EPA Administrator Gina McCarthy signed the following document on February 20, 

2014, and EPA is submitting it for publication in the Federal Register (FR). 

While we have taken steps to ensure the accuracy of this Internet version of 

the document, it is not the official version. Please refer to the official 

version in a forthcoming FR publication, which will appear on the Government 

Printing Office's FDSys website 

(http://fdsys.gpo.gov/fdsys/search/home.action). {It will also appear on 

Regulations.gov (http://www.regulations.gov) in Docket No. EPA-HQ-OAR-2011-

0512}.

6560-50-P

ENVIRONMENTAL PROTECTION AGENCY

40 CFR Part 98

[EPA-HQ-OAR-2011-0512; FRL-9906-85-OAR]

RIN 2060-AR96

Greenhouse Gas Reporting Rule: Revisions and Confidentiality Determinations for 

Petroleum and Natural Gas Systems; Proposed Rule

AGENCY: Environmental Protection Agency (EPA).

ACTION: Proposed rule.

SUMMARY: The EPA is proposing revisions and confidentiality determinations for the 

petroleum and natural gas systems source category and the general provisions of the Greenhouse 

Gas Reporting Rule. In particular, the EPA is proposing to revise certain calculation methods, 

amend certain monitoring and data reporting requirements, clarify certain terms and definitions, 

and correct certain technical and editorial errors that have been identified during the course of 

implementation. This action also proposes confidentiality determinations for new or substantially 

revised data elements contained in these proposed amendments, as well as proposes a revised 

confidentiality determination for one existing data element. 
Page 2 of 225

This document is a prepublication version, signed by EPA Administrator Gina McCarthy on February 20, 

2014. We have taken steps to ensure the accuracy of this version, but it is not the official version.

DATES: Comments. Comments must be received on or before [INSERT THE DATE 45

DAYS AFTER DATE OF PUBLICATION IN THE FEDERAL REGISTER]. 

Public Hearing. The EPA does not plan to conduct a public hearing unless requested. To 

request a hearing, please contact the person listed in the following FOR FURTHER 

GENERAL INFORMATION CONTACT section by [INSERT THE DATE 7 DAYS 

AFTER DATE OF PUBLICATION IN THE FEDERAL REGISTER]. If requested, the 

hearing will be conducted on [INSERT THE DATE 15 DAYS AFTER DATE OF 

PUBLICATION IN THE FEDERAL REGISTER], in the Washington, DC area. The EPA 

will provide further information about the hearing on the Greenhouse Gas Reporting Rule Web

site, http://www.epa.gov/ghgreporting/index.html if a hearing is requested.

ADDRESSES: Submit your comments, identified by Docket ID No. EPA-HQ-OAR-2011-0512

by any of the following methods:

• Federal eRulemaking Portal: http://www.regulations.gov. Follow the online instructions 

for submitting comments.

• Email: GHG_Reporting_Rule_Oil_And_Natural_Gas@epa.gov. Include Docket ID No. 

EPA-HQ-OAR-2011-0512 or RIN No. 2060-AR96 in the subject line of the message.

• Fax: (202) 566-9744.

• Mail: Environmental Protection Agency, EPA Docket Center (EPA/DC), Mailcode 

28221T, Attention Docket ID No. OAR-2011-0512, 1200 Pennsylvania Avenue, NW., 

Washington, DC 20460.

• Hand/Courier Delivery: EPA Docket Center, Public Reading Room, William Jefferson 

Clinton (WJC) West Building, Room 3334, 1301 Constitution Avenue, NW., 

Washington, DC 20004. Such deliveries are accepted only during the normal hours of 

operation of the Docket Center, and special arrangements should be made for deliveries 

of boxed information.

Additional Information on Submitting Comments: To expedite review of your comments 

by agency staff, you are encouraged to send a separate copy of your comments, in addition to the 

copy you submit to the official docket, to Carole Cook, U.S. EPA, Office of Atmospheric 
Page 3 of 225

This document is a prepublication version, signed by EPA Administrator Gina McCarthy on February 20, 

2014. We have taken steps to ensure the accuracy of this version, but it is not the official version.

Programs, Climate Change Division, Mail Code 6207-J, 1200 Pennsylvania Avenue, N.W., 

Washington, DC, 20460, telephone (202) 343-9263, email address: 

GHGReportingRule@epa.gov.

Instructions: Direct your comments to Docket ID No. EPA-HQ-OAR-2011-0512, 

Greenhouse Gas Reporting Rule: Revisions and Confidentiality Determinations for Petroleum 

and Natural Gas Systems; Proposed Rule. The EPA’s policy is that all comments received will 

be included in the public docket without change and may be made available online at 

http://www.regulations.gov, including any personal information provided, unless the comment 

includes information claimed to be confidential business information (CBI) or other information 

whose disclosure is restricted by statute. 

Should you choose to submit information that you claim to be CBI, clearly mark the part 

or all of the information that you claim to be CBI. For information that you claim to be CBI in a 

disk or CD-ROM that you mail to the EPA, mark the outside of the disk or CD-ROM as CBI and 

then identify electronically within the disk or CD-ROM the specific information that is claimed 

as CBI. In addition to one complete version of the comment that includes information claimed as 

CBI, a copy of the comment that does not contain the information claimed as CBI must be 

submitted for inclusion in the public docket. Information marked as CBI will not be disclosed 

except in accordance with procedures set forth in 40 CFR part 2. Send or deliver information 

identified as CBI to only the mail or hand/courier delivery address listed above, attention: 

Docket ID No. EPA-HQ-OAR-2011-0512. If you have any questions about CBI or the 

procedures for claiming CBI, please consult the person identified in the FOR FURTHER 

GENERAL INFORMATION CONTACT section.
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2014. We have taken steps to ensure the accuracy of this version, but it is not the official version.

Do not submit information that you consider to be CBI or otherwise protected through 

http://www.regulations.gov or email. The http://www.regulations.gov Web site is an 

“anonymous access” system, which means the EPA will not know your identity or contact 

information unless you provide it in the body of your comment. If you send an email comment 

directly to the EPA without going through http://www.regulations.gov your email address will be 

automatically captured and included as part of the comment that is placed in the public docket 

and made available on the Internet. If you submit an electronic comment, the EPA recommends 

that you include your name and other contact information in the body of your comment and with 

any disk or CD-ROM you submit. If the EPA cannot read your comment due to technical 

difficulties and cannot contact you for clarification, the EPA may not be able to consider your 

comment. Electronic files should avoid the use of special characters, any form of encryption, and 

be free of any defects or viruses. 

Docket: All documents in the docket are listed in the http://www.regulations.gov index. 

Although listed in the index, some information is not publicly available, e.g., CBI or other 

information whose disclosure is restricted by statute. Certain other material, such as copyrighted 

material, will be publicly available only in hard copy. Publicly available docket materials are 

available either electronically in http://www.regulations.gov or in hard copy at the Air Docket, 

EPA/DC, WJC West Building, Room 3334, 1301 Constitution Ave., NW., Washington, DC. 

This Docket Facility is open from 8:30 a.m. to 4:30 p.m., Monday through Friday, excluding 

legal holidays. The telephone number for the Public Reading Room is (202) 566-1744, and the 

telephone number for the Air Docket is (202) 566-1742.

FOR FURTHER GENERAL INFORMATION CONTACT: Carole Cook, Climate Change 

Division, Office of Atmospheric Programs (MC-6207J), Environmental Protection Agency, 1200 
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2014. We have taken steps to ensure the accuracy of this version, but it is not the official version.

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, please go to the Greenhouse Gas Reporting Rule Web site, 

http://www.epa.gov/ghgreporting/index.html. To submit a question, select Help Center, followed 

by “Contact Us.” 

Worldwide Web (WWW). In addition to being available in the docket, an electronic copy 

of today's proposal will also be available through the WWW. Following the Administrator’s 

signature, a copy of this action will be posted on EPA's Greenhouse Gas Reporting Rule Web 

site at http://www.epa.gov/ghgreporting/index.html.

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”). 

These are proposed amendments to existing regulations. If finalized, these amended regulations 

would affect owners or operators of petroleum and natural gas systems that directly emit 

greenhouse gases (GHGs). Regulated categories and entities include those listed in Table 1 of 

this preamble:

Table 1. Examples of Affected Entities by Category

Category NAICS Examples of affected facilities

Petroleum and Natural Gas Systems 486210 Pipeline transportation of natural gas.

221210 Natural gas distribution.

211111 Crude petroleum and natural gas 

extraction.

211112 Natural gas liquid extraction.

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. Other types of facilities than those 
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2014. We have taken steps to ensure the accuracy of this version, but it is not the official version.

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 and 40 CFR part 98, subpart W. If you have questions regarding the 

applicability of this action to a particular facility, consult the person listed in the preceding FOR 

FURTHER GENERAL INFORMATION CONTACT section.

Acronyms and Abbreviations. The following acronyms and abbreviations are used in this 

document.

BAMM best available monitoring methods

CAA Clean Air Act

CBI confidential business information

CFR Code of Federal Regulations

CH4 methane

CO2 carbon dioxide

CO2e carbon dioxide equivalent

EIA Energy Information Administration

EOR enhanced oil recovery

EPA U.S. Environmental Protection Agency

FERC Federal Energy Regulatory Commission

FR Federal Register

GHG greenhouse gas

GOR gas to oil ratio

GWP global warming potential

LNG liquefied natural gas

MMscf million standard cubic feet per day

N2O nitrous oxide

NAICS North American Industry Classification System

NGL natural gas liquids

NTTAA National Technology Transfer and Advancement Act

OMB Office of Management and Budget

QA/QC quality assurance/quality control

RFA Regulatory Flexibility Act
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scf standard cubic feet

TSD Technical Support Document

UIC underground injection control

U.S. United States

UMRA Unfunded Mandates Reform Act of 1995

Organization of This Document. The following outline is provided to aid in locating 

information in this preamble.

I. Background

A. Organization of this Preamble

B. Background on the Proposed Action

C. Legal Authority

D. How Would These Amendments Apply to 2014 and 2015 Reports?

II. Revisions and Other Amendments

A. Proposed Revisions to Provide Consistency Throughout Subpart W.

B. Proposed Changes to Calculation Methods and Reporting Requirements.

C. Proposed Revisions to Missing Data Provisions

D. Proposed Amendments to Best Available Monitoring Methods

III. Proposed Confidentiality Determinations

A. Overview and Background

B. Approach to Proposed CBI Determinations for New or Revised Subpart W Data Elements.

C. Proposed Confidentiality Determinations for Data Elements Assigned to the “Unit/Process 

‘Static’ Characteristics That Are Not Inputs to Emission Equations” and “Unit/Process Operating 

Characteristics That Are Not Inputs to Emission Equations” Data Categories

D. Other Proposed or Re-proposed Case-by-Case Confidentiality Determinations for Subpart W

E. Request for Comments on Proposed Confidentiality Determinations

IV. Impacts of the Proposed Amendments to Subpart W

V. 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
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2014. We have taken steps to ensure the accuracy of this version, but it is not the official version.

I. Background

A. Organization of this Preamble

The first section of this preamble provides background information regarding the origin 

of the proposed amendments. This section also discusses the EPA’s legal authority under the 

CAA to promulgate and amend 40 CFR part 98 of the Greenhouse Gas Reporting Rule 

(hereinafter referred to as “Part 98”) as well as the legal authority for making confidentiality 

determinations for the data to be reported. Section II of this preamble contains information on the 

proposed revisions to 40 CFR part 98, subpart W (hereafter referred to as “subpart W”). Section 

III of this preamble discusses proposed confidentiality determinations for new or substantially 

revised (i.e., requiring additional or different data to be reported) data reporting elements, as well 

as a proposed revised confidentiality determination for one existing data element. Section IV of 

this preamble discusses the impacts of the proposed amendments to subpart W. Finally, Section 

V of this preamble describes the statutory and executive order requirements applicable to this 

action. 

B. Background on the Proposed Action

On October 30, 2009, the EPA published Part 98 for collecting information regarding 

greenhouse gases (GHGs) from a broad range of industry sectors (74 FR 56260). The 2009 rule, 

which finalized reporting requirements for 29 source categories, did not include the petroleum 

and natural gas systems source category. A subsequent rule was published on November 20, 

2010 finalizing the requirements for the petroleum and natural gas systems source category at 40 

CFR part 98, subpart W (75 FR 74458) (hereafter referred to as “the final subpart W rule”). 

Following promulgation, the EPA finalized actions revising subpart W (76 FR 22825, April 25, 
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2014. We have taken steps to ensure the accuracy of this version, but it is not the official version.

2011; 76 FR 59533, September 27, 2011; 76 FR 80554, December 23, 2011; 77 FR 51477, 

August 24, 2012; 78 FR 25392, May 1, 2013; 78 FR 71904, Nov. 29, 2013). 

In this action, the EPA is proposing to make certain revisions to the petroleum and 

natural gas systems source category GHG reporting requirements (Part 98, subpart W) and one 

clarifying edit to a definition in the general provisions source category (Part 98, subpart A). The 

proposed changes revise certain calculation methods, amend certain monitoring and data 

reporting requirements, clarify certain terms and definitions, and correct certain technical and 

editorial errors identified during the course of implementation. The proposed revisions were 

identified from the verification of annual reports, review of Best Available Monitoring Method 

(BAMM) request submittals, and questions raised by reporting entities. In conjunction with this 

action, we are proposing confidentiality determinations for the new and substantially revised 

(i.e., requiring additional or different data to be reported) data elements contained in these

proposed amendments, as well as proposing a revised confidentiality determination for one

existing data element. 

C. Legal Authority

The EPA is proposing these rule amendments under its existing CAA authority provided 

in CAA section 114. As stated in the preamble to the 2009 final GHG reporting rule (74 FR 

56260, October 30, 2009), CAA section 114(a)(1) provides the EPA broad authority to require 

the information proposed to be gathered by this rule because such data would inform and are 

relevant to the EPA’s carrying out a wide variety of CAA provisions. See the preambles to the 

proposed (74 FR 16448, April 10, 2009) and final GHG reporting rule (74 FR 56260, October 

30, 2009) for further information. 
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2014. We have taken steps to ensure the accuracy of this version, but it is not the official version.

In addition, the EPA is proposing confidentiality determinations for proposed new or 

substantially revised data elements in subpart W, as well as proposing a revised confidentiality 

determination for one existing data element, under its authorities provided in sections 114, 301, 

and 307 of the CAA. Section 114(c) requires that the EPA make information obtained under 

section 114 available to the public, except where information qualifies for confidential treatment. 

The Administrator has determined that this action is subject to the provisions of section 307(d) of 

the CAA. 

D. How Would These Amendments Apply to 2014 and 2015 Reports?

The EPA is planning to address the comments we receive on these proposed changes and 

publish the final amendments before the end of 2014. If finalized, these amendments would 

become effective on January 1, 2015. Facilities would therefore be required to follow the revised 

methods in subpart W, as amended, to calculate emissions beginning January 1, 2015 (i.e.,

beginning with the 2015 reporting year). The first annual reports of emissions calculated using 

the amended requirements would be those submitted by March 31, 2016, which would cover the 

2015 reporting year. For the 2014 reporting year, reporters would continue to calculate emissions 

and other relevant data for the reports that are submitted according to the requirements of 40 

CFR part 98 that are applicable to the 2014 reporting year (i.e. those currently in effect). 

II. Revisions and Other Amendments 

The amendments to subpart W that the EPA is proposing include the following types of 

changes:

• Changes to clarify or simplify calculation methods for certain sources at a facility, and 

reduce some of the burden associated with data collection and reporting.

• Revisions to units of measure, terms, and definitions in certain equations to provide 

consistency throughout the rule, provide clarity, or better reflect facility operations. 
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• Revisions to reporting requirements to clarify and align more closely with the calculation 

methods and to clearly identify the data that must be reported for each source type. 

• Other amendments and revisions identified as a result of working with the affected 

sources during rule implementation and outreach.

In addition to the specific revisions or amendments discussed in this section of the 

preamble, the EPA is proposing several minor technical revisions to subpart W to improve 

readability, to create consistency in terminology, and/or to correct typographical or other errors. 

These proposed revisions contained in the proposed regulatory text are further explained in the 

memorandum, “Proposed Minor Technical Corrections to Subpart W, Petroleum and Natural 

Gas Systems, in the Greenhouse Gas Reporting Program” in Docket ID No. EPA-HQ-OAR2011-0512. The EPA invites public comment on the revisions identified in this memorandum, as 

well as those outlined in this preamble. 

A. Proposed Revisions to Provide Consistency Throughout Subpart W

1. Consistency In Units Of Measure For Emissions Reporting

Currently, subpart W requires that reported GHG emissions be expressed in metric tons 

of CO2 equivalent (CO2e). The EPA is proposing to amend 40 CFR 98.236 to revise the 

reporting of GHG emissions from units of metric tons of CO2e of each reported GHG to metric 

tons of each reported GHG. These proposed changes would increase consistency between the 

reporting requirements for subpart W and the rest of Part 98, because other subparts of Part 98 

generally require the reporting of metric tons of individual GHGs instead of metric tons of CO2e. 

Reporters would use the global warming potentials (GWPs) in Table A-1 of 40 CFR Part 98, 

subpart A, as required in 40 CFR 98.2(b)(4), to calculate annual emissions aggregated for all 

GHGs from all applicable source categories in metric tons of CO2e for their annual reports.

Specifically, we are proposing to revise the units of emissions reported in 40 CFR 98.236 

to require reporting in metric tons of methane (CH4), carbon dioxide (CO2), and nitrous oxide 
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(N2O), as applicable, instead of reporting each gas in metric tons of CO2e. We are also proposing 

to revise certain calculation methods that require the calculation of emissions in CO2e. For 

example, subpart W total GHG emissions are calculated using equations that reference GWPs 

(Equations W-36 and W-40). We are proposing to amend each equation referencing GWPs 

separately to remove the conversion factors and GWPs that are built into the equations, and 

allow for calculation of individual GHG emissions in metric tons. 

The proposed revisions reduce the likelihood of errors and inconsistencies, because it 

reduces the number of calculations that need to be completed by reporters and removes some 

variability in how different reporters may complete these calculations (e.g., a reporter could 

inadvertently use the wrong GWP). The proposed changes would also simplify analysis of 

emissions on a GHG-specific basis, which would facilitate the verification of reported data. In 

addition, this proposed change would align subpart W with the manner of reporting for most 

other subparts of Part 98. 

2. Onshore Production Source Category Definition

We are proposing to revise the source category definition of onshore petroleum and 

natural gas production at 40 CFR 98.230(a)(2) to clarify the emission sources covered for 

purposes of GHG reporting. The proposed amendments clarify the types of emission sources in 

the onshore petroleum and natural gas production source category to which the reporting 

requirements of subpart W apply. Specifically, we are proposing to add references to engines, 

boilers, heaters, flares, separation and processing equipment, and maintenance and repair 

equipment and to remove references to gravity separation equipment and auxiliary nontransportation-related equipment. Thus, the first sentence of 40 CFR 98.230(a)(2) is proposed to 

read as follows: “Onshore petroleum and natural gas production means all equipment on a single 
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well-pad or associated with a single well-pad (including but not limited to compressors, 

generators, dehydrators, storage vessels, engines, boilers, heaters, flares, separation and 

processing equipment, and portable non-self-propelled equipment which includes well drilling 

and completion equipment, workover equipment, maintenance and repair 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).” The 

references to gravity separation equipment and auxiliary non-transportation-related equipment in 

the current rule are redundant with other sources specified in the definition. The proposed 

amendments do not subject new emission sources to the reporting requirements and do not 

remove sources currently covered from the reporting requirements, but rather provide a more 

accurate description of the industry segment for purposes of GHG reporting. 

3. Definition Of Sub-Basin Category

The EPA is proposing to revise the definition of sub-basin category at 40 CFR 98.238 to 

clarify coverage for purposes of GHG reporting due to issues identified during implementation. 

Specifically, we are proposing to define sub-basin category as “a subdivision of a basin into the 

unique combination of wells with the surface coordinates within the boundaries of an individual 

county and subsurface completion in one or more of each of the following five formation types: 

oil, high permeability gas, shale gas, coal seam, or other tight gas reservoir rock. The distinction 

between high permeability gas and tight gas reservoirs shall be designated as follows: high 

permeability gas reservoirs with >0.1 millidarcy permeability, and tight gas reservoirs with ≤0.1 

millidarcy permeability. Permeability for a reservoir type shall be determined by engineering 

estimate. Wells that produce only from high permeability gas, shale gas, coal seam, or other tight 

gas reservoir rock are considered gas wells; gas wells producing from more than one of these 
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formation types shall be classified into only one type based on the formation with the most 

contribution to production as determined by engineering knowledge. All wells that produce 

hydrocarbon liquids (with or without gas) and do not meet the definition of a gas well in this subbasin category definition are considered to be in the oil formation. All emission sources that 

handle condensate from gas wells in high permeability gas, shale gas, or tight gas reservoir rock 

formations are considered to be in the formation that the gas well belongs to and not in the oil 

formation.” The EPA is proposing these edits to clarify that “tight gas reservoir rock” generally 

refers to tight reservoir rock formations that produce gas, and not tight reservoir rock formations 

that produce only oil, and that wells that produce liquids in a sub-basin from formations other 

than high permeability gas, shale gas, coal seam, or other tight gas reservoir rock are considered 

oil wells.

B. Proposed Changes to Calculation Methods and Reporting Requirements 

This section describes proposed changes or corrections to calculation methods and 

reporting requirements. In general, the proposed revisions to calculation methods would provide 

greater flexibility and potentially reduce burden to facilities (e.g., by increasing options for 

calculating emissions from compressors), and increase clarity and congruency of calculation and 

reporting requirements (e.g., by clarifying which reporting requirements apply to which 

calculation methods). The EPA is also proposing minor technical revisions to the calculation 

methods of subpart W, such as making equation variables and definitions consistent across 

multiple equations that identify the same parameters, or clarifying requirements that have caused 

confusion. Please see the memo, “Proposed Minor Technical Corrections to Subpart W, 

Petroleum and Natural Gas Systems, in the Greenhouse Gas Reporting Program” in Docket ID 
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No. EPA-HQ-OAR-2011-0512, for more information on the minor technical revisions included 

in this proposal.

We are also proposing revisions to the reporting requirements in 40 CFR 98.236. The 

proposed revisions would restructure the reporting requirements, make reporting requirements 

consistent with the calculation methods, clarify the data elements to be reported, and improve 

data utility. In the current subpart W rule, slight inconsistencies between the calculation and the 

reporting sections have caused confusion among some reporters. In order to improve the quality 

of the data reported, we are proposing to revise reporting requirements that more clearly align 

with the calculation methods for each source type. 

We are proposing to reorganize the reporting section by source type (e.g., natural gas 

pneumatic device venting, acid gas removal vents, etc.) and, for each industry segment, list 

which source types must be reported. These proposed changes would clarify the reporting 

requirements for each industry segment and streamline verification by reducing the amount of 

correspondence with facilities during verification regarding required data elements that were not 

reported. Although the proposed reporting requirements appear lengthier, the revisions separate 

the requirements into discrete reporting elements in order to facilitate reporting and improve data 

collection. The proposed revisions to the reporting requirements in 40 CFR 98.236 will clarify 

which data elements are required to be reported for which facilities. For example, in reviewing 

the current subpart W reporting forms, if a reporter left certain fields blank in the reporting form 

(e.g., emissions from flaring), the EPA has been unable to discern whether the field was left 

blank intentionally. Because the proposed 40 CFR 98.236 would clearly define each data 

element for each emission source in each industry segment that must be reported, it would clarify 

which fields in the subpart W reporting form should be populated. In some cases, we are also 
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proposing to add additional data elements to improve the quality of the data reported. The 

reporting of these proposed data elements would improve verification of reported emissions and 

reduce the amount of correspondence with reporters that is associated with follow-up and 

revision of annual reports. In nearly all cases, the new data elements are based on data that are 

already collected by the reporter or are readily available to the reporter, and would not require 

additional monitoring or data collection. For additional information on the proposed changes to 

the reporting section, see the memo, “Proposed Revisions to the Subpart W Reporting 

Requirements” in Docket Id. No. EPA-HQ-OAR-2011-0512.

1. Natural Gas Pneumatic Device Venting 

The EPA is proposing to revise the calculation method for natural gas pneumatic device 

venting to expand the use of site-specific data on gas compositions, if available, for facilities in 

the onshore natural gas transmission compression and underground natural gas storage industry 

segments. The final subpart W rule provides default natural gas compositions of 95 percent CH4

and 1 percent CO2 for onshore natural gas transmission compression and underground natural 

gas storage, when calculating CH4 and CO2 volumetric emissions from transmission storage 

tanks (transmission compression), blowdown vent stacks (transmission compression), and 

compressor venting (40 CFR 98.233(u)(2)(iii) and (iv)). The provisions of 40 CFR 98.233(u)(2) 

only allow default gas compositions to be used, unless otherwise specified in 40 CFR 

98.233(u)(2) (i.e., for onshore production and natural gas processing).

We are proposing to allow either the use of site-specific composition data for natural gas 

transmission compression and underground natural gas storage facilities or the use of a default 

gas composition (95 percent CH4 and 1 percent CO2). Specifically, we are proposing to revise 

the parameter “GHGi” in Equation W-1 to remove the default gas composition for CH4 and CO2
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and to direct reporters to use the concentrations determined as specified in 40 CFR 

98.233(u)(2)(i), (iii), and (iv). This amendment addresses reporter concerns and improves data 

quality for those using site-specific data. The proposed changes are consistent with provisions for 

other applicable emission sources at natural gas transmission compression and underground 

storage facilities and would allow a consistent gas composition to be used for all sources at a 

facility. The calculation still must be conducted in much the same way that is currently required; 

however, we are proposing that reporters be allowed to use site-specific data if they are

available. Therefore, the EPA does not anticipate that this proposed change will significantly 

affect the reporting burden. The EPA requests comment on whether the use of site-specific 

composition data for calculating emissions should be required or optional. The EPA also requests 

comment and specific details on when, if ever, a facility would not have site-specific gas 

composition data available. 

We are also proposing to revise the natural gas pneumatic device venting calculations (40 

CFR 98.233(a)(1), (a)(2), and (a)(3)) to simplify how “Countt” of Equation W-1 (total number of 

natural gas pneumatic devices) must be calculated each year as new devices are added. The 

revisions clarify that for all industry segments, the reported number of devices must represent the 

total number of devices for the reporting year. For the onshore petroleum and natural gas 

production industry segment, reporters would continue to have the option in the first two 

reporting years to estimate “Countt” using engineering estimates. 

2. Acid Gas Removal Vents 

For acid gas removal vents, we are proposing minor clarifying edits to 40 CFR 98.233(d) 

to clearly label each calculation method and to clarify provisions by providing references to 

equations where appropriate. We are also proposing to revise the parameters “VolCO2” in 
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Equation W-3 and parameters “VolI” and “VolO” in Equation W-4A and W-4B to clarify that the 

volumetric fraction used should be the annual average. We are also proposing to specify in 40 

CFR 98.233(d)(8) that reporters may use sales line quality specifications for CO2 in natural gas 

only if a continuous gas analyzer is not available. 

3. Dehydrators 

We are proposing to revise the dehydrator vents source by renumbering and revising the 

dehydrator calculation method for desiccant dehydrators in order to clarify the adjustment of 

emissions to account for venting to a vapor recovery system or to a flare (40 CFR 98.233(e)). 

The proposed amendments provide for the adjustment of emissions vented to a vapor recovery 

system or flare (40 CFR 98.233(e)(5) and (e)(6)) for desiccant dehydrators because in the final 

subpart W rule, it was not clear how such an adjustment would be made. As such, we are 

clarifying the calculation methods for desiccant dehydrators that vent to a flare or vapor recovery 

device. 

4. Well Venting for Liquids Unloading

The EPA is proposing to revise the calculation and reporting requirements for well 

venting from liquids unloading to allow for annualizing venting data for facilities that calculate 

emissions using a recording flow meter (Calculation Method 1). This proposed amendment 

would address reporter concerns and simplify reporting. Some reporters have expressed 

difficulty in collecting well venting data using a recording flow meter for the exact period of 

January 1 to December 31, because they contend that it would require them to be physically 

present at each recording flow meter on December 31. The EPA is proposing to revise 

Calculation Method 1 (40 CFR 98.233(f)(1)) such that reporters may use an annualized value to 

determine the cumulative amount of time of venting (“Tp” in Equation W-7A and W-7B) if data 
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are not available for the specific time period January 1 to December 31. We are specifying that if 

an annualized value is used, the monitoring period must begin before February 1 and must not 

end before December 1 of the reporting year, and that a minimum of 300 consecutive days must 

be used by reporters to determine the annualized vent time. The EPA is also proposing that the 

date of the end of one monitoring period must be the start of the next monitoring period for the 

next reporting year, and that all days must be monitored and all venting accounted for. We are 

proposing that if a reporter uses a monitoring period other than a full calendar year for any well, 

they must report the percentage of wells for which a monitoring period other than a full calendar 

year is used. Although the proposed change increases flexibility, the calculation still must be 

conducted in much the same way that is currently required. Therefore, the EPA does not 

anticipate that this proposed change will significantly affect reporting burden. 

We are proposing to change Calculation Method 1 at 40 CFR 98.233(f)(1) to separate the 

calculation and reporting of emissions from wells that have plunger lifts and wells that do not 

have plunger lifts. This separation would allow the EPA and the public to more easily 

disaggregate emission data and activity data for wells that have plunger lifts and wells that do not 

have plunger lifts. We are proposing a clarification to Calculation Method 2 in 40 CFR 

98.233(f)(2) to clarify that this method is used for wells without plunger lifts. 

In a harmonizing change, the EPA is proposing to revise the reporting requirement for 

reporters using Calculation Method 1, under 40 CFR 98.236 such that reporters would be 

required to report the cumulative amount of time of venting for each group of wells during the 

year. Calculation Method 1 uses the cumulative amount of time of venting and not the number of 

venting events, to calculate emissions; therefore, this revision would align the reporting 

requirement with the calculation method. We are proposing harmonizing changes to 40 CFR 
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98.236 to separate the reporting of emissions from wells with and without plunger lifts when 

Calculation Method 1 is used. 

We are also proposing to amend the definition of the term “SPp” in Equation W-8 (40 

CFR 98.233(f)(2)) to clarify that if casing pressure is not available for each well, reporters may 

determine the casing pressure using a ratio of the casing pressure to tubing pressure from a well 

in the same sub-basin where the casing pressure is known. This amendment would improve the 

consistency of the calculation method used to determine casing pressure across reporters.

We are also proposing to revise 40 CFR 98.236 to require that facilities using Calculation 

Methods 1, 2, and 3 report a separate count of wells with plunger lifts and wells without plunger 

lifts, and to report annual emissions separately from each of those sources, respectively. We are 

also proposing to amend 40 CFR 98.236 to require the reporting of the cumulative number of 

unloadings from wells with plunger lifts and unloadings from wells without plunger lifts, the 

average flow rate of the measured well venting for wells with and without plunger lifts, and the 

internal casing or tubing diameters and pressures for wells with and without plunger lifts, as 

applicable. These proposed revisions break out the existing count and emissions reporting 

requirements to more clearly specify the sources of emissions at facilities. For further 

information on well venting for liquids unloading, see the Technical Support Document (TSD) 

“Greenhouse Gas Reporting Rule: Technical Support for Revisions and Confidentiality 

Determinations for Petroleum and Natural Gas Systems; Proposed Rule” in Docket ID No. EPAHQ-OAR-2011-0512.

5. Gas Well Completions And Workovers

The EPA is proposing to amend 40 CFR 98.238 to add definitions for “reduced emissions 

completion” and “reduced emissions workover”. Currently, reduced emissions completions and 
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reduced emission workovers are mentioned in the relevant calculation method as equipment that 

separates natural gas from the backflow and sends this natural gas to a flow-line. However, there 

are currently no defined terms for reduced emissions completions and reduced emissions

workovers. The EPA notes that since the time that subpart W was promulgated, the EPA 

promulgated new source performance standards for the oil and natural gas sector under 40 CFR 

Part 60, subpart OOOO, that requires the use of a reduced emissions completion in specified 

circumstances. The EPA proposes to add a definition for “reduced emissions completion” to 

subpart W that would be consistent with the description of that term in the new source 

performance standard rulemaking (see 76 FR 52757-8). Specifically, the EPA is proposing to 

amend 40 CFR 98.238 to define a “reduced emissions completion” as a well completion 

following fracturing where gas flowback that is otherwise vented is captured, cleaned, and routed 

to the flow line or collection system, re-injected into the well or another well, used as an on-site 

fuel source, or used for other useful purpose that a purchased fuel or raw material would serve, 

with no direct release to the atmosphere. We are proposing to amend 40 CFR 98.238 to define a 

“reduced emissions workover” as a well workover with hydraulic fracturing (i.e., refracturing) 

where gas flowback that is otherwise vented is captured, cleaned, and routed to the flow line or 

collection system, re-injected into the well or another well, used as an on-site fuel source, or used 

for other useful purpose that a purchased fuel or raw material would serve, with no direct release 

to the atmosphere. The EPA does not anticipate these definitional changes would impact current 

reporters under Part 98 because these changes are clarifying in nature and do not change any 

requirements of subpart W. 

The EPA is also proposing to amend the definition of “well completions” in 40 CFR 98.6 

to delete the term "re-fracture" as this term applies to an already producing well and is 
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considered a well workover, not a well completion, for the purposes of part 98. This amendment 

is intended to avoid potential confusion concerning whether a re-fracture is a completion or 

workover in the context of subpart W. This change will also better align the existing definition of 

“well completions” with the new proposed definition of a "reduced emissions completion" by 

clarifying that a reduced emission completion only applies to new fractures and that re-fractures 

are potentially covered under the new definition of "reduced emission workover". The definition 

of “well workover” in 40 CFR 98.6 already refers to re-fractures, so no clarifying change is 

needed for that definition.

We are also proposing to revise reporting requirements for completions and workovers to 

differentiate between completions and workovers with different well type combinations in each 

sub-basin category. A well type combination is a unique combination of the following factors: 

vertical or horizontal, with flaring or without flaring, and reduced emission completion/workover 

or not reduced emission completion/workover. Specifically, for well completions and workovers 

with hydraulic fracturing, we are proposing to require separate counts and separate reporting of 

emissions for the different well type combinations. These revisions would improve data quality 

for emissions from wells with hydraulic fracturing. Because the EPA is proposing to expand the 

well type definition for completions and workovers with hydraulic fracturing to include whether 

the well completions/workovers are flared or not, and whether it is a reduced or not reduced 

emission completion/workover, it is possible that reporters will have more than one reporting 

category (i.e., different well types in each sub-basin) for completions and workovers with 

hydraulic fracturing. Therefore, some reporters will be required to further categorize their 

calculated emissions from completions and workovers with hydraulic fracturing, which they did 

not have to do before. We anticipate that these proposed changes will increase burden to some
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reporters somewhat. Reporters will be required to separate and report their calculated emissions 

from completions and workovers without hydraulic fracturing by whether the emissions are 

related to completions or workovers, which they do not have to do under the current version of 

the rule. We anticipate that those proposed changes would only slightly increase burden to 

reporters. 

We are also proposing revisions to Equation W-10A that would add clarity and increase 

the accuracy of emissions calculations for gas well completions and workovers with hydraulic 

fracturing. In the final subpart W rule, the measurement or calculation for determining the ratio 

of flowback during well completions and workovers to 30-day production rate in Equation W10A (40 CFR 98.233(g)) begins immediately upon initiating flowback of a well. Some reporters 

have asserted that the flowback characteristics of a well following hydraulic fracturing do not 

enable measurement or calculation to begin immediately upon initiating flowback due to a lack 

of sufficient gas being present, and the calculation needs to be revised to account for this fact. 

Therefore, the EPA is proposing to modify the calculation to require the measurement of flow 

rate only when sufficient gas is present to enable flow rate measurement. In addition, some 

reporters have asserted that the accuracy of emissions calculations could be affected by the 

combined use of sales gas volume and approximations on flow rates for non-measured wells. To 

resolve this apparent issue, the time variable “Tp” in Equation W-10A and W-10B is being 

modified. Time that the gas is routed to production would no longer be included, so it would no 

longer be necessary to subtract the volume of gas being sent to sales. This amendment would not 

significantly change the reporting burden. The proposed equations are similar in complexity as 

the previous equations and use measurements that are of similar complexity. This proposed 
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revision would improve data quality and provide flexibility by providing an estimation method 

for data that could not likely be measured accurately.

We are also proposing changes to the calculation section at 40 CFR 98.233(g) and (h) to 

support the separate calculation of emissions from completions and workovers that are vented, 

flared, or use equipment that separates natural gas from the backflow and sends this natural gas 

to a flow-line (e.g., reduced emissions completions or reduced emissions workovers). Reporters 

currently calculate emissions from all completion and workover activities, but the equations do 

not facilitate the classification of the activity needed for separate reporting. We are proposing to 

revise Equation W-13 in 40 CFR 98.233(h) to separate the calculation of emissions from 

workovers from the calculation of completions into two equations. This amendment will improve 

data quality. We are also proposing to clarify that reporters must calculate the annual volumetric 

natural gas emissions from each gas well venting during workovers without hydraulic fracturing 

using Equation W-13A and from each gas well venting from completions without hydraulic 

fracturing using new Equation W-13B. We do not anticipate that this proposed change would

significantly increase the reporting burden, because the proposed calculations are the same as the 

current calculation; we only propose to break it into two steps. The proposed methodology also 

requires the addition of parameter “Es,p” for Equation W-13B to specify the annual volumetric 

natural gas emissions in standard cubic feet from well completions. We are also proposing to 

revise 40 CFR 98.233(g)(1) to clarify the number of measurements or calculations that must be 

taken to estimate the average ratio of flowback rate (FRM). 

We are proposing to revise 40 CFR 98.233(g)(2) to clarify that measurements from the 

well flowing pressure upstream of a well choke to calculate well backflow must be collected for 

each sub-basin and well type combination. We are also proposing to revise parameter “PRs,p” in 
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Equations W-10A and W-10B and Equation W-12 to clarify that the first 30 day average 

production flow rate is the average taken after completions of newly drilled gas wells or 

workovers. 

For further information on gas well venting during completions and workovers, see the 

TSD “Greenhouse Gas Reporting Rule: Technical Support for Revisions and Confidentiality 

Determinations for Petroleum and Natural Gas Systems; Proposed Rule” in Docket ID No. EPAHQ-OAR-2011-0512.

6. Blowdown Vents

Based on questions received during implementation of the final subpart W rule and 

reporter concerns, the EPA is proposing to revise Equations W-14A and W-14B to include a 

compressibility term. Specifically, some reporters requested that the EPA allow the use of a 

factor to adjust for compressibility when calculating emissions from blowdown vents. The 

calculation method for blowdown vents included in the existing subpart W rule assumes natural 

gas is an ideal gas with a compressibility factor of 1, and does not include an adjustment for 

compressibility in the calculation. Although the EPA had previously considered including the 

compressibility term (76 FR 56010, September 9, 2011), the EPA ultimately did not propose 

including the factor, because we then concluded that including a compressibility adjustment 

could create a degree of uncertainty between reporters on how their reported blowdown values 

compared (on a volume basis). We noted at that time that although the compressibility of pure 

light hydrocarbon substances is well known, the compressibility of hydrocarbon mixtures is less 

well known and the composition of natural gas throughout the segments covered by subpart W 

can be variable. At that time, we determined that ideal gas law calculations were adequate for 

reporting purposes under Part 98.
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The EPA notes that the circumstances surrounding this issue are now different because, 

as discussed in Section III.B.1 of this preamble, the EPA is proposing to require the use of sitespecific data on gas compositions, if available. In addition, we have determined that at high 

pressures and low temperatures, the accuracy of the emission estimate would be improved if a 

compressibility factor were included in the calculation. The compressibility of methane at 

standard conditions is close to one. However, the compressibility of methane at low temperatures 

and high pressures is lower than one, which may affect the accuracy of the emission calculation 

if not included in that calculation. Therefore, the EPA proposes to revise Equations W-14A and 

W-14B in 40 CFR 98.233(i) to include the compressibility term “Za”. A default compressibility 

term of 1 may be used at conditions where the pressure is below 5 atmospheres, and the 

temperature is above -10 degrees Fahrenheit, or if the compressibility factor at the actual 

temperature and pressure is 0.98 or greater. We are proposing harmonizing changes to Equations 

W-33 and W-34 in 40 CFR 98.233(t) to include the compressibility term “Za” for conversion of 

volumetric emissions at actual conditions to standard conditions. Because it is likely that most 

facilities handle gas within the proposed compressibility factor default ranges, it is unlikely that 

adding this compressibility factor term into the blowdown vent stack calculations will 

significantly increase the reporting burden.

The EPA is also proposing to simplify the reporting for blowdowns. In the final subpart 

W rule, reporters must calculate and record emissions for each blowdown event that is greater 

than or equal to 50 cubic feet of actual volume. Currently, for each piece of equipment (unique 

physical volume) that is blown down more than one time in a calendar year, reports are 

submitted for the total number of blowdowns, the emissions for each unique physical volume, 

and the name or ID number for the unique physical volume. For all equipment that is blown 
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down only once during the calendar year, reports are submitted as an aggregate for all such 

equipment at each facility. Reports include the total number of blowdowns and the emissions 

from all equipment with unique physical volumes that are blown down only once. The volume of 

gas vented is calculated for each blowdown event using the conditions specific to the event. 

However, the reporting of each “unique physical volume” blown down more than once in a year 

may be an extensive list of unique equipment. 

A similar reporting approach was adopted by the EPA in the November 2010 version of

subpart W (75 FR 74458). There, the reporting requirement specified that emissions be reported 

collectively per equipment type. This approach caused some confusion because a list of 

equipment types was not provided. Therefore we are proposing to revise the current reporting 

requirements in 40 CFR 98.236(c)(7) to simplify the reporting structure to report blowdown 

emissions aggregated by seven categories: station piping, pipeline venting, compressors, 

scrubbers/strainers, pig launchers and receivers, emergency shutdowns, and all other blowdowns 

greater than or equal to 50 cubic feet. Although facilities are no longer required to report 

blowdown vent stack emissions by each unique physical volume, facilities still have to calculate 

blowdown vent stack emissions from each unique physical volume and categorize the emissions 

by equipment. Therefore, the EPA has determined that this proposed change would not 

significantly impact burden to reporters. 

The EPA is also proposing an optional calculation method for blowdown emissions for 

situations where a flow meter is in place to measure the emissions directly. If a blowdown vent is 

equipped with a flow meter, there would not be an advantage to calculating the emissions using 

the unique volume, temperature, and pressure conditions of the equipment instead of the directly 

measured flow rate. We are proposing this alternative calculation method in 40 CFR 98.233(i), 
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along with associated reporting requirements in 40 CFR 98.236. We are also proposing 

additional clarifying edits for both the blowdown calculation and reporting sections of the rule. If

a flow meter is in place to measure emissions, the emissions would be reported on a facility 

basis, and would not be aggregated by emission type per 40 CFR 98.236(i)(2). For further 

information on blowdown vents, see the TSD “Greenhouse Gas Reporting Rule: Technical 

Support for Revisions and Confidentiality Determinations for Petroleum and Natural Gas 

Systems; Proposed Rule” in Docket ID No. EPA-HQ-OAR-2011-0512.

