensate). This 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. 


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74462 Federal Register / Vol. 75, No. 229 / Tuesday, November 30, 2010 / Rules and Regulations 

• 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 

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, recondensers, 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, regasifies LNG, and delivers re-gasified natural 

gas to a natural gas transmission or 

distribution system. LNG export equipment 

means all onshore or offshore equipment that 

receives natural gas, liquefies natural gas, 

stores LNG, and transfers the LNG via ocean 

transportation to any location, including 

locations in the United States. 

• 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 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 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 

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. 


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TABLE 3—SUMMARY OF SOURCE TYPES IN EACH INDUSTRY SEGMENT

Source type 

Offshore 

production 

Onshore 

production 

Natural 

gas processing 

Natural 

gas transmission 

compression 

Underground 

storage 

LNG 

Storage 

LNG Import and 

export 

equipment 

Distribution 

Natural gas pneumatic device venting ............ X X X 

Natural gas driven pneumatic pump venting ... X 

Acid gas removal vent stack ............................ X X 

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 

Transmission 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 

Reciprocating compressor rod packing venting X X X X X X 

Other emissions from equipment leaks ........... X X X X X X X 

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 Distribution 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 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 PengRobinson 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 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 shutin 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 


srobinson on DSKHWCL6B1PROD with RULES2
74464 Federal Register / Vol. 75, No. 229 / Tuesday, November 30, 2010 / Rules and Regulations 

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 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 gas-containing 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 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 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. 

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–HQ–OAR–2009–0923. 


srobinson on DSKHWCL6B1PROD with RULES2
Federal Register / Vol. 75, No. 229 / Tuesday, November 30, 2010 / Rules and Regulations 74465 

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 

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 shut down 

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– 

OAR–2009–0923. 

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, W–3, W–4, W–5, 

W–6, and W–7 of subpart W. Tubing 

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. 

—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 

an 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 


srobinson on DSKHWCL6B1PROD with RULES2
74466 Federal Register / Vol. 75, No. 229 / Tuesday, November 30, 2010 / Rules and Regulations 

3The Bureau of Ocean Energy Management, 

Regulation, and Enforcement (BOEMRE) was 

formerly known as Minerals Management Service 

(MMS). 

natural gas production facilities using the 

methods outlined by BOEMRE 3 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. 

—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. 

—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 gas-containing 

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 

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 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 


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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 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–HQ–OAR– 

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, 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 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 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 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. 


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• 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 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–OAR–2009–0923–1011 

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 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. 

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 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 

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 


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4While 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. 

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 

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–OAR–2009–0923–1024–14 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 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 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 

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 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 sector.4

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 


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prescribed in the rule would result in 

undue burden to the industry and result 

in additional GHG emissions. 

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 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 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: 

• 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, 

open-ended 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 

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 which monitoring 

requirements it is appropriate to allow 

the use of best available monitoring 


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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. 

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 be 

possible to collect or reproduce data 

after the event is over. EPA recognizes 

that a significant portion of well-drilling 

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 wellrelated 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: 

—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 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: 

—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 


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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 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. 

• 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. 

—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 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 


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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 

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 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. 

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 

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; 


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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 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. 

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 non-regulatory 

approaches and technologies, for the 

prevention and control of air pollution, 

including GHGs. The data collected 

under this rule will also inform EPA’s 

implementation of CAA section 103(g) 

regarding improvement in sector based 

non-regulatory strategies and 

technologies for preventing or reducing 

air pollutants. For more information 

about EPA’s legal authority please see 

the related sections and documents in 

the preamble for subpart W. 

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 non-employee, 

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 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 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 

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 


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5http://www.epa.gov/climatechange/emissions/ 

GHG-calculator/index.html. 

6Reporting 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. 

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 

Program 5 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 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 

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 first year. 

Costs would also vary over time when 

site-specific emissions factors are 

developed every 2 or 3 years. Thus, EPA 

developed cost estimates for year one, 

which include 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 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. 

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. 


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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). 

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 

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 combustionrelated 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 

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. 

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 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 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 

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 


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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 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

Segment 

First year Subsequent year 

Annualized 

cost (3%) 2

($million) 

Annualized 

cost (7%) 3

($million) 

National 

cost 

($million) 

Cost 

($/metric 

ton) 

National 

cost 

($million) 

Cost 

($/metric 

ton) 

Processing ........... 8 .13 0 .26 2 .10 0 .07 2 .43 2 .57 

Transmission ........ 16 .87 0 .40 6 .49 0 .15 7 .02 7 .26 

Underground 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/export 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 Production .................... 26 .58 0 .12 7 .54 0 .03 8 .61 9 .05 

Offshore Production .................... 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 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). 2The cost to report annualized over 20 years at 3 percent (see additional details in section 5 of the EIA for the final rule). 

3The 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) 

Facilities 

required to 

report 

Total costs 1

(million 

2006$) 

Downstream 

emissions 

reported 

(MtCO2e/year) 

Percentage 

of total 

downstream 

emissions 

reported 

Average 

reporting 

cost 

($/Mt) 1

Incremental 

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) 

Facilities 

required 

to report 

Total 

costs 1

(million $2006) 

Downstream 

emissions 

reported 

(MtCO2e/year) 

Percentage 

of total 

downstream 

emissions 

reported 

Average 

reporting 

cost 

($/Mt) 1

Incremental 

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 


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8These estimates are conservative and should be 

viewed as an upper-bound 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). 

