Vol. 79 Tuesday, 

No. 227 November 25, 2014 

Part IV 

Environmental Protection Agency 

40 CFR Part 98 

Greenhouse Gas Reporting Rule: 2014 Revisions and Confidentiality 

Determinations for Petroleum and Natural Gas Systems; Final Rule 


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70352 Federal Register / Vol. 79, No. 227 / Tuesday, November 25, 2014 / Rules and Regulations 

ENVIRONMENTAL PROTECTION 

AGENCY 

40 CFR Part 98 

[EPA–HQ–OAR–2011–0512; FRL–9918–95– 

OAR] 

RIN 2060–AR96 

Greenhouse Gas Reporting Rule: 2014 

Revisions and Confidentiality 

Determinations for Petroleum and 

Natural Gas Systems 

AGENCY: Environmental Protection 

Agency. 

ACTION: Final rule. 

SUMMARY: The Environmental Protection 

Agency (EPA) is finalizing revisions and 

confidentiality determinations for the 

petroleum and natural gas systems 

source category and the general 

provisions of the Greenhouse Gas 

Reporting Rule. These revisions include 

changes to certain calculation methods, 

amendments to certain monitoring and 

data reporting requirements, 

clarification of certain terms and 

definitions, and corrections to certain 

technical and editorial errors that have 

been identified during the course of 

implementation. This action also 

finalizes confidentiality determinations 

for new or substantially revised data 

elements contained in these 

amendments and revises the 

confidentiality determination for one 

existing data element. 

DATES: This final rule is effective on 

January 1, 2015. 

ADDRESSES: 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., confidential 

business information (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 INFORMATION CONTACT: 

Carole Cook, Climate Change Division, 

Office of Atmospheric Programs (MC– 

6207A), Environmental Protection 

Agency, 1200 Pennsylvania Ave. NW., 

Washington, DC 20460; telephone 

number: (202) 343–9263; fax number: 

(202) 343–2342; email address: 

GHGReportingRule@epa.gov. For 

technical information, please go to the 

Greenhouse Gas Reporting Rule Web 

site, http://www.epa.gov/ghgreporting/. 

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 this final rule will 

also be available through the WWW. 

Following the Administrator’s signature, 

a copy of this action will be posted on 

the EPA’s Greenhouse Gas Reporting 

Rule Web site at http://www.epa.gov/

ghgreporting/index.html. 

SUPPLEMENTARY INFORMATION: 

Regulated Entities. This final rule 

revises certain calculation methods, 

monitoring, and data reporting 

requirements and finalizes 

confidentiality determinations for the 

petroleum and natural gas systems 

source category and the general 

provisions of the Greenhouse Gas 

Reporting Rule (40 CFR part 98). The 

Administrator determined that 40 CFR 

part 98 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’’). Entities affected by 

this final rule are owners and operators 

of petroleum and natural gas systems 

that directly emit greenhouse gases 

(GHGs), which 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 ......................................... 211111 Crude petroleum and natural gas extraction. 

211112 Natural gas liquid extraction. 

221210 Natural gas distribution. 

486210 Pipeline transportation of natural gas. 

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. Types of facilities other than 

those 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 INFORMATION

CONTACT section. 

What is the effective date? The final 

rule is effective on January 1, 2015. 

Section 553(d) of the Administrative 

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

5, generally provides that rules may not 

take effect earlier than 30 days after they 

are published in the Federal Register. 

The EPA is issuing this final rule under 

section 307(d)(1) of the Clean Air Act, 

which states: ‘‘The provisions of section 

553 through 557 * * * of Title 5 shall 

not, except as expressly provided in this 

section, apply to actions to which this 

subsection applies.’’ Thus, section 

553(d) of the APA does not apply to this 

rule. The EPA is nevertheless acting 

consistently with the purposes 

underlying APA section 553(d) in 

making this rule effective on January 1, 

2015. Section 5 U.S.C. 553(d)(3) allows 

an effective date less than 30 days after 

publication ‘‘as otherwise provided by 

the agency for good cause found and 

published with the rule.’’ As explained 

below, the EPA finds that there is good 

cause for this rule to become effective 

on January 1, 2015, even though this 

may result in an effective date fewer 

than 30 days from date of publication in 

the Federal Register. 