7. Onshore Production Storage Tanks

We are proposing to revise the method for estimating emissions from occurrences of well 

pad gas-liquid separator liquid dump valves that are not properly operating for onshore 

production storage tanks. The EPA initiated this revision to address reporter concerns and to 

improve data quality. Specifically, reporters expressed concern with the burden associated with 

quantifying and recording information for all properly functioning dump valves. The proposed 

revisions would require the detection of an anomaly and only then require quantification. Hence 

only those dump valves found to not be closing properly (i.e., stuck dump valves) would have to 

be quantified. Specifically, the EPA is proposing to simplify Equation W-16 to calculate 

emissions for only periods when the dump valve is not closing properly. 

The EPA is also proposing to revise the reporting section to make it clear that facilities 

are to separately report the emissions from onshore production storage tanks attributable to 

periods when dump valves are not closing properly, as opposed to emissions that occur when 

dump valves are closing properly. In the final subpart W rule, 40 CFR 98.236(c)(8)(iv) requires 

that facilities report annual total volumetric GHG emissions that resulted from dump valves that 

are not closing properly. However, Equation W-16 in the final subpart W rule sums the total 
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emissions for periods when the dump valve is closing properly and periods when the dump valve 

is not closing properly. The EPA is clarifying 40 CFR 98.236 to specify that facilities that use 

Equation W-16 should report only emissions that result from dump valves that are not closing 

properly. Note that emissions from atmospheric tanks that are not a result of dump valves not 

closing properly would continue to be reported in this proposed revision outside of Equation W16. There is no significant additional burden to facilities, because reporters already use these data 

elements in Equation W-16: separate tank and dump valve emissions already need to be 

calculated separately, but would now also be reported separately. This revision would eliminate 

potential confusion for reporters, clarify recordkeeping requirements, and improve the ability to 

quantify emissions from stuck dump valves. For further information on emissions from 

improperly functioning dump valves, see the TSD “Greenhouse Gas Reporting Rule: Technical 

Support for Revisions and Confidentiality Determinations for Petroleum and Natural Gas 

Systems; Proposed Rule” in Docket ID No. EPA-HQ-OAR-2011-0512. These proposed 

revisions would improve the quality of data collected.

8. Associated Gas Venting and Flaring

The EPA is proposing to add a term to Equation W-18 (40 CFR 98.233(m)(3)) to account 

for situations where part of the associated gas from a well goes to a sales line while another part 

of the gas is flared or vented. These amendments improve data quality by eliminating duplicate 

reporting. Emissions are currently calculated based on the gas-to-oil ratio (GOR) and volume of 

oil produced during the flaring period. The GOR is based on total gas from the well, which 

means all the gas would currently be reported as flared even though a portion of the gas goes to a 

sales line. The proposed revision to Equation W-18 subtracts the volume of associated gas sent to 

sales from the annual volumetric natural gas emissions from associated gas venting. The EPA 
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has also included in the equation a term (EREp,q) for emissions reported under other sources 

included in this subpart (i.e., tank venting) to avoid double counting of these emissions. The EPA 

also proposes updating the definition of the term GORp,q and the emission result Ea,n in Equation 

W-18 to specify that the gas to oil ratio and the result of the calculation are calculated at standard 

conditions rather than actual conditions. Because the GOR is measured in standard cubic feet, 

this change would harmonize the equation terms and the result of the emission calculation 

equation would be at standard conditions. Although the proposed calculation method modifies 

the current equation to include two new terms, these terms are already being calculated 

elsewhere and/or can be estimated. Therefore, the EPA does not anticipate that this proposed 

change will significantly affect the reporting burden.

The EPA is also proposing to add a definition for the term “Associated gas venting or 

flaring” to clarify what is included in this source. The EPA is proposing to define “Associated 

gas venting or flaring” as “the venting or flaring of natural gas which originates at wellheads that 

also produce hydrocarbon liquids and occurs either in a discrete gaseous phase at the wellhead or 

is released from the liquid hydrocarbon phase by separation. This definition does not include 

venting or flaring resulting from activities that are reported elsewhere, including tank venting, 

well completions, and well workovers.” The proposed definition allows for greater consistency 

with the changes made to the calculation method. This is a clarifying proposed change that 

improves data quality and should not significantly affect the burden to current reporters. For 

further information on emissions from associated gas, see the TSD “Greenhouse Gas Reporting

Rule: Technical Support for Revisions and Confidentiality Determinations for Petroleum and 

Natural Gas Systems; Proposed Rule” in Docket ID No. EPA-HQ-OAR-2011-0512.

9. Flare Stack Emissions
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The EPA is proposing to amend the calculation method for emissions from a flare stack 

to simplify the calculation to standard conditions and to account for gas that is sent to an unlit 

flare. Specifically, we are proposing to revise Equation W-19 and combine Equations W-20, and 

W-21. The EPA also proposes to revise the equations such that the emissions of CH4 and CO2

are calculated in standard conditions. We propose to remove paragraph 40 CFR 98.233(n)(11), 

which specifies estimating emissions for the volume of gas flared under actual conditions. We 

also propose to add the terms “ZU” and “ZL” to Equation W-19 and the terms “ZU” and “ZL” to 

Equation W-20 to account for the fraction of gas sent to an unlit flare and the fraction of gas sent 

to a burning flare. The fraction of feed gas sent to an unlit flare would be determined by using 

engineering estimates and process knowledge. The proposed changes simplify and clarify the 

calculation requirements and would improve the accuracy of the collected data by accounting for 

the fraction of emissions that are not combusted when sent to an unlit flare. 

The EPA is also proposing a revision to the onshore natural gas transmission 

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

and export equipment industry segments to clarify that emissions from any flares in these 

segments must be reported using the calculation method for emissions from a flare stack. This 

clarifying revision is consistent with the treatment of flares in other parts of subpart W and is 

necessary to calculate emissions for compressors routed to flares under the proposed compressor 

calculation requirement modifications. We anticipate that this proposed change may slightly 

increase burden for select reporters and will not significantly affect burden for most reporters; 

however, this clarifying revision is consistent with the treatment of flares in other parts of 

subpart W and is necessary to calculate emissions for compressors routed to flares under the 

proposed compressor calculation requirement modifications.
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10. Centrifugal and Reciprocating Compressors

Some reporters have contended that the current monitoring requirements for compressor 

venting are overly burdensome and present safety and operational process concerns. These 

reporters asserted that it is not practical to require a measurement from each individual 

compressor for groups of compressors that are routed to a common vent manifold (or flare 

header), because this would require the entire group of compressors that are connected to the 

common manifold (or flare header) to be shutdown, blown down, and purged in order to safely 

install meters (or ports for temporary meters) and enable individual measurements. The reporters 

stated that it is extremely rare that entire groups of compressors are shutdown at the same time. 

In the November 2010 response to public comments on the subpart W final rule (Docket ID No. 

EPA-HQ-OAR-2009-0923), the EPA noted that commenters requested that the EPA allow direct 

measurements of common manifolded vent lines on compressors. At least one commenter stated 

that if continuous measurement of manifolded vent lines and aggregate annual emissions

reporting were allowed as an option for measuring compressors, they would be able to safely 

collect and report to the EPA continuously measured data. The EPA did not include this option 

in the 2010 final subpart W rule because it was not clear whether measurements at a common 

vent outlet could be used to correctly characterize annual emissions from individual 

compressors.

In today’s action, we are proposing changes to the centrifugal and reciprocating 

compressor calculation sections (see 40 CFR 98.233(o) and (p)) in order to address reporter

concerns related to measuring centrifugal and reciprocating compressor emissions that are routed 

to a common vent manifold (or flare header). For those compressors, the EPA is proposing an 

option where reporters would take at least three measurements per year and report the average of 
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the measurements. These measurements would need to be taken before emissions are comingled 

with other non-compressor emission sources. This option would address reporter’s safety 

concerns for facilities that need to shut down equipment to install individual meters and maintain 

accurate characterization of annual emissions from compressors at the facility. Annual 

volumetric emissions would be determined for each manifolded group of compressors combined 

for all operating conditions (mode-source combinations). Reporters would still be required to 

report activity data for any individually measured sources (i.e., non-manifolded sources) at the 

compressor level. Activity data reported would include information about the individual 

compressors included in the manifolded vent. This proposed measurement option would allow 

the EPA to correctly characterize and analyze GHG emissions from all compressors at individual 

facilities in the petroleum and natural gas systems source category while potentially reducing 

burden to the industry. Although reporting elements include new activity data, reporters would 

no longer be required to sample manifolded compressor sources individually, thus decreasing 

overall burden and providing flexibility. For example, if a reporter operates seven compressors 

that have their blowdown vent stacks manifolded, the reporter would no longer have to conduct 

seven measurements every year (one for each blowdown vent stack) as required by the current 

rule. Instead, for this example, the reporter would be required to only conduct a measurement 

three times per year on the common vent stack that is associated with the manifolded group of 

seven compressor sources, which would decrease burden for the reporter compared to the seven 

measurements currently required.

The EPA considered requiring only one or two measurements per year for these 

manifolded sources (as opposed to the EPA proposal above for the average of three

measurements). The EPA concluded that the annual process variability for these sources was 
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2014. We have taken steps to ensure the accuracy of this version, but it is not the official version.

high enough to warrant more than one or two measurements per year. Please see the TSD

“Greenhouse Gas Reporting Rule: Technical Support for Revisions and Confidentiality 

Determinations for Petroleum and Natural Gas Systems; Proposed Rule” in Docket ID No. EPAHQ-OAR-2011-0512, for more background and information on the options considered. In 

addition to seeking comment on our proposed option, the EPA is specifically seeking comment 

on the two other options that were considered and other derivations of these options (i.e., four

measurements per year instead of three). Comments should include justification why the specific 

option receiving comment does not negatively impact safety, is technical and economically 

feasible, does not impose undue burden on reporters, and how the option is sufficiently accurate 

given the annual process variability for these sources. 

We are also proposing to include four definitions in 40 CFR 98.238 to support the 

addition of the calculation method for manifolded vents. We are proposing a definition for 

“compressor” to mean “any type of vent or valve (i.e., wet seal, blowdown valve, isolation valve, 

or rod packing) on a centrifugal or reciprocating compressor.” We are proposing a definition for 

“compressor mode” to mean “means the operational and pressurized status of a compressor. For 

a centrifugal compressor, “mode” refers to either operating -mode or not-operating-depressurized 

-mode. For a reciprocating compressor, “mode” refers to either: operating -mode, standbypressurized -mode, or not-operating-depressurized –mode.” We are proposing a definition for 

“manifolded compressor source” to mean “a compressor source that is manifolded to a common 

vent that routes gas from multiple compressors.” We are also proposing a definition of 

“manifolded group of compressor sources” to mean “a collection of any combination of 

compressor sources that are manifolded to a common vent.” 
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In addition, for compressors that are routed to an operational flare, we are proposing to 

allow operators to calculate and report emissions with other flare emissions (in lieu of estimating 

compressor emissions based on knowledge of the total flare emissions and the portion of those 

flare emissions that can be attributed to compressors). This proposed change addresses reporter

concerns, provides flexibility, and potentially decreases burden without affecting data quality. 

Although operators would still be required to report certain compressor-related activity data for 

each compressor that is routed to an operational flare (as provided for in 40 CFR 98.236(o)(1) 

and (p)(1)), reporting emissions from compressors (that are routed to an operational flare) with 

other flare emissions would reduce burden, because reporters would not be required to sample 

compressors individually or be required to portion flare emissions attributed to compressors. 

It was brought to the EPA’s attention that the 3-year cycle requirement for measuring 

compressors in the not-operating-depressurized-mode could present a compliance challenge for 

some facilities, because not every facility schedules routine shutdowns for maintenance within 3 

years. The EPA did not intend for reporters to perform an unscheduled shutdown of a facility for 

the sole purpose of taking a measurement of the compressor in the not-operating-depressurizedmode. Therefore, we are proposing to revise the requirement to measure each compressor in the 

not-operating-depressurized-mode at least once in any 3 consecutive calendar years, provided the 

measurement can be taken during a scheduled shutdown. If there is no scheduled shutdown 

within three consecutive calendar years, the EPA proposes that a measurement must be made at 

the next scheduled depressurized compressor shutdown (for reciprocating compressors, this 

measurement can be taken during the next scheduled shutdown when the compressor rod 

packing is replaced). By allowing the measurement to be taken at these specified scheduled 

shutdowns, operators would not have to plan a shutdown of their equipment to take a 
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measurement of their compressor in the not-operating-depressurized-mode. This proposed

amendment addresses reporters concerns and potentially decreases burden without affecting data 

quality. Even though the “not-operating-depressurized-mode” is measured only at scheduled 

shutdowns (which might be every 3 years or greater), the reporter is still required to conduct an 

annual measurement in whatever mode the compressor is found. Therefore, the frequency in 

measurements is unchanged. The EPA also considered modifying the existing requirement to 

measure each compressor in the not-operating-depressurized-mode at least once every 3 years to 

correspond to a longer term, such as every 5 years. However, such an extension might not 

resolve the issue for all reporters. The EPA is specifically seeking comment on our proposed 

option as well as the additional option that was considered.

The EPA is also clarifying that for reporters that elect to conduct as found leak 

measurements for individual compressor sources, all measurements from a single owner or 

operator may be used when developing an emission factor (using Equation W-24 or W-28 of 40 

CFR 98.233) for each compressor mode-source combination. If the reporter elects to use this 

option, the reporter emission factor must be applied to all reporting facilities for the owner or 

operator. Although this option may make it easier for some reporters to keep track of their 

calculated reporter emission factors, all reporters are still required to calculate reporter emission 

factors if they use the as found leak measurement option. Therefore, the EPA does not anticipate 

that this clarifying edit will significantly affect the reporting burden.

We are also proposing to restructure and revise the centrifugal and reciprocating 

compressor sections (see 40 CFR 98.233(o) and 40 CFR 98.233(p)) in order to improve clarity 

for reporters. Because the restructuring was extensive, entirely new text appears for 40 CFR 

98.233(o) and 40 CFR 98.233(p). Although the proposed restructuring changes would not 
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significantly change any of the requirements or burden, the proposed restructuring and revisions 

would clarify current requirements that are vague or confusing. For example, we are proposing to 

retain the current equations for determining emissions from each compressor’s measured modesource combination and unmeasured mode-source combination; however, we are proposing 

language that would explain when to use the equation(s). We are also proposing revisions to 

improve consistency between the centrifugal and reciprocating compressor sections (see 40 CFR 

98.233(o) and 40 CFR 98.233(p)). For example, we are proposing to revise the equation 

variables to bring consistency between the two sections. It is our view that the restructuring and 

clarification revisions that we are proposing in this action for the centrifugal and reciprocating 

compressor sections would improve readability and usability for both industry and government 

regulators. For further information on measuring emissions from compressors, see the TSD

“Greenhouse Gas Reporting Rule: Technical Support for Revisions and Confidentiality 

Determinations for Petroleum and Natural Gas Systems; Proposed Rule” in Docket ID No. EPAHQ-OAR-2011-0512. 

11. Natural Gas Distribution: Leak Detection Equipment And Emissions From Components

For natural gas distribution, the final subpart W rule requires reporters to calculate a 

facility emission factor for a meter/regulator run per component type at above grade meteringregulating (M-R) stations. The calculation of the emission factor using Equation W-32 in 40 

CFR 98.233(r) based on the results of equipment leak surveys that are required under 40 CFR 

98.233(q) at above grade transmission-distribution (T-D) stations and the subsequent annual 

emissions calculated for those stations using Equations W-30B. Reporters have pointed out that 

the nomenclature and inter-related calculations between 40 CFR 98.233(q) and (r) has caused 

confusion. Therefore, the EPA is proposing to revise the calculation requirements for natural gas 
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distribution facilities and associated terminology in 40 CFR 98.233(q) and (r). Specifically, the 

EPA is proposing to place the facility meter/regulator run emission factor calculation in 40 CFR 

98.233(q) instead of 40 CFR 98.233(r) and clarify that the emission factor is calculated 

separately for CO2 and CH4 and is on a meter/regulator run operational hour basis, instead of on 

a meter/regulator run component basis. Facilities calculate annual emissions from above grade 

transmission-distribution transfer stations using Equation W-30 of 40 CFR 98.233(q). The 

emissions are calculated in Equation W-30 on a per component basis based on equipment leak 

survey results and leaker emission factors for transmission-distribution transfer station 

components listed in Table W-7. The results of the component level annual emissions 

calculations using Equation W-30 are then summed for all component types in Equation W-31 to 

develop the annual facility meter/regulator run emission factors for CO2 and CH4. Those facility 

emission factors must be recalculated annually as additional equipment leak survey data becomes 

available from above grade transmission-distribution transfer stations. To calculate annual 

emissions from above grade metering-regulating stations that are not above grade transmissiondistribution transfer stations, facilities must use the emission factors (calculated in Equation W31) in the annual emissions calculation of Equation W-32B in 40 CFR 98.233(r). Emissions from 

below grade metering-regulating stations, below grade transmission-distribution transfer stations, 

distribution mains, and distribution services are calculated using Equation W-32A of 40 CFR 

98.233(r) using population emission factors listed in Table W-7. These proposed revisions will 

alleviate the current confusion with the calculation and reporting requirements for natural gas 

distribution facilities while capturing the same emissions sources from this industry segment and 

maintaining the same level of data accuracy. Data are generally reported at a less detailed level, 

but there is no change in emissions coverage. 
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12. Onshore Petroleum And Natural Gas Production And Natural Gas Distribution Combustion 

Emissions

The EPA is proposing to clarify that emissions and volume of fuel combusted must be 

reported for all compressor driven internal combustion units in 40 CFR 98.236. The EPA is

proposing to revise this reporting requirement to be consistent with the emission estimation 

methods in 40 CFR 98.233(z)(4) that specify the exemption from reporting emissions for internal 

combustion units with a rated heat input capacity less than or equal to 1 MMBtu/hr (130 

horsepower) does not apply to internal fuel combustion sources that are compressor drivers. 

C. Proposed Revisions to Missing Data Provisions

We are proposing to revise 40 CFR 98.235 to clarify the procedures for estimating 

missing data. We are proposing to increase the specificity regarding how to use, treat, and report 

missing data for each calculation specified in 40 CFR 98.233.These proposed revisions would 

increase clarity for reporters and improve the accuracy of the data reported by ensuring that the 

data substituted for missing values is limited in use, and, where necessary, well-documented and 

quality-assured or based on the best available estimates. To address newly acquired wells, the 

EPA is also proposing missing data procedures specific to facilities that are newly subject to 

subpart W and to existing onshore petroleum and natural gas production facilities that acquire 

wells that were not subject to subpart W prior to the acquisition. In these specific cases, the EPA 

is proposing to allow best engineering estimates for any parameter that cannot be reasonably 

measured or obtained according to the requirements in subpart W for up to six months from the 

first date of subpart W applicability. Where facilities acquired additional wells, only data and 

calculations associated with those newly acquired wells would fall within this proposed 

provision. This proposed revision provides flexibility for newly acquired facilities or wells. 
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Missing data procedures were previously not allowed for many areas of subpart W; however, 

with the proposed removal of BAMM, the missing data procedures provide clarity for reporters 

who may have unintentionally missed required data. 

D. Proposed Amendments to Best Available Monitoring Methods

In order to provide facilities with time to adjust to the requirements of the rule, subpart W 

has provisions allowing the optional use of best available monitoring methods (BAMM) for 

unique or unusual circumstances. Where a facility uses BAMM, it is required to follow emission 

calculations specified by the EPA, but is allowed to use alternative methods for determining 

inputs to calculate emissions. Inputs are the values used by facilities to calculate equation 

outputs. Examples of BAMM include: Monitoring methods used by the facility that do not meet 

the specifications of subpart W, supplier data, engineering calculations, and other company 

records. Facilities are required to receive approval from the EPA prior to using BAMM and these 

facilities are required to specify in their GHG annual reports when BAMM is used for an 

emission source. The EPA has previously noted that the Agency intended to “approve the use of 

BAMM beyond 2011 only in cases that are unique or unusual” (76 FR 59538). Furthermore, the 

EPA limited the approvals of BAMM to one reporting year in keeping with the intent to allow 

use of BAMM as a transitional provision until facilities come into compliance with the final rule. 

While the EPA occasionally uses BAMM for targeted, short-term monitoring flexibilities (i.e.,

provision for reporters who become subject to Part 98 from the recent GWP changes to subpart 

A to have automatic BAMM for the first three months of reporting), no industry-specific subpart 

within Part 98 continues to use the BAMM flexibility except subpart W.

In this action, the EPA is proposing to remove all provisions in 40 CFR 98.234(f) for 

BAMM. We are also proposing to remove and reserve 40 CFR 98.234(g), which is a provision 
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specific to the 2011 and 2012 reporting years. The removal of BAMM will improve data quality 

by requiring consistent reporting for each segment in subpart W. We are proposing these 

amendments because we expect facilities would be able to comply with the monitoring and 

QA/QC methods required under subpart W after this proposed rule is finalized and effective. 

Reporters with issues that were unidentified at the time of the final rule will, by January 1, 2015, 

have had adequate time to resolve these issues. It has been the EPA’s intent throughout 

implementation of subpart W that BAMM be available as a limited, transitional program to serve 

as a bridge to full compliance with the rule for cases where reporters faced reasonable 

impediments to compliance. The EPA never intended to extend BAMM requirements 

indefinitely. The proposed amendments are therefore in keeping with the EPA’s stated intent to 

transition to reporting without BAMM. We also believe, based on several years of experience 

with the industry and these reporting requirements, that facilities have successfully transitioned 

so that they either no longer need to use BAMM or will not need to use BAMM if these 

proposed revisions are finalized.

In a review of BAMM request submittals for the 2014 reporting year, the EPA found that 

the sources with the most frequent BAMM requests included centrifugal compressors, 

reciprocating compressors, blowdown vent stacks, and combustion emissions, which are 

addressed in this rulemaking. The proposed revisions would also resolve the need for BAMM for 

certain facilities for which the final subpart W monitoring requirements were technically 

infeasible. For example, the most common concerns raised in BAMM requests associated with 

technical infeasibility included concerns related to having to shut down a facility to install access 

ports to conduct compressor measurements. As discussed in Section II.B.10 of this preamble, we 

are making revisions that allow the testing of a common vent and that clarify that operators do 
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not have to shut a facility down for the sole purpose to test a compressor in its non-operating 

mode, but that the measurement must be made at the next scheduled shutdown. 

In light of the extended time period in which the EPA has granted BAMM to allow 

facilities to come into compliance with subpart W requirements, the revisions that the EPA is 

proposing to make to the final rule, and the fact that all other industry-specific subparts in Part 98 

no longer have continual BAMM, we expect that facilities would be in compliance with the 

monitoring and QA/QC methods required under subpart W for the 2015 calendar year. 

The EPA requests comment and strong technical evidence for site-specific unique or 

unusual circumstances that would require the use of BAMM after January 1, 2015. These 

comments should include the details of how and why the special circumstances exist, why the 

data collection methods in subpart W (including those in this proposal) are not feasible, the data 

that could not be monitored in order to comply with subpart W, and how specifically the data 

could otherwise be collected. For further information on BAMM, see the TSD “Greenhouse Gas 

Reporting Rule: Technical Support for Revisions and Confidentiality Determinations for 

Petroleum and Natural Gas Systems; Proposed Rule” in Docket ID No. EPA-HQ-OAR-2011-

0512.

III. Proposed Confidentiality Determinations 

A. Overview and Background

In this notice we are proposing confidentiality determinations for new and subtantially 

revised reporting data elements in the proposed amendments, with certain exceptions as 

discussed in more detail below. These new and substantially revised data elements would result 

from the proposed corrections, clarifying, and other amendments that are described in Section II 

of this preamble, which would also result in substantial changes to the data elements that are 
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reported. We are also proposing to revise the confidentiality determination for one existing data 

element that is not being amended, as discussed in Section III.B of this preamble. The final 

confidentiality determinations the EPA has previously made for the remainder of the subpart W 

data elements are unaffected by the proposed amendments and continue to apply. For 

information on confidentiality determinations for the GHGRP and subpart W data elements, see: 

75 FR 39094, July 7, 2010; 76 FR 30782, May 26, 2011; 77 FR 48072, August 13, 2012; and 78 

FR 55994, September 11, 2013. These proposed confidentiality determinations would be 

finalized after considering public comment. The EPA plans to finalize these determinations at the 

same time the proposed rule amendments described in this action are finalized. 

B. Approach to Proposed CBI Determinations for New or Revised Subpart W Data Elements 

For the proposed new and substantially revised data elements, except for the specific data 

elements separately addressed below, we are applying the same approach as previously used for 

making confidentiality determinations for data elements reported under the GHGRP. In the 

“Confidentiality Determinations for Data Required Under the Mandatory Greenhouse Gas 

Reporting Rule and Amendments to Special Rules Governing Certain Information Obtained 

Under the Clean Air Act” (hereinafter referred to as “2011 Final CBI Rule”)(76 FR 30782, May 

26, 2011), the EPA grouped Part 98 data elements into 22 data categories (11 direct emitter data 

categories and 11 supplier data categories) with each of the 22 data categories containing data 

elements that are similar in type or characteristics. The EPA then made categorical 

confidentiality determinations for eight direct emitter data categories and eight supplier data 

categories and applied the categorical confidentiality determination to all data elements assigned 

to the category. Of these data categories with categorical determinations, the EPA determined 

that four direct emitter data categories are comprised of those data elements that meet the 
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definition of “emissions data,” as defined at 40 CFR 2.301(a), and that, therefore, are not entitled 

to confidential treatment under section 114(c) of the CAA.

1 The EPA determined that the other 

four direct emitter data categories and the eight supplier data categories do not meet the 

definition of “emission data.” For these data categories that are determined not to be emission 

data, the EPA determined categorically that data in three direct emitter data categories and five 

supplier data categories are eligible for confidential treatment as CBI, and that the data in one 

direct emitter data category and three supplier data categories are ineligible for confidential

treatment as CBI. For two direct emitter data categories, “Unit/Process ‘Static’ Characteristics 

that Are Not Inputs to Emission Equations” and “Unit/Process Operating Characteristics that Are 

Not Inputs to Emission Equations,” and three supplier data categories, GHGs Reported,” 

“Production/Throughput Quantities and Composition,” and “Unit/Process Operating 

Characteristics,” the EPA determined in the 2011 Final CBI Rule that the data elements assigned 

to those categories are not emission data, but the EPA did not make categorical CBI 

determinations for them. Rather, the EPA made CBI determinations for each individual data 

element included in those categories on a case-by-case basis taking into consideration the criteria 

in 40 CFR 2.208. No final confidentiality determination was made for the inputs to emission 

equation data category (a direct emitter data category).

For this rulemaking, we are proposing to assign 243 new or revised data elements to the 

appropriate direct emitter data categories created in the 2011 Final CBI Rule based on the type 

and characteristics of each data element. Note that subpart W is a direct emitter source category, 

thus, no data are assigned to any supplier data categories. 

 1 Direct emitter data categories that meet the definition of “emission data” in 40 CFR 2.301(a) are Facility and Unit 

Identifier Information, Emissions, Calculation Methodology and Methodological Tier, Data Elements Reported for 

Periods of Missing Data that are not Inputs to Emission Equations, and Inputs to Emission Equations.
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For data elements the EPA has assigned in this proposed action to a direct emitter 

category with a categorical determination, the EPA is proposing that the categorical 

determination for the category be applied to the proposed new or revised data element. For the 

proposed categorical assignment of the data elements in these eight categories with categorical 

determinations, see Memorandum Data Category Assignments and Confidentiality 

Determinations for all Data Elements (excluding inputs to emission equations) in the Proposed 

‘Technical Revisions and Confidentiality Determinations for Petroleum and Natural Gas 

Systems’” in Docket ID No. EPA-HQ-OAR-2011-0512.

For data elements assigned to the “Unit/Process ‘Static’ Characteristics that Are Not 

Inputs to Emission Equations” and “Unit/Process Operating Characteristics that Are Not Inputs 

to Emission Equations,” we are proposing confidentiality determinations on a case-by-case basis 

taking into consideration the criteria in 40 CFR 2.208, consistent with the approach used for data 

elements previously assigned to these two data categories. For the proposed categorical 

assignment of these data elements, see Memorandum Data Category Assignments and 

Confidentiality Determinations for all Data Elements (excluding inputs to emission equations) in 

the Proposed ‘Technical Revisions and Confidentiality Determinations for Petroleum and 

Natural Gas Systems’” in Docket ID No. EPA-HQ-OAR-2011-0512. For the results of our caseby-case evaluation of these data elements, see Sections III.C and III.D of this preamble. 

For the reasons stated below, we are proposing individual confidentiality deteminations 

for 11 new or substantially revised data elements without making a data category assignment. In 

the 2011 Final CBI rule, although the EPA grouped similar data into categories and made 

categorical confidentiality determinations for a number of data categories, the EPA also 

recognized that similar data elements may not always have the same confidentiality status, in 
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which case the EPA made individual instead of categorical determinations for the data elements 

within such data categories.2 Similarly, while the 11 proposed new or substantiually revised data 

elements are similar in type or certain characteristics to data elements previously assigned to the 

“Production/Throughput Data Not Used as Input” and “Raw Materials Consumed that are Not 

Inputs to Emission Equations” data categories, we do not believe that they share the same 

confidentiality status as the non-subpart W data elements already assigned to those two data 

categories, which the EPA has determined categorically to be CBI based on the data elements 

assigned to those categories at the time of the 2011 Final CBI Rule. As discussed in more detail 

below, our review showed that these 11 subpart W production and throughput-related data 

elements fail to qualify for confidential treatment. Therefore, we do not believe that the 

categorical determinations for the “Production/Throughput Data Not Used as Input” and “Raw 

Materials Consumed that are Not Inputs to Emission Equations” data categories are appropriate 

for these 11 data elements; accordingly, these data elements should not be assigned to these data 

categories. Not assigning these 11 data elements to these two data categories would also leave 

unaffected the existing categorical determinations for these data categories, which remain valid 

and applicable to the data elements assigned to those data categories. For the reasons stated 

above, we are proposing individual confidentiality determinations for these 11 data elements 

without making categorical assignment. 

Our proposed individual determinations follow the same two-step evaluation process as 

set forth in the 2011 Final CBI Rule and subsequent confidentiality determinations for Part 98 

data. Specifically, we first determined whether the data element meets the definition of emission 

data in 40 CFR 2.301(a). Data elements that meet the definition of emission data are required to 

 2 In the 2011 Final CBI rule, several data categories include both CBI and non-CBI data elements. See 76 FR 30786.
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be released under section 114 of the Clean Air Act. For data elements found to not meet the 

definition of emission data, we evaluated whether a data element meets the criteria in 40 CFR 

2.208 for confidential treatment. In particular, we focus on: (1) whether the data are already 

public; and (2) whether “. . . disclosure of the information is likely to cause substantial harm to 

the business’s competitive position.” For the results of our case-by-case evaluation of these 

proposed new subpart W data elements, see Section III.D of this preamble.

We are also proposing to revise the confidentiality determinations for one existing 

subpart W data element. Our review of the 11 proposed data elements discussed above led us to 

re-examine our previous determination for this data element, which is similar in type or 

characteristics to the 11 proposed data elements for which the EPA is choosing to make case-bycase determinations. This one data element is the only subpart W data element currently assigned 

to “Production/Throughput Data Not Used as Input” data category. As discussed in more detail 

in Section III.D of this preamble, our review showed that this data element fails to qualify for 

confidential treatment. For the same reasons set forth above for not proposing categorical 

assignments for the 11 data elements, we are proposing to remove this data element’s current 

category assignment, as well as the application of the categorical CBI determination to this data 

element. Instead, we are re-proposing a confidentiality determination based on the two-step 

process discussed above for the proposed 11 new data elements. For the results of our case-bycase evaluation of the proposed subpart W data elements, see Section III.D of this preamble.

We are proposing to assign 40 new or substantially revised data elements used to 

calculate GHG emissions in subpart W to the “Input to Emission Equation” data category. To 

date, the EPA has not made confidentiality determinations for any data element, including any 

subpart W data element, assigned to the “Inputs to Emission Equation” data category. We are 
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therefore not proposing confidentiality determinations for the 40 proposed new or substantially 

revised inputs to emission equations data elements. However, due to concerns expressed by 

reporters with the potential release of inputs to emission equations, we previously established a 

process for evaluating “inputs to emission equation” data elements to identify potential 

disclosure concerns and actions to address such concerns if appropriate.

3 The EPA has used this 

process to evaluate inputs to emission equations, including the subpart W data elements that are 

already assigned to the inputs to emission equations data category.

4 We performed a similar 

evaluation for the 40 proposed new and substantially revised subapart W inputs to emission 

equations and did not identify any potential disclosure concerns. Accordingly, the proposal 

would require reporting of these data elements by March 31, 2016, which is the reporting 

deadline for the 2015 reporting year. For the list of new and revised subpart W inputs to emission 

equations and the results of our evaluation, see memorandum titled “Review for Potential 

Disclosure Concerns for Proposed New Inputs to Emission Equations in the Proposed ‘Revisions

and Confidentiality Determinations for Petroleum and Natural Gas Systems’” in Docket ID No. 

EPA-HQ-OAR-2011-0512.

The proposed amendments include revisions a number of subpart W data reporting 

elements for which confidentiality determinations were previously finalized in the August 13, 

2012 “Final Confidentiality Determinations for Regulations Under the Mandatory Reporting of 

Greenhouse Gases Rule” (77 FR 48072). The proposed revisions relative to some of these data 

 3 See the “Change to the Reporting Date for Certain Data Elements Required Under the Mandatory Reporting of 

Greenhouse Gases Rule” (hereinafter referred to as the “Final Deferral Notice”) (76 FR 53057, August 25, 2011) 

and the accompanying memorandum entitled ”Process for Evaluating and Potentially Amending Part 98 Inputs to 

Emission Equations” (Docket ID EPA–HQ–OAR–2010–0929). 4 See the memoranda titled “Summary of Data Collected to Support Determination of Public Availability of Inputs 

to Emission Equations for which Reporting was Deferred to March 31, 2015” and “Evaluation of Competitive Harm 

from Disclosure of Inputs to Equations Data Elements Deferred to March 31, 2015.” (Docket ID EPA–HQ–OAR–

2010–0929).
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reporting elements would not require different or additional data to be reported under these data 

elements. The proposed revisions include a reorganization of the reporting requirements so that 

the data elements more close align with the calculation methodologies. This reorganization of the 

reporting section would result in changes to many of the rule citations for data elements. In 

addition to re-structuring the reporting section, the EPA has proposed other minor revisions 

designed to clarify the existing reporting requirements. For example, some of the proposed 

changes would clarify the source type (e.g., natural gas pneumatic device venting, acid gas 

removal vents, etc.) and industry segment that is required to report the data element. The 

proposed revisions also include corrections of typographical and other clerical errors. These 

corrections would not change the data to be reported. Although the proposed revisions would 

separate the requirements into a larger number of discrete reporting elements and would clarify 

and correct typographical errors, they would not change the underlying data elements to be 

reported for many data elements. Therefore, the confidentiality determinations finalized in the 

August 13, 2012 rule continue to apply. We are therefore not proposing revisions to the existing

confidentially determinations for the data reporting elements that either would not require 

different or additional data to be reported under the proposed revisions or the proposed revisions 

would not change the underlying data elements to be reported. For a summary of the proposed 

reporting requirements for subpart W that incorporate these changes to data organization and 

descriptions, see the memo, “Proposed Revisions to the Subpart W Reporting Requirements” in 

Docket ID No. EPA-HQ-OAR-2011-0512.

C. Proposed Confidentiality Determinations for Data Elements Assigned to the “Unit/Process 

‘Static’ Characteristics That Are Not Inputs to Emission Equations” and “Unit/Process Operating 

Characteristics That Are Not Inputs to Emission Equations” Data Categories
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The EPA is proposing to assign 101 proposed new or substantially revised data elements 

for subpart W to the “Unit/Process ‘Operating’ Characteristics That Are Not Inputs to Emission 

Equations” data category or the “Unit/Process ‘Static’ Characteristics That Are Not Inputs to 

Emission Equations” data category, because the proposed new or substantially revised data 

elements share the same characteristics as the other data elements previously assigned to the 

category. We are proposing confidentiality determinations for these proposed new or 

substantially revised data elements based on the approach set forth in the 2011 Final CBI Rule 

for data elements assigned to these two data categories. In that rule, the EPA determined 

categorically that data elements assigned to these two data categories do not meet the definition 

of emission data in 40 CFR 2.301(a); the EPA then made individual, instead of categorical, 

confidentiality determinations for these data elements.

As with all other data elements assigned to these two categories, the proposed new or 

substantially revised data elements do not meet the definition of emissions data in 40 CFR 

2.301(a). The EPA then considered the confidentiality criteria at 40 CFR 2.208 in making our 

proposed confidentiality determinations. Specifically, we focused on whether the data are 

already publicly available from other sources and, if not, whether disclosure of the data is likely 

to cause substantial harm to the business’ competitive position. Table 2 of this preamble lists the

data elements the EPA proposes to assign to the “Unit/Process ‘Operating’ Characteristics That 

Are Not Inputs to Emission Equations” and “Unit/Process ‘Static’ Characteristics That Are Not 

Inputs to Emission Equations” data categories, the proposed confidentiality determination for 

each data element, and our rationale for each determination. 
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Table 2. Proposed New Data Elements Assigned to the “Unit/Process ‘Operating’ 

Characteristics That Are Not Inputs to Emission Equations” and “Unit/Process ‘Static’ 

Characteristics That Are Not Inputs to Emission Equations” Data Categories 

Citation Data Element

Proposed Confidentiality Determination 

and Rationale

Unit/Process ‘Operating’ Characteristics That Are Not Inputs to Emission Equations” Data Category

98.236(d)(1)(iv) Whether any CO2 emissions are 

recovered and transferred outside 

the facility.

This proposed data element would be 

reported by onshore petroleum and natural 

gas production facilities and by onshore 

natural gas processing plants. This data 

element indicates that a facility is operating 

an acid gas removal unit and indicates how 

the facility handles the CO2 emissions it 

generates. Acid gas removal units are used to 

remove carbon dioxide and hydrogen sulfide 

from raw natural gas streams and are

commonly found at gas processing facilities. 

These units are listed in a facility’s 

construction and operating permits, which 

are publicly available. Because this 

information is routinely available through 

required permits, we propose these data 

elements be designated as "not CBI.”

98.236(e)(1)(xvii) For each absorbent dehydrator, 

whether any dehydrator 

emissions are vented to the 

atmosphere without being routed 

to a flare or regenerator firebox.

These proposed data elements would be 

reported by onshore petroleum and natural 

gas production facilities and by onshore 

natural gas processing plants. These data 

elements indicate that a facility is equipped 

with dehydration units, the number of 

dehydrators used, the design of dehydrator 

used (glycol or desiccant), and how 

emissions from dehydration units are 

handled by the facility. Dehydration units 

are used to remove water from natural gas 

streams. Most natural gas processing 

facilities are equipped with these units and 

because they are a source of hazardous air 

pollutants, these units are subject to rigorous 

emissions control requirements (e.g., 40 

CFR part 63, subpart HH). Dehydration 

units and their associated control devices are 

listed in a facility’s construction and 

operating permits, which are publicly 

available. For this reason, we propose these 

data elements be designated as "not CBI" for 

both onshore production and natural gas 

processing plants.

98.236(e)(2)(i) For glycol dehydrators with an 

annual average daily natural gas 

throughput less than 0.4 MMscfd, 

the total number of dehydrators 

at the facility.

98.236(e)(2)(ii) For glycol dehydrators with an 

annual average daily natural gas 

throughput less than 0.4 MMscfd, 

the total number of dehydrators 

venting to a vapor recovery 

device.

98.236(e)(2)(iii) For glycol dehydrators with an 

annual average daily natural gas 

throughput less than 0.4 MMscfd, 

the number of dehydrators 

venting to a control device other 

than a vapor recovery device or a 

flare or regenerator firebox/fire 

tubes.

98.236(e)(2)(iv) For glycol dehydrators with an 

annual average daily natural gas 

throughput less than 0.4 MMscfd, 
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Proposed Confidentiality Determination 

and Rationale

whether any glycol dehydrator 

emissions are vented to a flare or 

regenerator firebox/fire tubes.

98.236(e)(2)(iv)(A) For glycol dehydrators with an 

annual average daily natural gas 

throughput less than 0.4 MMscfd 

and vented to a flare or 

regenerator firebox, the total 

number of dehydrators

98.236(e)(3)(i) For dehydrators that use 

desiccant, the total number of 

dehydrators at the facility.

98.236(e)(3)(i) For dehydrators that use 

desiccant, whether any 

dehydrator emissions are vented 

to a vapor recovery device.

98.236(e)(3)(i) For dehydrators that use 

desiccant, the total number of 

dehydrators venting to a vapor 

recovery device.

98.236(e)(3)(i) For dehydrators that use 

desiccant, whether any 

dehydrator emissions are vented 

to a control device other than a 

vapor recovery device or a flare 

or regenerator firebox/fire tubes, 

and the control device type.

98.236(e)(3)(i) For dehydrators that use 

desiccant, whether any 

dehydrator emissions are vented 

to a control device other than a 

vapor recovery device or a flare 

or regenerator firebox/fire tubes.

98.236(e)(3)(i) For dehydrators that use 

desiccant, the number of 

dehydrators venting to a control 

device other than a vapor 

recovery device or a flare or 

regenerator firebox/fire tubes.

98.236(e)(3)(i) For dehydrators that use 

desiccant, whether any glycol 

dehydrator emissions are vented 

to a flare or regenerator 

firebox/fire tubes.

98.236(e)(3)(i) For dehydrators that use 

desiccant and vent to a flare or 

regenerator firebox, the total 

number of dehydrators.
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Proposed Confidentiality Determination 

and Rationale

98.236(f) Liquids unloading. You must 

indicate whether well venting for 

liquids unloading occurs at your 

facility

These proposed data element would be 

reported by onshore petroleum and natural 

gas production facilities. Liquid unloading is 

conducted in mature gas wells that have an 

accumulation of liquids which impede the 

steady flow of natural gas. This is a common 

occurrence in reservoirs where the pressure 

is depleted and liquids enter the well bore. 

The fact that liquids unloading occurs and 

the number of unloading wells with and 

without plungers vented to the atmosphere 

indicate that the wells in a basin are older 

and may indicate changes in production 

rates. However, the age and production rates 

for wells are information that can be derived 

from or are already available to the public 

through state oil and gas commissions. 

Hence, this information is routinely publicly 

available, so we propose these data elements 

be designated as "not CBI."

98.236(f)(1)(iv) For each Sub-basin and well 

tubing diameter and pressure 

group for which you used 

Calculation Method 1 (reported 

separately for wells with plunger 

lifts and wells without plunger 

lifts), the count of wells vented to 

the atmosphere for this grouping.

98.236(g) Whether the facility had any gas 

well completions or workovers 

with hydraulic fracturing in the 

calendar year.