TABLE 7B—THRESHOLD COST-EFFECTIVENESS ANALYSIS—Continued 

[Subsequent Year, 2006$] 

Threshold 

(metric 

tons 

CO2e) 

Facilities 

required 

to report 

Total 

costs 1

(million $2006) 

Downstream 

emissions 

reported 

(MtCO2e/year) 

Percentage 

of total 

downstream 

emissions 

reported 

Average 

reporting 

cost 

($/Mt) 1

Incremental 

cost 

($/Mt)1, 2

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 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 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 nonreporters 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 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 

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 highercost, 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 

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 


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9Commenter estimated 823,000 wells based on a 

‘‘US Energy Information Administration’s 2008 

report,’’ but did not provide any other citation 

information. 

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 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 

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 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 

systems are typically tailored to an 

individual facility and used to 

simultaneously manage, among other 

things, criteria pollutants under the 

CAA, water discharge and permit data 

under the Clean Water Act, employee 

accident and injury reporting under 

Occupational Safety and Health 

Administration requirements, and 

onsite hazardous and non-hazardous 

solid waste information for the Resource 

Conservation and Recovery Act. In 

contrast, even the largest of reporters 

under this final action will be able to 

use standard spreadsheets or databases 

to collect the emissions data and 

perform calculations at a facility level. 

Spreadsheet software can store and 

manipulate tens of thousands of data 

points, and database software can store 

hundreds of thousands of data points. In 

short, spreadsheet and database 

software systems are capable of 

managing far more data than will be 

necessary for even the largest onshore 

production reporter under subpart W. 

Accordingly, EPA accounted for data 

management costs by factoring in 

estimates of labor to set up spreadsheets 

and other archiving and recordkeeping 

activities, as well as equipment costs 

like file cabinets and external hard 

drives; see the EIA for a complete 

discussion. 

Another assumption contributing to 

the commenters’ high cost estimates 

concerned the extent of sampling 

required. For example, commenters 

assumed that reporters would need to 

sample produced natural gas. EPA 

disagrees in part because it expects 

reporters to already have this 

information and would therefore not 

need to sample. In particular, producers 

conduct composition analysis of 

produced natural gas in order to pay 

royalties and taxes; they could use these 

data to estimate the percentage of GHGs 

instead of analyzing additional samples. 

The commenters also assumed that 

sampling would be required for tanks 

and dehydrators, which resulted in cost 

estimates significantly higher than 

EPA’s. Although not explicitly stated in 

the 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 

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 


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74480 Federal Register / Vol. 75, No. 229 / Tuesday, November 30, 2010 / Rules and Regulations 

10For example, see Global Water Instrumentation 

Inc., at http://www.globalw.com/products/ 

407119.html. 

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 

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 

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 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, 

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 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), 


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11Note: 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. 12 Guidelines for Preparing Economic Analyses 

(EPA, 2002, p. 124–125). 

13EPA’s RFA guidance for rule writers suggests 

the ‘‘sales’’ test continues to be the preferred 

quantitative metric for economic impact screening 

analysis. 

EPA did not change its cost estimate to 

reflect the much higher costs estimated 

by the commenter. 

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 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/entity) 

Average entity 

cost-to-sales 

ratio a

(percent) 

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 

aThis 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 

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.) 

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 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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74482 Federal Register / Vol. 75, No. 229 / Tuesday, November 30, 2010 / Rules and Regulations 

TABLE 9—ESTIMATED

COST-TO-SALES

RATIOS, SALES

RECEIPTS ($MILLION), AND

NUMBER OF

ESTABLISHMENTS FOR

FIRST

YEAR

COSTS BY INDUSTRY AND

ENTERPRISE

SIZEa

Industry NAICS NAICS Description 

SBA Size standard in num of employees (effective March 11, 2008) 

Average cost 

per entity 

($1,000/entity) 

All 

enterprises 

Owned by enterprises with: 

1 to 20 

Employees 

20 to 99 

Employees 

100 to 499 

Employees 

<500 

Employees 

500 to 749 

Employees 

750 to 999 

Employees 

1,000 to 

1,499 

Employees 

Onshore petroleum and natural 

gas production; offshore petroleum and natural gas production; LNG storage; LNG import and export.

211 Crude Petroleum and Natural 

Gas Extraction.

500 $17.1 0.08% d$160,879 e7,629 1.32% $7,573 5,836 0.11% $6,790 456 0.05% $9,609 292 0.47% $23,972 6,584 0.47% $4,609 60 0.03% $3,991 64 0.02% $2,805 31 

Onshore natural gas processing; 

onshore natural gas transmission; underground natural gas storage.