These proposed data elements would be 

reported by onshore petroleum and natural 

gas production facilities and provide 

information on whether the facility 

conducted any well completions or 

workovers during the reporting year, and for 

those facilities that had well completions 

and/or workovers, the number of 

completions and workovers that were 

completed. Information on the number of 

completions and workovers performed by an 

oil and gas operator in a given year and the 

age and production rates for wells can be 

derived from or is available publicly on state 

oil and gas commission Web sites. Because

disclosure of these data elements would not 

be likely to cause substantial competitive 

harm, we propose these data elements be 

designated as "not CBI.”

98.236(g)(3) For each completion or workover 

and well type combination, the 

total number of completions or 

workovers.

98.236(h)(1) You must indicate whether the 

facility had any gas well 

completions without hydraulic 

fracturing or any gas well 

workovers without hydraulic 

fracturing, and if the activities 

occurred with or without flaring.

This proposed data element would be 

reported by onshore petroleum and natural 

gas production facilities and provides 

information on whether the facility 

conducted any well completions or 

workovers during the reporting year and 

whether the emissions were flared. 

Information on completions and workovers

performed in a given year and the age and 
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and Rationale

production rates for wells can be derived 

from or is available publicly on state oil and 

gas commission Web sites and from the

Energy Information Administration (EIA). 

Whether the emissions from well 

completions and workovers are sent to a 

flare provides only information about how 

the emissions are handled by the facility, 

which is not considered to be sensitive 

information by the industry. Because 

disclosure of these data elements would not 

be likely to cause substantial competitive 

harm, we propose these data elements be 

designated as "not CBI.”

98.236(h)(1)(ii) For each sub-basin with gas well 

completions without hydraulic 

fracturing and without flaring, 

the number of completions that 

vented gas to the atmosphere.

These proposed data elements would be 

reported by onshore petroleum and natural 

gas production facilities and provide 

information on the number of completions 

where gas is vented to the atmosphere and 

the number of completions where the gas is 

vented to a flare. The number of completions 

that vent gas directly to the atmosphere and 

the number of completions that send the gas 

to a flare provides only information about 

the number of well completions that were 

performed in a sub-basin during a reporting 

year and how the emissions are handled by 

the facility. The number of completions 

performed each year is available publicly on 

state oil and gas commission Web sites and

from the EIA. Thus, disclosure of these data 

elements would not be likely to cause 

substantial competitive harm and we propose 

these data elements be designated as "not 

CBI."

98.236(h)(2)(ii) For each sub-basin with gas well 

completions without hydraulic 

fracturing with flaring, the 

number of well completions that 

flared gas.

98.236(h)(1)(iv) Average daily gas production rate 

for all completions without 

hydraulic fracturing in the subbasin without flaring, in standard 

cubic feet per hour (average of all 

“Vp” as used in Equation W13B).

This proposed data element would be 

reported by onshore petroleum and natural 

gas production facilities. This data element 

potentially provides information about the 

productivity of wells where hydraulic 

fracturing is not conducted and the emissions 

are not flared. Because production data for 

individual production wells are publicly 

available, the average daily production for 

all wells in a basin presents no information 

that is not already publicly available. 

Because disclosure of this data element 

would not be likely to cause substantial 
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Citation Data Element

Proposed Confidentiality Determination 

and Rationale

competitive harm, we propose this data 

element be designated as "not CBI."

98.236(h)(2)(iii) Total number of hours that gas 

vented to a flare during backflow 

for all completions in the subbasin category (sum of all “Tp” 

for completions that vented to a 

flare as used in Equation W13B).

This proposed data element would be 

reported by onshore petroleum and natural 

gas production facilities and potentially 

provides information on the time spent on 

well completions. Information specific to 

exploratory wells is generally considered 

proprietary information by the industry. 

However, by reporting this data as the total 

for all completed wells in a sub-basin 

category, data for individual wells would not 

be disclosed because of the large number of 

wells per sub-basin category. Because 

disclosure of this data element would not be 

likely to cause substantial competitive harm, 

we propose this data element be designated 

as "not CBI.”

98.236(h)(2)(iv) Average daily gas production rate 

for all completions without 

hydraulic fracturing in the subbasin with flaring, in standard 

cubic feet per hour (the average 

of all “Vp” from Equation W13B).

This proposed data element would be 

reported by onshore petroleum and natural 

gas production facilities. This data element 

potentially provides information about the 

productivity of wells where hydraulic 

fracturing is not conducted and the emissions 

are flared. Because production data for 

individual production wells are publicly 

available, the average daily production for 

all wells in a basin presents no information 

that is not already publicly available. 

Because disclosure of this data element 

would not be likely to cause substantial 

competitive harm, we propose this data 

element be designated as "not CBI."

98.236(i)(1)(i) Total number of blowdowns in 

the calendar year for the 

equipment type (sum equation 

variable “N” from Equation W14A or Equation W-14B of this 

subpart for all unique physical 

volumes for the equipment type).

This proposed data element would be 

reported by the onshore petroleum and 

natural gas production, onshore natural gas 

processing, onshore natural gas transmission 

compression, and LNG import and export 

facilities. Blowdowns occur when equipment 

is taken out of service, either to be placed on 

standby or for maintenance purposes, and 

the natural gas in the equipment is typically 

released to the atmosphere. This practice 

may occur as part of a routine scheduled 

maintenance or as the result of an unplanned event (e.g., equipment breakdown). 

Although blowdown events may be 
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Proposed Confidentiality Determination 

and Rationale

associated with periods of reduced 

production or throughput, natural gas 

processing plants and LNG import/export 

facilities typically have backup units that can 

be used to avoid production shutdowns.

Hence, the number of blowdown events that 

occur during a reporting year does not 

indicate a plant was shut down and would 

not provide any potentially sensitive 

information on the impact of such events on 

a facility’s production or throughput. Hence, 

the disclosure of the number of blowdowns 

occurring during a reporting year is not 

likely to cause substantial competitive harm. 

For this reason, we propose that this data 

element be designated “not CBI” when 

reported by onshore natural gas processing 

plants and LNG import/export facilities. 

These proposed data elements would also be 

reported by the natural gas transmission 

compression sector. Companies operating in 

this sector are subject to regulatory oversight 

by the Federal Energy Regulatory 

Commission (FERC), state utility 

commissions, and other federal agencies 

because they operate in an industry that is 

inherently uncompetitive. FERC controls 

pricing, sets rules for business practices, has 

the power to impose conditions on mergers 

and acquisitions, and has the sole 

responsibility for authorizing the location, 

construction and operations of companies 

operating in this sector. The rate charged for 

transporting gas is regulated. Hence the 

tightly regulated natural gas transmission 

sector is inherently less competitive than 

other industries. Because disclosure of the 

number of blowdowns occurring during a 

reporting year would not be likely to cause 

substantive competitive harm, we propose 

this data element be designated as "not CBI" 

when reported by the natural gas 

transmission sector.

98.236(j) You must indicate whether your 

facility sends produced oil to 

atmospheric tanks.

This proposed data element would be 

reported by onshore petroleum and natural 

gas production facilities and indicates only 

that a facility is equipped with atmospheric 
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Proposed Confidentiality Determination 

and Rationale

storage tanks. Atmospheric storage tanks are 

used to store hydrocarbon liquids from 

separators or production wells. Atmospheric 

tanks are a typical part of onshore 

production facilities and are listed in each 

facility’s construction and operating permits, 

which have to be reissued when 

modifications are made to the facility. 

Hence, disclosure of this data element would 

not be likely to cause substantial competitive 

harm and we propose that this data element 

be designated as "not CBI." 

98.236(j) If any of the atmospheric tanks 

are observed to have 

malfunctioning dump valves, 

indicate that dump valves were 

malfunctioning.

These proposed data elements would be 

reported by onshore petroleum and natural 

gas production facilities and provide 

information on malfunctioning of dump 

valves on gas-liquid separators. Separators 

are used to separate hydrocarbons into liquid 

and gas phases and are typically connected 

to atmospheric storage tanks where the 

hydrocarbon liquids are stored. Dump valves 

on separators periodically release liquids 

from the separator. The time period during 

which a dump valve is malfunctioning 

provides little insight into maintenance 

practices or the nature or cost of repairs that 

are needed. Therefore, this information 

would not be likely to cause substantial 

competitive harm to reporters. For this 

reason, we are proposing these data elements 

be designated as “not CBI.”

98.236(j)(3)(ii) If any of the gas-liquid separator 

liquid dump valves did not close 

properly during the reporting 

year, the total time, in hours, the 

dump valves on gas-liquid 

separators did not close properly

(“Tn” in equation W-16).

98.236(k)(1)(iii) For each transmission storage 

tank vent stack, indicate whether 

scrubber dump valve leakage is 

occurring for the underground 

storage vent.

These proposed data elements would be 

reported by the onshore natural gas 

transmission compression sector. Companies 

operating in this sector are subject to 

regulatory oversight by FERC, state utility 

commissions, and other federal agencies 

because they operate in an industry that is 

inherently uncompetitive. FERC controls 

pricing, sets rules for business practices, has 

the power to impose conditions on mergers 

and acquisitions, and has the sole 

responsibility for authorizing the location, 

construction and operations of companies 

operating in this sector. The rate charged for 

transporting gas is regulated. Hence the 

natural gas transmission sector is inherently 

less competitive than other industries and 

98.236(k)(1)(iv) For each transmission storage 

tank vent stack, indicate if there 

is a flare attached to the vent 

stack.
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and Rationale

there is little incentive to build additional 

pipelines and compressor stations within the 

same corridors as existing transmission lines. 

Because disclosure of these data elements 

would not be likely to cause substantive 

competitive harm, we propose these data 

elements be designated as "not CBI.”

98.236(l)(1)(iv) If oil well testing is performed 

where emissions are not vented 

to a flare, the average flow rate in 

barrels of oil per day for well(s) 

tested.

This proposed data element would be 

reported by onshore petroleum and natural 

gas production facilities. These data 

elements provide information on the oil flow 

and gas production rates of wells. Oil and 

gas production data for individual wells are 

publicly available. Because production data 

for individual production wells are publicly 

available, the average of all wells tested 

presents no information that is not already 

publicly available. Because disclosure of 

these data elements would not be likely to 

cause substantial competitive harm, we 

propose these data element be designated as 

"not CBI."

98.236(l)(2)(iv) If oil well testing is performed 

where emissions are vented to a 

flare, the average flow rate in 

barrels of oil per day for well(s) 

tested.

98.236(l)(3)(iii) If gas well testing is performed 

where emissions are not vented 

to a flare, the average annual 

production rate in actual cubic 

feet per day for well(s) tested.

98.236(l)(4)(iii) If gas well testing is performed 

where emissions are vented to a 

flare, the average annual 

production rate in actual cubic 

feet per day for well(s) tested.

98.236(m) You must indicate whether any 

associated gas was vented or 

flared during the reporting year.

These proposed data elements would be 

reported by onshore petroleum and natural 

gas production facilities and indicate 

whether associated gas is flared or vented 

directly to the atmosphere. Information on 

how emissions are handled does not provide 

any insight into the operation of the emission 

source. Therefore, disclosure of these data 

elements would be unlikely to cause 

competitive harm. For this reason, we are 

proposing these data elements be designated 

as “not CBI.”

98.236(m)(2) For each sub-basin, indicate 

whether any associated gas was 

vented without flaring.

98.236(m)(3) For each sub-basin, indicate 

whether any associated gas was 

flared.

98.236(m)(5) For each sub-basin, the volume 

of oil produced during time 

periods in which associated gas 

was vented or flared (barrels).

These proposed data elements would be 

reported by onshore petroleum and natural 

gas production facilities and provide 

production related information during 

periods when associated gas is vented or 

flared. Associated gas is vented or flared 

when it is not being captured for sales. Oil 

and gas production data for individual 

production wells are publicly available, By 

98.236(m)(6) For each sub-basin, the total 

volume of associated gas sent to 

sales during time periods in 

which associated gas was vented 

or flared (scf).
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reporting this data as total for all production 

wells in a sub-basin category, no data for 

individual wells is disclosed that is not 

already publicly available. Because

disclosure of these data elements would not 

be likely to cause substantial competitive 

harm, we propose they be designated as "not 

CBI."

98.236(o)(1)(xvi) Date of last maintenance 

shutdown that the compressor 

was depressurized.

These proposed data elements would be 

reported by onshore petroleum and natural 

gas production facilities, onshore natural gas 

processing plants, LNG import/export 

terminals, natural gas transmission 

compression, underground natural gas 

storage facilities, and LNG storage facilities. 

These data elements provide information 

about the operation and maintenance of 

centrifugal compressors. Centrifugal 

compressors are used to move gas at high 

pressure through pipelines and are standard 

equipment found at all types of natural gas 

facilities. Facilities typically have backup 

compressors to allow operations to continue 

without interruption during periods of 

maintenance and repair. Hence, the 

percentage of time a compressor was 

operational and the date of last maintenance 

shutdown would be not likely to cause 

substantial competitive harm to any type of 

natural gas facility. For these reasons, we 

propose these data elements be designated as 

"not CBI.”

98.236(o)(2)(viii) If the emission vent is routed to 

flare, combustion, or vapor 

recovery, report the percentage of 

time that the respective device 

was operational.

98.236(p)(1)(xvi) Date of last maintenance 

shutdown for rod packing 

replacement.

These proposed data elements would be 

reported by onshore petroleum and natural 

gas production facilities, onshore natural gas 

processing plants, LNG import/export 

terminals, natural gas transmission 

compression, underground natural gas 

storage facilities, and LNG storage facilities. 

These data elements provide information 

about the operation and maintenance of 

reciprocating compressors. Reciprocating 

compressors are used to move gas at high 

pressure through pipelines and are standard 

equipment found at all types of natural gas 

facilities. Facilities typically have backup 

compressors to allow operations to continue 

without interruption during periods of 

98.236(p)(2)(viii) If the emission vent is routed to 

flare, combustion, or vapor 

recovery, report the percentage of 

time that the respective device 

was operational.
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compressor maintenance and repair. Hence, 

the percentage of time a compressor is 

operational and date of last maintenance 

shutdown would be not likely to cause 

substantial competitive harm to any type of 

natural gas facility. For these reasons, we 

propose these data elements be designated as 

"not CBI.”

98.236(q)(2)(iii) Average time the surveyed 

components were found leaking 

and operational, in hours 

(average of Tp,z in Equation W-30 

of this subpart).

This proposed data element would provide 

information on the amount of time 

operational components were found to be 

leaking. This information would provide 

little insight into maintenance practices at a 

facility because it would not identify the 

cause of the leaks or the nature and cost of 

repairs. Therefore, this information would 

not be likely to cause substantial competitive 

harm to reporters. For this reason, we are 

proposing the average time operational 

components were found leaking be 

designated as “not CBI.”

98.236(q)(3)(ii) Number of meter/regulator runs 

at above grade transmissiondistribution transfer stations 

surveyed in the calendar year. 

These proposed data elements would be 

reported by natural gas distribution facilities. 

Natural gas distribution companies are 

subject to regulatory oversight by state 

utility commissions because they operate in 

an industry that is inherently not 

competitive. The state utility commission

controls pricing, sets rules for business 

practices, has the power to impose 

conditions on mergers and acquisitions, and 

has the sole responsibility for authorizing the 

location, construction and operations of 

companies operating in this sector. Because

disclosure of these data elements would not 

be likely to cause substantive competitive 

harm, we propose these data elements be 

designated as "not CBI" when reported by 

natural gas distributors.

98.236(q)(3)(iii) Average time that 

meter/regulator runs surveyed in 

the calendar year were 

operational, in hours (average of 

Tw,y in Equation W-31 of this 

subpart, for the current calendar 

year).

98.236(q)(3)(v) Number of meter/regulator runs 

at above grade transmissiondistribution transfer stations 

surveyed in current leak survey 

cycle.

98.236(q)(3)(vi) Average time that 

meter/regulator runs surveyed in 

the current leak survey cycle 

were operational, in hours.

98.236(w) Whether CO2 enhanced oil 

recovery (EOR) injection was 

used at the facility.

This proposed data element would be 

reported by onshore petroleum and natural 

gas production facilities. This data element 

indicates whether EOR is performed. 

However, underground injection of CO2 is 

regulated under 40 CFR parts 124, 144 and 

146. Facilities that inject CO2 underground 
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are required to have an Underground 

Injection Control (UIC) permit, which is a

public document issued by the EPA or by 

states that have primary enforcement 

authority for permitting injection wells. 

Since this information is already available 

through other public documents, we propose 

this data be designated as “not CBI.”

98.236(w) You must indicate whether any 

EOR injection pump blowdowns 

occurred during the year.

This proposed data element would be 

reported by the onshore petroleum and 

natural gas production facilities using EOR. 

Blowdowns are a typical operation 

undertaken by EOR operators and occur 

when equipment is taken out of service 

either to be placed on standby or for 

maintenance purposes. This practice may 

occur as part of a routine scheduled 

maintenance or be the result of an unplanned event (e.g., equipment breakdown). 

Although blowdown events may be 

associated with periods of reduced 

production, facilities typically have backup 

pumps that can be used to avoid production 

shutdowns. Hence, the disclosure of the 

number of blowdowns occurring during a 

reporting year is not likely to cause 

substantial competitive harm. For this 

reason, we propose that this data element be 

designated “not CBI.” 

98.236(x) Whether hydrocarbon liquids 

were produced through EOR 

operations.

This proposed data element would be 

reported by onshore petroleum and natural 

gas production facilities using EOR and 

provides production related information 

about EOR operations. However, production 

data for wells is available to the public 

through state oil and gas commissions. Since 

this information is already available through 

other public documents, we propose this data 

be designated as “not CBI.”

98.236(z)(2)(i) The type of combustion unit. This data element would be reported by 

onshore petroleum and gas production 

facilities and natural gas distribution. This 

data element would provide information on 

the types of combustion units. Information

on the types of combustion units located at a 

facility is often available in a facility’s 

construction and operating permits. For these 

reasons, we consider information on the 
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types of combustion units in production and 

distribution facilities would not be likely to 

cause substantive competitive harm and 

propose this data element be designated as 

"not CBI" for both industry sectors.

98.236(z)(2)(ii) Type of fuel combusted. This data element would be reported by 

onshore petroleum and gas production 

facilities and natural gas distribution. This 

data element would provide information on 

the types of fuel burned. However, facilities 

in both these sectors generally burn fuels 

that are readily available to them as part of 

their operations. Information on the types of 

fuels burned by a facility is often available in 

a facility’s construction and operating 

permits. For these reasons, we consider 

information on the types of fuels burned by 

production and distribution facilities would 

not be likely to cause substantive 

competitive harm and propose this data 

element be designated as "not CBI" for both 

industry sectors.

98.236(aa)(1)(ii)(I) For each sub-basin category, the 

average mole fraction CH4 in 

produced gas.

This proposed data element would be 

reported by onshore petroleum and natural 

gas production facilities. The typical 

composition of produced gas is available 

through the Gas Technology Institute and the 

Department of Energy, Gas Information 

System (GASIS) Database.5 Both of these 

sources are made available to the public. 

Since these data are publicly available we 

are proposing these data elements be 

designated as “not CBI.”

98.236(aa)(1)(ii)(J) For each sub-basin category, the 

average mole fraction CO2 in 

produced gas.

98.236(aa)(4)(i) The quantity of gas transported 

through the compressor station in 

the calendar year, in thousand 

standard cubic feet.

These proposed data elements would be 

reported by the onshore natural gas 

transmission compression sector. Companies 

operating in this sector are subject to 

regulatory oversight by FERC, state utility 

commissions, and other federal agencies 

because they operate in an industry that is 

inherently uncompetitive. FERC controls 

pricing, sets rules for business practices, has 

the power to impose conditions on mergers 

and acquisitions, and has the sole 

responsibility for authorizing the location, 

construction and operations of companies 

98.236(aa)(4)(iv) The average upstream pipeline 

pressure in pounds per square 

inch gauge.

98.236(aa)(4)(v) The average downstream pipeline 

pressure in pounds per square 

inch gauge.

 5 http://www.netl.doe.gov/technologies/oil-gas/publications/EPreports/ResourceAssess/Final_28139.pdf.
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operating in this sector. The rate charged for 

transporting gas is regulated. Hence the 

natural gas transmission sector is inherently 

less competitive than other industries and 

there is little incentive to build additional 

pipelines and compressor stations within the 

same corridors as existing transmission lines. 

Because disclosure of pipeline pressures and 

the quantity of gas transported through the 

compressor would not be likely to cause 

substantive competitive harm, we propose 

these data elements be designated as "not 

CBI.”

98.236(aa)(5)(i) The quantity of gas injected into 

storage in the calendar year, in 

thousand standard cubic feet.

These proposed data elements would be 

reported by underground natural gas storage 

facilities. Underground storage facilities are 

closely associated with and are part of the 

utilities’ integrated distribution systems. 

Some are owned by natural gas distribution 

companies. Distribution companies are 

regulated by state commissions, because 

they operate in an industry that is inherently 

not competitive. Underground storage 

facilities are constrained by geographical 

and geological requirements. These facilities 

must be located in areas where appropriate 

geologic conditions exist for gas storage, 

while also located near regions of the 

country where gas usage fluctuates during 

the year. Typically, gas is injected into 

underground storage during the summer 

months, when consumer demand is low, and 

withdrawn during the winter months, when 

demand peaks. These factors provide 

significant barriers to new companies 

moving into the underground storage sector 

or existing companies increasing their 

market share. Because disclosure of these 

proposed new data elements would not be 

likely to cause substantive competitive harm 

to underground storage facilities, we propose 

these data elements be designated as "not 

CBI.”

98.236(aa)(5)(ii) The quantity of gas withdrawn 

from storage in the calendar year, 

in thousand standard cubic feet.

98.236(aa)(6) For LNG import equipment, the 

quantity of LNG imported in the 

calendar year, in thousand 

standard cubic feet.

Quantities of LNG imported to the U.S. 

together with the name of the importer are 

published by EIA in quarterly reports. 

Because disclosure of this proposed new 

data element would not be likely to cause 
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substantive competitive harm, we propose 

this data element be designated as "not 

CBI.” 

98.236(aa)(7) For LNG export equipment, the 

quantity of LNG exported in the 

calendar year, in thousand 

standard cubic feet.

Quantities of natural gas exported from the 

U.S. are published by EIA in quarterly 

reports. Because disclosure of this proposed 

new data element would not be likely to 

cause substantive competitive harm, we 

propose this data element be designated as 

"not CBI.”

98.236(aa)(8)(i) The quantity of LNG added into 

storage in the calendar year, in 

thousand standard cubic feet.

These proposed data elements would be 

reported by LNG storage facilities. Most 

LNG storage facilities are owned by 

distributors whose operations are regulated 

by FERC and state commissions, because 

they operate in an industry that is inherently 

not competitive. FERC controls pricing, sets 

rules for business practices, has the power to 

impose conditions on mergers and 

acquisitions, and has the sole responsibility 

for authorizing the location, construction and 

operations of companies operating in this 

sector. Because disclosure of these proposed 

new data elements would not be likely to 

cause substantive competitive harm, we 

propose these data elements be designated as 

"not CBI.”

98.236(aa)(8)(ii) The quantity of LNG withdrawn 

from storage in the calendar year, 

in thousand standard cubic feet.

98.236(aa)(9)(i) The quantity of natural gas 

received at all custody transfer 

stations in the calendar year in 

thousand standard cubic feet..

Natural gas distribution companies are 

subject to regulatory oversight by state 

utility commissions, because they operate in 

an industry that is inherently not 

competitive. Many of these data elements 

are also reported to EIA on a monthly basis 

(e.g., natural gas withdrawn from storage, 

natural gas stored, gas received at city gate). 

EIA publishes the data on their Web site on 

an annual basis. Because disclosure of these 

proposed new data elements would not be 

likely to cause substantive competitive harm, 

we propose these data elements be 

designated as "not CBI.”

98.236(aa)(9)(ii) The quantity of natural gas 

withdrawn from in-system 

storage in the calendar year in 

thousand cubic feet.

98.236(aa)(9)(iii) The quantity of natural gas added 

to in-system storage in the 

calendar year in thousand cubic 

feet.

98.236(aa)(9)(iv) The quantity of natural gas 

delivered to end users in 

thousand cubic feet . This value 

does not include stolen gas, or 

gas that is otherwise unaccounted 

for.

98.236(aa)(9)(v) The quantity of natural gas 

transferred to third parties such 

as other LDCs or pipelines in 
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thousand cubic feet . This value 

does not include stolen gas, or 

gas that is otherwise unaccounted 

for.

98.236(aa)(9)(vi) The quantity of natural gas 

consumed by the LDC for 

operational purposes in thousand 

cubic feet.

98.236(aa)(9)(vii) The estimated quantity of gas 

stolen in the calendar year in 

thousand cubic feet.

Unit/Process ‘Static’ Characteristics That Are Not Inputs to Emission Equations” Data Category

98.236(o)(1)(iv) 

operating mode

(v) not operating 

mode

For non-manifolded compressors, 

whether the compressor was 

measured in the operating-mode 

or the not-operatingdepressurized–mode.

These proposed data elements would be 

reported by onshore petroleum and natural 

gas production facilities, onshore natural gas 

processing plants, LNG import/export 

terminals, natural gas transmission 

compression, underground natural gas 

storage facilities, and LNG storage facilities. 

These data elements indicate whether a 

facility has centrifugal compressors, how 

emissions from each unit are handled, and 

specific information about the design and 

age of each centrifugal compressor. 

Centrifugal compressors are used to move 

gas at high pressure through pipelines and 

are standard equipment found at all types of 

natural gas facilities. Centrifugal 

compressors are also listed in each facility’s 

construction and operating permits, which 

must be updated and reissued when 

modifications are made. Hence, the fact that 

a facility has a centrifugal compressor, its 

age and design, and emissions handling 

reveals no sensitive information that would 

be likely to cause substantial competitive 

harm to any type of natural gas facility. For 

these reasons, we propose these data 

elements be designated as "not CBI.” 

98.236(o)(1)(vii) Indicate whether any compressor 

sources are routed to a flare.

98.236(o)(1)(viii) Indicate whether any compressor 

sources have vapor recovery.

98.236(o)(1)(ix) Indicate whether emissions from 

any compressor sources are 

captured for fuel use or are 

routed to a thermal oxidizer.

98.236(o)(1)(x) Indicate whether the compressor 

has blind flanges installed.

98.236(o)(1)(xi) Indicate whether the compressor 

has wet or dry seals.

98.236(o)(1)(xiii) Compressor power rating (hp).

98.236(o)(1)(xiv) Year compressor was installed.

98.236(o)(1)(xv) Compressor model name and 

description.

98.236(p)(1)(viii) Indicate whether any compressor 

sources are part of a manifolded 

group of compressor sources.

These proposed data elements would be 

reported by onshore petroleum and natural 

gas production facilities, onshore natural gas 

processing plants, LNG import/export 

terminals, natural gas transmission 

compression, underground natural gas 

storage facilities, and LNG storage facilities. 

These data elements indicate whether a 

facility has reciprocating compressors, how 

98.236(p)(1)(ix) Indicate whether any compressor 

sources are routed to a flare.

98.236(p)(1)(x) Indicate whether any compressor 

sources have vapor recovery.

98.236(p)(1)(xi) Indicate whether emissions from 

any compressor sources are 
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captured for fuel use or are 

routed to a thermal oxidizer.

emissions from each unit are handled, and 

specific information about the design and 

age of each reciprocating compressor. 

Reciprocating compressors are used to move 

gas at high pressure through pipelines and 

are standard equipment found at all types of 

natural gas facilities. Reciprocating 

compressors are also listed in each facility’s 

construction and operating permit, which 

must be updated and reissued when 

modifications are made. Because disclosure 

of these data elements would be not likely to 

cause substantial competitive harm to any 

type of natural gas facility, we propose these 

data elements be designated as "not CBI.”

98.236(p)(1)(xii) Indicate whether the compressor 

has blind flanges installed.

98.236(p)(1)(xiii) Compressor power rating (hp).

98.236(p)(1)(xiv) Year compressor was installed.

98.236(p)(1)(xv) Compressor model name and 

description.

98.236(z)(1)(ii) The total number of combustion 

units.

This data element would be reported by 

onshore petroleum and gas production 

facilities and natural gas distribution. 

This data element provides information on 

the number of internal and external 

combustion units located at onshore 

petroleum and natural gas production 

facilities. However, this information would 

not be likely to cause substantial competitive 

harm if released to the public, since internal 

and external combustion units are typical 

parts of an onshore petroleum and natural 

gas production facility and the total number 

of such units is not considered to be 

competitively sensitive information by this 

industry sector. Because disclosure of the 

number of combustion units would not be 

likely to cause substantive competitive harm 

to this sector, we propose this data element 

be designated as "not CBI" when reported by 

onshore petroleum and natural gas 

production facilities.

Natural gas distribution companies are 

subject to regulatory oversight by state 

utility commissions, because they operate in 

an industry that is inherently not 

competitive. Because disclosure of the 

number combustion units would not be 

likely to cause substantive competitive harm, 

we propose this data element be designated 

as "not CBI" when reported by natural gas 
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distributors.

98.236(aa)(1)(ii)(C) For each sub-basin category, the 

formation type.

The formation type refers to the following 

types of formations: Oil, high permeability 

gas, shale gas, coal seam, or other tight gas 

reservoir rock. The location of these 

formations is general information that is 

publicly available from EIA. Because

disclosure of the formation would not be 

likely to cause substantive competitive harm, 

we propose this data element be designated 

as "not CBI.”

98.236(aa)(1)(ii)(D) For each sub-basin category, the 

number of producing wells at the 

end of the calendar year.

We are proposing that each of these 

proposed new data elements be assigned to 

the Unit/Process Static Characteristics That 

Are Not Inputs to Emission Equations" 

because each data element provides 

descriptive information about units at the 

facility and does not meet the definition of 

emission data. We propose that each new 

data element be designated as "not CBI" 

because detailed information regarding wells 

is available from state databases and permits. 

Because disclosure of the formation would 

not be likely to cause substantive 

competitive harm, we propose this data 

element be designated as "not CBI.”

98.236(aa)(1)(ii)(E) For each sub-basin category, the 

number of producing wells 

acquired during the calendar 

year.

98.236(aa)(1)(ii)(F) For each sub-basin category, the 

number of producing wells 

divested during the calendar year.

98.236(aa)(1)(ii)(G) For each sub-basin category, the 

number of wells completed 

during the calendar year.

98.236(aa)(1)(ii)(H) For each sub-basin category, the 

number of wells taken out of 

production during the calendar 

year.

98.236(aa)(3)(vii) Whether the onshore natural gas 

processing facility fractionates 

natural gas liquids (NGLs).

Whether a natural gas processing facility 

fractionates NGLs is information that is 

readily available from other public sources, 

such as the LPG Almanac (updated 

annually) and other trade journals. For this 

reason, disclosure of this information would 

not be likely to cause substantial competitive 

harm and we propose that this data element 

be designated as "not CBI.”

98.236(aa)(4)(ii) Number of compressors. These data elements would be reported by 

the onshore natural gas transmission 

compression sector. Companies operating in 

this sector are subject to regulatory oversight 

by FERC, state utility commissions, and 

other federal agencies because they operate 

in an industry that is inherently 

uncompetitive. FERC controls pricing, sets 

rules for business practices, has the power to 

impose conditions on mergers and 

acquisitions, and has the sole responsibility 

98.236(aa)(4)(iii) The total compressor power 

rating for all compressors 

combined, in horsepower.
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for authorizing the location, construction and 

operations of companies operating in this 

sector. Because disclosure of the number and 

power rating for compressors would not be 

likely to cause substantive competitive harm, 

we propose these data elements be 

designated as "not CBI.” 

98.236(aa)(5)(iii) The total storage capacity for 

underground natural gas storage 

facilities.

Companies operating underground gas 

storage facilities are required to report their 

storage capacity to the EIA by company on a 

monthly basis. EIA publishes the data on 

their Web site on an annual basis. Because 

disclosure of underground storage capacity 

would not be likely to cause substantial 

competitive harm, we propose these data 

elements be designated as "not CBI.” 

98.236(aa)(8)(iii) The total LNG storage capacity

in the calendar year, in thousand 

standard cubic feet.

Most LNG storage facilities are regulated by 

FERC and state commissions, because they 

operate in an industry that is inherently not 

competitive. FERC controls pricing, sets 

rules for business practices, has the power to 

impose conditions on mergers and 

acquisitions, and has the sole responsibility 

for authorizing the location, construction and 

operations of companies operating in this 

sector. Because disclosure of LNG storage 

capacity would not be likely to cause 

substantial competitive harm, we propose 

these data elements be designated as "not 

CBI.” 

D. Other Proposed or Re-proposed Case-by-Case Confidentiality Determinations for Subpart W

The proposed revision includes 11 new or substantially revised data elements relative to 

production and/or throughput data from subpart W facilities from the onshore petroleum and 

natural gas production, offshore petroleum and natural gas production, and onshore natural gas 

processing industry sectors. Although these data elements are similar in certain types or 

characteristics to the data elements in “Production/Throughput Data that are Not Inputs to 

Emissions Equations” or “Raw Materials Consumed that are Not Inputs to Emissions Equations” 
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data categories, for the reasons provided above in Section III.B of this preamble, we are not 

proposing to assign these data elements to a data category. Instead, we are proceeding to make 

individual confidentiality determinations for these data elements. As further explained in Section 

III.B of this preamble, we are also proposing to remove one existing data element, 40 CFR 

98.236(j)(2)(i)(A), from “Production/Throughput Data Not Used as Input,” thereby removing the 

application of the categorical confidentiality determination for this data category to this data 

element. We are re-proposing the confidentiality determination for this data element. Table 3 of 

this preamble lists the 11 new or substantially revised data elements and one existing data 

element and provides the rationale and proposed confidentiality determination for each data 

element.

As described above in Section III.B of this preamble, our proposed determinations for 

these data elements were based on a two-step process in which we first evaluated whether the 

data element met the definition of emission data. This first step in the evaluation is important 

because emission data are not eligible for confidential treatment pursuant to section 114(c) of the 

CAA, which precludes emissions data from being considered confidential and requires that such 

data be made available to the public. The term “emission data” is defined in 40 CFR 2.301(a) as: 

“(A) Information necessary to determine the identity, amount, frequency, 

concentration, or other characteristics (to the extent related to air quality) of any 

emission which has been emitted by the source (or of any pollutant resulting from 

any emission by the source), or any combination of the foregoing; (B) 

Information necessary to determine the identity, amount, frequency, 

concentration, or other characteristics (to the extent related to air quality) of the 

emissions which, under an applicable standard or limitation, the source was 
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authorized to emit (including, to the extent necessary for such purposes, a 

description of the manner or rate of operation of the source); and (C) A general 

description of the location and/or nature of the source to the extent necessary to 

identify the source and to distinguish it from other sources (including, to the 

extent necessary for such purposes, a description of the device, installation, or 

operation constituting the source).” 

We propose to determine that none of these 12 data elements are emission data under 40 

CFR 2.301(a)(2)(i), because they do not provide any information characterizing actual GHG 

emissions or descriptive information about the location or nature of the emissions source. 

However, we note that this determination is made strictly in the context of the GHGRP and may 

not apply to other regulatory programs.

In the second step, we evaluate whether the data element is entitled to confidentiality 

treatment, based on the criteria for confidential treatment specified in 40 CFR 2.208. In 

particular, the EPA focused on the following two factors: (1) whether the data was already 

publicly available; and (2) whether “ . . . disclosure of the information is likely to cause 

significant harm to the business’ competitive position.” See 40 CFR 2.208(e)(1). For each of 

these 12 data elements, we determined whether the information is already available in the public 

domain. 

For those data elements for which no published data could be found, we evaluated 

whether the publication would be likely to cause competitive harm. Many of the new data 

elements proposed to be reported by the onshore oil and gas production sector would be reported 

at an aggregated-level (i.e., sub-basin level) that would mask any underlying information for 

individual production wells. These data elements involve reporting aggregated data covering all 
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individual wells, exploratory wells, and production equipment in a sub-basin, rather than 

information specific to an individual well or other production unit. Reporting at a sub-basin level 

is at a large enough scale that disclosure of the collected data would not reveal any proprietary 

information, such as the sensitive operational information or the cost to do business. Because the 

proposed new data elements would also be collected at a sub-basin level, they would not disclose 

production data for individual wells, reveal information about individual exploratory wells, or 

provide insight into production costs. Therefore, we propose that the new production data 

proposed to be reported by the onshore oil and gas production sector be designated as non-CBI 

because its disclosure would not be likely to cause competitive harm. 

For offshore oil and gas production, the EPA is proposing that the quantity of gas 

produced for sales, quantity of oil produced for sales, and quantity of condensate produced for 

sales be reported. These data elements do not provide any competitively sensitive information on 

the costs of doing business. We note that similar data on throughputs for individual platforms are 

published annually by the Bureau of Ocean Energy Management. Therefore, we propose that 

these new production data proposed to be reported by offshore oil and gas platforms be 

designated as non-CBI because its disclosure would not be likely to cause competitive harm. 

For natural gas processing, the EPA is proposing that the total quantity of NGLs (bulk 

and fractionated) received at and leaving the processing plant be reported on an annual basis. 

Because the reported value would be the annual sum of bulk and fractionated NGLs received and 

the annual sum of bulk and fractionated NGLs leaving the plant, the data collected would 

provide very limited information on facility operations and would not disclose any detailed 

information about the facility’s day-to-day operations, such as the amount, contents, and price of 

each shipment of bulk material received, the amount, contents, and price of each shipment of 
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NGL product received, the amount of bulk materials fractionated and costs of fractionation, or 

the type and amounts of each individual NGL product produced. Because these data are to be 

reported at an aggregated level, these proposed two new data elements would not provide insight 

on operating costs, or other highly sensitive aspects of operation the disclosure of which would 

be likely to cause competitive harm. Therefore, we propose that the total quantity of NGLs (bulk 

and fractionated) received at and leaving the natural gas processing plant be designated as not 

CBI. In addition, many facilities in this sector already voluntarily report these data to the 

Worldwide Gas Processing survey and the data at the plant level are published annually in the 

Oil and Gas Journal. Similar data are also mandatorily reported monthly to the EIA. Although 

the EIA aggregates the data before publishing data, the EIA also acknowledges that some 

statistics may be based on data from fewer than three respondents, or that are dominated by data 

from one or two large respondents, and in these cases, it may be possible for a the information 

reported by a specific respondent to be accurately estimated.

Table 3. Proposed Individual Confidentiality Determination for 13 New or Substantially 

Revised Data Elements and Re-Proposal for One Existing Data Elements

Citation Data Element

Proposed Confidentiality Determination and 

Rationale

Onshore petroleum and natural gas production

98.236(aa)(1)(i)(A) The quantity of gas produced 

in the calendar year from 

wells, in thousand standard 

cubic feet. This includes gas 

that is routed to a pipeline, 

vented or flared, or used in 

field operations. This does 

not include gas injected back 

into reservoirs or shrinkage 

resulting from lease 

condensate production.

We propose that each of these data elements be 

designated as "not CBI." The onshore 

petroleum production sector is a regionally 

concentrated sector, with wells located in fixed 

geological formations and a large number of 

operators within each formation. Information 

that is typically considered sensitive to this 

industry includes data related to production 

costs for developed fields and information on 

individual exploratory wells. Information on 

exploratory wells is sensitive during the time 

period when a new formation is being 

developed because lease prices are not 

stabilized until wells have proven production 

records. Once the formation has been 

developed and several wells have been drilled 

in a basin, production decisions are based on 

98.236(aa)(1)(i)(B) The quantity of gas produced

in the calendar year for sales 

in thousand standard cubic 

feet.

98.236(aa)(1)(i)(C) For each basin, the quantity 

of crude oil produced in the 
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calendar year for sales, not 

including lease condensates, 

in barrels.

market prices and the ability to control flow 

from the well. The production data that will be 

reported at the basin or sub-basin level are 

already publicly available through the 

Department of Energy. Reporting at the basin 

or sub-basin level includes data aggregated to a 

scale large enough that it does not disclose 

production data for individual wells, reveal 

sensitive information about individual 

exploratory wells, or provide insight into 

production costs. 

98.236(aa)(1)(i)(D) For each basin, the quantity 

of lease condensate 

produced in the calendar 

year for sales (in barrels).

98.236(j)(2)(i)(A) The total annual oil 

throughput that is sent to all 

atmospheric tanks in the 

basin, in barrels. 

Offshore petroleum and natural gas production

98.236(aa)(2)(i) The quantity of gas produced 

for sales from the offshore 

platform in the calendar year

for sales, in thousand 

standard cubic feet. 

We propose that each of these new data 

elements be designated as "not CBI" because 

the production throughput data are published 

annually on the Bureau of Ocean Energy 

Management's Web site. 

98.236(aa)(2)(ii) The quantity of oil produced 

for sales from the offshore 

platform in the calendar year

for sales (in barrels). 

98.236(aa)(2)(iii) The quantity of condensate 

produced for sales from the 

offshore platform in the 

calendar year for sales (in 

barrels).

Onshore natural gas processing

98.236(aa)(3)(i) The quantity of produced gas 

received at the gas 

processing plant in thousand 

standard cubic feet.

We propose that each of these new data 

elements be designated as "not CBI" because 

the average annual flow and plant utilization 

rates are published quarterly on EIA's Web site

98.236(aa)(3)(ii) The quantity of processed and are already in the public domain. 

(residue) gas leaving the gas 

processing plant in thousand 

standard cubic feet.

98.236(aa)(3)(iii) The quantity of NGLs (bulk 

and fractionated) received at 

the gas processing plant in 

the calendar year, in barrels. 

We propose that each of these new data 

elements be designated as "not CBI" because 

they are already publicly available. Many 

facilities in this sector already voluntarily 

report these data to the Worldwide Gas 

Processing survey and the data at the plant 

level are published annually in the Oil and Gas 

Journal. Similar data are also mandatorily 

reported monthly to the EIA. Although the EIA 

aggregates the data before publishing data, the 

EIA also acknowledges that, “Disclosure 

limitation procedures are not applied to the 

statistical data published from this survey's 

98.236(aa)(3)(iv) The quantity of NGLs (bulk 

and fractionated) leaving the 

gas processing plant in the 

calendar year, in barrels. 
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information. Thus, there may be some statistics 

that are based on data from fewer than three 

respondents, or that are dominated by data 

from one or two large respondents. In these 

cases, it may be possible for a knowledgeable 

person to estimate the information reported by 

a specific respondent.”6

The list of data elements, their data category assignments, and proposed confidentiality 

determinations can be found in the memorandum titled “Data Category Assignments and 

Confidentiality Determinations for all Data Elements (excluding inputs to emission equations) in 

the Proposed ‘Technical Revisions and Confidentiality Determinations for Petroleum and 

Natural Gas Systems’” in Docket ID No. EPA-HQ-OAR-2011-0512.

E. Request for Comments on Proposed Confidentiality Determinations

For the CBI component of this rulemaking, we are specifically soliciting comment on the 

following issues. First, we specifically seek comment on the proposed data category 

assignments, and application of the established categorical confidentiality determinations to data 

elements assigned to categories with such determinations. If a commenter believes that the EPA 

has improperly assigned certain new or substantially revised data elements to any of the data 

categories established in the 2011 Final CBI Rule, please provide specific comments identifying 

which of these data elements may be mis-assigned along with a detailed explanation of why you 

believe them to be incorrectly assigned and in which data category you believe they belong. In 

addition, if you believe that a data element should be assigned to one of the two direct emitter 

data categories that do not have a categorical confidentiality determination, please also provide 

 6 http://www.eia.gov/survey/form/eia_816/instructions.pdf, Instructions for completing Form EIA-816, Monthly 

Natural Gas Liquids Report.
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specific comment along with detailed rationale and supporting information on whether such data 

element does or does not qualify as CBI.

We also seek comment on the proposed individual confidentiality determinations for the 

following data elements: 72 new or substantially revised data elements assigned to the 

“Unit/Process ‘Operating’ Characteristics That Are Not Inputs to Emission Equations” data 

category; 29 new or substantially revised data elements assigned to the “Unit/Process ‘Static’ 

Characteristics That Are Not Inputs to Emission Equations” category; 11 new data elements for 

which no data category assignment was proposed; and one existing data element for which we 

are proposing to remove the data category assignment and make a new confidentiality 

determination. 

By proposing confidentiality determinations prior to data reporting through this proposal 

and rulemaking process, we provide reporters an opportunity to submit comments, in particular 

comments identifying data they consider sensitive and their rationales and supporting 

documentation; this opportunity is the same opportunity that is afforded to submitters of 

information in case-by-case confidentiality determinations made in response to individual claims 

for confidential treatment not made through rulemaking. It provides an opportunity to rebut the 

Agency’s proposed determinations prior to finalization. We will evaluate the comments on our 

proposed determinations, including claims of confidentiality and information substantiating such 

claims, before finalizing the confidentiality determinations. Please note that this will be a 

reporter’s only opportunity to substantiate a confidentiality claim for these proposed new data 

elements. Upon finalizing the confidentiality determinations of the data elements identified in 

this rule, the EPA will release or withhold these data in accordance with 40 CFR 2.301, which 
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contains special provisions governing the treatment of Part 98 data for which confidentiality 

determinations have been made through rulemaking.

When submitting comments regarding the confidentiality determinations we are 

proposing in this action, please identify each individual data element you do or do not consider 

to be CBI or emission data in your comments. Please explain specifically how the public release 

of that particular data element would or would not cause a competitive disadvantage to a facility. 

Discuss how this data element may be different from or similar to data that are already publicly 

available. Please submit information identifying any publicly available sources of information 

containing the specific data elements in question. Data that are already available through other 

sources would likely be found not to qualify for CBI protection. In your comments, please 

identify the manner and location in which each specific data element you identify is publicly 

available, including a citation. If the data are physically published, such as in a book, industry 

trade publication, or federal agency publication, provide the title, volume number (if applicable), 

author(s), publisher, publication date, and International Standard Book Number (ISBN) or other 

identifier. For data published on a Web site, provide the address of the Web site and the date you 

last visited the Web site and identify the Web site publisher and content author.

If your concern is that competitors could use a particular data element to discern sensitive 

information, specifically describe the pathway by which this could occur and explain how the 

discerned information would negatively affect your competitive position. Describe any unique 

process or aspect of your facility that would be revealed if the particular data element you 

consider sensitive were made publicly available. If the data element you identify would cause 

harm only when used in combination with other publicly available data, then describe the other 

data, identify the public source(s) of these data, and explain how the combination of data could 
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be used to cause competitive harm. Describe the measures currently taken to keep the data 

confidential. Avoid conclusory and unsubstantiated statements, or general assertions regarding 

potential harm. Please be as specific as possible in your comments and include all information 

necessary for the EPA to evaluate your comments.

IV. Impacts of the Proposed Amendments to Subpart W

The proposed amendments to subpart W are based on identified improvements in the 

regulatory language and revisions to calculation methods that do not significantly increase the

burden of data collection and reporting, improve the accuracy of the data reported, and provide 

clarity. The proposed amendments do not impart significant additional burden to reporters and 

many reduce burden to reporters and regulators in some cases. 

As discussed in Section II of this preamble, the EPA is proposing to revise the reporting 

elements that must be reported. Any elements that were not previously required to be reported 

identify the equipment to be reported for the industry segment or are inputs to an emission 

equation. These data elements are typically already collected by reporters. These proposed 

revisions would remove ambiguity for the reporter and would not increase burden significantly, 

since the reporting elements are already available.

As discussed in Section II.D of this preamble, the EPA is proposing to remove the best 

available monitoring method (BAMM) provisions in 40 CFR 98.234(f). Removing these 

provisions would not add to previous burden estimates for subpart W reporters; previous burden 

estimates were prepared based on all reporters complying with the monitoring methods in 40 

CFR 98.234 without BAMM.
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The additional proposed amendments to subpart W are not expected to significantly 

increase burden. See the memorandum, “Assessment of Impacts of the 2014 Proposed Revisions 

to Subpart W” in Docket Id. No. EPA-HQ-OAR-2011-0512 for additional information.

V. Statutory and Executive Order Reviews 

A. Executive Order 12866: Regulatory Planning and Review and Executive Order 13563: 

Improving Regulation and Regulatory Review

This action is not a “significant regulatory action” under the terms of Executive Order 

12866 (58 FR 51735, October 4, 1993) and is therefore not subject to review under Executive 

Orders 12866 and 13563 (76 FR 3821, January 21, 2011). 

In addition, the EPA prepared an analysis of the potential costs and benefits associated 

with the proposed amendments to subpart W. This analysis is contained in “Assessment of 

Impacts of the 2014 Proposed Revisions to Subpart W.” A copy of the analysis is available in the 

docket for this action (see Docket Id. No. EPA-HQ-OAR-2011-0512) and the analysis is briefly 

summarized in Section IV of this preamble.

B. Paperwork Reduction Act

The information collection requirements in this proposed rule have been submitted for 

approval to the Office of Management and Budget (OMB) under the Paperwork Reduction Act, 

44 U.S.C. 3501 et seq. The Information Collection Request (ICR) document prepared by the 

EPA has been assigned EPA ICR number 2300.15.

This action proposes to simplify the existing reporting methods in subpart W and clarify 

monitoring methods and data reporting requirements, and proposes confidentiality 

determinations for reported data elements. The EPA is proposing to restructure the reporting 

requirements for clarity and align them with the calculation requirements. OMB has previously 
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approved the information collection requirements for 40 CFR part 98 under the provisions of the 

Paperwork Reduction Act, 44 U.S.C. 3501 et seq., and has assigned OMB control number 2060-

0629. The OMB control numbers for the EPA’s regulations in 40 CFR are listed in 40 CFR 

part 9. Burden is defined at 5 CFR 1320.3(b).

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

collection of information unless it displays a currently valid OMB control number. The OMB 

control numbers for the EPA's regulations in 40 CFR are listed in 40 CFR part 9.

This proposed rule is estimated to result in an increase in annual burden of 6,920 hours of 

labor, valued at $543,000. This represents a 2.5 percent increase in the total annual cost burden 

associated with reporting for subpart W. The new total cost and hour burden for annual reporting 

under Subpart W are $21,964,000 and 244,000 hours, respectively. For the hour burden, the 

estimated average burden hours per response is 54 hours, the proposed frequency of response is 

once annually, and the estimated number of likely respondents is 2,885. For the cost burden to 

respondents or record keepers resulting from the collection of information, the estimated total 

capital and start-up cost component annualized over its expected useful life is $796,000 per year, 

the total operation and maintenance component is $1,690,000 per year, and the total labor cost is 

$19,478,000 per year for all of subpart W.

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

burden estimates, and any suggested methods for minimizing respondent burden, the EPA has 

established a public docket for this rule, which includes this ICR, under Docket ID number EPAHQ-OAR-2011-0512. Submit any comments related to the ICR to the EPA and OMB. See 

ADDRESSES section at the beginning of this notice for where to submit comments to the EPA.

Send comments to OMB at the Office of Information and Regulatory Affairs, Office of 
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Management and Budget, 725 17th Street, NW, Washington, DC 20503, Attention: Desk Office 

for the EPA. Since OMB is required to make a decision concerning the ICR between 30 and 60 

days after [INSERT THE DATE OF PUBLICATION IN THE FEDERAL REGISTER], a 

comment to OMB is best assured of having its full effect if OMB receives it by [INSERT THE 

DATE 30 DAYS AFTER DATE OF PUBLICATION IN THE FEDERAL REGISTER].

The final rule will respond to any OMB or public comments on the information collection 

requirements contained in this proposal. We continue to be interested in the potential impacts of 

this proposed action on the burden associated with the proposed amendments and welcome 

comments on issues related to such impacts.

C. Regulatory Flexibility Act (RFA)

The Regulatory Flexibility Act (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 today’s proposed rule on small entities, small 

entity is defined as: (1) a small business as defined by the Small Business Administration’s 

regulations at 13 CFR 121.201; (2) a small governmental jurisdiction that is a government of a 

city, county, town, school district or special district with a population of less than 50,000; and (3) 

a small organization that is any not-for-profit enterprise which is independently owned and 

operated and is not dominant in its field. 
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After considering the economic impacts of this proposed rule on small entities, I certify 

that this action will not have a significant economic impact on a substantial number of small 

entities. This action proposes to (1) amend monitoring and calculation methodologies in subpart 

W; (2) assign subpart W data reporting elements into CBI data categories; and (3) amend a 

definition in subpart A. 

The small entities directly regulated by this proposed rule include small businesses in the 

petroleum and gas industry, small governmental jurisdictions and small non-profits. The EPA 

has determined that some small businesses would be affected because their production processes 

emit GHGs exceeding the reporting threshold. We have determined that these facilities would 

experience an average annual cost increase of $188 per facility. The increased costs would be the 

result of proposed changes to the calculation methods and the reporting requirements. We do not 

expect there to be any additional first-year costs, because we expect these revisions would only 

impact entities that are already reporting under the existing rule.

This action includes proposed amendments that do not result in a significant burden 

increase on subpart W reporters. In some cases, the EPA is proposing to increase flexibility in 

the selection of methods used for calculating GHGs, and is also proposing to revise certain 

methods that may result in greater conformance to current industry practices. In addition, the 

EPA is proposing to revise specific provisions to provide clarity on what information is being 

reported. These proposed revisions would not significantly increase the burden on reporters 

while maintaining the data quality of the information being reported to the EPA.

As part of the process of finalization of the final subpart W rule, the EPA took several 

steps to evaluate the effect of the rule on small entities. For example, the EPA determined 

appropriate thresholds that reduced the number of small businesses reporting. In addition, the 
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EPA conducted several meetings with industry associations to discuss regulatory options and the 

corresponding burden on industry, such as recordkeeping and reporting. Although this proposed 

rule will not have a significant economic impact on a substantial number of small entities, the 

EPA nonetheless has tried to reduce the impact of this rule on small entities. The EPA continues 

to conduct significant outreach on the GHG reporting rule and maintains an “open door” policy 

for stakeholders to help inform the EPA’s understanding of key issues for the industries.

The EPA continues to be interested in the potential impacts of the proposed rule 

amendments on small entities and welcomes comments on issues related to such impacts.

D. Unfunded Mandates Reform Act (UMRA)

Title II of the Unfunded Mandates Reform Act of 1995 (UMRA), 2 U.S.C. 1531-1538, 

requires federal agencies, unless otherwise prohibited by law, to assess the effects of their 

regulatory actions on state, local, and tribal governments and the private sector. Federal agencies 

must also develop a plan to provide notice to small governments that might be significantly or 

uniquely affected by any regulatory requirements. The plan must enable officials of affected 

small governments to have meaningful and timely input in the development of the EPA 

regulatory proposals with significant federal intergovernmental mandates and must inform, 

educate, and advise small governments on compliance with the regulatory requirements.

This action proposes to (1) amend monitoring and calculation methodologies in subpart 

W; (2) assign subpart W data reporting elements into CBI data categories; and (3) amend a 

definition in subpart A. This proposed 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. Thus, this proposed rule is not subject to the requirements of 

section 202 and 205 of the UMRA. This rule is also not subject to the requirements of section 
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203 of UMRA because it contains no regulatory requirements that might significantly or 

uniquely affect small governments. The proposed amendments would not impose any new 

requirements that are not currently required for 40 CFR part 98, and the rule amendments would 

not uniquely apply to small governments. Therefore, this action is not subject to the requirements 

of section 203 of the UMRA.

E. Executive Order 13132: Federalism 

This action does not have federalism implications. It will not have substantial direct 

effects on the States, on the relationship between the national government and the States, or on 

the distribution of power and responsibilities among the various levels of government, as 

specified in Executive Order 13132. However, for a more detailed discussion about how Part 98 

relates to existing state programs, please see Section II of the preamble to the final Part 98 rule 

(74 FR 56266, October 30, 2009).

This action proposes to (1) amend monitoring and calculation methodologies in subpart 

W; (2) assign subpart W data reporting elements into CBI data categories; and (3) amend a 

definition in subpart A. Few, if any, state or local government facilities would be affected by the 

provisions in this proposed rule. This regulation also does not limit the power of States or 

localities to collect GHG data and/or regulate GHG emissions. Thus, Executive Order 13132 

does not apply to this action.

In the spirit of Executive Order 13132, and consistent with the EPA policy to promote 

communications between the EPA and state and local governments, the EPA specifically solicits 

comment on this proposed action from state and local officials. For a summary of the EPA’s 

consultation with state and local organizations and representatives in developing Part 98, see 

Section VIII.E of the preamble to the final rule (74 FR 56371, October 30, 2009).
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F. Executive Order 13175: Consultation and Coordination with Indian Tribal Governments

Subject to the Executive Order 13175 (65 FR 67249, November 9, 2000) the EPA may 

not issue a regulation that has tribal implications, that imposes substantial direct compliance 

costs, and that is not required by statute, unless the federal government provides the funds 

necessary to pay the direct compliance costs incurred by tribal governments, or the EPA consults 

with tribal officials early in the process of developing the proposed regulation and develops a 

tribal summary impact statement.

The EPA has concluded that this action may have tribal implications. This action 

proposes to (1) Amend monitoring and calculation methodologies in subpart W; (2) assign 

subpart W data reporting elements into CBI data categories; and (3) amend a definition in 

subpart A. However, it will neither impose substantial direct compliance costs on tribal 

governments, nor preempt Tribal law. This regulation would apply directly to petroleum and 

natural gas facilities that emit greenhouses gases. Although few facilities that would be subject to 

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

provide information to tribal governments and representatives during the development of the 

proposed and final subpart W that was promulgated on November 30, 2010 (75 FR 74458). The 

EPA consulted with tribal officials early in the process of developing subpart W to permit them 

to have meaningful and timely input into its development. 

For additional information about the EPA’s interactions with tribal governments, see 

section IV.F of the preamble to the re-proposal of subpart W published on April 12, 2010 (75 FR 

18608), and section IV.F of the preamble to the final subpart W published on November 30, 

2010 (75 FR 74458). 
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The EPA specifically solicits additional comment on this proposed action from tribal 

officials.

G. Executive Order 13045: Protection of Children from Environmental Health Risks and Safety 

Risks

The EPA interprets Executive Order 13045 (62 FR 19885, April 23, 1997) as applying 

only to those regulatory actions that concern health or safety risks, such that the analysis required 

under section 5-501 of the Executive Order has the potential to influence the regulation. This 

action proposes to (1) Amend monitoring and calculation methodologies in subpart W; (2) assign 

subpart W data reporting elements into CBI data categories; and (3) amend a definition in 

subpart A. This action is not subject to Executive Order 13045 because it does not establish an 

environmental standard intended to mitigate health or safety risks.

H. Executive Order 13211: Actions that Significantly Affect Energy Supply, Distribution, or Use

This action is not subject to Executive Order 13211 (66 FR 28355 (May 22, 2001)), 

because it is not a significant regulatory action under Executive Order 12866. 

I. National Technology Transfer and Advancement Act

Section 12(d) of the National Technology Transfer and Advancement Act of 1995 

(NTTAA), Public Law No. 104-113 (15 U.S.C. 272 note) directs the 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.
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This action proposes to (1) Amend monitoring and calculation methodologies in subpart 

W; (2) assign subpart W data reporting elements into CBI data categories; and (3) amend a 

definition in subpart A. This proposed rulemaking does not involve the use of any technical 

standards. No changes are being proposed that affect the test methods currently in use for subpart 

W. Therefore, the EPA is not considering the use of any voluntary consensus standards.

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 lowincome populations in the United States. 

This action proposes to (1) amend monitoring and calculation methodologies in subpart 

W; (2) assign subpart W data reporting elements into CBI data categories; and (3) amend a 

definition in subpart A. The EPA has determined that this proposed rule will not have 

disproportionately high and adverse human health or environmental effects on minority or lowincome populations because it does not affect the level of protection provided to human health or 

the environment. Instead, this proposed rule addresses information collection and reporting 

procedures.
Greenhouse Gas Reporting Rule: Revisions and Confidentiality 

Determinations for Petroleum and Natural Gas Systems; Proposed Rule

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List of Subjects in 40 CFR Part 98

Environmental protection, Administrative practice and procedure, Greenhouse gases, 

Incorporation by reference, Reporting and recordkeeping requirements.

Dated:

Gina McCarthy, 

Administrator.
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For the reasons stated in the preamble, title 40, chapter I, of the Code of Federal 

Regulations is proposed to be amended as follows: 

PART 98–MANDATORY GREENHOUSE GAS REPORTING

1. The authority citation for part 98 continues to read as follows:

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

Subpart A—[AMENDED]

2. Section 98.6 is amended by revising the definition of “Well completions” to read as 

follows: 

§98.6 Definitions.

* * * * *

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 and prop open new fractures in 

existing lower permeability gas reservoirs, steps that may vent large quantities of produced gas 

to the atmosphere.

* * * * *

Subpart W—[AMENDED]

3. Section 98.230 is amended by revising paragraph (a)(2) to read as follows: 

§ 98.230 Definition of the source category.
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(a) * * *

(2) Onshore petroleum and natural gas production. Onshore petroleum and natural gas 

production means all equipment on a single well-pad or associated with a single well-pad 

(including but not limited to compressors, generators, dehydrators, storage vessels, engines, 

boilers, heaters, flares, separation and processing equipment, and portable non-self-propelled 

equipment, which includes well drilling and completion equipment, workover equipment, 

maintenance and repair 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 all petroleum and natural gas production equipment located on islands, 

artificial islands, or structures connected by a causeway to land, an island, or an artificial island. 

Onshore petroleum and natural gas production also means all equipment on or associated with a 

single enhanced oil recovery (EOR) well pad using CO2 or natural gas injection. 

* * * * *

4. Section 98.232 is amended by: 

a. Revising paragraph (c)(11);

b. Revising paragraph (d)(1);

c. Revising paragraphs (e)(1) and (e)(6);

d. Revising paragraphs (f)(1) and (f)(4);

e. Revising paragraphs (g)(1) and (g)(4);

f. Revising paragraphs (h)(1) and (h)(5); and

g. Revising paragraphs (i)(1) through (i)(7).

The revisions read as follows:
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§ 98.232 GHGs to report.

* * * * *

(c) * * *

(11) Reciprocating compressor venting.

* * * * *

(d) * * *

(1) Reciprocating compressor venting.

* * * * *

(e) * * *

(1) Reciprocating compressor venting.

* * * * *

(6) Flare stack emissions.

(f) * * *

(1) Reciprocating compressor venting.

* * * * *

(4) Flare stack emissions.

* * * * *

(g) For LNG storage, report CO2, CH4, and N2O emissions from the following sources:

(1) Reciprocating compressor venting.

* * * * *

(4) Flare stack emissions.

(h) * * *

(1) Reciprocating compressor venting.
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* * * * *

(5) Flare stack emissions.

(i) * * *

(1) Equipment leaks from connectors, block valves, control valves, pressure relief valves, 

orifice meters, regulators, and open-ended lines at above grade transmission-distribution transfer 

stations.

(2) Equipment leaks at below grade transmission-distribution transfer stations.

(3) Equipment leaks at above grade metering-regulating stations that are not above grade 

transmission-distribution transfer stations.

(4) Equipment leaks at below grade metering-regulating stations.

(5) Distribution main equipment leaks.

(6) Distribution services equipment leaks. 

(7) 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).

* * * * *

5. Section 98.233 is amended by: 

a. Revising paragraphs (a) introductory text, (a)(1), and (a)(2); 

b. Adding paragraph (a)(4); 

c. Revising paragraphs (c), (d), (e), (f), (g), (h), and (i);

d. Revising paragraphs (j) introductory text, (j)(1) introductory text, (j)(1)(vii) 

introductory text, and (j)(2);

e. Redesignating paragraph (j)(5) introductory text as paragraph (j)(3) introductory text 

and revising newly redesignated paragraph (j)(3) introductory text;
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f. Redesignating paragraph (j)(6) as paragraph (j)(4) and revising newly redesignated 

paragraph (j)(4);

g. Redesignating paragraph (j)(7) as paragraph (j)(5) and revising newly redesignated 

paragraph (j)(5); 

h. Redesignating paragraph (j)(8) as paragraph (j)(6) and revising newly redesignated 

paragraph (j)(6); 

i. Redesignating paragraph (j)(9) as paragraph (j)(7) and revising newly redesignated 

paragraph (j)(7);

j. Revising paragraph (k);

k. Revising paragraphs (l) introductory text, (l)(2) introductory text, and (l)(2)(ii);

l. Revising paragraphs (l)(3) introductory text and the parameters “FR” and “D” of 

Equation W-17B in paragraph (l)(3);

m. Revising paragraphs (l)(5) and (l)(6);

n. Revising paragraphs (m), (n), (o), (p), (q), and (r);

o. Revising paragraphs (s)(2) introductory text, (s)(2)(i), (s)(3), (s)(4), and (t) 

introductory text.

p. Revising Equation W-33 of paragraph (t)(1) and adding the parameter “Za” to Equation 

W-33 in paragraph (t)(1);

q. Revising Equation W-34 of paragraph (t)(2) and adding the parameter “Za” to Equation 

W-34 in paragraph (t)(2);

r. Revising paragraphs (u) introductory text, (u)(2)(iii), and (u)(2)(v) through (vii);

s. Revising paragraphs (v), (w) introductory text, (w)(1), and (w)(3) introductory text;
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t. Revising the parameters “MassCO2”, “N”, and “Vv” to Equation W-37 in paragraph 

(w)(3);

u. Revising paragraphs (x) introductory text and (x)(1);

v. Revising the parameter “Shl” to Equation W-38 in paragraph (x)(2);

w. Revising paragraphs (z)(1) introductory text, (z)(1)(i), and (z)(1)(ii);

x. Revising the parameters “Va”, “YCO2”, “Yj”, and “YCH4” to Equations W-39B and W39B in paragraph (z)(2)(iii);

y. Revising Equation W-40 in paragraph (z)(2)(vi) and the parameters “MassN2O”, 

“Fuel”, and “HHV” to Equation W-40 in paragraph (z)(2)(vi);

z. Removing the parameter “GWP” of Equation W-40 in paragraph (z)(2)(vi); and

The revisions and additions read as follows:

§ 98.233 Calculating GHG emissions.

* * * * *

(a) Natural gas pneumatic device venting. Calculate CH4 and CO2 volumetric emissions 

from continuous high bleed, continuous low bleed, and intermittent bleed natural gas pneumatic 

devices using Equation W-1 of this section.

= ∑

t

i

Es i Countt EFt GHGi Tt * * * , (Eq. W-1)

Where:

Es,i = Annual total volumetric GHG emissions at standard conditions in standard 

cubic feet per year from natural gas pneumatic device vents, of types “t” 

(continuous high bleed, continuous low bleed, intermittent bleed), for 

GHGi.

Countt = Total number of natural gas pneumatic devices of type “t” (continuous 

high bleed, continuous low bleed, intermittent bleed) as determined in 

paragraph (a)(1) or (a)(2) of this section.
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EFt = Population emission factors for natural gas pneumatic device vents (in 

standard cubic feet per hour per device) of each type “t” 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, onshore 

natural gas transmission compression facilities, and underground natural 

gas storage facilities, concentration of GHGi, CH4 or CO2, in produced 

natural gas or processed natural gas for each facility as specified in 

paragraphs (u)(2)(i), (iii), and (iv) of this section.

Tt = Average estimated number of hours in the operating year the devices, of each 

type “t”, were operational using engineering estimates based on best 

available data. Default is 8760 hours.

(1) For all industry segments, determine “Countt” for Equation W-1 of this subpart for 

each type of natural gas pneumatic device (continuous high bleed, continuous low bleed, and 

intermittent bleed) by counting the devices, except as specified in paragraph (a)(2) of this 

section. The reported number of devices must represent the total number of devices for the 

reporting year. 

(2) For the onshore petroleum and natural gas production industry segment, you have the 

option in the first two consecutive calendar years to determine “Countt” for Equation W-1 of this 

subpart for each type of natural gas pneumatic device (continuous high bleed, continuous low 

bleed, and intermittent bleed) using engineering estimates based on best available data.

* * * * *

(4) Calculate both CH4 and CO2 mass emissions from volumetric emissions using 

calculations in paragraph (v) of this section.

* * * * *

(c) Natural gas driven pneumatic pump venting.
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(1) Calculate CH4 and CO2 volumetric 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 this paragraph (c).

Es,i = Count * EF * GHGi* T (Eq. W-2)

Where:

Es,i = Annual total volumetric GHG emissions at standard conditions in standard 

cubic feet per year from all natural gas driven pneumatic pump venting, 

for GHGi.

Count = Total number of natural gas driven pneumatic pumps.

EF = Population emissions factors for natural gas driven pneumatic pumps (in 

standard cubic feet per hour per pump) listed in Table W-1A of this 

subpart for onshore petroleum and natural gas production.

GHGi = Concentration of GHGi, CH4, or CO2, in produced natural gas as defined 

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

T = Average estimated number of hours in the operating year the pumps were 

operational using engineering estimates based on best available data. 

Default is 8760 hours.

(2) Calculate both CH4 and CO2 mass emissions from volumetric emissions using 

calculations in paragraph (v) of this section.

(d) Acid gas removal (AGR) vents. For AGR vents (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 emitted 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 methods described in this 

paragraph (d), as applicable.

(1) Calculation Method 1. If you operate and maintain a continuous emissions monitoring 

system (CEMS) that has both a CO2 concentration monitor and volumetric flow rate monitor, 

you must calculate CO2 emissions under this subpart by following the Tier 4 Calculation Method 
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and all associated calculation, quality assurance, reporting, and recordkeeping requirements for 

Tier 4 in subpart C of this part (General Stationary Fuel Combustion Sources). Alternatively, you 

may follow the manufacturer's instructions or industry standard practice. If a CO2 concentration 

monitor and volumetric flow rate monitor are not available, you may elect to install a CO2

concentration monitor and a volumetric flow rate monitor that comply with all of the 

requirements specified for the Tier 4 Calculation Method in subpart C of this part (General 

Stationary Fuel Combustion Sources). The calculation and reporting of CH4 and N2O emissions 

is not required as part of the Tier 4 requirements for AGR units.

(2) Calculation Method 2. If a CEMS is not available but a vent meter is installed, use the 

CO2 composition and annual volume of vent gas to calculate emissions using Equation W-3 of 

this section.

2 , 2 * CO a CO E Vs Vol = (Eq. W-3)

Where:

Ea,CO2 = Annual volumetric CO2 emissions at actual conditions, in cubic feet per 

year.

VS = Total annual volume of vent gas flowing out of the AGR unit in cubic feet 

per year at actual conditions as determined by flow meter using methods 

set forth in § 98.234(b). Alternatively, you may follow the manufacturer's 

instructions or industry standard practice for calibration of the vent meter.

VolCO2 = Annual average volumetric fraction of CO2 content in vent gas flowing out of 

the AGR unit as determined in paragraph (d)(6) of this section.

(3) Calculation Method 3. If a CEMS or a vent meter is not installed, you may use the 

inlet or outlet gas flow rate of the acid gas removal unit to calculate emissions for CO2 using 

Equations W-4A or W-4B of this section. If inlet gas flow rate is known, use Equation W-4A. If 

outlet gas flow rate is known, use Equation W-4B.
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



 





−

− = ∗

O

I O

a CO in Vol

Vol Vol E V

1 , 2 (Eq. W-4A)





 





−

− = ∗

I

I O

a CO out Vol

Vol Vol E V

1 , 2 (Eq. W-4B)

Where:

Ea, CO2 = Annual volumetric CO2 emissions at actual conditions, in cubic feet per 

year.

Vin = Total annual volume of natural gas flow into the AGR unit in cubic feet 

per year at actual conditions as determined using methods specified in 

paragraph (d)(5) of this section.

Vout = Total annual volume of natural gas flow out of the AGR unit in cubic feet 

per year at actual conditions as determined using methods specified in 

paragraph (d)(5) of this section.

VolI = Annual average volumetric fraction of CO2 content in natural gas flowing 

into the AGR unit as determined in paragraph (d)(7) of this section.

Volo = Annual average volumetric fraction of CO2 content in natural gas flowing out 

of the AGR unit as determined in paragraph (d)(8) of this section.

(4) Calculation Method 4. If CEMS or a vent meter is not installed, you may calculate 

emissions using any standard simulation software package, such as AspenTech HYSYS®, or API 

4679 AMINECalc, that uses the Peng-Robinson 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.
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(5) For Calculation Method 3, determine the gas flow rate of the inlet when using 

Equation W-4A of this section or the gas flow rate of the outlet when using Equation W-4B of 

this section for the 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) For Calculation Method 2, if a 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 in Equation W-3 of this section according to methods set forth in §

98.234(b).

(7) For Calculation Method 3, if a continuous gas analyzer is installed on the inlet gas 

stream, then the continuous gas analyzer results must be used. If a 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 in Equation W-4A or W-4B of this section according to methods set 

forth in § 98.234(b).

(8) For Calculation Method 3, determine annual average volumetric fraction of CO2

content in natural gas flowing out of the AGR unit using one of the methods specified in 

paragraphs (d)(8)(i) through (d)(8)(iii) 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 in Equation W-4A or W-4B of this section 

according to methods set forth in § 98.234(b).
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(iii) If a continuous gas analyzer is not available or installed, you may use sales line 

quality specification for CO2 in natural gas.

(9) Calculate annual volumetric CO2 emissions at standard conditions using calculations 

in paragraph (t) of this section.

(10) Calculate annual mass CO2 emissions at standard conditions using calculations in 

paragraph (v) of this section.

(11) Determine if CO2 emissions from the AGR unit are recovered and transferred 

outside the facility. Adjust the CO2 emissions estimated in paragraphs (d)(1) through (d)(10) of 

this section downward by the magnitude of CO2 emissions recovered and transferred outside the 

facility.

(e) Dehydrator vents. For dehydrator vents, calculate annual CH4 and CO2 emissions 

using the applicable calculation methods described in paragraphs (e)(1) through (e)(4) of this 

section. If emissions from dehydrator vents are routed to a vapor recovery system, you must 

adjust the emissions downward according to paragraph (e)(5) of this section. If emissions from 

dehydrator vents are routed to a flare or regenerator fire-box/fire tubes, you must calculate CH4, 

CO2, and N2O annual emissions as specified in paragraph (e)(6) of this section.

(1) Calculation Method 1. Calculate annual mass emissions from absorbent dehydrators 

that have an annual average of daily natural gas throughput that is greater than or equal to 0.4 

million standard cubic feet per day by using a software program, such as AspenTech HYSYS® or 

GRI-GLYCalcTM, 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 
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assist pump. The following parameters must be determined by engineering estimate based on 

best available data and must be used at a minimum 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 (e.g., natural gas pneumatic/air pneumatic/electric).

(v) Absorbent circulation rate.

(vi) Absorbent type (e.g., triethylene glycol (TEG), diethylene glycol (DEG) or ethylene 

glycol (EG)).

(vii) Use of stripping 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 using one of the methods 

described in paragraphs (e)(1)(xi)(A) through (e)(1)(xi)(D) of this section.

(A) Use the GHG mole fraction as defined in paragraph (u)(2)(i) or (u)(2)(ii) of this 

section.

(B) If the GHG mole fraction cannot be determined using paragraph (u)(2)(i) or (u)(2)(ii) 

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) to sample and analyze wet natural gas composition.
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(D) If only composition data for dry natural gas is available, assume the wet natural gas is 

saturated.

(2) Calculation Method 2. Calculate annual volumetric emissions from glycol 

dehydrators that have an annual average of daily natural gas throughput that is less than 0.4 

million standard cubic feet per day using Equation W-5 of this section:

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

Where:

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

conditions in cubic feet.

EFi = Population emission factors for glycol dehydrators in thousand standard 

cubic feet per dehydrator per year. Use 73.4 for CH4 and 3.21 for CO2 at 

60 °F and 14.7 psia.

Count = Total number of glycol dehydrators that have an annual average of daily 

natural gas throughput that is less than 0.4 million standard cubic feet per 

day.

1000 = Conversion of EFi in thousand standard cubic feet to standard cubic feet.

(3) Calculation Method 3. Dehydrators that use desiccant must calculate emissions from 

the amount of gas vented from the vessel when it is depressurized for the desiccant refilling 

process using Equation W-6 of this section. Desiccant dehydrator emissions covered in this 

paragraph do not have to be calculated separately using the method specified in paragraph (i) of 

this section for blowdown vent stacks.

( )

(4* *100)

* * * *% *

1

2

2

, P

H D p P G N Es n=

(Eq. W-6)

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).
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P2 = Pressure of the gas (psia).

p = pi (3.14).

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

N = Number of dehydrator openings in the calendar year.

100 = Conversion of %G to fraction.

(4) For glycol dehydrators that use the calculation method in paragraph (e)(2) of this 

section, calculate both CH4 and CO2 mass emissions from volumetric GHGi emissions using 

calculations in paragraph (v) of this section. For desiccant dehydrators that use the calculation 

method in paragraph (e)(3) of this section, calculate both CH4 and CO2 volumetric and mass 

emissions from volumetric natural gas emissions using calculations in paragraphs (u) and (v) of 

this section. 

(5) Determine if the dehydrator unit has vapor recovery. Adjust the emissions estimated 

in paragraphs (e)(1), (e)(2), and (e)(3) 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.

(6) Calculate annual emissions from dehydrator vents to flares or regenerator fire-box/fire 

tubes as follows:

(i) Use the dehydrator vent volume and gas composition as determined in paragraphs 

(e)(1) or (e)(2) of this section for absorbent dehydrators. Use the dehydrator vent volume and gas 

composition as determined in paragraphs (e)(3) and (e)(4) of this section for dehydrators that use 

desiccant.

(ii) Use the calculation method of flare stacks in paragraph (n) of this section to 

determine dehydrator vent emissions from the flare or regenerator combustion gas vent. 
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(f) Well venting for liquids unloadings. Calculate annual volumetric natural gas 

emissions from well venting for liquids unloading using one of the calculation methods 

described in paragraphs (f)(1), (f)(2), or (f)(3) of this section. Calculate annual CH4 and CO2

volumetric and mass emissions using the method described in paragraph (f)(4) of this section.

(1) Calculation Method 1. Calculate emissions from wells with plunger lifts and wells 

without plunger lifts separately. For at least one well of each unique well tubing diameter group 

and pressure group combination in each sub-basin category (see § 98.238 for the definitions of 

tubing diameter group, pressure group, and sub-basin category), where gas wells are vented to 

the atmosphere to expel liquids accumulated in the tubing, install a recording flow meter 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 the total 

emissions from well venting to the atmosphere for liquids unloading using Equation W-7A of 

this section. For any tubing diameter group and pressure group combination in a sub-basin where 

liquids unloading occurs both with and without plunger lifts, Equation W-7A will be used twice, 

once for wells with plunger lifts and once for wells without plunger lifts.

∑=

=

h

p

Ea FR Tp

1

(Eq. W-7A)

Where:

Ea = Annual natural gas emissions for all wells of the same tubing diameter 

group and pressure group combination in a sub-basin at actual conditions, 

a, in cubic feet. Calculate emission from wells with plunger lifts and wells 

without plunger lifts separately.

h = Total number of wells of the same tubing diameter group and pressure 

group combination in a sub-basin either with or without plunger lifts.

p = Wells 1 through h of the same tubing diameter group and pressure group 

combination in a sub-basin.

Tp = Cumulative amount of time in hours of venting for each well, p, of the 

same tubing diameter group and pressure group combination in a sub-
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basin during the year. If the available venting data do not contain a record 

of the date of the venting events and data are not available to provide the 

venting hours for the specific time period of January 1 to December 31, 

you may calculate an annualized vent time, Tp, using Equation W-7B of 

this section.

FR = Average flow rate in cubic feet per hour for all measured wells of the same 

tubing diameter group and pressure group combination in a sub-basin, 

over the duration of the liquids unloading, under actual conditions as 

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

x p

p p

p

HR

T D

MP = (Eq.W-7B)

Where:

HRp = Cumulative amount of time in hours of venting for each well, p, during the 

monitoring period. 

MPp = Time period, in days, of the monitoring period for each well, p. A 

minimum of 300 days in a calendar year are required. The next period of 

data collection must start immediately following the end of data collection 

for the previous reporting year.

Dp = Time period, in days during which the well, p, was in production (365 if the 

well was in production for the entire year).

(i) Determine the well vent average flow rate (“FR” in Equation W-7A of this section) as 

specified in paragraphs (f)(1)(i)(A) through (f)(1)(i)(C) of this section for at least one well in a 

unique well tubing diameter group and pressure group combination in each sub-basin category. 

Calculate emissions from wells with plunger lifts and wells without plunger lifts separately.

(A) Calculate the average flow rate per hour of venting for each unique tubing diameter 

group and pressure group combination in each sub-basin category by dividing the recorded total 

annual flow by the recorded time (in hours) for all measured liquid unloading events with 

venting to the atmosphere.

(B) Apply the average hourly flow rate calculated under paragraph (f)(1)(i)(A) of this 

section to all wells in the same pressure group that have the same tubing diameter group, for the 

number of hours of venting these wells.
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(C) Calculate a new average flow rate every other calendar year starting with the first 

calendar year of data collection. For a new producing sub-basin category, calculate an average 

flow rate beginning in the first year of production.

(ii) Calculate natural gas volumetric emissions at standard conditions using calculations 

in paragraph (t) of this section.

(2) Calculation Method 2. Calculate the total emissions for each sub-basin from well 

venting to the atmosphere for liquids unloading without plunger lift assist using Equation W-8 of 

this section.

∑ (( ) ) ∑( ( ) ) = =

−





 



 = × × × × × + × − ×

W

p

V

q

s p p p p p p q p q

p

E V CD WD SP SFR HR Z

1 1

, ,

3 2 0.37 10 1.0 (Eq. W-8)

Where:

Es = Annual natural gas emissions for each sub-basin at standard conditions, s, 

in cubic feet per year.

W = Total number of wells with well venting for liquids unloading for each 

sub-basin.

p = Wells 1 through W with well venting for liquids unloading for each subbasin.

Vp = Total number of unloading events in the monitoring period per well, p.

0.37×10−3 = {3.14 (pi)/4}/{14.7*144} (psia converted to pounds per square feet).

CDp = Casing internal diameter for each well, p, in inches.

WDp = Well depth from either the top of the well or the lowest packer to the 

bottom of the well, for each well, p, in feet.

SPp = For each well, p, shut-in pressure or surface pressure for wells with tubing 

production, or casing pressure for each well with no packers, in pounds 

per square inch absolute (psia). If casing pressure is not available for each 

well, you may determine the casing pressure by multiplying the tubing 

pressure of each well with a ratio of casing pressure to tubing pressure 

from a well in the same sub-basin for which the casing pressure is known. 

The tubing pressure must be measured during gas flow to a flow-line. The 

shut-in pressure, surface pressure, or casing pressure must be determined 

just prior to liquids unloading when the well production is impeded by 

liquids loading or closed to the flow-line by surface valves.
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SFRp = Average flow-line rate of gas for well, p, at standard conditions in cubic 

feet per hour. Use Equation W-33 of this section to calculate the average 

flow-line rate at standard conditions.

HRp,q = Hours that each well, p, was left open to the atmosphere during each 

unloading event, q.

1.0 = Hours for average well to blowdown casing volume at shut-in pressure.

q = Unloading event.

Zp,q = If HRp,q is less than 1.0 then Zp,q is equal to 0. If HRp,q is greater than or equal 

to 1.0 then Zp,q is equal to 1.

(3) Calculation Method 3. Calculate the total emissions for each sub-basin from well 

venting to the atmosphere for liquids unloading with plunger lift assist using Equation W-9 of 

this section.

∑ (( ) ) ∑( ( ) ) = =

−





 



 = × × × × × + × − ×

W

p

V

q

s p p p p p p q p q

p

E V TD WD SP SFR HR Z

1 1

, ,

3 2 0.37 10 0.5 (Eq. W-9)

Where:

Es = Annual natural gas emissions for each sub-basin at standard conditions, s, 

in cubic feet per year.

W = Total number of wells with plunger lift assist and well venting for liquids 

unloading for each sub-basin.

p = Wells 1 through W with well venting for liquids unloading for each subbasin.

Vp = Total number of unloading events in the monitoring period for each well, 

p.

0.37×10−3 = {3.14 (pi)/4}/{14.7*144} (psia converted to pounds per square feet).

TDp = Tubing internal diameter for each well, p, in inches.

WDp = Tubing depth to plunger bumper for each well, p, in feet.

SPp = Flow-line pressure for each well, p, in pounds per square inch absolute 

(psia), using engineering estimate based on best available data.

SFRp = Average flow-line rate of gas for well, p, at standard conditions in cubic 

feet per hour. Use Equation W-33 of this section to calculate the average 

flow-line rate at standard conditions.

HRp,q = Hours that each well, p, was left open to the atmosphere during each 

unloading event, q.
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0.5 = Hours for average well to blowdown tubing volume at flow-line pressure.

q = Unloading event.

Zp,q = If HRp,q is less than 0.5 then Zp,q is equal to 0. If HRp,q is greater than or equal 

to 0.5 then Zp,q is equal to 1.

(4) Calculate CH4 and CO2 volumetric and mass emissions from volumetric natural gas 

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

(g) Gas well venting during completions and workovers with hydraulic fracturing.

Calculate annual volumetric natural gas emissions from gas well venting during completions and 

workovers involving hydraulic fracturing using Equation W-10A or Equation W-10B of this 

section. Equation W-10A applies to well venting when the flowback rate is measured from a 

specified number of example completions or workovers and Equation W-10B applies when the 

flowback vent or flare volume is measured for each completion or workover. Completion and 

workover activities are separated into two periods, an initial period when flowback is routed to 

open pits or tanks and a subsequent period when gas content is sufficient to route the flowback to 

a separator or when the gas content is sufficient to allow measurement by the devices specified in 

paragraph (g)(1) of this section, regardless of whether a separator is actually utilized. If you elect 

to use Equation W-10A of this section, you must follow the procedures specified in paragraph 

(g)(1) of this section. Emissions must be calculated separately for completions and workovers, 

for each sub-basin, and for each well type combination identified in paragraph (g)(2) of this 

section. You must calculate CH4 and CO2 volumetric and mass emissions as specified in 

paragraph (g)(3) of this section. If emissions from gas well venting during completions and 

workovers with hydraulic fracturing are routed to a flare, you must calculate CH4, CO2, and N2O 

annual emissions as specified in paragraph (g)(4) of this section. 