486210 Pipeline Transportation of Natural Gas. (b) $15.7 0.08% d$35,897 

e1,936 

0.12% 

$1,035 

81 

0.40% 

c$106 

27 

0.24% 

c$394 

61 

0.10% 

$2,566 

36 

(c)(c)

169 

(c)

(c)

2 

(c)

(c)

20 

Natural gas distribution ................. 221210 Natural Gas Distribution .......... 500 $13.9 0.06% d$67,275 

e2,897 

0.27% 

$2,524 

483 

0.03% 

$4,642 

86 

0.06% 

$2,878 

131 

0.11% 

$13,127 

700 

0.07% 

$865 

68 

0.02% 

$2,116 

33 

0.03% 

$3,757 

73 

aThe Census Bureau defines an enterprise as a business organization consisting of one or more domestic establishments that were specified under common ownership or control. The enterprise and the establishment are the same for single-establishment firms. Each multi-establishment company forms one enterprise—the enterprise employment and annual payroll are summed from the associated establishments. Enterprise 

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

Since the SBA’s business size definitions (http://www.sba.gov/size) apply to an establishment’s ultimate parent company, EPA assumes in this analysis that the enterprise definition above is consistent with the concept of ultimate parent company that is typically used for Small Business Regulatory Enforcement Fairness Act (SBREFA) screening analyses. bThe SBA size standard for NAICS 486210 is $7 million in average annual receipts. 

cThe U.S. Census Bureau has missing data for this employee range; some estimates were possible using partial data. The receipts for these categories underestimate true value. dThis row presents total annual sales receipts ($Million)for establishments in each enterprise category. Source: U.S. Census Bureau. eThis row presents total number of establishments in each enterprise category. Source: U.S. Census Bureau. 


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As shown, the cost-to-sales ratios are 

less than one percent for establishments 

owned by small businesses that EPA 

considers most likely to be covered by 

the reporting program. The only 

exception is the ratio for enterprises 

with 1–20 employees for crude 

petroleum and natural gas extraction, 

which is greater than 1 percent but less 

than 2 percent. 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 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 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 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 wellknown 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. 

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 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. 


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74484 Federal Register / Vol. 75, No. 229 / Tuesday, November 30, 2010 / Rules and Regulations 

14Burden 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. 

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 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 

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 facility-level 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 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 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, 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. 

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 non-profits. 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 gasspecific data on revenues for small 


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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 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. 

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 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-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 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 analyses, EPA found one tribe 

that may potentially be impacted by this 

final action. Finally, during the 

comment period for the April 2010 

proposal, EPA received comment from 

one tribe, Southern Ute, which were 

specific to the proposed reporting 

methodologies. 

As further discussed in the 2009 final 

rule that established the Greenhouse 

Gas reporting program, EPA believes 

that there are minimal impacts to tribes. 

Tribes could be required to submit an 

annual GHG report for any facility they 

own or operate that is subject to the 

rule. Specifically, tribes that own or 

operate oil and gas operations could be 

required to report emissions under this 


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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). 

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– 

HQ–OAR–2008–0508–055 for a 

complete list of Tribal contacts. EPA 

participated in a conference call with 

Tribal air coordinators in April 2009 

and prepared a guidance sheet for Tribal 

governments on the final Part 98. It was 

posted on the Greenhouse Gas Reporting 

Program Web site 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 

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 104– 

113 (15 U.S.C. 272 note) directs EPA to 

use voluntary consensus standards in its 

regulatory activities unless to do so 

would be inconsistent with applicable 

law or otherwise impractical. Voluntary 

consensus standards are technical 

standards (e.g., materials specifications, 

test methods, sampling procedures, and 

business practices) that are developed or 

adopted by voluntary consensus 

standards bodies. NTTAA directs EPA 

to provide Congress, through OMB, 

explanations when the Agency decides 

not to use available and applicable 

voluntary consensus standards. 

This rulemaking involves technical 

standards. EPA provides the flexibility 

to use any one of the voluntary 

consensus standards from at least seven 

different voluntary consensus standards 

bodies, including the following: ASTM, 

ASME, ISO, Gas Processors Association, 

and American Gas Association. These 

voluntary consensus standards will help 

facilities monitor, report, and keep 

records of greenhouse gas emissions. No 

new test methods were developed for 

this final rule. Instead, EPA reviewed 

existing rules for source categories and 

voluntary greenhouse gas programs and 

identified existing means of monitoring, 

reporting, and keeping records of 

greenhouse gas emissions. The existing 

methods (voluntary consensus 

standards) include a broad range of 

measurement techniques, including 

many for combustion sources such as 

methods to analyze fuel and measure its 

heating value; methods to measure gas 

or liquid flow; and methods to gauge 

and measure petroleum and petroleum 

products. 

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 

Low-Income Populations 

Executive Order 12898 (59 FR 7629, 

February 16, 1994) establishes Federal 

executive policy on environmental 

justice. Its main provision directs 

Federal agencies, to the greatest extent 

practicable and permitted by law, to 

make environmental justice part of their 

mission by identifying and addressing, 

as appropriate, disproportionately high 

and adverse human health or 

environmental effects of their programs, 

policies, and activities on minority 

populations and low-income 

populations in the United States. 

EPA has determined that this final 

rule will not have disproportionately 

high and adverse human health or 

environmental effects on minority or 

low-income populations because it does 

not affect the level of protection 

provided to human health or the 

environment because it is a rule 

addressing information collection and 

reporting procedures. 

K. Congressional Review Act 

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 

December 30, 2010. 

List of Subjects in 40 CFR Part 98 

Environmental protection, 

Administrative practice and procedure, 

Greenhouse gases, Incorporation by 

reference, Suppliers, Reporting and 

recordkeeping requirements. 


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Dated: November 8, 2010. 

Lisa P. Jackson, 

Administrator. 

■ 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: 

* * * * * 

■ 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, nonelastic, anti-static bag of a calibrated 

volume that can be affixed to an 

emitting source such that the emissions 

inflate the bag to its calibrated volume. 

* * * * * 

Centrifugal compressor means any 

equipment that increases the pressure of 

a process natural gas or CO2 by 

centrifugal action, employing rotating 

movement of the driven shaft. 