∑[ [ ]] =

= × × − + × ÷ ×

W

p

Es n Tp s FRMs PRs p EnFs p Tp i FRMi PRs p

1

, , , , , 2 , (Eq. W-10A)
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∑[ [ ]] =

= − + × ÷

W

p

Es n FVs p EnFs p Tp i FRp i

1

, , , , , 2 (Eq. W-10B)

Where:

Es,n = Annual volumetric natural gas emissions in standard cubic feet from gas 

well venting during completions or workovers following hydraulic 

fracturing for each sub-basin and well type combination.

W = Total number of wells completed or worked over using hydraulic 

fracturing in a sub-basin and well type combination.

Tp,s = Cumulative amount of time of flowback, after sufficient quantities of gas 

are present to enable separation, where gas is vented or flared for the 

completion or workover, in hours, for each well, p, in a sub-basin and well 

type combination during the reporting year. This may include noncontiguous periods of venting or flaring.

Tp,i = Cumulative amount of time of flowback to open tanks/pits, from when gas 

is first detected until sufficient quantities of gas are present to enable 

separation, for the completion or workover, in hours, for each well, p, in a 

sub-basin and well type combination during the reporting year. This may 

include non-contiguous periods of routing to open tanks/pits.

FRMs = Ratio of average flowback, during the period when sufficient quantities of 

gas are present to enable separation, of well completions and workovers 

from hydraulic fracturing to 30-day production rate for the sub-basin and 

well type combination, calculated using procedures specified in paragraph

(g)(1)(iii) of this section, expressed in standard cubic feet per hour.

FRMi = Ratio of initial flowback rate during well completions and workovers from 

hydraulic fracturing to 30-day production rate for the sub-basin and well 

type combination, calculated using procedures specified in paragraph 

(g)(1)(iv) of this section, expressed in standard cubic feet per hour, for the 

period of flow to open tanks/pits.

PRs,p = Average production flow rate during the first 30 days of production after 

completions of newly drilled gas wells or gas well workovers using 

hydraulic fracturing in standard cubic feet per hour of each well p, that 

was measured in the sub-basin and well type combination.

EnFs,p = Volume of N2 injected gas in cubic feet at standard conditions that was 

injected into the reservoir during an energized fracture job for each well, 

p, as determined by using an appropriate meter according to methods 

described in § 98.234(b), or by using receipts of gas purchases that are 

used for the energized fracture job. Convert to standard conditions using 

paragraph (t) of this section. If the fracture process did not inject gas into 

the reservoir or if the injected gas is CO2 then EnFs,p is 0.
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FVs,p = Flow volume vented or flared of each well, p, in standard cubic feet

measured using a recording flow meter (digital or analog) on the vent line 

to measure flowback during the separation period of the completion or 

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

FRp,i = Flow rate vented or flared of each well, p, in standard cubic feet measured 

using a recording flow meter (digital or analog) on the vent line to 

measure the flowback, at the beginning of the period of time when 

sufficient quantities of gas are present to enable separation, of the 

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

(1) If you elect to use Equation W-10A of this section, you must use Calculation Method 

1 as specified in paragraph (g)(1)(i) of this section, or Calculation Method 2 as specified in 

paragraph (g)(1)(ii) of this section, to determine the value of FRMs and FRMi. These values must 

be based on the flow rate for flowback, once sufficient gas is present to enable separation. The 

number of measurements or calculations required to estimate FRMs and FRMi must be 

determined individually for completions and workovers per sub-basin and well type as follows: 

complete measurements or calculations for a least one completion or workover for less than or 

equal to 25 completions or workovers for each well type within a sub-basin; complete 

measurements or calculations for at least two completions or workovers for 26 to 50 completions 

or workovers for each sub-basin and well type combination; complete measurements or 

calculations for at least three completions or workovers for 51 to 100 completions or workovers 

for each sub-basin and well type combination; complete measurements or calculations for at least 

four completions or workovers for 101 to 250 completions or workovers for each sub-basin and 

well type combination; and complete measurements or calculations for at least five completions 

or workovers for greater than 250 completions or workovers for each sub-basin and well type 

combination.

(i) Calculation Method 1. You must use Equation W-12A as specified in paragraph 

(g)(1)(iii) of this section to determine the value of FRMs. You must use Equation W-12B as 
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specified in paragraph (g)(1)(iv) of this section to determine the value of FRMi. The procedures 

specified in paragraphs (g)(1)(v) and (g)(1)(vi) also apply. When making flowback 

measurements for use in Equations W-12A and W-12B of this section, you must use a recording 

flow meter (digital or analog) installed on the vent line, ahead of a flare or vent, to measure the 

flowback rates in units of standard cubic feet per hour according to methods set forth in § 

98.234(b).

(ii) Calculation Method 2. You must use Equation W-12A as specified in paragraph 

(g)(1)(iii) of this section to determine the value of FRMs. You must use Equation W-12B as 

specified in paragraph (g)(1)(iv) of this section to determine the value of FRMi. The procedures 

specified in paragraphs (g)(1)(v) and (g)(1)(vi) also apply. When calculating the flowback rates 

for use in Equations W-12A and W-12B of this section based on well parameters, you must 

record the well flowing pressure immediately upstream (and immediately downstream in 

subsonic flow) of a well choke according to methods set forth in § 98.234(b) to calculate the well 

flowback. The upstream pressure must be surface pressure and reservoir pressure cannot be 

assumed. The downstream pressure must be measured after the choke and atmospheric pressure 

cannot be assumed. Calculate flowback rate using Equation W-11A of this section for subsonic 

flow or Equation W-11B of this section for sonic flow. You must use best engineering estimates 

based on best available data along with Equation W-11C of this section to determine whether the 

predominant flow is sonic or subsonic. If the value of R in Equation W-11C of this section is 

greater than or equal to 2, then flow is sonic; otherwise, flow is subsonic. Convert calculated FRa

values shall be converted from actual conditions upstream of the restriction orifice to standard 

conditions (FRs,p and FRi,p) for use in Equations W-12A and W-12B of this section using 

Equation W-33 in paragraph (t) of this section. 
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





























 − 













 = ∗

1.758

1

2

1.515

1

5 2 1.27 10 * * 3430* * P

P

P

P FRa A Tu (Eq. W-11A)

Where:

FRa = Flowback rate in actual cubic feet per hour, under actual subsonic flow 

conditions.

A = Cross sectional open area of the restriction orifice (m2

).

P1 = Pressure immediately upstream of the choke (psia).

Tu = Temperature immediately upstream of the choke (degrees Kelvin).

P2 = Pressure immediately downstream of the choke (psia).

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

1.27*105 = Conversion from m3 /second to ft3

/hour.

FRa A 08*Tu 1.27 10 * * 187. 5 = ∗ (Eq. W-11B)

Where:

FRa = Flowback rate in actual cubic feet per hour, under actual sonic flow 

conditions.

A = Cross sectional open area of the restriction orifice (m2).

Tu = Temperature immediately upstream of the choke (degrees Kelvin).

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

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

2

1

P R = P

(Eq. W-11C)

Where:

R = Pressure ratio.

P1 = Pressure immediately upstream of the choke (psia).

P2 = Pressure immediately downstream of the choke (psia).

(iii) For Equation W-10A of this section, calculate FRMs using Equation W-12A of this 

section.
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∑

∑

=

= = N

p

s p

N

p

s p

s

PR

FR

FRM

1

,

1

,

(Eq. W-12A)

Where:

FRMs = Ratio of average flowback rate, during the period of time when sufficient 

quantities of gas are present to enable separation, of well completions and 

workovers from hydraulic fracturing to 30-day production rate for each 

sub-basin and well type combination.

FRs,p = Measured average flowback rate from Calculation Method 1 described in 

paragraph (g)(1)(i) of this section or calculated average flowback rate 

from Calculation Method 2 described in paragraph (g)(1)(ii) of this 

section, during the separation period in standard cubic feet per hour for 

well(s) p for each sub-basin and well type combination. Convert measured 

and calculated FRa values shall be converted from actual conditions 

upstream of the restriction orifice (FRa) to standard conditions (FRs,p) for 

each well p using Equation W-33 in paragraph (t) of this section. You may 

not use flow volume as used in Equation W-10B converted to a flow rate 

for this parameter.

PRs,p = Average production flow rate during the first 30 days of production after 

completions of newly drilled gas wells or gas well workovers using 

hydraulic fracturing, in standard cubic feet per hour for each well, p, that 

was measured in the sub-basin and well type combination.

N = Number of measured or calculated well completions or workovers using 

hydraulic fracturing in a sub-basin and well type combination.

(iv) For Equation W-10A of this section, calculate FRMi using Equation W-12B of this 

section. 

,

1

,

1

N

i p

p

i N

s p

p

FR

FRM

PR

=

=

=

∑

∑

(Eq. W-12B)

Where:

FRMi = Ratio of flowback gas rate while flowing to open tanks/pits during well 

completions and workovers from hydraulic fracturing to 30-day 

production rate.

FRi,p = Initial measured gas flowback rate from Calculation Method 1 described 

in paragraph (g)(1)(i) of this section or initial calculated flow rate from 
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Calculation Method 2 described in paragraph (g)(1)(ii) of this section in 

standard cubic feet per hour for well(s), p, for each sub-basin and well 

type combination. Measured and calculated FRi,p values must be based on 

flow conditions at the beginning of the separation period and must be 

expressed at standard conditions.

PRs,p = Average production flow rate during the first 30-days of production after 

completions of newly drilled gas wells or gas well workovers using 

hydraulic fracturing, in standard cubic feet per hour of each well, p, that 

was measured in the sub-basin and well type combination.

N = Number of measured or calculated well completions or workovers using 

hydraulic fracturing in a sub-basin and well type combination.

(v) For Equation W-10A of this section, the ratio of flowback rate during well 

completions and workovers from hydraulic fracturing to 30-day production rate for horizontal 

and vertical wells are applied to all horizontal and vertical well completions in the gas producing 

sub-basin and well type combination and to all horizontal and vertical well workovers, 

respectively, in the gas producing sub-basin and well type combination for the total number of 

hours of flowback and for the first 30 day average production rate for each of these wells.

(vi) For Equation W-12A and W-12B of this section, calculate new flowback rates for 

horizontal and vertical gas well completions and horizontal and vertical gas well workovers in 

each sub-basin category once every two years starting in the first calendar year of data collection.

(2) For paragraphs (g) and (g)(1) of this section, measurements and calculations are 

completed separately for workovers and completions per sub-basin and well type combination. A 

well type combination is a unique combination of the parameters listed in paragraphs (g)(2)(i) 

through (g)(2)(iii) of this section. 

(i) Vertical or horizontal (directional drilling).

(ii) With flaring or without flaring.

(iii) Reduced emission completion/workover or not reduced emission 

completion/workover.
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(3) Calculate both CH4 and CO2 volumetric and mass emissions from total natural gas 

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

(4) Calculate annual emissions from gas well venting during well completions and 

workovers from hydraulic fracturing where all or a portion of the gas is flared as specified in 

paragraphs (g)(4)(i) and (g)(4)(ii) of this section.

(i) Use the volumetric total natural gas emissions vented to the atmosphere during well 

completions and workovers as determined in paragraph (g) of this section to calculate volumetric 

and mass emissions using paragraphs (u) and (v) of this section.

(ii) Use the calculation method of flare stacks in paragraph (n) of this section to adjust 

emissions for the portion of gas flared during well completions and workovers using hydraulic 

fracturing. This adjustment to emissions from completions using flaring, versus completions 

without flaring, accounts for the conversion of CH4 to CO2 in the flare and for the formation on 

N2O during flaring.

(h) Gas well venting during completions and workovers without hydraulic fracturing.

Calculate annual volumetric natural gas emissions from each gas well venting during workovers 

without hydraulic fracturing using Equation W-13A of this section. Calculate annual volumetric 

natural gas emissions from each gas well venting during completions without hydraulic 

fracturing using Equation W-13B of this section. You must convert annual volumetric natural 

gas emissions to CH4 and CO2 volumetric and mass emissions as specified in paragraph (h)(1) of 

this section. If emissions from gas well venting during completions and workovers without 

hydraulic fracturing are routed to a flare, you must calculate CH4, CO2, and N2O annual 

emissions as specified in paragraph (h)(2) of this section.

Es wo Nwo EFwo * , = (Eq. W-13A)
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p

f

p

Es p Vp* T

1

, ∑=

= (Eq. W-13B)

Where:

Es,wo = Annual volumetric natural gas emissions in standard cubic feet from gas 

well venting during well workovers without hydraulic fracturing.

Nwo = Number of workovers per sub-basin category that do not involve hydraulic 

fracturing in the reporting year.

EFwo = Emission factor for non-hydraulic fracture well workover venting in 

standard cubic feet per workover. Use 3,114 standard cubic feet natural 

gas per well workover without hydraulic fracturing.

Es,p = Annual volumetric natural gas emissions in standard cubic feet from gas 

well venting during well completions without hydraulic fracturing.

p = Well completions 1 through f in a sub-basin.

f = Total number of well completions without hydraulic fracturing in a subbasin category.

Vp = Average daily gas production rate in standard cubic feet per hour for each 

well, p, undergoing completion without hydraulic fracturing. This is the 

total annual gas production volume divided by total number of hours the 

wells produced to the flow-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.

Tp = Time that gas is vented to either the atmosphere or a flare for each well, p, 

undergoing completion without hydraulic fracturing, in hours during the 

year.

(1) Calculate both CH4 and CO2 volumetric emissions from natural gas volumetric 

emissions using calculations in paragraph (u) of this section. Calculate both CH4 and CO2 mass 

emissions from volumetric emissions vented to atmosphere using calculations in paragraph (v) of 

this section.

(2) Calculate annual emissions of CH4, CO2, and N2O from gas well venting to flares 

during well completions and workovers not involving hydraulic fracturing as specified in

paragraphs (h)(2)(i) and (h)(2)(ii) of this section.
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(i) Use the gas well venting volume and gas composition during well completions and 

workovers that are flared as determined using the methods specified in paragraphs (h) and (h)(1) 

of this section.

(ii) Use the calculation method of flare stacks in paragraph (n) of this section to 

determine emissions from the flare for gas well venting to a flare during completions and 

workovers without hydraulic fracturing.

(i) Blowdown vent stacks. Calculate CO2 and CH4 blowdown vent stack emissions from 

the depressurization of equipment to reduce system pressure for planned or emergency 

shutdowns resulting from human intervention or to take equipment out of service for 

maintenance as specified in either paragraph (i)(2) or (i)(3) of this section. Equipment with a 

unique physical volume of less than 50 cubic feet as determined in paragraph (i)(1) of this 

section are not subject to the requirements in paragraphs (i)(2) through (i)(4) this section. The 

requirements in this paragraph (i) do not apply to blowdown vent stack emissions from 

depressurizing to a flare, over-pressure relief, operating pressure control venting, blowdown of 

non-GHG gases, and desiccant dehydrator blowdown venting before reloading. 

(1) Method for calculating unique physical volumes. You must calculate each unique 

physical volume (including pipelines, compressor case or cylinders, manifolds, suction bottles, 

discharge bottles, and vessels) between isolation valves, in cubic feet, by using engineering 

estimates based on best available data.

(2) Method for determining emissions from blowdown vent stacks according to 

equipment type. If you elect to determine emissions according to each equipment type, using 

unique physical volumes as calculated in paragraph (i)(1) of this section, you must calculate 

emissions as specified in paragraphs (i)(2)(i) through (i)(2)(iii) of this section for each equipment 
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type. Equipment types must be grouped into the following seven categories: station piping, 

pipeline venting, compressors, scrubbers/strainers, pig launchers and receivers, emergency 

shutdowns, and all other blowdowns greater than or equal to 50 cubic feet.

(i) Calculate the total annual natural gas emissions from each unique physical volume 

that is blown down using either Equation W-14A or W-14B of this section.

( )

( ) ,

459.67

* *

459.67

s a

s n

a sa

T P

E N V V C

T PZ

    + =     − +    

(Eq. W-14A)

Where:

Es,n = Annual natural gas emissions at standard conditions from each unique 

physical volume that is blown down, in cubic feet.

N = Number of occurrences of blowdowns for each unique physical volume in 

the calendar year. You must retain logs documenting the number of 

occurrences of blowdowns for each unique physical volume in the 

calendar year.

V = Unique physical volume between isolation valves, in cubic feet, as 

calculated in paragraph (i)(1) of this section.

C = Purge factor is 1 if the unique physical volume is not purged, or 0 if the 

unique physical volume is purged using non-GHG gases.

Ts = Temperature at standard conditions (60 °F).

Ta = Temperature at actual conditions in the unique physical volume (°F).

Ps = Absolute pressure at standard conditions (14.7 psia).

Pa = Absolute pressure at actual conditions in the unique physical volume 

(psia).

Za = Compressibility factor at actual conditions for natural gas. You may use 1 if 

the temperature is above -10 degrees Fahrenheit and pressure is below 5 

atmospheres, or if the compressibility factor at the actual temperature and 

pressure is 0.98 or greater. 

( )( )

( )

,, ,,

,

1 ,

459.67

459.67

N

s ab p ae p

p s n

p ap s a

TP P

E V = T PZ

    + − =    

+    

∑ (Eq. W-14B)

Where:
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Es,n = Annual natural gas emissions at standard conditions from each unique 

physical volume that is blown down, in cubic feet.

p = Individual occurrence of blowdown for the same unique physical volume.

N = Number of occurrences of blowdowns for each unique physical volume in 

the calendar year. You must retain logs documenting the number of 

occurrences of blowdowns for each unique physical volume in the 

calendar year.

Vp = Unique physical volume between isolation valves, in cubic feet, for each 

blowdown “p.”

Ts = Temperature at standard conditions (60 °F).

Ta,p = Temperature at actual conditions in the unique physical volume (°F) for 

each blowdown “p”.

Ps = Absolute pressure at standard conditions (14.7 psia).

Pa,b,p = Absolute pressure at actual conditions in the unique physical volume 

(psia) at the beginning of the blowdown “p”.

Pa,e,p = Absolute pressure at actual conditions in the unique physical volume 

(psia) at the end of the blowdown “p”; 0 if blowdown volume is purged 

using non-GHG gases.

Za = Compressibility factor at actual conditions for natural gas. You may use 1 if 

the temperature is above -10 degrees Fahrenheit and pressure is below 5 

atmospheres, or if the compressibility factor at the actual temperature and 

pressure is 0.98 or greater.

(ii) Calculate the annual natural gas emissions, in cubic feet, from each equipment type 

by summing Es,n, as calculated in either Equation W-14A or Equation W-14B of this subpart, for 

all unique physical volumes associated with the equipment type.

(iii) Calculate total annual CH4 and CO2 volumetric and mass emissions from each 

equipment type by using the annual natural gas emission value calculated in paragraph (i)(2)(ii) 

of this section for the equipment type and the calculation method specified in paragraph (i)(4) of 

this section.

(3) Method for determining emissions from blowdown vent stacks using a flow meter. In 

lieu of determining emissions from blowdown vent stacks using unique physical volumes as 
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specified in paragraphs (i)(1) and (i)(2) of this section, you may use a flow meter and measure 

blowdown vent stack emissions. If you choose to use this method, you must measure the natural 

gas emissions from the blowdown(s) at the facility using a flow meter according to methods in § 

98.234(b), and calculate annual CH4 and CO2 volumetric and mass emissions measured by the 

meters according to paragraph (i)(4) of this section.

(4) Method for converting from natural gas emissions to GHG volumetric and mass 

emissions. Calculate both CH4 and CO2 volumetric and mass emissions using the methods 

specified in paragraphs (u) and (v) 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), as specified in this paragraph (j). For wells 

flowing to gas-liquid separators with annual average daily throughput of oil greater than or equal 

to 10 barrels per day, calculate annual CH4 and CO2 using Calculation Method 1 or 2 as specified 

in paragraphs (j)(1) and (j)(2) of this section. For wells flowing directly to atmospheric storage 

tanks without passing through a wellhead separator with throughput greater than 10 barrels per 

day, calculate annual CH4 and CO2 emissions using Calculation Method 2 as specified in 

paragraph (j)(2) of this section. For wells flowing to gas-liquid separators or directly to 

atmospheric storage tanks with throughput less than 10 barrels per day, use Calculation Method 

3 as specified in paragraphs (j)(3) of this section. You must also calculate emissions that may 

have occurred due to dump valves not closing properly using the method specified in paragraph 

(j)(6) of this section. If emissions from atmospheric pressure fixed roof storage tanks are routed 

to a vapor recovery system, you must adjust the emissions downward according to paragraph 
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(j)(4) of this section. If emissions from atmospheric pressure fixed roof storage tanks are routed 

to a flare, you must calculate CH4, CO2, and N2O annual emissions as specified in paragraph 

(j)(5) of this section.

(1) Calculation Method 1. 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. The following parameters 

must be determined for typical operating conditions over the year by engineering estimate and 

process knowledge based on best available data, and must be used at a minimum to characterize 

emissions from liquid transferred to tanks:

* * * * *

(vii) Separator oil composition and Reid vapor pressure. If this data is not available, 

determine these parameters by using one of the methods described in paragraphs (j)(1) (vii)(A) 

through (j)(1)(vii)(C) of this section.

* * * * *

(2) Calculation Method 2. Calculate annual CH4 and CO2 emissions by assuming that all 

of the CH4 and CO2 in solution at separator temperature and pressure is emitted from oil sent to 

storage tanks, using either of the methods in paragraphs (j)(2)(i) or (j)(2)(ii) 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 as described in § 98.234(b) 

to sample and analyze separator oil composition at separator pressure and temperature.
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* * * * *

(3) Calculation Method 3. Calculate CH4 and CO2 emissions using Equation W-15 of this 

section:

Es,i= EFi*Count *1000 (Eq. W-15)

Where:

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

conditions in cubic feet.

EFi = Population emission factor for separators or wells in thousand standard 

cubic feet per separator or well per year, for crude oil use 4.2 for CH4 and 

2.8 for CO2 at 60 °F and 14.7 psia, and for gas condensate use 17.6 for 

CH4 and 2.8 for CO2 at 60 °F and 14.7 psia.

Count = Total number of separators or wells with annual average daily throughput 

less than 10 barrels per day. Count only separators or wells that feed oil 

directly to the storage tank.

1,000 = Conversion from thousand standard cubic feet to standard cubic feet.

(4) 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)(3) 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]

(5) 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 method of flare stacks in paragraph (n) of this section to 

determine storage tank emissions from the flare.
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(6) 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. 





 



 = n

n

s i o n T E E CF *

8760

* , , (Eq. W-16)

Where:

Es,i,o = Annual volumetric GHG emissions at standard conditions from each 

storage tank in cubic feet that resulted from the dump valve on the gasliquid separator not closing properly.

En = Storage tank emissions as determined in Calculation Methods 1, 2, or 3 in 

paragraphs (j)(1), (j)(2), and (j)(3) of this section (with wellhead 

separators) in standard cubic feet per year. 

Tn = Total time a dump valve is not closing properly in the calendar year in

hours. Estimate Tn based on maintenance, operations, or routine well pad 

inspections that indicate the period of time when the valve was 

malfunctioning in open or partially open position. 

CFn = Correction factor for tank emissions for time period Tn is 2.87 for crude oil 

production. Correction factor for tank emissions for time period Tn is 4.37 

for gas condensate production. 

8,760 = Conversion to hourly emissions.

(7) Calculate both CH4 and CO2 mass emissions from natural gas volumetric emissions 

using calculations in paragraph (v) of this section.

(k) Transmission storage tanks. For vent stacks connected to one or more transmission 

condensate storage tanks, either water or hydrocarbon, without vapor recovery, in onshore 

natural gas transmission compression, calculate CH4 and CO2 annual emissions from compressor 

scrubber dump valve leakage as specified in paragraphs (k)(1) through (k)(3) of this section. If 

emissions from compressor scrubber dump valve leakage are routed to a flare, you must 

calculate CH4, CO2, and N2O annual emissions as specified in paragraph (k)(4) of this section.
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(1) Except as specified in paragraph (k)(1)(iv) of this section, you must monitor the tank 

vapor vent stack annually for emissions using one of the methods specified in paragraphs 

(k)(1)(i) through (k)(1)(iii) of this section.

(i) Use an optical gas imaging instrument according to methods set forth in § 

98.234(a)(1).

(ii) Measure the tank vent directly using a flow meter or high volume sampler according 

to methods in § 98.234(b) or (d) for a duration of 5 minutes.

(iii) Measure the tank vent using a calibrated bag according to methods in § 98.234(c) for 

a duration of 5 minutes or until the bag is full, whichever is shorter. 

(iv) 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 from the vent stack are continuous for 5 minutes, or the acoustic 

leak detection device detects a leak, then you must use one of the methods in either paragraph 

(k)(2)(i) or (k)(2)(ii) of this section and the requirements specified in paragraphs (k)(2)(iii) and 

(k)(2)(iv) of this section to quantify annual emissions.

(i) Use a flow meter, such as a turbine meter, calibrated bag, or high volume sampler to 

estimate tank vapor volumes from the vent stack according to methods set forth in § 98.234(b) 

through (d). If you do not have a continuous flow measurement device, you may install a flow 

measuring device on the tank vapor vent stack. If the vent is directly measured for five minutes 

under paragraph (k)(1)(ii) or (k)(1)(iii) of this section to detect continuous leakage, this serves as 

the measurement.

(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).
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(iii) Use the appropriate gas composition in paragraph (u)(2)(iii) of this section.

(iv) Calculate CH4 and CO2 volumetric and mass emissions at standard conditions using 

calculations in paragraphs (t), (u), and (v) of this section, as applicable to the monitoring 

equipment used.

(3) If a leaking dump valve is identified, the leak must be counted as having occurred 

since the beginning of the calendar year, or from the previous test that did not detect leaking in 

the same calendar year. If the leaking dump valve is fixed following leak detection, the leak 

duration will end upon being repaired. If a leaking dump valve is identified and not repaired, the 

leak must be counted as having occurred through the rest of the calendar year.

(4) Calculate annual emissions from storage tanks to flares as specified in paragraphs 

(k)(4)(i) and (k)(4)(ii) of this section.

(i) Use the storage tank emissions volume and gas composition as determined in 

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

(ii) Use the calculation method of flare stacks in paragraph (n) of this section to 

determine storage tank emissions sent to a flare.

(l) Well testing venting and flaring. Calculate CH4 and CO2 annual emissions from well 

testing venting as specified in paragraphs (l)(1) through (l)(5) of this section. If emissions from 

well testing venting are routed to a flare, you must calculate CH4, CO2, and N2O annual 

emissions as specified in paragraph (l)(6) of this section.

* * * * *

(2) If GOR cannot be determined from your available data, then you must measure 

quantities reported in this section according to one of the procedures specified in paragraph 

(l)(2)(i) or (l)(2)(ii) of this section to determine GOR.
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* * * * *

(ii) You may use an industry standard practice as described in § 98.234(b).

(3) Estimate venting emissions using Equation W-17A (for oil wells) or Equation W-17B 

(for gas wells) of this section.

* * * * *

FR = Average annual flow rate in barrels of oil per day for the oil well(s) being 

tested.

* * * * *

D = Number of days during the calendar year that the well(s) is tested.

* * * * *

(5) Calculate both CH4 and CO2 volumetric and mass emissions from natural gas 

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

(6) Calculate emissions from well testing if emissions are routed to a flare as specified in 

paragraphs (l)(6)(i) and (l)(6)(ii) of this section.

(i) Use the well testing emissions volume and gas composition as determined in 

paragraphs (l)(1) through (4) of this section.

(ii) Use the calculation method 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 and CO2 annual emissions from 

associated gas venting not in conjunction with well testing (refer to paragraph (l): Well testing 

venting and flaring of this section) as specified in paragraphs (m)(1) through (m)(4) of this 

section. If emissions from associated gas venting are routed to a flare, you must calculate CH4, 

CO2, and N2O annual emissions as specified in paragraph (m)(5) of this section.
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(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, use the GOR from a 

cluster of wells in the same sub-basin category.

(2) If GOR cannot be determined from your available data, then you must use one of the 

procedures specified in paragraphs (m)(2)(i) or (m)(2)(ii) 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) You may use an industry standard practice as described in § 98.234(b).

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

, , , , , 1 1

y x

s n pq pq p q p q

q p

E GOR V SG ERE = =

= ∗− − ∑∑ (Eq. W-18)

Where:

Es,n = Annual volumetric natural gas emissions, at the facility level, from 

associated gas venting at standard conditions, in cubic feet.

GORp,q = Gas to oil ratio, for well p in sub-basin q, in standard cubic feet of gas per 

barrel of oil; oil here refers to hydrocarbon liquids produced of all API 

gravities.

Vp,q = Volume of oil produced, for well p in sub-basin q, in barrels in the 

calendar year during time periods in which associated gas was vented or 

flared.

SGp,q = Volume of associated gas sent to sales, for well p in sub-basin q, in 

standard cubic feet of gas in the calendar year during time periods in 

which associated gas was vented or flared.

EREp,q = Emissions reported elsewhere, volume of associated gas for well p in subbasin q, in standard cubic feet, during time periods in which associated gas 

was vented or flared and for which emission source types of this section 

calculate and report emissions from the associated gas stream prior to 

venting or flaring of the associated gas (i.e., § 98.233(j) for onshore 

production storage tanks).

x = Total number of wells in sub-basin that vent or flare associated gas.

y = Total number of sub-basins in a basin that contain wells that vent or flare 

associated gas.
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(4) Calculate both CH4 and CO2 volumetric and mass emissions from volumetric natural 

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

(5) Calculate emissions from associated natural gas if emissions are routed to a flare as 

specified in paragraphs (m)(5)(i) and (m)(5)(ii) of this section.

(i) Use the associated natural gas volume and gas composition as determined in 

paragraph (m)(1) through (m)(4) of this section.

(ii) Use the calculation method 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 

specified in paragraphs (n)(1) through (n)(9) of this section.

(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 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 specified in paragraphs (n)(2)(i) through (n)(2)(iii) of this 

section.

(i) For onshore natural gas production, determine the GHG mole fraction using paragraph 

(u)(2)(i) of this section.
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(ii) For onshore natural gas processing, when the stream going to flare is natural gas, use 

the GHG mole fraction in feed natural gas for all streams 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. For onshore natural gas processing plants 

that solely fractionate a liquid stream, use the GHG mole fraction in feed natural gas liquid for 

all streams.

(iii) For any applicable industry segment, when the stream going to the flare is a 

hydrocarbon product stream, such as methane, ethane, propane, butane, pentane-plus and mixed 

light hydrocarbons, then you may 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) Convert GHG volumetric emissions to standard conditions using calculations in 

paragraph (t) of this section. 

(5) Calculate GHG volumetric emissions from flaring at standard conditions using 

Equations W-19 and W-20 of this section.

E VX s CH s CH , 4 4 = −+ * *1 * ( η ) Z Z L U     (Eq. W-19)

( )

5

, 2 2

1

s * *** *

s CO CO s j j L

j

E VX VY R Z η

=

= +∑ (Eq. W-20)

Where:

Es,CH4 = Annual CH4 emissions from flare stack in cubic feet, at standard 

conditions.
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Es,CO2 = Annual CO2 emissions from flare stack in cubic feet, at standard 

conditions.

Vs = Volume of gas sent to flare in standard cubic feet, during the year as 

determined in paragraph (n)(1) of this section.

η = Flare combustion efficiency, expressed as fraction of gas combusted by a 

burning flare (default is 0.98).

XCH4 = Mole fraction of CH4 in the feed gas to the flare as determined in 

paragraph (n)(2) of this section.

XCO2 = Mole fraction of CO2 in the feed gas to the flare as determined in 

paragraph (n)(2) of this section.

ZU = Fraction of the feed gas sent to an un-lit flare determined by engineering 

estimate and process knowledge based on best available data and 

operating records.

ZL = Fraction of the feed gas sent to a burning flare (equal to 1- ZU).

Yj = Mole fraction of hydrocarbon constituents j (such as methane, ethane, 

propane, butane, and pentanes-plus) in the feed gas to the flare as 

determined in paragraph (n)(1) of this section.

Rj = Number of carbon atoms in the hydrocarbon constituent j in the feed gas to 

the flare: 1 for methane, 2 for ethane, 3 for propane, 4 for butane, and 5 for 

pentanes-plus).

(6) Calculate both CH4 and CO2 mass emissions from volumetric emissions using 

calculation in paragraph (v) of this section.

(7) Calculate N2O emissions from flare stacks using Equation W-40 in paragraph (z) of 

this section.

(8) If you operate and maintain a CEMS that has both a CO2 concentration monitor and 

volumetric flow rate monitor for the combustion gases from the flare, you must calculate only 

CO2 emissions for the flare. You must follow the Tier 4 Calculation Method and all associated 

calculation, quality assurance, reporting, and recordkeeping requirements for Tier 4 in subpart C 

of this part (General Stationary Fuel Combustion Sources). If a CEMS is used to calculate flare 

stack emissions, the requirements specified in paragraphs (n)(1) through (n)(7) are not required.
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(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. If you are required to report emissions from 

centrifugal compressor venting as specified in § 98.232(d)(2), (e)(2), (f)(2), (g)(2), and (h)(2), 

you must conduct volumetric emission measurements specified in paragraph (o)(1) of this 

section using methods specified in paragraphs (o)(2) through (o)(5) of this section; perform 

calculations specified in paragraphs (o)(6) through (o)(9) of this section; and calculate CH4 and 

CO2 mass emissions as specified in paragraph (o)(11) of this section. If emissions from a 

compressor source are routed to a flare, paragraphs (o)(1) through (o)(11) of this section do not 

apply and instead you must calculate CH4, CO2, and N2O emissions as specified in paragraph 

(o)(12) of this section. If emissions from a compressor source are captured for fuel use or are 

routed to a thermal oxidizer, paragraphs (o)(1) through (o)(12) of this section do not apply and 

instead you must calculate and report emissions as specified in subpart C of this part. If 

emissions from a compressor source are routed to vapor recovery, the calculations specified in 

paragraphs (o)(1) through (o)(12) of this section do not apply. If you are required to report 

emissions from centrifugal compressor venting at an onshore petroleum and natural gas 

production facility as specified in § 98.232(c)(19), you must calculate volumetric emissions as 

specified in paragraph (o)(10) of this section; and calculate CH4 and CO2 mass emissions as 

specified in paragraph (o)(11) of this section.

(1) General requirements for conducting volumetric emission measurements. You must 

conduct volumetric emission measurements on each centrifugal compressor as specified in this 

paragraph. Compressor sources (as defined in § 98.238) without manifolded vents must use a 
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measurement method specified in paragraph (o)(1)(i) or (o)(1)(ii) of this section. Manifolded 

compressor sources (as defined in § 98.238) must use a measurement method specified in 

paragraph (o)(1)(i), (o)(1)(ii), (o)(1)(iii), or (o)(1)(iv) of this section. 

(i) Centrifugal compressor source as found leak measurements. Measure venting from 

each compressor according to either paragraph (o)(1)(i)(A) or (o)(1)(i)(B) of this section at least 

once annually, based on the compressor mode (as defined in § 98.238) in which the compressor 

was found at the time of measurement, except as specified in paragraphs (o)(1)(i)(C) and 

(o)(1)(i)(D) of this section. If additional measurements beyond the required annual testing are 

performed (including duplicate measurements or measurement of additional operating modes), 

then all measurements satisfying the applicable monitoring and QA/QC that is required by this 

paragraph (o) must be used in the calculations specified in this section.

(A) For a compressor measured in operating-mode, you must measure volumetric 

emissions from blowdown valve leakage through the blowdown vent as specified in either 

paragraph (o)(2)(i)(A) or (o)(2)(i)(B) of this section and, if the compressor has wet seal oil 

degassing vents, measure volumetric emissions from wet seal oil degassing vents as specified in 

paragraph (o)(2)(ii) of this section. If a compressor has a continuously operating vapor recovery 

system for the wet seal degassing, then measurement of wet seal degassing is not required. 

(B) For a compressor measured in not-operating-depressurized-mode, you must measure 

volumetric emissions from isolation valve leakage as specified in either paragraph (o)(2)(i)(A), 

(o)(2)(i)(B), or (o)(2)(i)(C) of this section. If a compressor is not operated and has blind flanges 

in place throughout the reporting period, measurement is not required in this compressor mode.

(C) You must measure the compressor as specified in paragraph (o)(1)(i)(B) of this 

section at least once in any three consecutive calendar years, provided the measurement can be 
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taken during a scheduled shutdown. If three consecutive calendar years occur without measuring 

the compressor in not-operating-depressurized-mode, you must measure the compressor as 

specified in paragraph (o)(1)(i)(B) of this section at the next scheduled depressurized shutdown. 

The requirement specified in this paragraph does not apply if the compressor has blind flanges in 

place throughout the reporting year.

(D) You must measure the compressor as specified in paragraph (o)(1)(i)(A) of this 

section at least once in any three consecutive calendar years, provided that the measurement can 

be taken when the compressor is in operating-mode. If three consecutive calendar years occur 

without measuring the compressor in operating-mode, you must measure the compressor as 

specified in paragraph (o)(1)(i)(A) of this section in the next calendar year that the compressor is 

in operating-mode for more than 2,000 hours. 

(ii) Centrifugal compressor source continuous monitoring. Instead of measuring the 

compressor source according to paragraph (o)(1)(i) of this section for a given compressor, you 

may elect to continuously measure volumetric emissions from a compressor source as specified 

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

(iii) Manifolded centrifugal compressor source as found leak measurements. For a 

compressor source that is part of a manifolded group of compressor sources (as defined in § 

98.238), instead of measuring the compressor source according to paragraph (o)(1)(i), (o)(1)(ii), 

or (o)(1)(iv) of this section, you may elect to measure combined volumetric emissions from the 

manifolded group of compressor sources by conducting leak measurements at the common vent 

stack as specified in paragraph (o)(4) of this section. The leak measurements must be conducted 

at the frequency specified in paragraphs (o)(1)(iii)(A) through (o)(1)(iii)(C) of this section.
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(A) A minimum of three leak measurements must be taken for each manifolded group of 

compressor sources in a calendar year.

(B) The leak measurements may be performed while the compressors are in any 

compressor mode.

(C) The three required leak measurements must be separated by a minimum of 60 days. If 

more than two leak measurements are performed, the first and last measurements in a calendar 

year must be separated by a minimum of 120 days.

(iv) Manifolded centrifugal compressor source continuous monitoring. For a compressor 

source that is part of a manifolded group of compressor sources, instead of measuring the 

compressor source according to paragraph (o)(1)(i), (o)(1)(ii), or (o)(1)(iii) of this section, you 

may elect to continuously measure combined volumetric emissions from the manifolded group of 

compressor sources as specified in paragraph (o)(5) of this section. 

(2) Methods for performing as found leak measurements from individual centrifugal 

compressor sources. If conducting leak measurements for each compressor source, you must 

determine the volumetric emissions of leaks from blowdown valves and isolation valves as 

specified in paragraph (o)(2)(i) of this section, and the volumetric emissions of leaks from wet 

seal oil degassing vents as specified in paragraph (o)(2)(ii) of this section.

(i) For blowdown valves on compressors in operating-mode and for isolation valves on 

compressors in not-operating-depressurized-mode, determine the volumetric emissions of leaks 

using one of the methods specified in paragraphs (o)(2)(i)(A) through (o)(2)(i)(C) of this section. 

(A) Measure the volumetric flow at standard conditions from the blowdown vent using 

calibrated bagging or high volume sampler according to methods set forth in § 98.234(c) and § 

98.234(d), respectively. 
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(B) Measure the volumetric flow at standard conditions from the blowdown vent using a 

temporary meter such as a vane anemometer according to methods set forth in § 98.234(b). 

(C) For isolation valves, you may use an acoustic leak detection device according to 

methods set forth in § 98.234(a) instead of measuring the isolation valve leakage through the 

blowdown vent as provided for in paragraphs (o)(2)(i)(A) or (o)(2)(i)(B) of this section.

(ii) For wet seal oil degassing vents in operating-mode, determine vapor volumes at 

standard conditions, using a temporary meter such as a vane anemometer or permanent flow 

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

(3) Methods for continuous leak measurement from individual centrifugal compressor 

sources. If you elect to conduct continuous volumetric emission measurements for an individual 

compressor source as specified in paragraph (o)(1)(ii) of this section, you must measure 

volumetric emissions as specified in paragraphs (o)(3)(i) and (o)(3)(ii) of this section.

(i) Continuously measure the volumetric flow for the individual compressor source at 

standard conditions using a permanent meter according to methods set forth in § 98.234(b). 

(ii) If compressor blowdown emissions are included in the metered emissions specified in 

paragraph (o)(3)(i) of this section, the compressor blowdown emissions may be included with the 

reported emissions for the compressor source and do not need to be calculated separately using 

the method specified in paragraph (i) of this section for blowdown vent stacks.

(4) Methods for performing as found leak measurements from manifolded groups of 

centrifugal compressor sources. If conducting leak measurements for a manifolded group of 

compressor sources, you must measure volumetric emissions of leaks as specified in paragraphs 

(o)(4)(i) and (o)(4)(ii) of this section.
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(i) Measure at a single point in the manifold downstream of all compressor inputs and 

where emissions cannot be comingled with other non-compressor emission sources. 

(ii) Determine the volumetric flow at standard conditions from the common stack using 

one of the methods specified in paragraph (o)(4)(ii)(A) through (o)(4)(ii)(C). 

(A) A temporary meter such as a vane anemometer according the methods set forth in § 

98.234(b).

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

(C) A high volume sampler according to methods set forth § 98.234(d).

(5) Methods for continuous leak measurement from manifolded groups of centrifugal 

compressor sources. If you elect to conduct continuous volumetric emission measurements for a 

manifolded group of compressor sources as specified in paragraph (o)(1)(iv) of this section, you 

must measure volumetric emissions as specified in paragraphs (o)(5)(i) through (o)(5)(iii) of this 

section.

(i) Measure at a single point in the manifold downstream of all compressor inputs and 

where emissions cannot be comingled with other non-compressor emission sources. 

(ii) Continuously measure the volumetric flow for the manifolded group of compressor 

sources at standard conditions using a permanent meter according to methods set forth in § 

98.234(b). 

(iii) If compressor blowdown emissions are included in the metered emissions specified 

in paragraph (o)(5)(ii) of this section, the compressor blowdown emissions may be included with 

the reported emissions for the manifolded group of compressor sources and do not need to be 

calculated separately using the method specified in paragraph (i) of this section for blowdown 

vent stacks.
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(6) Method for calculating volumetric GHG emissions from as found leak measurements 

for individual centrifugal compressor sources. For compressor sources measured according to 

paragraph (o)(1)(i) of this section, you must calculate annual GHG emissions from the 

compressor sources as specified in paragraphs (o)(6)(i) through (o)(6)(iv) of this section.

(i) Using Equation W-21 of this section, calculate the annual volumetric GHG emissions 

for each centrifugal compressor mode-source combination specified in paragraphs (o)(1)(i)(A) 

and (o)(1)(i)(B) of this section that was measured during the reporting year. 

Es,i,m MTs,m Tm GHGi,m = * * (Eq. W-21)

Where:

Es,i,m = Annual volumetric GHGi (either CH4 or CO2) emissions for measured 

compressor mode-source combination m, at standard conditions, in cubic 

feet.

MTs,m = Volumetric gas emissions for measured compressor mode-source 

combination m, in standard cubic feet per hour, measured according to 

paragraph (o)(2) of this section. If multiple measurements are performed 

for a given mode-source combination m, use the average of all 

measurements.

Tm = Total time the compressor is in the mode-source combination for which 

Es,i,m is being calculated in the reporting year, in hours.

GHGi,m = Mole fraction of GHGi in the vent gas for measured compressor modesource combination m; use the appropriate gas compositions in paragraph 

(u)(2) of this section.

m = Compressor mode-source combination specified in paragraph (o)(1)(i)(A) or 

(o)(1)(i)(B) of this section that was measured for the reporting year.

(ii) Using Equation W-22 of this section, calculate the annual volumetric GHG emissions 

from each centrifugal compressor mode-source combination specified in paragraph (o)(1)(i)(A) 

and (o)(1)(i)(B) of this section that was not measured during the reporting year. 

Es,i,m EFm,s Tm GHGi,m = * * (Eq. W-22)

Where:
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Es,i,m = Annual volumetric GHGi (either CH4 or CO2) emissions for unmeasured 

compressor mode-source combination m, at standard conditions, in cubic 

feet.

EFm,s = Reporter emission factor for compressor mode-source combination m, in 

standard cubic feet per hour, as calculated in paragraph (o)(6)(iii) of this 

section.

Tm = Total time the compressor was in the unmeasured mode-source 

combination m, for which Es,i,m is being calculated in the reporting year, in 

hours.

GHGi,m = Mole fraction of GHGi in the vent gas for unmeasured compressor modesource combination m; use the appropriate gas compositions in paragraph 

(u)(2) of this section.

m = Compressor mode-source combination specified in paragraph (o)(1)(i)(A) or 

(o)(1)(i)(B) of this section that was not measured in the reporting year.

(iii) Using Equation W-23 of this section, develop an emission factor for each compressor 

mode-source combination specified in paragraph (o)(1)(i)(A) and (o)(1)(i)(B) of this section. 

These emission factors must be used in Equation W-22 of this section to determine volumetric 

emissions from a centrifugal compressor in the mode-source combinations that were not 

measured in the reporting year.

EF

MT

Count m s

m p s

p

Count

m

m

,

, ,

= =

∑

1

(Eq. W-23)

Where:

EFm,s = Reporter emission factor to be used in Equation W-22 of this section for 

compressor mode-source combination m, in standard cubic feet per hour. 

The reporter emission factor must be based on all compressors measured 

in compressor mode-source combination m in the current reporting year 

and the preceding two reporting years.

MTm,p,s = Average volumetric gas emission measurement for compressor modesource combination m, for compressor p, in standard cubic feet per hour, 

calculated using all volumetric gas emission measurements (MTm in 

Equation W-21 of this section) for compressor mode-source combination 

m for compressor p in the current reporting year and the preceding two 

reporting years.
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Countm = Total number of compressors measured in compressor mode-source 

combination m in the current reporting year and the preceding two 

reporting years.

m = Compressor mode-source combination specified in paragraph (o)(1)(i)(A) or 

(o)(1)(i)(B) of this section.

(iv) The reporter emission factor in Equation W-23 of this section may be calculated by 

using all measurements from a single owner or operator instead of only using measurements 

from a single facility. If you elect to use this option, the reporter emission factor must be applied 

to all reporting facilities for the owner or operator. 

(7) Method for calculating volumetric GHG emissions from continuous monitoring of 

individual centrifugal compressor sources. For compressor sources measured according to 

paragraph (o)(1)(ii) of this section, you must use the continuous volumetric emission 

measurements taken as specified in paragraph (o)(3) of this section and calculate annual 

volumetric GHG emissions associated with the compressor source using Equation W-24A of this 

section.

Es,i,v Qs,v GHGi,v = * (Eq. W-24A)

Where:

Es,i,v = Annual volumetric GHGi (either CH4 or CO2) emissions from compressor 

source v, at standard conditions, in cubic feet.

Qs,v = Volumetric gas emissions from compressor source v, for reporting year, in 

standard cubic feet. 

GHGi,v = Mole fraction of GHGi in the vent gas for compressor source v; use the 

appropriate gas compositions in paragraph (u)(2) of this section. 

(8) Method for calculating volumetric GHG emissions from as found leak measurements 

of manifolded groups of centrifugal compressor sources. For manifolded groups of compressor 

sources measured according to paragraph (o)(1)(iii) of this section, you must calculate annual 

volumetric GHG emissions using Equation W-24B of this section. 
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Es,i,g MTg,avg GHGi,g = 8760* * (Eq. W-24B)

Where:

Es,i,g = Annual volumetric GHGi (either CH4 or CO2) emissions for manifolded 

group of compressor sources g, at standard conditions, in cubic feet.

MTg,avg = Average volumetric gas emissions of all measurements performed in the 

reporting year according to paragraph (o)(4) of this section for the 

manifolded group of compressor sources g, in standard cubic feet per 

hour. 

GHGi,g = Mole fraction of GHGi in the vent gas for manifolded group of compressor 

sources g; use the appropriate gas compositions in paragraph (u)(2) of this 

section.

(9) Method for calculating volumetric GHG emissions from continuous monitoring of 

manifolded group of centrifugal compressor sources. For a manifolded group of compressor 

sources measured according to paragraph (o)(1)(iv) of this section, you must use the continuous 

volumetric emission measurements taken as specified in paragraph (o)(5) of this section and 

calculate annual volumetric GHG emissions associated with each manifolded group of 

compressor sources using Equation W-24C of this section. If the centrifugal compressors 

included in the manifolded group of compressor sources share the manifold with reciprocating 

compressors, you must follow the procedures in either this paragraph (o)(9) or paragraph (p)(9) 

of this section to calculate emissions from the manifolded group of compressor sources. 

Es,i,g Qs,g GHGi,g = * (Eq. W-24C)

Where:

Es,i,g = Annual volumetric GHGi (either CH4 or CO2) emissions from manifolded 

group of compressor sources g, at standard conditions, in cubic feet.

Qs,g = Volumetric gas emissions from manifolded group of compressor sources 

g, for reporting year, in standard cubic feet. 

GHGi,g = Mole fraction of GHGi in the vent gas for measured manifolded group of 

compressor sources g; use the appropriate gas compositions in paragraph 

(u)(2) of this section. 
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(10) Method for calculating volumetric GHG emissions from wet seal oil degassing vents 

at an onshore petroleum and natural gas production facility. You must calculate emissions from 

centrifugal compressor wet seal oil degassing vents at an onshore petroleum and natural gas 

production facility using Equation W-25 of this section.

Es,i Count EFi,s = * (Eq. W-25)

Where:

Es,i = Annual volumetric GHGi (either CH4 or CO2) emissions from centrifugal 

compressor wet seals, at standard conditions, in cubic feet.

Count = Total number of centrifugal compressors that have wet seal oil degassing 

vents.

EFi,s = Emission factor for GHGi. Use 1.2 × 107 standard cubic feet per year per 

compressor for CH4 and 5.30 × 105 standard cubic feet per year per 

compressor for CO2 at 60 °F and 14.7 psia.

(11) Method for converting from volumetric to mass emissions. You must calculate both 

CH4 and CO2 mass emissions from volumetric emissions using calculations in paragraph (v) of 

this section.

(12) General requirements for calculating volumetric GHG emissions from centrifugal 

compressors routed to flares. You must calculate and report emissions from all centrifugal 

compressor sources that are routed to a flare as specified in paragraphs (o)(12)(i) through 

(o)(12)(iii) of this section.

(i) Emissions calculations under this paragraph (o) of this section are not required for 

compressor sources that are routed to a flare.

(ii) If any compressor sources are routed to a flare, calculate the emissions for the flare 

stack as specified in paragraph (n) of this section and report emissions from the flare as specified 

in § 98.236(n), without subtracting emissions attributable to compressor sources from the flare.
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(iii) Report all applicable activity data for compressors with compressor sources routed to 

flares as specified in § 98.236(o).

(p) Reciprocating compressor venting. If you are required to report emissions from 

reciprocating compressor venting as specified in § 98.232(d)(1), (e)(1), (f)(1), (g)(1), and (h)(1), 

you must conduct volumetric emission measurements specified in paragraph (p)(1) of this 

section using methods specified in paragraphs (p)(2) through (p)(5) of this section; perform 

calculations specified in paragraphs (p)(6) through (p)(9) of this section; and calculate CH4 and 

CO2 mass emissions as specified in paragraph (p)(11) of this section. If emissions from a 

compressor source are routed to a flare, paragraphs (p)(1) through (p)(11) of this section do not 

apply and instead you must calculate CH4, CO2, and N2O emissions as specified in paragraph 

(p)(12) of this section. If emissions from a compressor source are captured for fuel use or are 

routed to a thermal oxidizer, paragraphs (p)(1) through (p)(12) of this section do not apply and 

instead you must calculate and report emissions as specified in subpart C of this part. If 

emissions from a compressor source are routed to vapor recovery, the calculations specified in 

paragraphs (p)(1) through (p)(12) of this section do not apply. If you are required to report 

emissions from reciprocating compressor venting at an onshore petroleum and natural gas 

production facility as specified in § 98.232(c)(11), you must calculate volumetric emissions as 

specified in paragraph (p)(10) of this section; and calculate CH4 and CO2 mass emissions as 

specified in paragraph (p)(11) of this section.

(1) General requirements for conducting volumetric emission measurements. You must 

conduct volumetric emission measurements on each reciprocating compressor as specified in this 

paragraph. Compressor sources (as defined in § 98.238) without manifolded vents must use a 

measurement method specified in paragraph (p)(1)(i) or (p)(1)(ii) of this section. Manifolded 
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compressor sources (as defined in § 98.238) must use a measurement method specified in 

paragraph (p)(1)(i), (p)(1)(ii), (p)(1)(iii), or (p)(1)(iv) of this section.

(i) Reciprocating compressor source as found leak measurements. Measure venting from 

each compressor according to either paragraph (p)(1)(i)(A), (p)(1)(i)(B), or (p)(1)(i)(C) of this 

section at least once annually, based on the compressor mode (as defined in § 98.238) in which 

the compressor was found at the time of measurement, except as specified in paragraph 

(p)(1)(i)(D) of this section. If additional measurements beyond the required annual testing are 

performed (including duplicate measurements or measurement of additional operating modes), 

then all measurements satisfying the applicable monitoring and QA/QC that is required by this 

paragraph (o) must be used in the calculations specified in this section.

(A) For a compressor measured in operating-mode, you must measure volumetric 

emissions from blowdown valve leakage through the blowdown vent as specified in either 

paragraph (p)(2)(i)(A) or (p)(2)(i)(B) of this section, and measure volumetric emissions from 

reciprocating rod packing as specified in paragraph (p)(2)(ii) of this section.

(B) For a compressor measured in standby-pressurized-mode, you must measure 

volumetric emissions from blowdown valve leakage through the blowdown vent as specified in 

either paragraph (p)(2)(i)(A) or (p)(2)(i)(B) of this section.

(C) For a compressor measured in not-operating-depressurized-mode, you must measure 

volumetric emissions from isolation valve leakage as specified in either paragraph (p)(2)(i)(A), 

(p)(2)(i)(B), or (p)(2)(i)(C) of this section. If a compressor is not operated and has blind flanges 

in place throughout the reporting period, measurement is not required in this compressor mode.

(D) You must measure the compressor as specified in paragraph (p)(1)(i)(C) of this 

section at least once in any three consecutive calendar years, provided the measurement can be 
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taken during a scheduled shutdown. If there is no scheduled shutdown within three consecutive 

calendar years, you must measure the compressor as specified in paragraph (p)(1)(i)(C) of this 

section either prior to or during the next compressor shutdown when the replacement of the 

compressor rod packing occurs.

(ii) Reciprocating compressor source continuous monitoring. Instead of measuring the 

compressor source according to paragraph (p)(1)(i) of this section for a given compressor, you 

may elect to continuously measure volumetric emissions from a compressor source as specified 

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

(iii) Manifolded reciprocating compressor source as found leak measurements. For a 

compressor source that is part of a manifolded group of compressor sources (as defined in § 

98.238), instead of measuring the compressor source according to paragraph (p)(1)(i), (p)(1)(ii), 

or (p)(1)(iv) of this section, you may elect to measure combined volumetric emissions from the 

manifolded group of compressor sources by conducting leak measurements at the common vent 

stack as specified in paragraph (p)(4) of this section. The leak measurements must be conducted 

at the frequency specified in paragraphs (p)(1)(iii)(A) through (p)(1)(iii)(C) of this section.

(A) A minimum of three leak measurements must be taken for each manifolded group of 

compressor sources in a calendar year.

(B) The leak measurements may be performed while the compressors are in any 

compressor mode.

(C) The three required leak measurements must be separated by a minimum of 60 days. If 

more than three leak measurements are performed, the first and last measurements in a calendar 

year must be separated by a minimum of 120 days.
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(iv) Manifolded reciprocating compressor source continuous monitoring. For a 

compressor source that is part of a manifolded group of compressor sources, instead of 

measuring the compressor source according to paragraph (p)(1)(i), (p)(1)(ii), or (p)(1)(iii) of this 

section, you may elect to continuously measure combined volumetric emissions from the 

manifolded group of compressors sources as specified in paragraph (p)(5) of this section.

(2) Methods for performing as found leak measurements from individual reciprocating 

compressor sources. If conducting leak measurements for each compressor source, you must 

determine the volumetric emissions of leaks from blowdown valves and isolation valves as 

specified in paragraph (p)(2)(i) of this section. You must determine the volumetric emissions of 

leaks from reciprocating rod packing as specified in paragraph (p)(2)(ii) or (p)(2)(iii) of this 

section.

(i) For blowdown valves on compressors in operating-mode or standby-pressurizedmode, and for isolation valves on compressors in not-operating-depressurized-mode, determine 

the volumetric emissions of leaks using one of the methods specified in paragraphs (p)(2)(i)(A) 

through (p)(2)(i)(C) of this section. 

(A) Measure the volumetric flow at standard conditions from the blowdown vent using 

calibrated bagging or high volume sampler according to methods set forth in § 98.234(c) and § 

98.234(d), respectively. 

(B) Measure the volumetric flow at standard conditions from the blowdown vent using a 

temporary meter such as a vane anemometer, according to methods set forth in § 98.234(b). 

(C) For isolation valves, you may use an acoustic leak detection device according to 

methods set forth in § 98.234(a) instead of measuring the isolation valve leakage through the 

blowdown vent as provided for in paragraphs (p)(2)(i)(A) or (p)(2)(i)(B) of this section.
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(ii) For reciprocating rod packing equipped with an open-ended vent line on compressors 

in operating-mode, determine the volumetric emissions of leaks using one of the methods 

specified in paragraphs (p)(2)(ii)(A) and (p)(2)(ii)(B) of this section.

(A) Measure the volumetric flow at standard conditions from the open-ended vent line 

using calibrated bagging or high volume sampler according to methods set forth in § 98.234(c) 

and § 98.234(d), respectively. 

(B) Measure the volumetric flow at standard conditions from the open-ended vent line 

using a temporary meter such as a vane anemometer, according to methods set forth in § 

98.234(b). 

(iii) For reciprocating rod packing not equipped with an open-ended vent line on 

compressors in operating-mode, you must determine the volumetric emissions of leaks using the 

method specified in paragraphs (p)(2)(iii)(A) and (p)(2)(iii)(B) of this section.

(A) 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.

(B) You must measure emissions found in paragraph (p)(2)(iii)(A) of this section using 

an appropriate meter, calibrated bag, or high volume sampler according to methods set forth in § 

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

(3) Methods for continuous leak measurement from individual reciprocating compressor 

sources. If you elect to conduct continuous volumetric emission measurements for an individual 

compressor source as specified in paragraph (p)(1)(ii) of this section, you must measure 

volumetric emissions as specified in paragraphs (p)(3)(i) and (p)(3)(ii) of this section.
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(i) Continuously measure the volumetric flow for the individual compressor sources at 

standard conditions using a permanent meter according to methods set forth in § 98.234(b). 

(ii) If compressor blowdown emissions are included in the metered emissions specified in 

paragraph (p)(3)(i) of this section, the compressor blowdown emissions may be included with the 

reported emissions for the compressor source and do not need to be calculated separately using 

the method specified in paragraph (i) of this section for blowdown vent stacks.

(4) Methods for performing as found leak measurements from manifolded groups of 

reciprocating compressor sources. If conducting leak measurements for a manifolded group of 

compressor sources, you must measure volumetric emissions of leaks as specified in paragraphs 

(p)(4)(i) and (p)(4)(ii) of this section.

(i) Measure at a single point in the manifold downstream of all compressor inputs and 

where emissions cannot be comingled with other non-compressor emission sources. 

(ii) Determine the volumetric flow at standard conditions from the common stack using 

one of the methods specified in paragraph (p)(4)(ii)(A) through (p)(4)(ii)(C). 

(A) A temporary meter such as a vane anemometer according the methods set forth in § 

98.234(b).

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

(C) A high volume sampler according to methods set forth § 98.234(d).

(5) Methods for continuous leak measurement from manifolded groups of reciprocating 

compressor sources. If you elect to conduct continuous volumetric emission measurements for a 

manifolded group of compressor sources as specified in paragraph (p)(1)(iv) of this section, you 

must measure volumetric emissions as specified in paragraphs (p)(5)(i) through (p)(5)(iii) of this 

section.
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(i) Measure at a single point in the manifold downstream of all compressor inputs and 

where emissions cannot be comingled with other non-compressor emission sources. 

(ii) Continuously measure the volumetric flow for the manifolded group of compressor 

sources at standard conditions using a permanent meter according to methods set forth in § 

98.234(b). 

(iii) If compressor blowdown emissions are included in the metered emissions specified 

in paragraph (p)(5)(ii) of this section, the compressor blowdown emissions may be included with 

the reported emissions for the manifolded group of compressor sources and do not need to be 

calculated separately using the method specified in paragraph (i) of this section for blowdown 

vent stacks.

(6) Method for calculating volumetric GHG emissions from as found leak measurements 

for individual reciprocating compressor sources. For compressor sources measured according to 

paragraph (p)(1)(i) of this section, you must calculate GHG emissions from the compressor 

sources as specified in paragraphs (p)(6)(i) through (p)(6)(iv) of this section.

(i) Using Equation W-26 of this section, calculate the annual volumetric GHG emissions 

for each reciprocating compressor mode-source combination specified in paragraphs (p)(1)(i)(A) 

through (p)(1)(i)(C) of this section that was measured during the reporting year. 

Es,i,m MTs,m Tm GHGi,m = * * (Eq. W-26)

Where:

Es,i,m = Annual volumetric GHGi (either CH4 or CO2) emissions for measured 

compressor mode-source combination m, at standard conditions, in cubic 

feet.

MTs,m = Volumetric gas emissions for measured compressor mode-source 

combination m, in standard cubic feet per hour, measured according to 

paragraph (p)(2) of this section. If multiple measurements are performed 

for a given mode-source combination m, use the average of all 

measurements.
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Tm = Total time the compressor is in the mode-source combination m, for which 

Es,i,m is being calculated in the reporting year, in hours.

GHGi,m = Mole fraction of GHGi in the vent gas for measured compressor modesource combination m; use the appropriate gas compositions in paragraph 

(u)(2) of this section.

m = Compressor mode-source combination specified in paragraph (p)(1)(i)(A), 

(p)(1)(i)(B), or (p)(1)(i)(C) of this section that was measured for the 

reporting year.

(ii) Using Equation W-27 of this section, calculate the annual volumetric GHG emissions 

from each reciprocating compressor mode-source combination specified in paragraph 

(p)(1)(i)(A), (p)(1)(i)(B), and (p)(1)(i)(C) of this section that was not measured during the 

reporting year. 

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

Where:

Es,i,m = Annual volumetric GHGi (either CH4 or CO2) emissions for unmeasured 

compressor mode-source combination m, at standard conditions, in cubic 

feet.

EFm,s = Reporter emission factor for compressor mode-source combination m, in 

standard cubic feet per hour, as calculated in paragraph (p)(6)(iii) of this 

section.

Tm = Total time the compressor was in the unmeasured mode-source 

combination m, for which Es,i,m is being calculated in the reporting year, in 

hours.

GHGi,m = Mole fraction of GHGi in the vent gas for unmeasured compressor modesource combination m; use the appropriate gas compositions in paragraph 

(u)(2) of this section.

m = Compressor mode-source combination specified in paragraph (p)(1)(i)(A), 

(p)(1)(i)(B), or (p)(1)(i)(C) of this section that was not measured in the 

reporting year.

(iii) Using Equation W-28 of this section, develop an emission factor for each compressor 

mode-source combination specified in paragraph (p)(1)(i)(A), (p)(1)(i)(B), and (p)(1)(i)(C) of 

this section. These emission factors must be used in Equation W-27 of this section to determine 
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volumetric emissions from a reciprocating compressor in the mode-source combinations that 

were not measured in the reporting year.

EF

MT

Count m s

m p s

p

Count

m

m

,

, ,

= =

∑

1

(Eq. W-28)

Where:

EFm,s = Reporter emission factor to be used in Equation W-27 of this section for 

compressor mode-source combination m, in standard cubic feet per hour. 

The reporter emission factor must be based on all compressors measured 

in compressor mode-source combination m in the current reporting year 

and the preceding two reporting years.

MTm,p,s = Average volumetric gas emission measurement for compressor modesource combination m, for compressor p, in standard cubic feet per hour, 

calculated using all volumetric gas emission measurements (MTm in 

Equation W-26 of this section) for compressor mode-source combination 

m for compressor p in the current reporting year and the preceding two 

reporting years.

Countm = Total number of compressors measured in compressor mode-source 

combination m in the current reporting year and the preceding two 

reporting years.

m = Compressor mode-source combination specified in paragraph (p)(1)(i)(A), 

(p)(1)(i)(B), or (p)(1)(i)(C) of this section. 

(A) Emission factors must be calculated annually for each compressor mode-source 

combination specified in paragraph ((p)(1)(i)(A), (p)(1)(i)(B), and (p)(1)(i)(C) of this section.

(B) You must combine emissions for blowndown vents, measured in the operating and 

standby-pressurized modes.

(iv) The reporter emission factor in Equation W-28 of this section may be calculated by 

using all measurements from a single owner or operator instead of only using measurements 

from a single facility. If you elect to use this option, the reporter emission factor must be applied 

to all reporting facilities for the owner or operator.
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(7) Method for calculating volumetric GHG emissions from continuous monitoring of 

individual reciprocating compressor sources. For compressor sources measured according to 

paragraph (p)(1)(ii) of this section, you must use the continuous volumetric emission 

measurements taken as specified in paragraph (p)(3) of this section and calculate annual 

volumetric GHG emissions associated with the compressor source using Equation W-29A of this 

section.

Es,i,v Qs,v GHGi,v = *

(Eq. W-29A)

Where:

Es,i,v = Annual volumetric GHGi (either CH4 or CO2) emissions from compressor 

source v, at standard conditions, in cubic feet.

Qs,v = Volumetric gas emissions from compressor source v, for reporting year, in 

standard cubic feet. 

GHGi,v = Mole fraction of GHGi in the vent gas for compressor source v; use the 

appropriate gas compositions in paragraph (u)(2) of this section. 

(8) Method for calculating volumetric GHG emissions from as found leak measurements 

of manifolded groups of reciprocating compressor sources. For manifolded groups of compressor 

sources measured according to paragraph (p)(1)(iii) of this section, you must calculate annual 

GHG emissions using Equation W-29B of this section. 

Es,i,g MTg,avg GHGi,g = 8760* * (Eq. W-29B)

Where:

Es,i,g = Annual volumetric GHGi (either CH4 or CO2) emissions for manifolded 

group of compressor sources g, at standard conditions, in cubic feet.

MTg,avg = Average volumetric gas emissions of all measurements performed in the 

reporting year according to paragraph (p)(4) of this section for the 

manifolded group of compressor sources g, in standard cubic feet per 

hour. 

GHGi,g = Mole fraction of GHGi in the vent gas for manifolded group of compressor 

sources g; use the appropriate gas compositions in paragraph (u)(2) of this 

section.
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(9) Method for calculating volumetric GHG emissions from continuous monitoring of 

manifolded group of reciprocating compressor sources. For a manifolded group of compressor 

sources measured according to paragraph (p)(1)(iv) of this section, you must use the continuous 

volumetric emission measurements taken as specified in paragraph (p)(5) of this section and 

calculate annual volumetric GHG emissions associated with each manifolded group of 

compressor sources using Equation W-29C of this section. If the reciprocating compressors 

included in the manifolded group of compressor sources share the manifold with centrifugal 

compressors, you must follow the procedures in either this paragraph (p)(9) or paragraph (o)(9) 

of this section to calculate emissions from the manifolded group of compressor sources. 

Es,i,g Qs,g GHGi,g = * (Eq. W-29C)

Where:

Es,i,g = Annual volumetric GHGi (either CH4 or CO2) emissions from manifolded 

group of compressor sources g, at standard conditions, in cubic feet.

Qs,g = Volumetric gas emissions from manifolded group of compressor sources 

g, for reporting year, in standard cubic feet. 

GHGi,g = Mole fraction of GHGi in the vent gas for measured manifolded group of 

compressor sources g; use the appropriate gas compositions in paragraph 

(u)(2) of this section. 

(10) Method for calculating volumetric GHG emissions from reciprocating compressor 

venting at an onshore petroleum and natural gas production facility. You must calculate 

emissions from reciprocating compressor venting at an onshore petroleum and natural gas 

production facility using Equation W-29D of this section.

Es,i Count EFi,s = * (Eq. W-29D)

Where:

Es,i = Annual volumetric GHGi (either CH4 or CO2 ) emissions from 

reciprocating compressors, at standard conditions, in cubic feet.

Count = Total number of reciprocating compressors.
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EFi,s = Emission factor for GHGi. Use 9.48 × 103 standard cubic feet per year per 

compressor for CH4 and 5.27 × 102 standard cubic feet per year per 

compressor for CO2 at 60 °F and 14.7 psia. 

(11) Method for converting from volumetric to mass emissions. You must calculate both 

CH4 and CO2 mass emissions from volumetric emissions using calculations in paragraph (v) of 

this section.

(12) General requirements for calculating volumetric GHG emissions from reciprocating 

compressors routed to flares. You must calculate and report emissions from all reciprocating 

compressor sources that are routed to a flare as specified in paragraphs (p)(12)(i) through 

(p)(12)(iii) of this section.

(i) Emissions calculations under this paragraph (p) of this section are not required for 

compressor sources that are routed to a flare.

(ii) If any compressor sources are routed to a flare, calculate the emissions for the flare 

stack as specified in paragraph (n) of this section and report emissions from the flare as specified 

in § 98.236(n), without subtracting emissions attributable to compressor sources from the flare.

(iii) Report all applicable activity data for compressors with compressor sources routed to 

flares as specified in § 98.236(p).

(q) Equipment leak surveys. You must use the methods described in § 98.234(a) to 

conduct leak detection(s) of equipment leaks from all component types listed in § 98.232(d)(7), 

(e)(7), (f)(5), (g)(3), (h)(4), and (i)(1). This paragraph (q) applies to component types in streams 

with gas content greater than 10 percent CH4 plus CO2 by weight. Component types in streams 

with gas content less than or equal to 10 percent CH4 plus CO2 by weight are exempt from the 

requirements of this paragraph (q) and 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 
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not need to be reported. For industry segments listed in § 98.230(a)(3) through (a)(8), if 

equipment leaks are detected for component types listed in this paragraph (q), then you must 

calculate equipment leak emissions per component type per reporting facility using Equations 

W-30 of this section. For the industry segment listed in § 98.230(a)(8), the results from Equation 

W-30 are used to calculate population emission factors on a meter/regulator run basis using 

Equation W-31 of this section.

∑=

=

p x

z

Es p i GHGi EFs p Tp z

1

, , , , * * (Eq. W-30)

Where:

Es,p,i = Annual total volumetric emissions of GHGi from specific component type 

“p” (listed in § 98.232(d)(7), (e)(7), (f)(5), (g)(3), (h)(4), and (i)(1)) in 

standard (“s”) cubic feet, as specified in paragraphs (q)(1) through (q)(8) 

of this section.

xp = Total number of specific component type “p” detected as leaking during 

annual leak surveys.

EFs,p = Leaker emission factor for specific component types 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 onshore 

natural gas transmission compression and underground natural gas 

storage, GHGi equals 0.975 for CH4 and 1.1 ×10−2 for CO2 ; for LNG 

storage and LNG import and export equipment, GHGi equals 1 for CH4

and 0 for CO2 ; and for natural gas distribution, GHGi equals 1 for CH4

and 1.1 × 10−2 CO2.

Tp,z = The total time the surveyed component “z”, component type “p”, was found 

leaking and operational, in hours. If one leak detection survey is 

conducted in the calendar year, assume the component was leaking for the 

entire calendar year, accounting for time the component was not 

operational (i.e. not operating under pressure) using engineering estimate 

based on best available data. If multiple leak detection surveys are 

conducted in the calendar year, assume that the component found to be 

leaking has been leaking since the previous survey (if not found leaking in 

the previous survey) or the beginning of the calendar year (if it was found 

leaking in the previous survey), accounting for time the component was 

not operational using engineering estimate based on best available data.

For the last leak detection survey in the calendar year, assume that all 
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leaking components continue to leak until the end of the calendar year, 

accounting for time the component was not operational using engineering 

estimate based on best available data.

(1) You must conduct either one leak detection survey in a calendar year or multiple 

complete leak detection surveys in a calendar year. The leak detection surveys selected must be 

conducted during the calendar year.

(2) Calculate both CO2 and CH4 mass emissions using calculations in paragraph (v) of 

this section.

(3) Onshore natural gas processing facilities must use the appropriate default total 

hydrocarbon leaker emission factors for compressor components in gas service and noncompressor components in gas service listed in Table W-2 of this subpart.

(4) Onshore natural gas transmission compression facilities must use the appropriate 

default total hydrocarbon leaker emission factors for compressor components in gas service and 

non-compressor components in gas service listed in Table W-3 of this subpart.

(5) Underground natural gas storage facilities must use the appropriate default total 

hydrocarbon leaker emission factors for storage stations in gas service listed in Table W-4 of this 

subpart.

(6) LNG storage facilities must use the appropriate default methane leaker emission 

factors for LNG storage components in gas service listed in Table W-5 of this subpart.

(7) LNG import and export facilities must use the appropriate default methane leaker 

emission factors for LNG terminals components in LNG service listed in Table W-6 of this 

subpart.

(8) Natural gas distribution facilities must use Equation W-30 of this section and the 

default methane leaker emission factors for transmission-distribution transfer station components 
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in gas service listed in Table W-7 of this subpart to calculate component emissions from annual 

equipment leak surveys conducted at above grade transmission-distribution transfer stations. 

Natural gas distribution facilities are required to perform equipment leak surveys only at above 

grade stations that qualify as transmission-distribution transfer stations. Below grade 

transmission-distribution transfer stations and all metering-regulating stations that do not meet 

the definition of transmission-distribution transfer stations are not required to perform equipment 

leak surveys under this section.

(i) Natural gas distribution facilities may choose to conduct equipment leak surveys at all 

above grade transmission-distribution transfer stations over multiple years, not exceeding a five 

year period to cover all above grade transmission-distribution transfer stations. If the facility 

chooses to use the multiple year option, then the number of transmission-distribution transfer 

stations that are monitored in each year should be approximately equal across all years in the 

cycle.

(ii) Use Equation W-31 to determine the meter/regulator run population emission factors 

for each GHGi. The meter/regulator run population emission factors calculated using Equation 

W-31 must be used in Equation W-32B of this section to estimate emissions from above grade 

metering-regulating stations that are not transmission-distribution transfer stations. As additional 

survey data become available, you must recalculate the meter/regulator run population emission 

factors for each GHGi annually according to paragraph (q)(8)(iii) of this section. 

∑ ∑

∑∑

= =

= = = n

y

Count

w

w y

n

y p

s p i y

s MR i MR y

T

E

EF

1 1

,

1

7

1

, , ,

, , ,

(Eq. W-31)

Where:
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EFs,MR,i = Meter/regulator run population emission factor for GHGi based on all 

surveyed above grade transmission-distribution transfer stations over “n” 

years, in standard cubic feet of GHGi per operational hour of all 

meter/regulator runs.

Es,p,i,y = Annual total volumetric emissions at standard conditions of GHGi from 

component type “p” during year “y” in standard (“s”) cubic feet, as 

calculated using Equation W-30 of this section.

p = Seven component types listed in Table W-7 of this subpart for 

transmission-distribution transfer stations.

Tw,y = The total time the surveyed meter/regulator run “w” was operational, in 

hours during survey year “y” using engineering estimate based on best 

available data.

CountMR,y = Count of meter/regulator runs surveyed at above grade transmissiondistribution transfer stations in year “y”.

y = Year of data included in emission factor “EFs,MR,i” according to paragraph 

(q)(8)(iii) of this section.

n = Number of years of data used to calculate emission factor “EFs,MR,i” 

according to paragraph (q)(8)(iii) of this section.

(iii) The emission factor “EFs,MR,i”, based on annual equipment leak surveys at above 

grade transmission-distribution transfer stations, must be calculated annually. If the facility has 

submitted a smaller number of annual reports than the duration of the selected cycle period (up to 

5 years), then all available data from the current year and previous years must be used in the 

emission calculation. After the first cycle is completed, the survey will continue on a rolling 

basis by including the measurements from the current calendar year and as many of the previous 

calendar years as are needed to complete the survey cycle.

(r) Equipment leaks by population count. This paragraph applies to emissions sources 

listed in § 98.232 (c)(21), (f)(5), (g)(3), (h)(4), (i)(2), (i)(3), (i)(4), (i)(5), and (i)(6) on streams 

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

with gas content less than or equal to 10 percent CH4 plus CO2 by weight are exempt from the 

requirements of this paragraph (q) do not need to be reported. Tubing systems equal to or less 
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than one half inch diameter are exempt from the requirements of paragraph (r) of this section and 

do not need to be reported. You must calculate emissions from all emission sources listed in this 

paragraph using Equation W-32A of this section, except for natural gas distribution facility 

emission sources listed in § 98.232(i)(3). Natural gas distribution facility emission sources listed 

in § 98.232(i)(3) must calculate emissions using Equation W-32B and according to paragraph 

(r)(6) of this section. 

Es e i Counte EFs e GHGi Te * * * , , = , (Eq. W-32A)

Es,MR,i CountMR EFs,MR,i Tw,avg = * * (Eq. W-32B)

Where:

Es,e,i = Annual volumetric emissions of GHGi from the emission source type in 

standard cubic feet. The emission source type may be a component (e.g. 

connector, open-ended line, etc.), below grade metering-regulating station, 

below grade transmission-distribution transfer station, distribution main, 

or distribution service.

Es,MR,i = Annual volumetric emissions of GHGi from all meter/regulator runs at 

above grade metering regulating stations that are not above grade 

transmission distribution transfer stations, in standard cubic feet.

Counte = Total number of the emission source type at the facility. For onshore 

petroleum and natural gas production facilities, 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. Underground natural gas storage facilities must count each 

component listed in Table W-4 of this subpart. LNG storage facilities must 

count the number of vapor recovery compressors. LNG import and export 

facilities must count the number of vapor recovery compressors. Natural 

gas distribution facilities must count: (1) the number of distribution 

services by material type; (2) miles of distribution mains by material type; 

and (3) number of below grade metering-regulating stations, by pressure 

type; as listed in Table W-7 of this subpart.

CountMR = Total number of meter/regulator runs at above grade metering-regulating 

stations that are not above grade transmission-distribution transfer 

stations.

EFs,e = Population emission factor for the specific emission source type, as listed 

in Tables W-1A and W-4 through W-7 of this subpart. Use appropriate 
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population emission factor for operations in Eastern and Western U.S., 

according to Table W-1D of this subpart.

EFs,MR,i = Meter/regulator run population emission factor for GHGi based on all 

surveyed above grade transmission-distribution transfer stations over “n” 

years, in standard cubic feet of GHGi per operational hour of all 

meter/regulator runs., as determined in Equation W-31.

GHGi = For onshore petroleum and natural gas production facilities, concentration 

of GHGi, CH4, or CO2, in produced natural gas as defined in paragraph 

(u)(2) of this section; for onshore natural gas transmission compression 

and underground natural gas storage, GHGi equals 0.975 for CH4 and 1.1 

× 10−2 for CO2; for LNG storage and LNG import and export equipment, 

GHGi equals 1 for CH4 and 0 for CO2; and for natural gas distribution, 

GHGi equals 1 for CH4 and 1.1 × 10−2CO2.

Te = Average estimated time that each emission source type associated with the 

equipment leak emission was operational in the calendar year, in hours, 

using engineering estimate based on best available data.

Tw,avg = Average estimated time that each meter/regulator run was operational in the 

calendar year, in hours per meter/regulator run, using engineering estimate 

based on best available data.

(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 must use the appropriate 

default whole gas population emission factors listed in Table W-1A of this subpart. Major 

equipment and components associated with gas wells are considered gas service components in 

reference to Table W-1A 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 W-1A 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 
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either of the calculation methods described in this paragraph (r)(2). The same calculation method 

must be used for the entire calendar year.

(i) Component Count Method 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. For 

meters/piping, use one meters/piping per well-pad.

(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 Method 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 must use the appropriate default total 

hydrocarbon population emission factors for storage wellheads in gas service listed in Table W-4 

of this subpart.

(4) LNG storage facilities must use the appropriate default methane population emission 

factor for LNG storage compressors in gas service listed in Table W-5 of this subpart.

(5) LNG import and export facilities must use the appropriate default methane population 

emission factor for LNG terminal compressors in gas service listed in Table W-6 of this subpart.

(6) Natural gas distribution facilities must use the appropriate methane emission factors 

as described in paragraph (r)(6) of this section.
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(i) Below grade metering-regulating stations, distribution mains, and distribution services 

must use the appropriate default methane population emission factors listed in Table W-7 of this 

subpart. Below grade transmission-distribution transfer stations must use the emission factor for 

below grade metering-regulating stations.

(ii) Above grade metering-regulating stations (that are not above grade transmissiondistribution transfer stations) must use the meter/regulator run population emission factor 

calculated in Equation W-31. Natural gas distribution facilities that do not have above grade 

transmission-distribution transfer stations are not required to calculate emissions for above grade 

metering-regulating stations.

(s) * * *

(2) Offshore production facilities that are not under BOEMRE jurisdiction must use the 

most recent monitoring methods and calculation methods published by BOEMRE referenced in 

30 CFR 250.302 through 304 to calculate and report annual emissions (GOADS).

(i) For any calendar year that does not overlap with the most recent BOEMRE emissions 

study publication, you may report the most recently reported emissions data submitted to 

demonstrate compliance with this subpart of part 98, with emissions adjusted based on the 

operating time for the facility relative to operating time in the previous reporting period.

* * * * *

(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 estimate emissions. These emission estimates would be 

used to report emissions from the facility sources as required in paragraph (s)(1)(i) of this 

section.
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(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 

must 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.

(t) GHG volumetric emissions using actual conditions. If equation parameters in § 98.233 

are already at standard conditions, which results in volumetric emissions at standard conditions, 

then this paragraph does not apply. Calculate volumetric emissions at standard conditions as 

specified in paragraphs (t)(1) or (2) of this section, with actual pressure and temperature 

determined by engineering estimates based on best available data unless otherwise specified.

(1) * * *

( )

( ) a s a

a n s a

s n T P Z

E T P

E

459.67 * *

* 459.67 * ,

, +

+ = (Eq. W-33)

* * * * *

Za = Compressibility factor at actual conditions for natural gas. You may use 1 if 

the temperature is above -10 degrees Fahrenheit and pressure is below 5 

atmospheres, or if the compressibility factor at the actual temperature and 

pressure is 0.98 or greater.

(2) * * *

( )

( ) a s a

a i s a

s i T P Z

E T P

E

459.67 * *

* 459.67 * ,

, +

+ = (Eq. W-34)

* * * * *

Za = Compressibility factor at actual conditions for GHG i. You may use 1 if the 

compressibility factor at the actual temperature and pressure is 0.98 or 

greater.

* * * * *

(u) GHG volumetric emissions at standard conditions. Calculate GHG volumetric 

emissions at standard conditions as specified in paragraphs (u)(1) and (2) of this section.
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(2) * * * 

(iii) GHG mole fraction in transmission pipeline natural gas that passes through the 

facility for the onshore natural gas transmission compression industry segment. You may use 

either a default 95 percent methane and 1 percent carbon dioxide fraction for GHG mole fraction 

in natural gas or site specific engineering estimates based on best available data. 

* * * * *

(v) GHG mole fraction in natural gas stored in the LNG storage industry segment. You 

may use either a default 95 percent methane and 1 percent carbon dioxide fraction for GHG mole 

fraction in natural gas or site specific engineering estimates based on best available data.

(vi) GHG mole fraction in natural gas stored in the LNG import and export industry 

segment. For export facilities that receive gas from transmission pipelines, you may use either a 

default 95 percent methane and 1 percent carbon dioxide fraction for GHG mole fraction in 

natural gas or site specific engineering estimates based on best available data.

(vii) GHG mole fraction in local distribution pipeline natural gas that passes through the 

facility for natural gas distribution facilities. You may use a default 95 percent methane and 1 

percent carbon dioxide fraction for GHG mole fraction in natural gas or site specific engineering 

estimates based on best available data.

(v) GHG mass emissions. Calculate GHG mass emissions in metric tons by converting 

the GHG volumetric emissions at standard conditions into mass emissions using Equation W-36 

of this section.

3

, * *10− Massi

= Es i ρi (Eq. W-36)

Where:

Massi = GHGi (either CH4, CO2, or N2O) mass emissions in metric tons.
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Es,i = GHGi (either CH4, CO2, or N2O) volumetric emissions at standard 

conditions, in cubic feet.

Pi = Density of GHGi. Use 0.0526 kg/ft3 for CO2 and N2O, and 0.0192 kg/ft3 for 

CH4 at 60 °F and 14.7 psia.

(w) EOR injection pump blowdown. Calculate CO2 pump blowdown emissions from 

each EOR injection pump system as follows:

(1) Calculate the total injection pump system volume in cubic feet (including pipelines, 

manifolds and vessels) between isolation valves.

* * * * *

(3) Calculate the total annual CO2 emissions from each EOR injection pump system 

using Equation W-37 of this section:

* * * * *

MassCO2 = Annual EOR injection pump system emissions in metric tons from 

blowdowns.

N = Number of blowdowns for the EOR injection pump system in the calendar 

year.

Vv = Total volume in cubic feet of EOR injection pump system chambers 

(including pipelines, manifolds and vessels) between isolation valves.