Centrifugal compressor dry seals 

mean a series of rings around the 

compressor shaft where it exits the 

compressor case that operates 

mechanically under the opposing forces 

to prevent natural gas or CO2 from 

escaping to the atmosphere. 

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 highpressure 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. 

* * * * * 

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. 

* * * * * 

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. 

* * * * * 

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 

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 


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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. 

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 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 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 re-fracture 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.’’ 

* * * * * 

■ 4. Section 98.7 is amended by adding 

and 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, http:// 

www.eia.doe.gov/pub/oil_gas/

natural_gas/data_publications/

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 Categories a Applicable in 2010 and 

Future Years 

* * * * * * * 

Additional Source Categories a Applicable in 

2011 and Future Years 

* * * * * * * 

Petroleum and Natural Gas Systems 

(subpart W) 

aSource categories are defined in each applicable subpart. 

■ 6. Add Subpart W—Petroleum and 

Natural Gas Systems to read as follows: 

Subpart W—Petroleum and Natural 

Gas Systems 

Sec. 

98.230 Definition of the source category. 


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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. 

Table W–1A to Subpart W of 

Part 98—Default Whole Gas Emission 

Factors for Onshore Petroleum and Natural 

Gas Production 

Table W–1B to Subpart W of Part 98—Default 

Average Component Counts for Major 

Onshore Natural Gas Production 

Equipment 

Table W–1C to Subpart W of Part 98—Default 

Average Component Counts For Major 

Crude Oil Production Equipment 

Table W–1D of Subpart W of Part 98— 

Designation Of Eastern And Western U.S. 

Table W–2 to Subpart W of Part 98—Default 

Total Hydrocarbon Emission Factors for 

Onshore Natural Gas Processing 

Table W–3 to Subpart W of Part 98—Default 

Total Hydrocarbon Emission Factors for 

Onshore Natural Gas Transmission 

Compression 

Table W–4 to Subpart W of Part 98—Default 

Total Hydrocarbon Emission Factors for 

Underground Natural Gas Storage 

Table W–5 to Subpart W of Part 98—Default 

Methane Emission Factors for Liquefied 

Natural Gas (LNG) Storage 

Table W–6 to Subpart W of Part 98—Default 

Methane Emission Factors for LNG Import 

and Export Equipment 

Table W–7 to Subpart W of Part 98—Default 

Methane Emission Factors for Natural Gas 

Distribution 

§ 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 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 nontransportation-related equipment, and 

leased, rented or contracted equipment) 

used in the production, extraction, 

recovery, lifting, stabilization, 

separation or treating of petroleum and/ 

or natural gas (including condensate). 

This 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 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. 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 regasification 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-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 and the facility meets the 

requirements of § 98.2(a)(2). Facilities 

must report emissions from the onshore 

petroleum and natural gas production 


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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 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. 

(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 

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: 

(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: 

(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 

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, 


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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. 

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 determined in 

paragraph (a)(1) of this section. 

EF = Population emission factors for natural 

gas pneumatic device venting listed in 

Tables W–1A, 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 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. 

Where: 

Masss,i = Annual total mass GHG emissions 

in metric tons CO2e per year at standard 

conditions from all natural gas 

pneumatic pump venting, for GHG i. 

Count = Total number of natural gas 

pneumatic pumps. 

EF = Population emission factors for natural 

gas pneumatic pump venting listed in 

Tables W–1A of this subpart for onshore 

petroleum and natural gas production. 

GHGi = Concentration of GHG i, CH4 or CO2, 

in produced natural gas. 

Convi = Conversion from standard cubic feet 

to metric tons CO2e; 0.000410 for CH4, 

and 0.00005357 for CO2. 

24 * 365 = Conversion to yearly emissions 

estimate. 

(d) Acid gas removal (AGR) 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 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. 

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. 


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Where: 

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. 

a = 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. 

(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. 

(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 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 GRI–GLYCalc, that uses the 

Peng-Robinson equation of state to 

calculate the equilibrium coefficient, 

speciates CH4 and CO2 emissions from 

dehydrators, and has provisions to 

include regenerator control devices, a 

separator flash tank, stripping gas and a 

gas injection pump or gas assist pump. 

A minimum of the following parameters 

determined by engineering estimate 

based on best available data must be 

used to characterize emissions from 

dehydrators: 

(i) Feed natural gas flow rate. 

(ii) Feed natural gas water content. 

(iii) Outlet natural gas water content. 

(iv) Absorbent circulation pump type 

(natural gas pneumatic/air pneumatic/ 

electric). 

(v) Absorbent circulation rate. 

(vi) Absorbent type: including 

triethylene glycol (TEG), diethylene 

glycol (DEG) or ethylene glycol (EG). 

(vii) Use of stripping natural gas. 

(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: 

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. 


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(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. 

(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. 

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 

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. 

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. 

(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. 

Where: 

Ea,n = Annual natural gas emissions at actual 

conditions, in cubic feet/year. 

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

converted to pounds per square feet). 

CD = Casing diameter (inches). 

WD = Well depth to first producing horizon 

(feet). 

SP = Shut-in pressure (psia). 

NV = Number of vents per year. 

SFR = Average sales flow rate of gas well in 

cubic feet per hour. 

HR = Hours that the well was left open to the 

atmosphere during unloading. 

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. 


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Where: 

Ea,n = Annual natural gas emissions at actual 

conditions, in cubic feet/year. 

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

converted to pounds per square feet). 

TD = Tubing diameter (inches). 

WD = Tubing depth 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 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. 

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 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. 

(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: 

Where: 

FR = Average flow rate in cubic feet per hour, 

under subsonic flow conditions. 

A = Cross sectional area of orifice (m2). 

P1 = Upstream pressure (psia). 

Tu = Upstream temperature (degrees Kelvin). 

P2 = Downstream pressure (psia). 

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

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

hour. 

Where: 

FR = Average flow rate in cubic feet per hour, 

under sonic flow conditions. 

A = Cross sectional area of orifice (m2). 

Tu = Upstream temperature (degrees Kelvin). 

187.08 = Constant with units of m2/(sec2 * 

K). 

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

hour. 

(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 


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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 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). 

(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 fracturing and well 

workovers not involving hydraulic 

fracturing using Equation W–13 of this 

section: 

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. 

(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 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: 


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Where: 

Es,n = Annual natural gas venting emissions 

at standard conditions from blowdowns 

in cubic feet. 

N = Number of repetitive blowdowns for 

each 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 (°F). 

Ta = Temperature at actual conditions in the 

blowdown equipment chamber (°F). 

Ps = Absolute pressure at standard conditions 

(psia). 

Pa = Absolute pressure at actual conditions 

in the blowdown equipment chamber 

(psia). 

(4) Calculate both CH4 and CO2 mass 

emissions from volumetric natural gas 

emissions using calculations in 

paragraph (v) of this section. 

(5) Calculate total annual venting 

emissions for all blowdown vent stacks 

by adding all standard volumetric and 

mass emissions determined in Equation 

W–14 and paragraph (i)(4) of this 

section. 

(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 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, 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: 

(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 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 gas-liquid 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: 

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 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 


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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. 

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 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 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. 

(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). 

(3) Estimate venting emissions using 

Equation W–17 of this section. 

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. 

(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. 


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(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. 

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: 

(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 systems for all 

emissions sources downstream of the 

de-methanizer 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. 

Where: 

Ea,CH4(un-combusted) = Contribution of 

annual un-combusted CH4 emissions 

from flare stack in cubic feet, under 

actual conditions. 

Ea,CO2(un-combusted) = Contribution of 

annual un-combusted CO2 emissions 

from flare stack in cubic feet, under 

actual conditions. 

Ea,CO2(combusted) = Contribution of annual 

combusted CO2 emissions from flare 

stack in cubic feet, under actual 

conditions. 

Va = Volume of gas sent to flare in cubic feet, 

during the year. 

h = Fraction of gas combusted by a burning 

flare (default is 0.98). For gas sent to an 

unlit flare, h 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. 

(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) 


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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 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. 

(4) Estimate annual emissions using 

the flow measurement and Equation 

W–22 of this section. 

Where: 

Es,i,m = Annual GHGi (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 GHGi 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. 

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. 

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). 

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 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: 


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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: 

(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. 

(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. 

(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 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. 

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. 

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. 

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 


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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). 

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). 

(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: 

Where: 

Es,i = Annual total volumetric GHG emissions 

at standard conditions from 

reciprocating compressors in cubic feet. 

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. 

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. 

(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 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. 


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Where: 

Es,i = Annual volumetric GHG emissions at 

standard conditions from each 

equipment leak source in cubic feet. 

Counts = Total number of this type of 

emission source at the facility. Average 

component counts are provided by major 

equipment piece in 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, 

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 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. 

(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 

W–31 of this section. 

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 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 the 


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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 

pressure of natural gas emissions to 

standard temperature and pressure of 

natural gas using Equation W–33 of this 

section. 

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 (°F). 

Ta = Temperature at actual emission 

conditions (°F). 

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. 

Where: 

Es,i = GHG i volumetric emissions at standard 

temperature and pressure (STP) 

conditions in cubic feet. 

Ea,i = GHG i volumetric emissions at actual 

conditions in cubic feet. 

Ts = Temperature at standard conditions (°F). 

Ta = Temperature at actual emission 

conditions (°F). 

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. 

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. 

(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. 

(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. 


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Where: 

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

emissions at standard conditions in 

metric tons CO2e. 

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

emissions at standard conditions, in 

cubic feet. 

ri = Density of GHG i. 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: 

(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: 

Where: 

Massc,i = Annual EOR injection gas venting 

emissions in metric tons at critical 

conditions ‘‘c’’ from blowdowns. 

N = Number of blowdowns for the equipment 

in the calendar year. 

Vv = Total volume in cubic feet of blowdown 

equipment chambers (including 

pipelines, manifolds and vessels) 

between isolation valves. 

Rc = Density of critical phase EOR injection 

gas in kg/ft3. You may use an appropriate 

standard method published by a 

consensus-based standards organization 

if such a method exists or you may use 

an industry standard practice to 

determine density of super critical EOR 

injection gas. 

GHGi = Mass fraction of GHGi in critical 

phase injection gas. 

1 × 10¥3 = Conversion factor from kilograms 

to metric tons. 

(x) EOR hydrocarbon liquids 

dissolved CO2. Calculate dissolved CO2

in hydrocarbon liquids produced 

through EOR operations as follows: 

(1) Determine the amount of CO2

retained in hydrocarbon liquids after 

flashing in tankage at STP conditions. 

Annual samples must be taken 

according to methods set forth in 

§ 98.234(b) to determine retention of 

CO2 in hydrocarbon liquids 

immediately downstream of the storage 

tank. Use the annual analysis for the 

calendar year. 