* * * * *

(x) EOR hydrocarbon liquids dissolved CO2. Calculate CO2 emissions downstream of the 

storage tank from 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 of hydrocarbon liquids downstream of the storage 

tank must be taken according to methods set forth in § 98.234(b) to determine retention of CO2

in hydrocarbon liquids immediately downstream of the storage tank. Use the annual analysis for 

the calendar year.
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(2) * * *

* * * * *

Shl = Amount of CO2 retained in hydrocarbon liquids downstream of the storage 

tank, in metric tons per barrel, under standard conditions.

* * * * *

(z) * * *

(1) If a fuel combusted in the stationary or portable equipment is listed in Table C-1 of 

subpart C of this part, or is a blend containing one or more fuels listed in Table C-1, calculate 

emissions according to (z)(1)(i). If the fuel combusted is natural gas and is of pipeline quality 

specification and has a minimum high heat value of 950 Btu per standard cubic foot, use the 

calculation method described in (z)(1)(i) and you may use the emission factor provided for 

natural gas as listed in Table C-1. If the fuel is natural gas, and is not pipeline quality or has a 

high heat value of less than 950 Btu per standard cubic feet, calculate emissions according to 

(z)(2). If the fuel is field gas, process vent gas, or a blend containing field gas or process vent 

gas, calculate emissions according to (z)(2).

(i) For fuels listed in Table C-1 or a blend containing one or more fuels listed in Table C1, calculate CO2, CH4, and N2O emissions according to any Tier listed in subpart C of this part. 

You must follow all applicable calculation requirements for that tier listed in § 98.33, any 

monitoring or QA/QC requirements listed for that tier in § 98.34, any missing data procedures 

specified in § 98.35, and any recordkeeping requirements specified in § 98.37.

(ii) Emissions from fuel combusted in stationary or portable equipment at onshore natural 

gas and petroleum production facilities and at natural gas distribution facilities will be reported 

according to the requirements specified in § 98.236(c)(19) and not according to the reporting 

requirements specified in subpart C of this part.
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(2) * * *

(iii) * * *

* * * * *

Va = Volume of gas sent to combustion unit in actual cubic feet, during the 

year.

YCO2 = Mole fraction of CO2 constituent in gas sent to combustion unit.

* * * * *

Yj = Mole fraction of gas hydrocarbon constituents j (such as methane, ethane, 

propane, butane, and pentanes plus) in gas sent to combustion unit.

* * * * *

YCH4 = Mole fraction of methane constituent in gas sent to combustion unit.

* * * * *

(vi) * * *

MassN O = ( × )× Fuel × HHV × EF −3

2 1 10 (Eq. W-40)

* * * * *

MassN2O = Annual N2O emissions from the combustion of a particular type of fuel 

(metric tons).

Fuel = Annual mass or volume of the fuel combusted (mass or volume per year, 

choose appropriately to be consistent with the units of HHV).

HHV = Higher heating value of fuel, mmBtu/unit of fuel (in units consistent with 

the fuel quantity combusted). For the higher heating value for field gas or 

process vent gas, use 1.235 × 10−3 mmBtu/scf for HHV.

6. Section 98.234 is amended by: 

a. Revising paragraphs (a) introductory text and (d)(1);

b. Removing and reserving paragraph (f); and

c. Revising paragraph (h).

The revisions read as follows:
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§ 98.234 Monitoring and QA/QC requirements.

* * * * *

(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.

(d) * * *

(1) A technician following manufacturer instructions shall conduct measurements, 

including equipment manufacturer operating procedures and measurement methods relevant to 

using a high volume sampler, including positioning the instrument for complete capture of the 

equipment leak without creating backpressure on the source.

* * * * *

(h) For well venting for liquids unloading, if a monitoring period other than the full 

calendar year is used to determine the cumulative amount of time in hours of venting for each 

well (the term “Tp” in Equation W-7A and W-7B of § 98.233) or the number of unloading events 

per well (the term “Vp” in Equations W-8 and W-9 of § 98.233), then the monitoring period must 

begin before February 1 of the reporting year and must not end before December 1 of the 

reporting year. The end of one monitoring period must immediately precede the start of the next 

monitoring period for the next reporting year. All production days must be monitored and all 

venting accounted for. 

7. Section 98.235 is revised to read as follows: 

§ 98.235 Procedures for estimating missing data.

Except as specified in § 98.233, whenever a value of a parameter is unavailable for a 

GHG emission calculation required by this subpart (including, but not limited to, if a measuring 
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device malfunctions during unit operation, a required gas sample is not taken, or activity data are 

not collected), you must follow the procedures specified in paragraphs (a) through (h) of this 

section, as applicable.

(a) If you choose to take quarterly gas samples as allowed in § 98.233(d) in lieu of using 

a continuous gas analyzer, and there is a missing sample, you must substitute the average value 

of the last four samples for which data are available.

(b) If you did not conduct monitoring as specified in § 98.233(k) for a transmission 

storage tank(s), you must assume the vent stack(s) connected to the transmission storage tank(s) 

was leaking for the entire calendar year.

(c) For stationary and portable combustion sources that use the calculation methods of 

subpart C of this part, you must use the missing data procedures in subpart C of this part.

(d) For each missing value of a parameter that should have been measured using a 

continuous flow meter, composition analyzer, thermocouple, or pressure gauge, you must 

substitute the arithmetic average of the quality-assured values of that parameter immediately 

preceding and immediately following the missing data incident. If the “after” value is not 

obtained by the end of the reporting year, you may use the “before” value for the missing data 

substitution. If, for a particular parameter, no quality-assured data are available prior to the 

missing data incident, you must use the first quality-assured value obtained after the missing data 

period as the substitute data value. A value is quality-assured according to the procedures 

specified in § 98.234.

(e) For the first six months of required data collection, facilities that become newly 

subject to subpart W may use best engineering estimates for any data that cannot reasonably be 

measured or obtained according to the requirements of this subpart.
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(f) For the first six months of required data collection, facilities that are currently subject 

to subpart W and that acquire new wells that were not previously subject to subpart W may use 

best engineering estimates for any data related to those newly acquired wells that cannot 

reasonably be measured or obtained according to the requirements of this subpart.

(g) For each missing value of any activity data not described in this section, you must 

substitute data value(s) using the best available estimate(s) of the parameter(s), based on all 

available process data (including, but not limited to, processing rates, operating hours).

(h) You must report information for all measured and substitute values of a parameter, 

and the procedures used to substitute an unavailable value of a parameter per the requirements in 

§98.236(bb).

8. Section 98.236 is revised to read as follows: 

§ 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) The annual report must include the information specified in paragraphs (a)(1) through 

(8) of this section for each applicable industry segment. The annual report must also include 

annual emissions totals, in metric tons of CO2e of each GHG, for each applicable industry 

segment listed in paragraphs (a)(1) through (a)(8) of this section, and each applicable emission 

source listed in paragraphs (b) through (z) of this section.

(1) Onshore petroleum and natural gas production. For the equipment/activities specified 

in paragraphs (a)(1)(i) through (a)(1)(xvii) of this section, report the information specified in the 

applicable paragraphs of this section.
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(i) Natural gas pneumatic devices. Report the information specified in paragraph (b) of 

this section.

(ii) Natural gas driven pneumatic pumps. Report the information specified in paragraph 

(c) of this section.

(iii) Acid gas removal units. Report the information specified in paragraph (d) of this 

section.

(iv) Dehydrators. Report the information specified in paragraph (e) of this section.

(v) Liquids unloading. Report the information specified in paragraph (f) of this section.

(vi) Completions and workovers with hydraulic fracturing. Report the information 

specified in paragraph (g) of this section.

(vii) Completions and workovers without hydraulic fracturing. Report the information 

specified in paragraph (h) of this section.

(viii) Onshore production storage tanks. Report the information specified in paragraph (j) 

of this section.

(ix) Well testing. Report the information specified in paragraph (l) of this section.

(x) Associated natural gas. Report the information specified in paragraph (m) of this 

section.

(xi) Flare stacks. Report the information specified in paragraph (n) of this section.

(xii) Centrifugal compressors. Report the information specified in paragraph (o) of this 

section.

(xiii) Reciprocating compressors. Report the information specified in paragraph (p) of 

this section.
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(xiv) Equipment leaks by population count. Report the information specified in paragraph 

(r) of this section. 

(xv) EOR injection pumps. Report the information specified in paragraph (w) of this 

section.

(xvi) EOR hydrocarbon liquids. Report the information specified in paragraph (x) of this 

section.

(xvii) Combustion equipment. Report the information specified in paragraph (z) of this 

section.

(2) Offshore petroleum and natural gas production. Report the information specified in 

paragraph (s) of this section.

(3) Onshore natural gas processing. For the equipment/activities specified in paragraphs 

(a)(3)(i) through (a)(3)(vii) of this section, report the information specified in the applicable 

paragraphs of this section.

(i) Acid gas removal units. Report the information specified in paragraph (d) of this 

section.

(ii) Dehydrators. Report the information specified in paragraph (e) of this section.

(iii) Blowdown vent stacks. Report the information specified in paragraph (i) of this 

section.

(iv) Flare stacks. Report the information specified in paragraph (n) of this section.

(v) Centrifugal compressors. Report the information specified in paragraph (o) of this 

section.

(vi) Reciprocating compressors. Report the information specified in paragraph (p) of this 

section.
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(vii) Equipment leak surveys. Report the information specified in paragraph (q) of this 

section. 

(4) Onshore natural gas transmission compression. For the equipment/activities specified 

in paragraphs (a)(4)(i) through (a)(4)(vii) of this section, report the information specified in the 

applicable paragraphs of this section.

(i) Natural gas pneumatic devices. Report the information specified in paragraph (b) of 

this section.

(ii) Blowdown vent stacks. Report the information specified in paragraph (i) of this 

section.

(iii) Transmission storage tanks. Report the information specified in paragraph (k) of this 

section.

(iv) Flare stacks. Report the information specified in paragraph (n) of this section.

(v) Centrifugal compressors. Report the information specified in paragraph (o) of this 

section.

(vi) Reciprocating compressors. Report the information specified in paragraph (p) of this 

section.

(vii) Equipment leak surveys. Report the information specified in paragraph (q) of this 

section.

(5) Underground natural gas storage. For the equipment/activities specified in paragraphs 

(a)(5)(i) through (a)(5)(vi) of this section, report the information specified in the applicable 

paragraphs of this section.

(i) Natural gas pneumatic devices. Report the information specified in paragraph (b) of 

this section.
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(ii) Flare stacks. Report the information specified in paragraph (n) of this section.

(iii) Centrifugal compressors. Report the information specified in paragraph (o) of this 

section.

(iv) Reciprocating compressors. Report the information specified in paragraph (p) of this 

section.

(v) Equipment leak surveys. Report the information specified in paragraph (q) of this 

section. 

(vi) Equipment leaks by population count. Report the information specified in paragraph 

(r) of this section. 

(6) LNG storage. For the equipment/activities specified in paragraphs (a)(6)(i) through 

(a)(6)(v) of this section, report the information specified in the applicable paragraphs of this 

section.

(i) Flare stacks. Report the information specified in paragraph (n) of this section.

(ii) Centrifugal compressors. Report the information specified in paragraph (o) of this 

section.

(iii) Reciprocating compressors. Report the information specified in paragraph (p) of this 

section.

(iv) Equipment leak surveys. Report the information specified in paragraph (q) of this 

section. 

(v) Equipment leaks by population count. Report the information specified in paragraph 

(r) of this section. 
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(7) LNG import and export equipment. For the equipment/activities specified in 

paragraphs (a)(7)(i) through (a)(7)(vi) of this section, report the information specified in the 

applicable paragraphs of this section.

(i) Blowdown vent stacks. Report the information specified in paragraph (i) of this 

section.

(ii) Flare stacks. Report the information specified in paragraph (n) of this section.

(iii) Centrifugal compressors. Report the information specified in paragraph (o) of this

section.

(iv) Reciprocating compressors. Report the information specified in paragraph (p) of this 

section.

(v) Equipment leak surveys. Report the information specified in paragraph (q) of this 

section. 

(vi) Equipment leaks by population count. Report the information specified in paragraph 

(r) of this section. 

(8) Natural gas distribution. For the equipment/activities specified in paragraphs (a)(8)(i) 

through (a)(8)(iii) of this section, report the information specified in the applicable paragraphs of 

this section.

(i) Combustion equipment. Report the information specified in paragraph (z) of this 

section.

(ii) Equipment leak surveys. Report the information specified in paragraph (q) of this 

section. 

(iii) Equipment leaks by population count. Report the information specified in paragraph 

(r) of this section.
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(b) Natural gas pneumatic devices. You must indicate whether the facility contains the 

following types of equipment: continuous high bleed natural gas pneumatic devices, continuous 

low bleed natural gas pneumatic devices, and intermittent bleed natural gas pneumatic devices. If 

the facility contains any continuous high bleed natural gas pneumatic devices, continuous low 

bleed natural gas pneumatic devices, or intermittent bleed natural gas pneumatic devices, then 

you must report the information specified in paragraphs (b)(1) through (b)(4) of this section.

(1) The number of natural gas pneumatic devices as specified in paragraphs (b)(1)(i) and 

(b)(1)(ii) of this section.

(i) The total number of devices, determined according to § 98.233(a)(1) and (a)(2). 

(ii) If the reported value in paragraph (b)(1)(i) of this section is an estimated value 

determined according to § 98.233(a)(2), then you must report the information specified in 

paragraphs (b)(1)(ii)(A) through (b)(1)(ii)(C) of this section.

(A) The number of devices reported in paragraph (b)(1)(i) of this section that are counted.

(B) The number of devices reported in paragraph (b)(1)(i) of this section that are 

estimated (not counted).

(C) Whether the calendar year is the first calendar year of reporting or the second 

calendar year of reporting.

(2) Estimated average number of hours in the calendar year that the natural gas pneumatic 

devices reported in paragraph (b)(1)(i) of this section were operating in the calendar year (“Tt” in 

Equation W-1 of this subpart).

(3) Annual CO2 emissions, in metric tons CO2, for the natural gas pneumatic devices 

combined, calculated using Equation W-1 of this subpart and § 98.233(a)(4), and reported in 

paragraph (b)(1)(i) of this section.
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(4) Annual CH4 emissions, in metric tons CH4, for the natural gas pneumatic devices 

combined, calculated using Equation W-1 of this subpart and § 98.233(a)(4), and reported in 

paragraph (b)(1)(i) of this section.

(c) Natural gas driven pneumatic pumps. You must indicate whether the facility has any 

natural gas driven pneumatic pumps. If the facility contains any natural gas driven pneumatic 

pumps, then you must report the information specified in paragraphs (c)(1) through (c)(4) of this 

section.

(1) Count of natural gas driven pneumatic pumps.

(2) Average estimated number of hours in the calendar year the pumps were operational 

(“T” in Equation W-2 of this subpart).

(3) Annual CO2 emissions, in metric tons CO2, for all natural gas driven pneumatic 

pumps combined, calculated according to § 98.233(c)(1) and (c)(2).

(4) Annual CH4 emissions, in metric tons CH4, for all natural gas driven pneumatic 

pumps combined, calculated according to § 98.233(c)(1) and (c)(2).

(d) Acid gas removal units. You must indicate whether your facility has any acid gas 

removal units that vent directly to the atmosphere, to a flare or engine, or to a sulfur recovery 

plant. If your facility contains any acid gas removal units that vent directly to the atmosphere, to 

a flare or engine, or to a sulfur recovery plant, then you must report the information specified in 

paragraphs (d)(1) and (d)(2) of this section.

(1) You must report the information specified in paragraphs (d)(1)(i) through (d)(1)(vi) of 

this section for each acid gas removal unit.
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(i) A unique name or ID number for the acid gas removal unit. For the onshore petroleum 

and natural gas production industry segment, a different name or ID may be used for a single 

acid gas removal unit for each location it operates at in a given year.

(ii) Total feed rate entering 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.

(iii) The calculation method used to calculate CO2 emissions from the acid gas removal 

unit, as specified in § 98.233(d).

(iv) Whether any CO2 emissions from the acid gas removal unit are recovered and 

transferred outside the facility, as specified in § 98.233(d)(11). If any CO2 emissions from the 

acid gas removal unit were recovered and transferred outside the facility, then you must report 

the annual quantity of CO2, in metric tons CO2, that was recovered and transferred outside the 

facility.

(v) Annual CO2 emissions, in metric tons CO2, from the acid gas removal unit, calculated 

using any one of the calculation methods specified in § 98.233(d) and as specified in § 

98.233(d)(10) and (11).

(vi) Sub-basin ID (for the onshore petroleum and natural gas production industry segment 

only).

(2) You must report information specified in paragraphs (d)(2)(i) through (d)(2)(iii) of 

this section, applicable to the calculation method reported in paragraph (d)(1)(iii) of this section, 

for each acid gas removal unit.

(i) If you used Calculation Method 1 or Calculation Method 2 as specified in § 98.233(d) 

to calculate CO2 emissions from the acid gas removal unit, then you must report the information 

specified in paragraphs (d)(2)(i)(A) and (d)(2)(i)(B) of this section. 
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(A) Annual average volumetric fraction of CO2 in the vent gas exiting the acid gas 

removal unit.

(B) Annual volume of gas vented from the acid gas removal unit, in cubic feet.

(ii) If you used Calculation Method 3 as specified in § 98.233(d) to calculate CO2

emissions from the acid gas removal unit, then you must report the information specified in 

paragraphs (d)(2)(ii)(A) through (d)(2)(ii)(D) of this section.

(A) Which equation was used; Equation W-4A or W-4B.

(B) Annual average volumetric fraction of CO2 in the natural gas flowing out of the acid 

gas removal unit, as specified in Equation W-4A or Equation W-4B of this subpart.

(C) Annual average volumetric fraction of CO2 content in natural gas flowing into the 

acid gas removal unit, as specified in Equation W-4A or Equation W-4B of this subpart.

(D) The natural gas flow rate used, as specified in Equation W-4A of this subpart, 

reported as either total annual volume of natural gas flow into the acid gas removal unit in cubic 

feet at actual conditions; or total annual volume of natural gas flow out of the acid gas removal 

unit, as specified in Equation W-4B of this subpart, in cubic feet at actual conditions,.

(iii) If you used Calculation Method 4 as specified in § 98.233(d) to calculate CO2

emissions from the acid gas removal unit, then you must report the information specified in 

paragraphs (d)(2)(iii)(A) through (d)(2)(iii)(L) of this section, as applicable to the simulation 

software package used. 

(A) The name of the simulation software package used.

(B) Natural gas feed temperature, in degrees Fahrenheit. 

(C) Natural gas feed pressure, in pounds per square inch.

(D) Natural gas flow rate, in standard cubic feet per minute.
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(E) Acid gas content of the feed natural gas, in mole percent.

(F) Acid gas content of the outlet natural gas, in mole percent.

(G) Unit operating hours, excluding downtime for maintenance or standby, in hours per 

year.

(H) Exit temperature of the natural gas, in degrees Fahrenheit.

(I) Solvent pressure, in pounds per square inch.

(J) Solvent temperature, in degrees Fahrenheit.

(K) Solvent circulation rate, in gallons per minute.

(L) Solvent weight, in pounds per gallon. 

(e) Dehydrators. You must indicate whether your facility contains any of the following 

equipment: absorbent dehydrators with an annual average daily natural gas throughput greater 

than or equal to 0.4 million standard cubic feet per day, glycol dehydrators with an annual 

average daily natural gas throughput less than 0.4 million standard cubic feet per day, and 

dehydrators that use desiccant. If your facility contains any of the equipment listed in this 

paragraph (e), then you must report the applicable information in paragraphs (e)(1) through 

(e)(3).

(1) For each absorbent dehydrator that has an annual average daily natural gas throughput 

greater than or equal to 0.4 million standard cubic feet per day (as specified in § 98.233(e)(1)), 

you must report the information specified in paragraphs (e)(1)(i) through (e)(1)(xviii) of this 

section for the dehydrator.

(i) A unique name or ID number for the dehydrator. For the onshore petroleum and 

natural gas production industry segment, a different name or ID may be used for a single 

dehydrator for each location it operates at in a given year.
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(ii) Dehydrator feed natural gas flow rate, in million standard cubic feet per day, 

determined by engineering estimate based on best available data.

(iii) Dehydrator feed natural gas water content, in pounds per million standard cubic feet.

(iv) Dehydrator outlet natural gas water content, in pounds per million standard cubic 

feet.

(v) Dehydrator absorbent circulation pump type (e.g., natural gas pneumatic, air 

pneumatic, or electric).

(vi) Dehydrator absorbent circulation rate, in gallons per minute.

(vii) Type of absorbent (e.g., triethylene glycol (TEG), diethylene glycol (DEG), or 

ethylene glycol (EG)).

(viii) Whether stripper gas is used in dehydrator.

(ix) Whether a flash tank separator is used in dehydrator.

(x) Total time the dehydrator is operating, in hours.

(xi) Temperature of the wet natural gas, in degrees Fahrenheit.

(xii) Pressure of the wet natural gas, in pounds per square inch gauge.

(xiii) Mole fraction of CH4 in wet natural gas.

(xiv) Mole fraction of CO2 in wet natural gas.

(xv) Whether any dehydrator emissions are vented to a vapor recovery device. 

(xvi) Whether any dehydrator emissions are vented to a flare or regenerator firebox/fire 

tubes. If any emissions are vented to a flare or regenerator firebox/fire tubes, report the 

information specified in paragraphs (e)(1)(xvi)(A) through (e)(1)(xvi)(C) of this section for these 

emissions from the dehydrator.
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(A) Annual CO2 emissions, in metric tons CO2, for the dehydrator, calculated according 

to § 98.233(e)(6).

(B) Annual CH4 emissions, in metric tons CH4, for the dehydrator, calculated according 

to § 98.233(e)(6).

(C) Annual N2O emissions, in metric tons N2O, for the dehydrator, calculated according 

to § 98.233(e)(6).

(xvii) Whether any dehydrator emissions are vented to the atmosphere without being 

routed to a flare or regenerator firebox/fire tubes. If any emissions are not routed to a flare or 

regenerator firebox/fire tubes, then you must report the information specified in paragraphs 

(e)(1)(xvii)(A) and (e)(1)(xvii)(B) of this section for those emissions from the dehydrator.

(A) Annual CO2 emissions, in metric tons CO2, for the dehydrator when not venting to a 

flare or regenerator firebox/fire tubes, calculated according to § 98.233(e)(1) and (e)(5).

(B) Annual CH4 emissions, in metric tons CH4, for the dehydrator when not venting to a 

flare or regenerator firebox/fire tubes, calculated according to § 98.233(e)(1) and (e)(5).

(xviii) Sub-basin ID (for the onshore petroleum and natural gas production industry 

segment only).

(2) For glycol dehydrators with an annual average daily natural gas throughput less than 

0.4 million standard cubic feet per day (as specified in § 98.233(e)(2)), you must report the 

information specified in paragraphs (e)(2)(i) through (e)(2)(v) of this section for the entire 

facility.

(i) The total number of dehydrators at the facility.

(ii) Whether any dehydrators reported in paragraph (e)(2)(i) of this section were vented to 

a vapor recovery device. If any dehydrators reported in paragraph (e)(2)(i) of this section were 
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vented to a vapor recovery device, then you must report the total number of dehydrators at the 

facility that vented to a vapor recovery device. 

(iii) Whether any dehydrators reported in paragraph (e)(2)(i) of this section were vented 

to a control device other than a vapor recovery device or a flare or regenerator firebox/fire tubes. 

If any dehydrators reported in paragraph (e)(2)(i) of this section were vented to a control device 

other than a vapor recovery device or a flare or regenerator firebox/fire tubes, then you must 

specify the type of control device and the number of dehydrators at the facility that were vented 

to each type of control device. 

(iv) Whether any dehydrators reported in paragraph (e)(2)(i) of this section were vented 

to a flare or regenerator firebox/fire tubes. If any dehydrators reported in paragraph (e)(2)(i) of 

this section were vented to a flare or regenerator firebox/fire tubes, then you must report the 

information specified in paragraphs (e)(2)(iv)(A) through (e)(2)(iv)(D) of this section.

(A) The total number of dehydrators venting to a flare or regenerator firebox/fire tubes.

(B) Annual CO2 emissions, in metric tons CO2, for the dehydrators reported in paragraph 

(e)(2)(iv)(A) of this section, calculated according to § 98.233(e)(6).

(C) Annual CH4 emissions, in metric tons CH4, for the dehydrators reported in paragraph 

(e)(2)(iv)(A) of this section, calculated according to § 98.233(e)(6).

(D) Annual N2O emissions, in metric tons N2O, for the dehydrators reported in paragraph 

(e)(2)(iv)(A) of this section, calculated according to § 98.233(e)(6).

(v) For dehydrators reported in paragraph (e)(2)(i) of this section that were not vented to 

a flare or regenerator firebox/fire tubes, report the information specified in paragraphs 

(e)(2)(v)(A) and (e)(2)(v)(B) of this section.
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(A) Annual CO2 emissions in metric tons CO2, for emissions from all dehydrators 

reported in paragraph (e)(2)(i) of this section that were not vented to a flare or regenerator 

firebox/fire tubes, calculated according to § 98.233(e)(2), (e)(4), and (e)(5), where emissions are 

added together for all such dehydrators.

(B) Annual CH4 emissions in metric tons CO2, for emissions from all dehydrators 

reported in paragraph (e)(2)(i) of this section that were not vented to a flare or regenerator 

firebox/fire tubes, calculated according to § 98.233(e)(2), (e)(4), and (e)(5), where emissions are 

added together for all such dehydrators.

(3) For dehydrators that use desiccant (as specified in § 98.233(e)(3)), you must report 

the information specified in paragraphs (e)(3)(i) through (e)(3)(iii) of this section for the entire 

facility.

(i) The same information specified in paragraphs (e)(2)(i) through (e)(2)(iv) of this 

section for glycol dehydrators, and report the information under this paragraph for dehydrators 

that use desiccant.

(ii) Annual CO2 emissions, in metric tons CO2, for emissions from all desiccant 

dehydrators reported under paragraph (e)(3)(i) of this section that are not venting to a flare or 

regenerator firebox/fire tubes, calculated according to § 98.233(e)(3), (e)(4), and (e)(5), and 

summing for all such dehydrators.

(iii) Annual CH4 emissions, in metric tons CH4, for emissions from all desiccant 

dehydrators reported in paragraph (e)(3)(i) of this section that are not venting to a flare or 

regenerator firebox/fire tubes, calculated according to § 98.233(e)(3), (e)(4), and (e)(5), and 

summing for all such dehydrators.
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(f) Liquids unloading. You must indicate whether well venting for liquids unloading 

occurs at your facility, and if so, which methods (as specified in § 98.233(f)) were used to 

calculate emissions. If your facility performs well venting for liquids unloading and uses 

Calculation Method 1, then you must report the information specified in paragraph (f)(1) of this 

section. If the facility performs liquids unloading and uses Calculation Method 2 or 3, then you 

must report the information specified in paragraph (f)(2) of this section.

(1) For each sub-basin and well tubing diameter and pressure grouping for which you 

used Calculation Method 1 to calculate natural gas emissions from well venting for liquids 

unloading, report the information specified in paragraphs (f)(1)(i) through (f)(1)(xii) of this 

section. Report information separately for wells with plunger lifts and wells without plunger lifts.

(i) Sub-basin ID.

(ii) Well tubing diameter and pressure group ID.

(iii) Plunger lift indicator.

(iv) Count of wells vented to the atmosphere for the sub-basin/well tubing diameter and 

pressure grouping.

(v) Percentage of wells for which the monitoring period used to determine the cumulative 

amount of time venting was not the full calendar year.

(vi) Cumulative amount of time wells were vented (sum of “Tp” from Equation W-7A or 

W-7B of this subpart), in hours.

(vii) Cumulative number of unloadings vented to the atmosphere for each well, 

aggregated across all wells in the sub-basin/well tubing diameter and pressure grouping.

(viii) Annual natural gas emissions, in standard cubic feet, from well venting for liquids 

unloading, calculated according to § 98.233(f)(1).
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(ix) Annual CO2 emissions, in metric tons CO2, from well venting for liquids unloading, 

calculated according to § 98.233(f)(1) and § 98.233(f)(4).

(x) Annual CH4 emissions, in metric tons CH4, from well venting for liquids unloading, 

calculated according to § 98.233(f)(1) and § 98.233(f)(4).

(xi) For each well tubing diameter group and pressure group combination, you must 

report the information specified in paragraphs (f)(1)(xi)(A) through (f)(1)(xi)(E) of this section 

for each individual well not using a plunger lift that was tested during the year.

(A) API number of tested well.

(B) Casing pressure, in pounds per square inch absolute.

(C) Internal casing diameter, in inches.

(D) Measured depth of the well, in feet.

(E) Average flow rate of the well venting over the duration of the liquids unloading, in 

standard cubic feet per hour.

(xii) For each well tubing diameter group and pressure group combination, you must 

report the information specified in paragraphs (f)(1)(xii)(A) through (f)(1)(xii)(E) of this section 

for each individual well using a plunger lift that was tested during the year.

(A) The API well number.

(B) The tubing pressure, in pounds per square inch absolute. 

(C) The internal tubing diameter, in inches. 

(D) Measured depth of the well, in feet.

(E) Average flow rate of the well venting over the duration of the liquids unloading, in 

standard cubic feet per hour.
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(2) For each sub-basin for which you used Calculation Method 2 or 3 (as specified in § 

93.233(f)) to calculate natural gas emissions from well venting for liquids unloading, you must 

report the information in (f)(2)(i) through (f)(2)(x) of this section. Report information separately 

for each calculation method.

(i) Sub-basin ID.

(ii) Calculation method.

(iii) Plunger lift indicator.

(iv) Number of wells vented to the atmosphere.

(v) Cumulative number of unloadings vented to the atmosphere for each well, aggregated 

across all wells.

(vi) Annual natural gas emissions, in standard cubic feet, from well venting for liquids 

unloading, calculated according to § 98.233(f)(2) or § 98.233(f)(3), as applicable.

(vii) Annual CO2 emissions, in metric tons CO2, from well venting for liquids unloading, 

calculated according to § 98.233(f)(2) or § 98.233(f)(3), as applicable, and § 98.233(f)(4).

(viii) Annual CH4 emissions, in metric tons CH4, from well venting for liquids unloading, 

calculated according to § 98.233(f) (2) or § 98.233(f)(3), as applicable, and § 98.233(f)(4).

(ix) For wells without plunger lifts, the average internal casing diameter, in inches. 

(x) For wells with plunger lifts, the average internal tubing diameter, in inches. 

(g) Completions and workovers with hydraulic fracturing. You must indicate whether 

your facility had any gas well completions or workovers with hydraulic fracturing during the 

calendar year. If your facility had gas well completions or workovers with hydraulic fracturing 

during the calendar year, then you must report information specified in paragraphs (g)(1) through 
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(g)(10) of this section, for each sub-basin and well type combination. Report information 

separately for completions and workovers.

(1) Sub-basin ID.

(2) Well type.

(3) Number of completions or workovers in the category.

(4) Calculation method used.

(5) If you used Equation W-10A to calculate annual volumetric total gas emissions, then 

you must report the information specified in paragraphs (g)(5)(i) and (g)(5)(ii) of this section.

(i) Cumulative backflow time, in hours, for each sub-basin (“Tp” in Equation W-10A).

(ii) Measured flowback rate, in standard cubic feet per hour, for each sub-basin (“FRs,p” 

in Equation W-12A).

(6) If you used Equation W-10B to calculate annual volumetric total gas emissions for 

completions that vent gas to the atmosphere, then you must report the vented natural gas volume, 

in standard cubic feet, for each well in the sub-basin (“FVs,p” in Equation W-10B).

(7) Annual gas emissions, in standard cubic feet (“Es,n” in Equation W-10A or W-10B).

(8) Annual CO2 emissions, in metric tons CO2.

(9) Annual CH4 emissions, in metric tons CH4.

(10) If the well emissions were vented to a flare, then you must report the total N2O 

emissions, in metric tons N2O. 

(h) Completions and workovers without hydraulic fracturing. You must indicate whether 

the facility had any gas well completions without hydraulic fracturing or any gas well workovers 

without hydraulic fracturing, and if the activities occurred with or without flaring. If the facility 
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had gas well completions or workovers without hydraulic fracturing, then you must report the 

information specified in paragraphs (h)(1) through (h)(4) of this section, as applicable.

(1) For each sub-basin with gas well completions without hydraulic fracturing and 

without flaring, report the information specified in paragraphs (h)(1)(i) through (h)(1)(vi) of this 

section.

(i) Sub-basin ID.

(ii) Number of well completions that vented gas directly to the atmosphere without 

flaring.

(iii) Total number of hours that gas vented directly to the atmosphere during backflow for 

all completions in the sub-basin category (the sum of all “Tp” for completions that vented to the 

atmosphere as used in Equation W-13B).

(iv) Average daily gas production rate for all completions without hydraulic fracturing in 

the sub-basin without flaring, in standard cubic feet per hour (average of all “Vp” used in 

Equation W-13B). 

(v) Annual CO2 emissions, in metric tons CO2, that resulted from completions venting 

gas directly to the atmosphere (“Es,p” from Equation W-13B for completions that vented directly 

to the atmosphere, converted to mass emissions according to § 98.233(h)(1)).

(vi) Annual CH4 emissions, in metric tons CH4, that resulted from completions venting 

gas directly to the atmosphere (Es,p from Equation W-13B for completions that vented directly to 

the atmosphere, converted to mass emissions according to § 98.233(h)(1)).

(2) For each sub-basin with gas well completions without hydraulic fracturing and with 

flaring, report the information specified in paragraphs (h)(2)(i) through (h)(2)(vii) of this section.

(i) Sub-basin ID.
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(ii) Number of well completions that flared gas.

(iii) Total number of hours that gas vented to a flare during backflow for all completions 

in the sub-basin category (the sum of all “Tp” for completions that vented to a flare from 

Equation W-13B).

(iv) Average daily gas production rate for all completions without hydraulic fracturing in 

the sub-basin with flaring, in standard cubic feet per hour (the average of all “Vp” from Equation 

W-13B). 

(v) Annual CO2 emissions, in metric tons CO2, that resulted from completions that flared 

gas calculated according to § 98.233(h)(2).

(vi) Annual CH4 emissions, in metric tons CH4, that resulted from completions that flared 

gas calculated according to § 98.233(h)(2).

(vii) Annual N2O emissions, in metric tons N2O, that resulted from completions that 

flared gas calculated according to § 98.233(h)(2).

(3) For each sub-basin with gas well workovers without hydraulic fracturing and without 

flaring, report the information specified in paragraphs (h)(3)(i) through (h)(3)(iv) of this section.

(i) Sub-basin ID.

(ii) Number of workovers that vented gas to the atmosphere without flaring.

(iii) Annual CO2 emissions, in metric tons CO2 per year, that resulted from workovers 

venting gas directly to the atmosphere (“Es,wo” in Equation W-13A for workovers that vented 

directly to the atmosphere, converted to mass emissions as specified in § 98.233(h)(1)).

(iv) Annual CH4 emissions, in metric tons CH4 per year, that resulted from workovers 

venting gas directly to the atmosphere (“Es,wo” in Equation W-13A for workovers that vented 

directly to the atmosphere, converted to mass emissions as specified in § 98.233(h)(1)).
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(4) For each sub-basin with gas well workovers without hydraulic fracturing and with 

flaring, report the information specified in paragraphs (h)(4)(i) through (h)(4)(v) of this section.

(i) Sub-basin ID.

(ii) Number of workovers that flared gas.

(iii) Annual CO2 emissions, in metric tons CO2 per year, that resulted from workovers 

that flared gas calculated as specified in § 98.233(h)(2).

(iv) Annual CH4 emissions, in metric tons CH4 per year, that resulted from workovers 

that flared gas, calculated as specified in § 98.233(h)(2).

(v) Annual N2O emissions, in metric tons N2O per year, that resulted from workovers that 

flared gas calculated as specified in § 98.233(h)(2).

(i) Blowdown vent stacks. You must indicate whether your facility has blowdown vent 

stacks. If your facility has blowdown vent stacks, then you must report whether emissions were 

calculated by equipment type or by using flow meters. If you calculated emissions by equipment 

type, then you must report the information specified in paragraph (i)(1) of this section. If you 

calculated emissions using flow meters, then you must report the information specified in 

paragraph (i)(2) of this section.

(1) Report by equipment type. If you calculated emissions from blowdown vent stacks by 

equipment type, then you must report the equipment types and the information specified in 

paragraphs (i)(1)(i) through (i)(1)(iii) of this section for each equipment type. If a blowdown 

event resulted in emissions from multiple equipment types, then you must report the information 

in paragraphs (i)(1)(i) through (i)(1)(iii) of this section for the equipment type that represented 

the largest portion of the emissions for the blowdown event.
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(i) Total number of blowdowns in the calendar year for the equipment type (the sum of 

equation variable “N” from Equation W-14A or Equation W-14B of this subpart, for all unique 

physical volumes for the equipment type).

(ii) Annual CO2 emissions for the equipment type, in metric tons CO2, calculated 

according to § 98.233(i)(2)(iii).

(iii) Annual CH4 emissions for the equipment type, in metric tons CH4, calculated 

according to § 98.233(i)(2)(iii).

(2) Report by flow meter. If you elect to calculate emissions from blowdown vent stacks 

by using a flow meter according to § 98.233(i)(3), then you must report the information specified 

in paragraphs (i)(2)(i) and (i)(2)(ii) of this section for the facility.

(i) Annual CO2 emissions from all blowdown vent stacks at the facility, in metric tons 

CO2 (the sum of all CO2 mass emission values calculated according to § 98.233(i)(3), for all flow 

meters).

(ii) Annual CH4 emissions from all blowdown vent stacks at the facility, in metric tons 

CH4, (the sum of all CH4 mass emission values calculated according to § 98.233(i)(3), for all 

flow meters).

(j) Onshore production storage tanks. You must indicate whether your facility sends 

produced oil to atmospheric tanks. If your facility sends produced oil to atmospheric tanks, then 

you must indicate which Calculation Method(s) you used to calculate GHG emissions, and you 

must report the information specified in paragraphs (j)(1) and (j)(2) of this section as applicable. 

If any atmospheric tanks were observed to have malfunctioning dump valves during the calendar 

year, then you must indicate that dump valves were malfunctioning and you must report the 

information specified in paragraph (j)(3) of this section. 
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(1) If you used Calculation Method 1 or Calculation Method 2 to calculate GHG 

emissions, then you must report the information specified in paragraphs (j)(1)(i) through 

(j)(1)(xiv) of this section for each sub-basin and by calculation method.

(i) Sub-basin ID.

(ii) Calculation method used, and name of the software package used if using Calculation 

Method 1.

(iii) The total annual gas-liquid separator oil volume that is sent to applicable onshore 

production storage tanks, in barrels.

(iv) The average gas-liquid separator temperature, in degrees.

(v) The average gas-liquid separator pressure, in pounds per square inch gauge.

(vi) The average sales oil or stabilized oil API gravity, in degrees.

(vii) The minimum and maximum concentration (mole fraction) of CO2 in flash gas from 

onshore production storage tanks.

(viii) The minimum and maximum concentration (mole fraction) of CH4 in flash gas from 

onshore production storage tanks.

(ix) The number of wells sending oil to gas-liquid separators or directly to atmospheric 

tanks.

(x) The number of atmospheric tanks.

(xi) An estimate of the number of atmospheric tanks, not on well-pads, receiving your oil.

(xii) If any emissions from the atmospheric tanks at your facility were controlled with 

vapor recovery systems, then you must report the information specified in paragraphs 

(j)(1)(xii)(A) through (j)(1)(xii)(E) of this section.
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(A) The number of atmospheric tanks that control emissions with vapor recovery 

systems.

(B) Total CO2 mass, in metric tons CO2, that was recovered during the calendar year 

using a vapor recovery system.

(C) Total CH4 mass, in metric tons CH4, that was recovered during the calendar year 

using a vapor recovery system.

(D) Annual CO2 emissions, in metric tons CO2, from atmospheric tanks equipped with 

vapor recovery systems.

(E) Annual CH4 emissions, in metric tons CH4, from atmospheric tanks equipped with 

vapor recovery systems.

(xiii) If any atmospheric tanks at your facility vented gas directly to the atmosphere 

without using a vapor recovery system or without flaring, then you must report the information 

specified in paragraphs (j)(1)(xiii)(A) through (j)(1)(xiii)(C) of this section.

(A) The number of atmospheric tanks that vented gas directly to the atmosphere without 

using a vapor recovery system or without flaring.

(B) Annual CO2 emissions, in metric tons CO2, that resulted from venting gas directly to 

the atmosphere.

(C) Annual CH4 emissions, in metric tons CH4, that resulted from venting gas directly to 

the atmosphere.

(xiv) If you controlled emissions from any atmospheric tanks at your facility with one or 

more flares, then you must report the information specified in paragraphs (j)(1)(xiv)(A) through 

(j)(1)(xiv)(D) of this section.

(A) The number of atmospheric tanks that controlled emissions with flares.
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(B) Annual CO2 emissions, in metric tons CO2, from atmospheric tanks that controlled 

emissions with one or more flares.

(C) Annual CH4 emissions, in metric tons CH4, from atmospheric tanks that controlled 

emissions with one or more flares.

(D) Annual N2O emissions, in metric tons N2O, from atmospheric tanks that controlled 

emissions with one or more flares.

(2) If you used Calculation Method 3 to calculate GHG emissions, then you must report 

the information specified in paragraph (j)(2)(i) through (j)(2)(iii) of this paragraph.

(i) Report the information specified in paragraphs (j)(2)(i)(A) through (j)(2)(i)(F) of this 

section, at the basin level, for atmospheric tanks where emissions were calculated using 

Calculation Method 3.

(A) The total annual oil throughput that is sent to all atmospheric tanks in the basin, in 

barrels.

(B) An estimate of the fraction of oil throughput reported in paragraph (j)(2)(i)(A) sent to 

atmospheric tanks in the basin that controlled emissions with flares.

(C) An estimate of the fraction of oil throughput reported in paragraph (j)(2)(i)(A) sent to 

atmospheric tanks in the basin that controlled emissions with vapor recovery systems.

(D) The number of atmospheric tanks in the basin.

(E) The number of wells with gas-liquid separators (“Count” from Equation W-15 of this 

subpart)in the basin.

(F) The number of wells without gas-liquid separators (“Count” from Equation W-15 of 

this subpart) in the basin.
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(ii) Report the information specified in paragraphs (j)(2)(ii)(A) through (j)(2)(ii)(D) of 

this section for each sub-basin with atmospheric tanks whose emissions were calculated using 

Calculation Method 3 and that did not control emissions with flares.

(A) Sub-basin ID.

(B) The number of atmospheric tanks in the sub-basin that did not control emissions with 

flares.

(C) Annual CO2 emissions, in metric tons CO2, from atmospheric tanks in the sub-basin 

that did not control emissions with flares, calculated using Equation W-15 of this subpart.

(D) Annual CH4 emissions, in metric tons CH4, from atmospheric tanks in the sub-basin 

that vented gas directly to the atmosphere, calculated using Equation W-15 of this subpart.

(iii) Report the information specified in paragraphs (j)(2)(iii)(A) through (j)(2)(iii)(E) of 

this section for each sub-basin with atmospheric tanks whose emissions were calculated using 

Calculation Method 3 and that controlled emissions with flares.