(2) Estimate emissions using Equation 

W–38 of this section. 

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 CO2 CH4,and N2O combustionrelated 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. 

(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. 

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 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. 


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(6) Calculate N2O mass emissions 

using Equation W–40 of this section. 

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. 

(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 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 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 through-valve leak. When 

using the acoustic leak detection device, 

if a leak of 3.1 scf per hour or greater 

is calculated, a leak is detected. In 

addition, you must operate the acoustic 

leak detection device to monitor the 

source valves required by this subpart in 

accordance with the instrument 

manufacturer’s operating parameters. 

(b) You must operate and calibrate all 

flow meters, composition analyzers and 

pressure gauges used to measure 

quantities reported in § 98.233 

according to the procedures in § 98.3(i) 

and the procedures in paragraph (b) of 

this section. You may use an 

appropriate standard method published 

by a consensus-based standards 

organization if such a method exists or 

you may use an industry standard 

practice. Consensus-based standards 

organizations include, but are not 

limited to, the following: ASTM 

International, the American National 

Standards Institute (ANSI), the 

American Gas Association (AGA), the 

American Society of Mechanical 

Engineers (ASME), the American 

Petroleum Institute (API), and the North 

American Energy Standards Board 

(NAESB). 

(c) Use calibrated bags (also known as 

vent bags) only where the emissions are 

at near-atmospheric pressures such that 

it is safe to handle and can capture all 

the emissions, below the maximum 

temperature specified by the vent bag 

manufacturer, and the entire emissions 

volume can be encompassed for 

measurement. 

(1) Hold the bag in place enclosing the 

emissions source to capture the entire 

emissions and record the time required 

for completely filling the bag. If the bag 

inflates in less than one second, assume 

one second inflation time. 

(2) Perform three measurements of the 

time required to fill the bag, report the 

emissions as the average of the three 

readings. 

(3) Estimate natural gas volumetric 

emissions at standard conditions using 

calculations in § 98.233(t). 

(4) Estimate CH4 and CO2 volumetric 

and mass emissions from volumetric 

natural gas emissions using the 

calculations in § 98.233(u) and (v). 

(d) Use a high volume sampler to 

measure emissions within the capacity 

of the instrument. 

(1) A technician following 

manufacturer instructions shall conduct 

measurements, including equipment 

manufacturer operating procedures and 

measurement methodologies relevant to 

using a high volume sampler, including 

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 

anti-static wraps or other aids to capture 

all emissions without violating 

operating requirements as provided in 

the instrument manufacturer’s manual. 

(3) Estimate CH4 and CO2 volumetric 

and mass emissions from volumetric 

natural gas emissions using the 

calculations in § 98.233(u) and (v). 


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(4) Calibrate the instrument at 2.5 

percent methane with 97.5 percent air 

and 100 percent CH4 by using calibrated 

gas samples and by following 

manufacturer’s instructions for 

calibration. 

(e) Peng Robinson Equation of State 

means the equation of state defined by 

Equation W–41 of this section: 

Where: 

p = Absolute pressure. 

R = Universal gas constant. 

T = Absolute temperature. 

Vm = Molar volume. 

Where: 

w = Acentric factor of the species. 

Tc = Critical temperature. 

Pc = Critical pressure. 

(f) Special reporting provisions 

(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. 

(2) Best available monitoring methods 

for well-related 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: 

(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 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 


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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 

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. 

(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 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. 

(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 

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. 

(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. 


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(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 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 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. 

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. 

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 

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: 

(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: 


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(A) Glycol dehydrator feed natural gas 

flow rate in MMscfd, determined by 

engineering estimate based on best 

available data. 

(B) Glycol dehydrator absorbent 

circulation pump type. 

(C) Whether stripper gas is used in 

glycol dehydrator. 

(D) Whether a flash tank separator is 

used in glycol dehydrator. 

(E) Type of absorbent. 

(F) Total time the glycol dehydrator is 

operating in hours. 

(G) Temperature, in degrees 

Fahrenheit and pressure, in psig, of the 

wet natural gas. 

(H) Concentration of CH4 and CO2 in 

natural gas. 

(I) What vent gas controls are used 

(refer to § 98.233(e)(3) and (e)(4)). 

(J) Report vent and flared emissions 

individually. 

(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. 

(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)). 

(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. 

(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. 

(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: 

(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. 

(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. 


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74510 Federal Register / Vol. 75, No. 229 / Tuesday, November 30, 2010 / Rules and Regulations 

(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. 

(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: 

(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. 

(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). 

(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 

W–28 of § 98.233). 

(v) For reciprocating compressors in 

onshore petroleum and natural gas 

production (refer to Equation W–29 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). 

(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 W–30 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 W–31 of § 98.233) 

collectively by equipment type. 

(16) For local distribution companies, 

report the following: 

(i) Number of custody transfer gate 

stations. 

(ii) Number of non-custody transfer 

gate stations. 

(iii) Custody transfer gate station 

meter run leak factor (refer to 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. 


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(xiii) Number of plastic distribution 

services. 

(xiv) Number of copper distribution 

services. 

(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. 

(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 

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 

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 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 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. 

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). 


srobinson on DSKHWCL6B1PROD with RULES2
74512 Federal Register / Vol. 75, No. 229 / Tuesday, November 30, 2010 / Rules and Regulations 

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 

chamber. In an internal combustion 

engine the expansion of the hightemperature 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. 