(A) Sub-basin ID.

(B) The number of atmospheric tanks in the sub-basin that controlled emissions with 

flares.

(C) Annual CO2 emissions, in metric tons CO2, from atmospheric tanks that controlled 

emissions with flares.

(D) Annual CH4 emissions, in metric tons CH4, from atmospheric tanks that controlled 

emissions with flares.

(E) Annual N2O emissions, in metric tons N2O, from atmospheric tanks that controlled 

emissions with flares.
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(3) If any gas-liquid separator liquid dump values did not close properly during the 

calendar year, then you must report the information specified in paragraphs (j)(3)(i) through 

(j)(3)(iv) of this section.

(i) The total number of gas-liquid separators whose liquid dump valves did not close 

properly during the calendar year.

(ii) The total time the dump valves on gas-liquid separators did not close properly in the 

calendar year, in hours (“Tn” in Equation W-16 of this subpart).

(iii) Annual CO2 emissions, in metric tons CO2, that resulted from dump valves on gasliquid separators not closing properly during the calendar year, calculated using Equation W-16 

of this subpart.

(iv) Annual CH4 emissions, in metric tons CH4, that resulted from the dump valves on 

gas-liquid separators not closing properly during the calendar year, calculated using Equation W16 of this subpart.

(k) Transmission storage tanks. You must indicate whether your facility contains any 

transmission storage tanks. If your facility contains at least one transmission storage tank, then 

you must report the information specified in paragraphs (k)(1) through (k)(3) of this section for 

each transmission storage tank vent stack.

(1) For each transmission storage tank vent stack, report the information specified in 

(k)(1)(i) through (k)(1)(iv) of this section.

(i) The unique name or ID number for the transmission storage tank vent stack.

(ii) Method used to determine if dump valve leakage occurred.

(iii) Indicator whether scrubber dump valve leakage occurred for the transmission storage 

tank vent.
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(iv) Indicator if there is a flare attached to the transmission storage tank vent stack.

(2) If scrubber dump valve leakage occurred for a transmission storage tank vent stack, as 

reported in paragraph (k)(1)(iii), and the vent stack vented directly to the atmosphere during the 

calendar year, then you must report the information specified in paragraphs (k)(2)(i) through 

(k)(2)(v) of this section for each transmission storage vent stack where scrubber dump valve 

leakage occurred.

(i) Method used to measure the leak rate.

(ii) Measured leak rate (average leak rate from a continuous flow measurement device),

in standard cubic feet per hour.

(iii) Duration of time that venting occurred, in hours (may use best available data if a 

continuous flow measurement device was used).

(iv) Annual CO2 emissions, in metric tons CO2, that resulted from venting gas directly to 

the atmosphere, calculated according to § 98.233(k)(1) through (k)(3).

(v) Annual CH4 emissions, in metric tons CH4, that resulted from venting gas directly to 

the atmosphere, calculated according to § 98.233(k)(1) through (k)(3).

(3) If scrubber dump valve leakage occurred for a transmission storage tank vent stack, as 

reported in paragraph (k)(1)(iii), and the vent stack vented to a flare during the calendar year, 

then you must report the information specified in paragraphs (k)(3)(i) through (k)(3)(vi).

(i) Method used to measure the leak rate.

(ii) Measured leakage rate (average leak rate from a continuous flow measurement 

device) in standard cubic feet per hour.

(iii) Duration of time that flaring occurred in hours (may use best available data if a 

continuous flow measurement device was used).
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(iv) Annual CO2 emissions, in metric tons CO2, that resulted from flaring gas, calculated 

according to § 98.233(k)(4).

(v) Annual CH4 emissions, in metric tons CH4, that resulted from flaring gas, calculated 

according to § 98.233(k)(4).

(vi) Annual N2O emissions, in metric tons N2O, that resulted from flaring gas, calculated 

according to § 98.233(k)(4).

(l) Well testing. You must indicate whether you performed gas well or oil well testing, 

and if the testing of gas wells or oil wells resulted in vented or flared emissions during the 

calendar year. If you performed well testing that resulted in vented or flared emissions during the 

calendar year, then you must report the information specified in paragraphs (l)(1) through (l)(4), 

as applicable.

(1) If you used Equation W-17A to calculate annual volumetric natural gas emissions at 

actual conditions from oil wells and the emissions are not vented to a flare, then you must report 

the information specified in paragraphs (l)(1)(i) through (l)(1)(vi) of this section.

(i) Number of wells tested in the calendar year.

(ii) Average number of well testing days in the calendar year.

(iii) Average gas to oil ratio for well(s) tested, in cubic feet of gas per barrel of oil.

(iv) Average flow rate for well(s) tested, in barrels of oil per day.

(v) Annual CO2 emissions, in metric tons CO2, calculated according to § 98.233(l).

(vi) Annual CH4 emissions, in metric tons CH4, calculated according to § 98.233(l).

(2) If you used Equation W-17A to calculate annual volumetric natural gas emissions at 

actual conditions from oil wells and the emissions are vented to a flare, then you must report the 

information specified in paragraphs (l)(2)(i) through (l)(2)(vii) of this section.
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(i) Number of wells tested in the calendar year.

(ii) Average number of well testing days in the calendar year.

(iii) Average gas to oil ratio for well(s) tested, in cubic feet of gas per barrel of oil.

(iv) Average flow rate for well(s) tested, in barrels of oil per day.

(v) Annual CO2 emissions, in metric tons CO2, calculated according to § 98.233(l).

(vi) Annual CH4 emissions, in metric tons CH4, calculated according to § 98.233(l).

(vii) Annual N2O emissions, in metric tons N2O, calculated according to § 98.233(l).

(3) If you used Equation W-17B to calculate annual volumetric natural gas emissions at 

actual conditions from gas wells and the emissions were not vented to a flare, then you must 

report the information specified in paragraphs (l)(3)(i) through (l)(3)(v) of this section.

(i) Number of wells tested in the calendar year.

(ii) Average number of well testing days in the calendar year.

(iii) Average annual production rate for well(s) tested, in actual cubic feet per day.

(iv) Annual CO2 emissions, in metric tons CO2, calculated according to § 98.233(l).

(v) Annual CH4 emissions, in metric tons CH4, calculated according to § 98.233(l).

(4) If you used Equation W-17B to calculate annual volumetric natural gas emissions at 

actual conditions from gas wells and the emissions were vented to a flare, then you must report 

the information specified in paragraphs (l)(4)(i) through (l)(4)(vi) of this section.

(i) Number of wells tested in calendar year.

(ii) Average number of well testing days in the calendar year.

(iii) Average annual production rate for well(s) tested, in actual cubic feet per day.

(iv) Annual CO2 emissions, in metric tons CO2, calculated according to § 98.233(l).

(v) Annual CH4 emissions, in metric tons CH4, calculated according to § 98.233(l).
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(vi) Annual N2O emissions, in metric tons N2O, calculated according to § 98.233(l).

(m) Associated natural gas. You must indicate whether any associated gas was vented or 

flared during the calendar year. If associated gas was vented or flared during the calendar year, 

then you must report the information specified in paragraphs (m)(1) through (m)(9) of this 

section for each sub-basin.

(1) Sub-basin ID. 

(2) Indicator whether any associated gas was vented directly to the atmosphere without 

flaring.

(3) Indicator whether any associated gas was flared.

(4) Average gas to oil ratio, in standard cubic feet of gas per barrel of oil (average of the 

“GOR” values used in Equation W-18 of this subpart).

(5) Volume of oil produced, in barrels, in the calendar year during the time periods in 

which associated gas was vented or flared (the sum of “Vp,q” used in Equation W-18 of this 

subpart).

(6) Total volume of associated gas sent to sales, in standard cubic feet, in the calendar 

year during time periods in which associated gas was vented or flared (the sum of “SG” values 

used in Equation W-18 of this subpart).

(7) Total volume of emissions reported elsewhere, in standard cubic feet, during time 

periods in which associated gas was vented or flared and which are calculated and reported under 

other paragraphs of this section, in standard cubic feet (the sum of “EREp,q” values used in 

Equation W-18 of this subpart).
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(8) If you had associated gas emissions directly to the atmosphere without flaring, then 

you must report the information specified in paragraphs (m)(8)(i) through (m)(8)(iii) of this 

section for each sub-basin.

(i) Total number of wells for which associated gas was vented directly to the atmosphere 

without flaring.

(ii) Annual CO2 emissions, in metric tons CO2, calculated according to § 98.233(m)(3) 

and (m)(4).

(iii) Annual CH4 emissions, in metric tons CH4, calculated according to § 98.233(m)(3) 

and (m)(4).

(9) If you had associated gas emissions that were flared, then you must report the 

information specified in paragraphs (m)(9)(i) through (m)(9)(iv) of this section for each subbasin.

(i) Total number of wells for which associated gas was flared.

(ii) Annual CO2 emissions, in metric tons CO2, calculated according to § 98.233(m)(5).

(iii) Annual CH4 emissions, in metric tons CH4, calculated according to § 98.233(m)(5).

(iv) Annual N2O emissions, in metric tons N2O, calculated according to § 98.233(m)(5). 

(n) Flare stacks. You must indicate if your facility contains any flare stacks. You must 

report the information specified in paragraphs (n)(1) through (n)(12) of this section for each flare 

stack at your facility, and for each industry segment applicable to your facility.

(1) Unique name or ID for the flare stack. For the onshore petroleum and natural gas 

production industry segment, a different name or ID may be used for a single flare stack for each 

location where it operates at in a given calendar year.

(2) Indicate whether the flare stack has a continuous flow measurement device.
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(3) Indicate whether the flare stack has a continuous gas composition analyzer on feed 

gas to the flare.

(4) Volume of gas sent to the flare, in standard cubic feet (“Va” in Equation W-19 of this 

subpart).

(5) Fraction of the feed gas sent to an un-lit flare (“Zu” in Equation W-19 of this subpart).

(6) Flare combustion efficiency, expressed as the fraction of gas combusted by a burning 

flare.

(7) Mole fraction of CH4 in the feed gas to the flare (“XCH4” in Equation W-19 of this 

subpart).

(8) Mole fraction of CO2 in the feed gas to the flare (“XCO2” in Equation W-20 of this 

subpart).

(9) Annual CO2 emissions, in metric tons CO2 (refer to Equation W-20 of this subpart).

(10) Annual CH4 emissions, in metric tons CH4 (refer to Equation W-19 of this subpart).

(11) Annual N2O emissions, in metric tons N2O (refer to Equation W-40 of this subpart).

(12) Indicate whether a CEMS was used to measure emissions from the flare. If a CEMS 

was used to measure emissions from the flare, then you are not required to report N2O and CH4

emissions for the flare stack.

(o) Centrifugal compressors. You must indicate whether your facility has centrifugal 

compressors. You must report the information specified in paragraphs (o)(1) and (o)(2) of this 

section for all centrifugal compressors at your facility. For each compressor source or 

manifolded group of compressor sources that you conduct as found leak measurements as 

specified in § 98.233(o)(2) or (o)(4), you must report the information specified in paragraph 

(o)(3) of this section. For each compressor source or manifolded group of compressor sources 
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that you conduct continuous monitoring as specified in § 98.233(o)(3) or (o)(5), you must report 

the information specified in paragraph (o)(4) of this section. Centrifugal compressors in onshore 

petroleum and natural gas production are not required to report information in paragraphs (o)(1) 

through (o)(4) of this section and instead must report the information specified in paragraph 

(o)(5) of this section. 

(1) Compressor activity data. Report the information specified in paragraphs (o)(1)(i) 

through (o)(1)(xvi) of this section for each compressor located at your facility.

(i) Unique name or ID for the centrifugal compressor.

(ii) Hours in operating-mode.

(iii) Hours in not-operating-depressurized-mode.

(iv) Indicate whether the compressor was measured in operating-mode.

(v) Indicate whether the compressor was measured in not-operating-depressurized-mode.

(vi) Indicate whether any compressor sources are part of a manifolded group of 

compressor sources.

(vii) Indicate whether any compressor sources are routed to a flare.

(viii) Indicate whether any compressor sources have vapor recovery.

(ix) Indicate whether emissions from any compressor sources are captured for fuel use or 

are routed to a thermal oxidizer.

(x) Indicate whether the compressor has blind flanges installed.

(xi) Indicate whether the compressor has wet or dry seals.

(xii) If the compressor has wet seals, the number of wet seals.

(xiii) Compressor power rating (hp).

(xiv) Year compressor was installed.
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(xv) Compressor model name and description.

(xvi) Date of last maintenance shutdown that compressor was depressurized.

(2) Compressor source emission vent. For each compressor source at each compressor, 

report the information specified in paragraphs (o)(2)(i) through (o)(2)(viii) of this section.

(i) Centrifugal compressor name or ID. Use the same ID as in paragraph (o)(1)(i) of this 

section.

(ii) Centrifugal compressor source (wet seal, isolation valve, or blowdown valve).

(iii) Unique name or ID for the emission vent. If the emission vent is connected to a 

manifolded group of compressor sources, use the same emission vent ID for each compressor 

source.

(iv) Emission vent type. Indicate whether the emission vent is for a single compressor 

source or manifolded group of compressor sources and whether the emissions from the emission 

vent are released to the atmosphere, routed to a flare, combustion (fuel or thermal oxidizer), or 

vapor recovery.

(v) Indicate whether an as found leak measurement(s) as identified in § 98.233(o)(2) or 

(o)(4) was conducted on the emission vent.

(vi) Indicate whether continuous leak measurements as identified in § 98.233(o)(3) or 

(o)(5) were conducted on the emission vent.

(vii) Report emissions as specified in paragraphs (o)(2)(vii)(A) and (o)(2)(vii)(B) of this 

section for the emission vent. For emission vents associated with individual compressor sources 

that use an as found leak measurement(s), calculate emissions by summing all emissions from all 

compressor mode-source combinations for the emission vent.

(A) Annual CO2 emissions, in metric tons CO2.
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(B) Annual CH4 emissions, in metric tons CH4.

(viii) If the emission vent is routed to flare, combustion, or vapor recovery, report the 

percentage of time that the respective device was operational.

(3) As found leak measurement sample data. If the measurement methods specified in 

paragraphs § 98.233(o)(2) or (o)(4) are conducted, report the information specified in paragraph 

(o)(3)(i) of this section. If the measurement method specified in paragraph § 98.233(o)(2) is 

performed, report the information specified in paragraph (o)(3)(ii) of this section.

(i) For each as found leak measurement performed on an emission vent, report the 

information specified in paragraphs (o)(3)(i)(A) through (o)(3)(i)(E) of this section.

(A) Name or ID of emission vent. Use same emission vent ID as in paragraph (o)(2)(iii) 

of this section.

(B) Sample date.

(C) Leak measurement method.

(D) Measured flow rate, in standard cubic feet per hour.

(E) For each compressor attached to the emission vent, report the mode of operation the 

compressor was in when the sample was taken.

(ii) For each compressor mode-source combination where a reporter emission factor as 

calculated in equation W-24 was used to calculate emissions in Equation W-23, report the 

information specified in paragraphs (o)(3)(ii)(A) through (o)(3)(ii)(D) of this section

(A)The compressor mode-source combination.

(B) The compressor mode-source combination reporter emission factor, in standard cubic 

feet per hour (EFm,s in Equation W-24).
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(C) The total number of compressors measured in the compressor mode-source 

combination in the current reporting year and the preceding two reporting years (Countm in 

Equation W-24).

(D) Indicate whether the compressor mode-source combination reporter emission factor 

is facility-specific or corporate.

(4) Continuous leak measurement data. If the measurement methods specified in 

paragraphs § 98.233(o)(3) or (o)(5) are conducted, report the information specified in paragraphs 

(o)(4)(i) and (o)(4)(ii) of this section for each continuous measurement conducted on each 

emission vent associated with each compressor source or manifolded group of compressor 

sources.

(i) Name or ID of emission vent. Use same emission vent ID as in paragraph (o)(2)(iii) of 

this section.

(ii) Measured volume of flow during the reporting year, in million standard cubic feet.

(5) Centrifugal compressors with wet seal degassing vents in onshore petroleum and 

natural gas production must report the information specified in paragraphs (o)(5)(i) through 

(o)(5)(iii) of this section.

(i) Number of centrifugal compressors that have wet seal oil degassing vents.

(ii) Annual CO2 emissions, in metric tons CO2, from centrifugal compressors with wet 

seal oil degassing vents.

(iii) Annual CH4 emissions, in metric tons CH4, from centrifugal compressors with wet 

seal oil degassing vents.

(p) Reciprocating compressors. You must indicate whether your facility has reciprocating 

compressors. You must report the information specified in paragraphs (p)(1) and (p)(2) of this 
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section for all reciprocating compressors at your facility. For each compressor source or 

manifolded group of compressor sources that you conduct as found leak measurements as 

specified in § 98.233(p)(2) or (p)(4), you must report the information specified in paragraph 

(p)(3) of this section. For each compressor source or manifolded group of compressor sources 

that you conduct continuous monitoring as specified in § 98.233(p)(3) or (p)(5), you must report 

the information specified in paragraph (p)(4) of this section. Reciprocating compressors in 

onshore petroleum and natural gas production are not required to report information in 

paragraphs (p)(1) through (p)(4) of this section and instead must report the information specified 

in paragraph (p)(5) of this section. 

(1) Compressor activity data. Report the information specified in paragraphs (p)(1)(i) 

through (p)(1)(xvi) of this section for each compressor located at your facility.

(i) Unique name or ID for the reciprocating compressor.

(ii) Hours in operating-mode.

(iii) Hours in standby-depressurized-mode.

(iv) Hours in not-operating-depressurized-mode.

(v) Indicate whether the compressor was measured in operating-mode.

(vi) Indicate whether the compressor was measured in standby-depressurized-mode.

(vii) Indicate whether the compressor was measured in not-operating-depressurizedmode.

(viii) Indicate whether any compressor sources are part of a manifolded group of 

compressor sources.

(ix) Indicate whether any compressor sources are routed to a flare.

(x) Indicate whether any compressor sources have vapor recovery.
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(xi) Indicate whether emissions from any compressor sources are captured for fuel use or 

are routed to a thermal oxidizer.

(xii) Indicate whether the compressor has blind flanges installed.

(xiii) Compressor power rating (hp).

(xiv) Year compressor was installed.

(xv) Compressor model name and description.

(xvi) Date of last maintenance shutdown for rod packing replacement.

(2) Compressor source emission vent. For each compressor source at each compressor, 

report the information specified in paragraphs (p)(2)(i) through (p)(2)(viii) of this section.

(i) Reciprocating compressor name or ID. Use the same ID as in paragraph (p)(1)(i) of 

this section.

(ii) Reciprocating compressor source (isolation valve, blowdown valve, or rod packing).

(iii) Unique name or ID for the emission vent. If the emission vent is connected to a 

manifolded group of compressor sources, use the same emission vent ID for each compressor 

source.

(iv) Emission vent type. Indicate whether the emission vent is for a single compressor 

source or manifolded group of compressor sources and whether the emissions from the emission 

vent are released to the atmosphere, routed to a flare, combustion (fuel or thermal oxidizer), or 

vapor recovery.

(v) Indicate whether an as found leak measurement(s) as identified in § 98.233(p)(2) or 

(p)(4) was conducted on the emission vent.

(vi) Indicate whether continuous leak measurements as identified in § 98.233(p)(3) or 

(p)(5) were conducted on the emission vent.
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(vii) Report emissions as specified in paragraphs (p)(2)(vii)(A) and (p)(2)(vii)(B) of this 

section for the emission vent. For emission vents associated with individual compressor sources 

that use an as found leak measurement(s), calculate emissions by summing all emissions from all 

compressor mode-source combinations for the emission vent.

(A) Annual CO2 emissions, in metric tons CO2.

(B) Annual CH4 emissions, in metric tons CH4.

(viii) If the emission vent is routed to flare, combustion, or vapor recovery, report the 

percentage of time that the respective device was operational.

(3) As found leak measurement sample data. If the measurement methods specified in 

paragraphs § 98.233(p)(2) or (p)(4) are conducted, report the information specified in paragraph 

(p)(3)(i) of this section. If the measurement method specified in paragraph § 98.233(p)(2) is 

performed, report the information specified in paragraph (p)(3)(ii) of this section.

(i) For each as found leak measurement performed on an emission vent, report the 

information specified in paragraphs (p)(3)(i)(A) through (p)(3)(i)(E) of this section.

(A) Name or ID of emission vent. Use same emission vent ID as in paragraph (p)(2)(iii) 

of this section.

(B) Sample date.

(C) Leak measurement method.

(D) Measured flow rate, in standard cubic feet per hour.

(E) For each compressor attached to the emission vent, report the mode of operation the 

compressor was in when the sample was taken.
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(ii) For each compressor mode-source combination where a reporter emission factor as 

calculated in equation W-28 was used to calculate emissions in Equation W-27, report the 

information specified in paragraphs (p)(3)(ii)(A) through (p)(3)(ii)(D) of this section

(A) The compressor mode-source combination.

(B) The compressor mode-source combination reporter emission factor, in standard cubic 

feet per hour (EFm,s in Equation W-28).

(C) The total number of compressors measured in the compressor mode-source 

combination in the current reporting year and the preceding two reporting years (Countm in 

Equation W-28).

(D) Indicate whether the compressor mode-source combination reporter emission factor 

is facility-specific or corporate.

(4) Continuous leak measurement data. If the measurement methods specified in 

paragraphs § 98.233(p)(3) or (p)(5) are conducted, report the information specified in paragraphs 

(p)(4)(i) and (p)(4)(ii) of this section for each continuous measurement conducted on each 

emission vent associated with each compressor source or manifolded group of compressor 

sources.

(i) Name or ID of emission vent. Use same emission vent ID as in paragraph (p)(2)(iii) of 

this section.

(ii) Measured volume of flow during the reporting year, in million standard cubic feet.

(5) Reciprocating compressors in onshore petroleum and natural gas production must 

report the information specified in paragraphs (p)(5)(i) through (p)(5)(iii) of this section.

(i) Number of reciprocating compressors.

(ii) Annual CO2 emissions, in metric tons CO2, from reciprocating compressors.
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(iii) Annual CH4 emissions, in metric tons CH4, from reciprocating compressors.

(q) Equipment leak surveys. If your facility is subject to the requirements of § 98.233(q), 

then you must report the information specified in paragraphs (q)(1) and (q)(2) of this section. 

Natural gas distribution facilities must also report the information specified in paragraph (q)(3) 

of this section.

(1) You must report the information specified in paragraphs (q)(1)(i) and (ii) of this 

section.

(i) The number of complete equipment leak surveys performed during the calendar year.

(ii) Natural gas distribution facilities performing equipment leak surveys across a 

multiple year leak survey cycle must report the number of years in the leak survey cycle.

(2) You must indicate whether your facility contains any of the component types listed in 

§ 98.232(d)(7), (e)(7), (f)(5), (g)(3), (h)(4), or (i)(1), for your facility’s industry segment. For 

each component type that is located at your facility, you must report the information specified in 

paragraphs (q)(2)(i) through (q)(2)(v) of this section. If a component type is located at your 

facility and no leaks were identified from that component, then you must report the information 

in paragraphs (q)(2)(i) through (q)(2)(v) of this section but report a zero (“0”) for the information 

required according to paragraphs (q)(2)(iii), (q)(2)(iv), and (q)(2)(v) of this section..

(i) Component type. 

(ii) Total number of the surveyed component type that were identified as leaking in the 

calendar year (“xp” in Equation W-30 of this subpart for the component type).

(iii) Average time the surveyed components were found leaking and operational, in hours 

(average of “Tp,z” from Equation W-30 of this subpart for the component type).

(iv) Annual CO2 emissions, in metric tons CO2, for the component type.
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(v) Annual CH4 emissions, in metric tons CH4, for the component type.

(3) Natural gas distribution facilities must report the information specified in paragraphs 

(q)(3)(i) through (q)(3)(viii) of this subpart.

(i) Number of above grade transmission-distribution transfer stations surveyed in the 

calendar year.

(ii) Number of meter/regulator runs at above grade transmission-distribution transfer 

stations surveyed in the calendar year (“CountMR,y” from Equation W-31 of this subpart, for the 

current calendar year). 

(iii) Average time that meter/regulator runs surveyed in the calendar year were 

operational, in hours (average of “Tw,y” from Equation W-31 of this subpart, for the current 

calendar year).

(iv) Number of above grade transmission-distribution transfer stations surveyed in the 

current leak survey cycle.

(v) Number of meter/regulator runs at above grade transmission-distribution transfer 

stations surveyed in current leak survey cycle (sum of “CountMR,y” from Equation W-31 of this 

subpart, for all calendar years in the current leak survey cycle).

(vi) Average time that meter/regulator runs surveyed in the current leak survey cycle 

were operational, in hours (average of “Tw,y” from Equation W-31 of this subpart, for all years 

included in the leak survey cycle).

(vii) Meter/regulator run CO2 emission factor based on all surveyed transmissiondistribution transfer stations in the current leak survey cycle, in standard cubic feet of CO2 per 

meter/regulator run operating hour (“EFs,MR,i” for CO2 calculated using Equation W-31 of this 

subpart).
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(viii) Meter/regulator run CH4 emission factor based on all surveyed transmissiondistribution transfer stations in the current leak survey cycle, in standard cubic feet of CH4 per 

meter/regulator run operating hour (“EFs,MR,i” for CH4 calculated using Equation W-31 of this 

subpart).

(r) Equipment leaks by population count. If your facility is subject to the requirements of 

§ 98.233(r), then you must report the information specified in paragraph (r)(1) of this section. 

Natural gas distribution facilities must also report the information specified in paragraph (r)(2) of 

this section. Onshore petroleum and natural gas production facilities must also report the 

information specified in paragraph (r)(3) of this section.

(1) You must indicate whether your facility contains any of the emission source types 

covered by § 98.233(r), for the applicable industry segment. You must report the information 

specified in paragraphs (r)(1)(i) through (r)(1)(v) of this section separately for each emission 

source type that is located at your facility. Onshore petroleum and natural gas production 

facilities must report the information specified in paragraphs (r)(1)(i) through (r)(1)(v) of this 

section separately by component type, service type, and geographic location (i.e., Eastern U.S or 

Western U.S.).

(i) Emission source type. Onshore petroleum and natural gas production facilities must 

report the component type, service type and geographic location.

(ii) Total number of the emission source type at the facility (“Counte” in Equation W-32A 

of this subpart).

(iii) Average estimated time that the emission source type was operational in the calendar 

year, in hours (“Te” in Equation W-32A of this subpart).

(iv) Annual CO2 emissions, in metric tons CO2, for the emission source type.
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(v) Annual CH4 emissions, in metric tons CH4, for the emission source type.

(2) Natural gas distribution facilities must also report the information specified in 

paragraphs (q)(2)(i) through (q)(2)(viii) of this subpart.

(i) Number of above grade transmission-distribution transfer stations at the facility.

(ii) Number of above grade metering-regulating stations that are not transmissiondistribution transfer stations at the facility.

(iii) Number of below grade transmission-distribution transfer stations at the facility.

(iv) Number of below grade metering-regulating stations that are not transmissiondistribution transfer stations at the facility.

(v) Total number of meter/regulator runs at above grade metering-regulating stations that 

are not above grade transmission-distribution transfer stations (“CountMR” in Equation W-32B of 

this subpart).

(vi) Average estimated time that each meter/regulator run was operational in the calendar 

year, in hours per meter/regulator run (“Tw,avg” in Equation W-32B of this subpart).

(vii) Annual CO2 emissions, in metric tons CO2, from above grade metering regulating 

stations that are not above grade transmission-distribution transfer stations.

(viii) Annual CH4 emissions, in metric tons CH4, from above grade metering regulating 

stations that are not above grade transmission-distribution transfer stations.

(3) Onshore petroleum and natural gas production facilities must also report the 

information specified in paragraphs (r)(3)(i) and (r)(3)(ii) of this section.

(i) Calculation method used. 

(ii) Onshore petroleum and natural gas production facilities must report the information 

specified in paragraphs (r)(3)(ii)(A) and (r)(3)(ii)(B) of this section, for each major equipment 
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type, production type (i.e., natural gas or crude oil), and geographic location combination in 

Tables W-1B and W-1C of this subpart.

(A) An indication of whether the facility contains the major equipment type.

(B) If the facility does contain the equipment type, the count of the major equipment 

type.

(s) Offshore petroleum and natural gas production. You must report the information 

specified in paragraphs (s)(1) through (s)(3) of this section for each emission source type listed 

in the most recent BOEMRE study. 

(1) Annual CO2 emissions, in metric tons CO2.

(2) Annual CH4 emissions, in metric tons CH4.

(3) Annual N2O emissions, in metric tons N2O.

(t) [Reserved]

(u) [Reserved]

(v) [Reserved]

(w) EOR injection pumps. You must indicate whether CO2 EOR injection was used at 

your facility during the calendar year and if any EOR injection pump blowdowns occurred 

during the year. If any EOR injection pump blowdowns occurred during the calendar year, then 

you must report the information specified in paragraphs (w)(1) through (w)(8) of this section for 

each EOR injection pump system.

(1) Sub-basin ID.

(2) EOR injection pump system identifier.

(3) Pump capacity, in barrels per day.
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(4) Total volume of EOR injection pump system equipment chambers, in cubic feet (“Vv” 

in Equation W-37 of this subpart).

(5) Number of blowdowns for the EOR injection pump system in the calendar year.

(6) Density of critical phase EOR injection gas, in kilograms per cubic foot (“Rc” in 

Equation W-37 of this subpart).

(7) Mass fraction of CO2 in critical phase EOR injection gas (“GHGCO2” in Equation W37 of this subpart).

(8) Annual CO2 emissions, in metric tons CO2, from EOR injection pump system 

blowdowns.

(x) EOR hydrocarbon liquids. You must indicate whether hydrocarbon liquids were 

produced through EOR operations. If hydrocarbon liquids were produced through EOR 

operations, you must report the information specified in paragraphs (x)(1) through (x)(4) of this 

section for each sub-basin category with EOR operations.

(1) Sub-basin ID. 

(2) Total volume of hydrocarbon liquids produced through EOR operations in the 

calendar year, in barrels (“Vhl” in Equation W-38 of this subpart).

(3) Average CO2 retained in hydrocarbon liquids downstream of the storage tank, in 

metric tons per barrel under standard conditions (“Shl” in Equation W-38 of this subpart).

(4) Annual CO2 emissions, in metric tons CO2, from CO2 retained in hydrocarbon liquids 

produced through EOR operations downstream of the storage tank (“MassCO2” in Equation W-38 

of this subpart). 

(y) [Reserved]
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(z) Combustion equipment at onshore petroleum and natural gas production facilities and 

natural gas distribution facilities. If your facility is required by § 98.232(c)(22) or (i)(7) to report 

emissions from combustion equipment, then you must indicate whether your facility has any 

combustion units subject to reporting according to paragraphs (a)(1)(xvii) or (a)(8)(i) of this 

section. If your facility contains any combustion units subject to reporting according to 

paragraphs (a)(1)(xvii) or (a)(8)(i) of this section, then you must report the information specified 

in paragraphs (z)(1) and (z)(2) of this section, as applicable.

(1) Indicate whether the combustion units include: external fuel combustion units with a 

rated heat capacity less than or equal to 5 million Btu per hour; or, internal fuel combustion units 

that are not compressor-drivers, with a rated heat capacity less than or equal to 1 mmBtu/hr (or 

the equivalent of 130 horsepower). If the facility contains external fuel combustion units with a 

rated heat capacity less than or equal to 5 million Btu per hour or internal fuel combustion units 

that are not compressor-drivers, with a rated heat capacity less than or equal to 1 million Btu per 

hour (or the equivalent of 130 horsepower), then you must report the information specified in 

paragraphs (z)(1)(i) and (z)(1)(ii) of this section for each unit type.

(i) The type of combustion unit. 

(ii) The total number of combustion units.

(2) Indicate whether the combustion units include: external fuel combustion units with a 

rated heat capacity greater than 5 million Btu per hour; internal fuel combustion units that are not 

compressor-drivers, with a rated heat capacity greater than 1 million Btu per hour (or the 

equivalent of 130 horsepower); or, internal fuel combustion units of any heat capacity that are 

compressor-drivers. If your facility contains: external fuel combustion units with a rated heat 

capacity greater than 5 mmBtu/hr; internal fuel combustion units that are not compressor-drivers, 
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with a rated heat capacity greater than 1 million Btu per hour (or the equivalent of 130 

horsepower); or internal fuel combustion units of any heat capacity that are compressor-drivers, 

then you must report the information specified in paragraphs (z)(2)(i) through (z)(2)(vi) for each 

combustion unit type and fuel type combination. 

(i) The type of combustion unit.

(ii) The type of fuel combusted.

(iii) The quantity of fuel combusted in the calendar year, in thousand standard cubic feet, 

gallons, or tons.

(iv) Annual CO2 emissions, in metric tons CO2, calculated according to § 98.233(z)(1) 

and (z)(2).

(v) Annual CH4 emissions, in metric tons CH4, calculated according to § 98.233(z)(1) and 

(z)(2). 

(vi) Annual N2O emissions, in metric tons N2O, calculated according to § 98.233(z)(1) 

and (z)(2).

(aa) Each facility must report the information specified in paragraphs (aa)(1) through 

(aa)(9) of this section, for each applicable industry segment, by using best available data. If a 

quantity required to be reported is zero, you must report zero as the value.

(1) For onshore petroleum and natural gas production, report the data specified in 

paragraphs (aa)(1)(i) and (aa)(1)(ii) of this section.

(i) Report the information specified in paragraphs (aa)(1)(i)(A) through (aa)(1)(i)(D) of 

this section for the basin as a whole.

(A) The quantity of gas produced in the calendar year from wells, in thousand standard 

cubic feet. This includes gas that is routed to a pipeline, vented or flared, or used in field 
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operations. This does not include gas injected back into reservoirs or shrinkage resulting from 

lease condensate production.

(B) The quantity of gas produced in the calendar year for sales, in thousand standard 

cubic feet.

(C) The quantity of crude oil produced in the calendar year for sales, not including lease 

condensates, in barrels.

(D) The quantity of lease condensate produced in the calendar year for sales, in barrels.

(ii) Report the information specified in paragraphs (aa)(1)(ii)(A) through (aa)(1)(ii)(M) of 

this section for each unique sub-basin category.

(A) State.

(B) County.

(C) Formation type.

(D) The number of producing wells at the end of the calendar year.

(E) The number of producing wells acquired during the calendar year.

(F) The number of producing wells divested during the calendar year.

(G) The number of wells completed during the calendar year.

(H) The number of wells taken out of production during the calendar year.

(I) Average mole fraction of CH4 in produced gas.

(J) Average mole fraction of CO2 in produced gas.

(K) If an oil sub-basin, report the average GOR of all wells, in thousand standard cubic 

feet per barrel.

(L) If an oil sub-basin, report the average API gravity of all wells.
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(M) If an oil sub-basin, report average low pressure separator pressure, in pounds per 

square inch gauge.

(2) For offshore production, report the quantities specified in paragraphs (aa)(2)(i) 

through (aa)(2)(iii) of this section.

(i) The quantity of gas produced from the offshore platform in the calendar year for sales, 

in thousand standard cubic feet.

(ii) The quantity of oil produced from the offshore platform in the calendar year for sales, 

in barrels.

(iii) The quantity of condensate produced from the offshore platform in the calendar year 

for sales, in barrels.

(3) For natural gas processing, report the quantities specified in paragraphs (aa)(3)(i) 

through (aa)(3)(vii) of this section.

(i) The quantity of produced gas received at the gas processing plant in the calendar year, 

in thousand standard cubic feet.

(ii) The quantity of processed (residue) gas leaving the gas processing plant in the 

calendar year, in thousand standard cubic feet.

(iii) The quantity of NGLs (bulk and fractionated) received at the gas processing plant in 

the calendar year, in barrels.

(iv) The quantity of NGLs (bulk and fractionated) leaving the gas processing plant in the 

calendar year, in barrels.

(v) Average mole fraction of CH4 in produced gas received.

(vi) Average mole fraction of CO2 in produced gas received.

(vii) Indicate whether the facility fractionates NGLs.
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(4) For natural gas transmission compression, report the quantity specified in paragraphs 

(aa)(4)(i) through (aa)(4)(v) of this section.

(i) The quantity of gas transported through the compressor station in the calendar year, in 

thousand standard cubic feet.

(ii) Number of compressors.

(iii) Total compressor power rating of all compressors combined, in horsepower.

(iv) Average upstream pipeline pressure, in pounds per square inch gauge.

(v) Average downstream pipeline pressure, in pounds per square inch gauge.

(5) For underground natural gas storage, report the quantities specified in paragraphs 

(aa)(5)(i) through (aa)(5)(iii) of this section.

(i) The quantity of gas injected into storage in the calendar year, in thousand standard 

cubic feet.

(ii) The quantity of gas withdrawn from storage in the calendar year, in thousand standard 

cubic feet.

(iii) Total storage capacity, in thousand standard cubic feet.

(6) For LNG import equipment, report the quantity of LNG imported in the calendar year, 

in thousand standard cubic feet.

(7) For LNG export equipment, report the quantity of LNG exported in the calendar year, 

in thousand standard cubic feet.

(8) For LNG storage, report the quantities specified in paragraphs (aa)(8)(i) through 

(aa)(8)(iii) of this section.

(i) The quantity of LNG added into storage in the calendar year, in thousand standard 

cubic feet.
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(ii) The quantity of LNG withdrawn from storage in the calendar year , in thousand 

standard cubic feet.

(iii) Total storage capacity, in thousand standard cubic feet.

(9) For natural gas distribution, report the quantities specified in paragraphs (aa)(9)(i) 

through (aa)(9)(vii) of this section.

(i) The quantity of natural gas received at all custody transfer stations in the calendar 

year, in thousand standard cubic feet. This value may include meter corrections, but only for the 

calendar year covered by the annual report.

(ii) The quantity of natural gas withdrawn from in-system storage in the calendar year, in 

thousand standard cubic feet.

(iii) The quantity of natural gas added to in-system storage in the calendar year, in 

thousand standard cubic feet.

(iv) The quantity of natural gas delivered to end users, in thousand standard cubic feet. 

This value does not include stolen gas, or gas that is otherwise unaccounted for.

(v) The quantity of natural gas transferred to third parties such as other LDCs or 

pipelines, in thousand standard cubic feet. This value does not include stolen gas, or gas that is 

otherwise unaccounted for.

(vi) The quantity of natural gas consumed by the LDC for operational purposes, in 

thousand standard cubic feet.

(vii) The estimated quantity of gas stolen in the calendar year, in thousand standard cubic 

feet.

(bb) For any missing data procedures used, report the information in paragraphs (bb)(1) 

through (bb)(5) in this section for each individual missing data value used in a calculation. 
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Aggregation of missing data values within a component, well, sub-basin, or basin is not 

acceptable. If missing data is substituted for the same parameter in non-consecutive periods 

during the calendar year, the information in paragraphs (bb)(1) through (bb)(5) in this section 

should be reported for each period separately.

(1) The date(s) the missing data is used.

(2) The equation(s) in which the missing data is used.

(3) The description of the unique or unusual circumstance that led to missing data use, 

including information on any equipment or components involved and any procedures that were 

not followed.

(4) The description of the procedures used to substitute an unavailable value of a 

parameter.

(5) The description of how the owner or operator will avoid the use of missing data in the 

future, such as mitigation strategies or changes to standard operating procedures.

9. Section 98.238 is amended by: 

a. Adding a definition for “Associated gas venting or flaring”;

b. Removing the definition for “Component”;

c. Adding definitions for “Compressor mode” and “Compressor Source”;

d. Removing the definitions for “Equipment leak” and “Equipment leak detection”;

e. Adding definitions for “Manifolded compressor source” and “Manifolded group of 

compressor sources”;

f. Revising the definition for “Meter/regulator run”;
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g. Adding definitions for “Reduced emissions completion” and “Reduced emissions 

workover”; and

h. Revising the definition for “Sub-basin category, for onshore natural gas production.”

The revisions and additions read as follows:

§ 98.238 Definitions.

* * * * *

Associated gas venting or flaring means the venting or flaring of natural gas which 

originates at wellheads that also produce hydrocarbon liquids and occurs either in a discrete 

gaseous phase at the wellhead or is released from the liquid hydrocarbon phase by separation. 

This does not include venting or flaring resulting from activities that are reported elsewhere, 

including tank venting, well completions, and well workovers.

* * * * *

Compressor mode means the operational and pressurized status of a compressor. For a 

centrifugal compressor, “mode” refers to either operating -mode or not-operating-depressurized -

mode. For a reciprocating compressor, “mode” refers to either: operating -mode, standbypressurized -mode, or not-operating-depressurized -mode.

Compressor source means any type of vent or valve (i.e., wet seal, blowdown valve, 

isolation valve, or rod packing) on a centrifugal or reciprocating compressor.

* * * * *

Manifolded compressor source means a compressor source (as defined in this section) 

that is manifolded to a common vent that routes gas from multiple compressors.
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Manifolded group of compressor sources means a collection of any combination of 

manifolded compressor sources (as defined in this section) that are manifolded to a common 

vent.

Meter/regulator run means a series of components used in regulating pressure or metering 

natural gas flow or both. At least one meter, at least on regulator, or any combination of both on 

a single run of piping is considered one meter/regulator run.

* * * * *

Reduced emissions completion means a well completion following hydraulic fracturing 

where gas flowback that is otherwise vented is captured, cleaned, and routed to the flow line or 

collection system, re-injected into the well or another well, used as an on-site fuel source, or used 

for other useful purpose that a purchased fuel or raw material would serve, with no direct release 

to the atmosphere.

Reduced emissions workover means a well workover with hydraulic fracturing (i.e., 

refracturing) where gas flowback that is otherwise vented is captured, cleaned, and routed to the 

flow line or collection system, re-injected into the well or another well, used as an on-site fuel 

source, or used for other useful purpose that a purchased fuel or raw material would serve, with 

no direct release to the atmosphere.

* * * * *

Sub-basin category, for onshore natural gas production, means a subdivision of a basin 

into the unique combination of wells with the surface coordinates within the boundaries of an 

individual county and subsurface completion in one or more of each of the following five 

formation types: Oil, high permeability gas, shale gas, coal seam, or other tight gas reservoir 

rock. The distinction between high permeability gas and tight gas reservoirs shall be designated 
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as follows: High permeability gas reservoirs with >0.1 millidarcy permeability, and tight gas 

reservoirs with ≤0.1 millidarcy permeability. Permeability for a reservoir type shall be 

determined by engineering estimate. Wells that produce only from high permeability gas, shale 

gas, coal seam, or other tight gas reservoir rock are considered gas wells; gas wells producing 

from more than one of these formation types shall be classified into only one type based on the 

formation with the most contribution to production as determined by engineering knowledge. All 

wells that produce hydrocarbon liquids (with or without gas) and do not meet the definition of a 

gas well in this sub-basin category definition are considered to be in the oil formation. All 

emission sources that handle condensate from gas wells in high permeability gas, shale gas, or 

tight gas reservoir rock formations are considered to be in the formation that the gas well belongs 

to and not in the oil formation.

* * * * *