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. 

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 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 TO SUBPART W OF PART

98—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 Service:1

Valve ..................................... 0.027 

Connector ............................. 0.004 

Open-ended Line .................. 0.062 

Pressure Relief Valve ........... 0.041 

Low Continuous Bleed Pneumatic Device Vents 2 ......... 1.80 

High Continuous Bleed 

Pneumatic Device Vents 2 48.1 

Intermittent Bleed Pneumatic 

Device Vents 2 ................... 17.4 

Pneumatic Pumps 3 .............. 13.3 

Population Emission Factors—All Components, 

Light Crude Service:4

Valve ..................................... 0.04 

Flange ................................... 0.002 

Connector ............................. 0.005 

Open-ended Line .................. 0.04 

Pump .................................... 0.01 

Other 5 ................................... 0.23 

Population Emission Factors—All Components, 

Heavy Crude Service:6

Valve ..................................... 0.0004 

Flange ................................... 0.0007 

Connector (other) ................. 0.0002 

Open-ended Line .................. 0.004 

Other 5 ................................... 0.002 

Western U.S. 

Population Emission Factors—All Components, 

Gas Service:1

Valve ..................................... 0.123 

Connector ............................. 0.017 

Open-ended Line .................. 0.032 

Pressure Relief Valve ........... 0.196 

Low Continuous Bleed Pneumatic Device Vents 2 ......... 1.80 

High Continuous Bleed 

Pneumatic Device Vents 2 48.1 

Intermittent Bleed Pneumatic 

Device Vents 2 ................... 17.4 

Pneumatic Pumps 3 .............. 13.3 

Population Emission Factors—All Components, 

Light Crude Service:4

Valve ..................................... 0.04 

Flange ................................... 0.002 

Connector (other) ................. 0.005 

Open-ended Line .................. 0.04 

Pump .................................... 0.01 

Other 5 ................................... 0.23 


srobinson on DSKHWCL6B1PROD with RULES2
Federal Register / Vol. 75, No. 229 / Tuesday, November 30, 2010 / Rules and Regulations 74513 

TABLE W–1A TO SUBPART W OF PART

98—DEFAULT WHOLE GAS EMISSION FACTORS FOR ONSHORE PETROLEUM AND NATURAL GAS PRODUCTION—Continued 

Onshore petroleum and 

natural gas production 

Emission 

factor 

(scf/hour/ 

component) 

Population Emission Factors—All Components, 

Heavy Crude Service:6

Valve ..................................... 0.0004 

Flange ................................... 0.0007 

TABLE W–1A TO SUBPART W OF PART

98—DEFAULT WHOLE GAS EMISSION FACTORS FOR ONSHORE PETROLEUM AND NATURAL GAS PRODUCTION—Continued 

Onshore petroleum and 

natural gas production 

Emission 

factor 

(scf/hour/ 

component) 

Connector (other) ................. 0.0002 

Open-ended Line .................. 0.004 

Other 5 ................................... 0.002 

1For multi-phase flow that includes gas, use 

the gas service emissions factors. 

2Emission Factor is in units of ‘‘scf/hour/device.’’ 3Emission 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.’’ 

TABLE W–1B TO SUBPART W OF PART 98—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 

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 TO SUBPART W OF PART 98—DEFAULT AVERAGE COMPONENT COUNTS FOR MAJOR CRUDE OIL

PRODUCTION EQUIPMENT

Major equipment Valves Flanges Connectors Open-ended 

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 

TABLE W–1D OF SUBPART W OF PART

98—DESIGNATION OF EASTERN AND

WESTERN U.S.—Continued 

Eastern U.S. Western U.S. 

Indiana ...................... Colorado 

Kentucky ................... Hawaii 

Maine ........................ Idaho 

Maryland ................... Iowa 

Massachusetts .......... Kansas 

TABLE W–1D OF SUBPART W OF PART

98—DESIGNATION OF EASTERN AND

WESTERN U.S.—Continued 

Eastern U.S. Western U.S. 

Michigan .................... Louisiana 

New Hampshire ........ Minnesota 

New Jersey ............... Mississippi 

New York .................. Missouri 

North Carolina ........... Montana 


srobinson on DSKHWCL6B1PROD with RULES2
74514 Federal Register / Vol. 75, No. 229 / Tuesday, November 30, 2010 / Rules and Regulations 

TABLE W–1D OF SUBPART W OF PART

98—DESIGNATION OF EASTERN AND

WESTERN U.S.—Continued 

Eastern U.S. Western U.S. 

Ohio ........................... Nebraska 

Pennsylvania ............. Nevada 

Rhode Island ............. New Mexico 

South Carolina .......... North Dakota 

Tennessee ................ Oklahoma 

Vermont ..................... Oregon 

Virginia ...................... South Dakota 

West Virginia ............. Texas 

Wisconsin .................. Utah 

................................... Washington 

................................... Wyoming 

TABLE W–2 TO SUBPART W OF PART

98—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—NonCompressor Components, Gas Service 

Valve ..................................... 6.52 

Connector ............................. 5.80 

Open-Ended Line ................. 11.44 

Pressure Relief Valve ........... 2.04 

Meter ..................................... 2.98 

1Valves include control valves, block valves 

and regulator valves. 

TABLE W–3 TO SUBPART W OF PART

98—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—NonCompressor Components, Gas Service 

Valve1 ................................... 6.52 

Connector ............................. 5.80 

Open-Ended Line ................. 11.44 

Pressure Relief Valve ........... 2.04 

TABLE W–3 TO SUBPART W OF PART

98—DEFAULT TOTAL HYDROCARBON

EMISSION FACTORS FOR ONSHORE

NATURAL GAS TRANSMISSION COMPRESSION—Continued 

Onshore natural gas transmission compression 

Emission Factor (scf/hour/ 

component) 

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 

1Valves include control valves, block valves 

and regulator valves. 2Emission Factor is in units of ‘‘scf/hour/ 

device.’’ 

TABLE W–4 TO SUBPART W OF PART

98—DEFAULT TOTAL HYDROCARBON

EMISSION FACTORS FOR UNDERGROUND NATURAL GAS STORAGE

Underground natural gas 

storage 

Emission Factor (scf/hour/ 

component) 

Leaker Emission Factors—Storage Station, Gas Service 

Valve 1 ................................... 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 

Leaker Emission Factors—Storage Station, Gas Service 

Open-ended Line .................. 0.03 

Population Emission Factors—Other Components, Gas Service 

Low Continuous Bleed Pneumatic Device Vents 2 ......... 1.41 

High Continuous Bleed 

Pneumatic Device Vents 2 18.8 

Intermittent Bleed Pneumatic 

Device Vents 2 ................... 18.8 

1Valves include control valves, block valves 

and regulator valves. 2Emission Factor is in units of ‘‘scf/hour/ 

device’’ 

TABLE W–5 TO SUBPART W OF PART

98—DEFAULT METHANE EMISSION

FACTORS FOR LIQUEFIED NATURAL

GAS (LNG) STORAGE

LNG Storage 

Emission Factor (scf/hour/ 

component) 

Leaker Emission Factors—LNG Storage 

Components, LNG Service 

Valve ..................................... 1.21 

Pump Seal ............................ 4.06 

Connector ............................. 0.35 

Other 1 ................................... 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. 2Emission Factor is in units of ‘‘scf/hour/ 

compressor.’’ 

TABLE W–6 TO SUBPART W OF PART

98—DEFAULT METHANE EMISSION

FACTORS FOR LNG IMPORT AND EXPORT EQUIPMENT

LNG import and export 

equipment 

Emission Factor (scf/hour/ 

component) 

Leaker Emission Factors—LNG Terminals 

Components, LNG Service 

Valve ..................................... 1.21 

Pump Seal ............................ 4.06 

Connector ............................. 0.35 

Other 1 ................................... 1.80 

Population Emission Factors—LNG Terminals Compressor, Gas Service 

Vapor Recovery Compressor 2 ............................ 4.23 

1 ‘‘other’’ equipment type should be applied 

for any equipment type other than connectors, 

pumps, or valves. 2Emission Factor is in units of ‘‘scf/hour/ 

compressor.’’ 

TABLE W–7 TO SUBPART W OF PART

98—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 Stations 1 Components, Gas Service 

Connector ............................. 1.72 

Block Valve ........................... 0.566 

Control Valve ........................ 9.48 

Pressure Relief Valve ........... 0.274 

Orifice Meter ......................... 0.215 


srobinson on DSKHWCL6B1PROD with RULES2
Federal Register / Vol. 75, No. 229 / Tuesday, November 30, 2010 / Rules and Regulations 74515 

TABLE W–7 TO SUBPART W OF PART

98—DEFAULT METHANE EMISSION

FACTORS FOR NATURAL GAS DISTRIBUTION—Continued 

Natural gas distribution 

Emission Factor (scf/hour/ 

component) 

Regulator .............................. 0.784 

Open-ended Line .................. 26.533 

Population Emission Factors—Below 

Grade M&R 2 Components, Gas Service 3

Below Grade M&R Station, 

Inlet Pressure > 300 psig 1.32 

Below Grade M&R Station, 

Inlet Pressure 100 to 300 

psig .................................... 0.20 

TABLE W–7 TO SUBPART W OF PART

98—DEFAULT METHANE EMISSION

FACTORS FOR NATURAL GAS DISTRIBUTION—Continued 

Natural gas distribution 

Emission Factor (scf/hour/ 

component) 

Below Grade M&R Station, 

Inlet Pressure < 100 psig 0.10 

Population Emission Factors—Distribution Mains, Gas Service 4

Unprotected Steel ................. 12.77 

Protected Steel ..................... 0.36 

Plastic ................................... 1.15 

Cast Iron ............................... 27.67 

Population Emission Factors—Distribution Services, Gas Service 5

Unprotected Steel ................. 0.19 

TABLE W–7 TO SUBPART W OF PART

98—DEFAULT METHANE EMISSION

FACTORS FOR NATURAL GAS DISTRIBUTION—Continued 

Natural gas distribution 

Emission Factor (scf/hour/ 

component) 

Protected Steel ..................... 0.02 

Plastic ................................... 0.001 

Copper .................................. 0.03 

1 City gate stations at custody transfer and 

excluding customer meters. 2Excluding customer meters. 

3Emission Factor is in units of ‘‘scf/hour/station’’. 4Emission Factor is in units of ‘‘scf/hour/ 

mile’’. 5Emission Factor is in units of ‘‘scf/hour/ 

number of services’’. 

[FR Doc. 2010–28655 Filed 11–29–10; 8:45 am] 

BILLING CODE 6560–50–P 


srobinson on DSKHWCL6B1PROD with RULES2