While this action is being signed prior 

to December 1, 2014, there is likely to 

be a significant delay in the publication 

of this rule as it contains complex 

equations and tables and is relatively 

long. As an example, the EPA 

Administrator signed the Revisions and 

Confidentiality Determinations for 

Petroleum and Natural Gas Systems 

proposed rule on February 7, 2014, but 

the proposed rule was not published in 

the Federal Register until March 10, 

2014 (79 FR 13394). The purpose of the 

30-day waiting period prescribed in 5 

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

a reasonable time to adjust their 


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1Omnipoint Corp. v. FCC, 78 F3d 620, 630 (D.C. 

Cir. 1996), quoting U.S. v. Gavrilovic, 551 F.2d 

1099, 1105 (8th Cir. 1977). 

behavior and prepare before the final 

rule takes effect. 

To employ the 5 U.S.C. 553(d)(3) 

‘‘good cause’’ exemption, an agency 

must balance the necessity for 

immediate implementation against 

principles of fundamental fairness 

which require that all affected persons 

be afforded a reasonable amount of time 

to prepare for the effective date of its 

ruling.1 Where, as here, the final rule 

will be signed and made available on 

the EPA Web site more than 30 days 

before the effective date, but where the 

publication is likely to be delayed due 

to the complexity and length of the rule, 

the regulated entities are afforded this 

reasonable amount of time. This is 

particularly true given that many of the 

revisions being made in this package 

provide flexibilities to sources covered 

by the reporting rule, or otherwise 

relieve a restriction. We balance these 

circumstances with the need for the 

amendments to be effective by January 

1, 2015; a delayed effective date would 

result in regulatory uncertainty, 

program disruption, and an inability to 

have the amendments (many of which 

clarify requirements, relieve burden, 

and/or are made at the request of the 

regulated facilities) effective for the 

2015 reporting year. Accordingly, we 

find good cause exists to make this rule 

effective on January 1, 2015, consistent 

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

Judicial Review. Under CAA section 

307(b)(1), judicial review of this final 

rule is available only by filing a petition 

for review in the U.S. Court of Appeals 

for the District of Columbia Circuit (the 

Court) by January 26, 2015. Under CAA 

section 307(d)(7)(B), only an objection 

to this final rule that was raised with 

reasonable specificity during the period 

for public comment can be raised during 

judicial review. Section 307(d)(7)(B) of 

the CAA also provides a mechanism for 

the EPA to convene a proceeding for 

reconsideration, ‘‘[i]f the person raising 

an objection can demonstrate to the EPA 

that it was impracticable to raise such 

objection within [the period for public 

comment] or if the grounds for such 

objection arose after the period for 

public comment (but within the time 

specified for judicial review) and if such 

objection is of central relevance to the 

outcome of the rule.’’ Any person 

seeking to make such a demonstration to 

us should submit a Petition for 

Reconsideration to the Office of the 

Administrator, Environmental 

Protection Agency, Room 3000, William 

Jefferson Clinton Building, 1200 

Pennsylvania Ave. NW., Washington, 

DC 20460, with a copy to the person 

listed in the preceding FOR FURTHER

INFORMATION CONTACT section, and the 

Associate General Counsel for the Air 

and Radiation Law Office, Office of 

General Counsel (Mail Code 2344A), 

Environmental Protection Agency, 1200 

Pennsylvania Ave. NW., Washington, 

DC 20004. Note that under CAA section 

307(b)(2), the requirements established 

by this final rule may not be challenged 

separately in any civil or criminal 

proceedings brought by the EPA to 

enforce these requirements. 

Acronyms and Abbreviations. The 

following acronyms and abbreviations 

are used in this document. 

AGR—acid gas removal 

APA—Administrative Procedure Act 

API—American Petroleum Institute 

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 

EPA—U.S. Environmental Protection Agency 

FERC—Federal Energy Regulatory 

Commission 

FR—Federal Register 

GHG—greenhouse gas 

GOR—gas to oil ratio 

HHV—higher heating value 

hp—horsepower 

ICR—information collection request 

ID—identification 

IR—infrared 

LNG—liquefied natural gas 

mmBtu—million British thermal units 

MMscf—million standard cubic feet 

N2O—nitrous oxide 

NAICS—North American Industry 

Classification System 

NESHAP—National Emission Standards for 

Hazardous Air Pollutants 

NGL—natural gas liquids 

NOD—not-operating-depressurized 

NSPS—New Source Performance Standards 

NTTAA—National Technology Transfer and 

Advancement Act 

O&M—operation and maintenance 

OMB—Office of Management and Budget 

psig—pounds per square inch gauge 

QA/QC—quality assurance/quality control 

REC—reduced emissions completion 

RFA—Regulatory Flexibility Act 

scf—standard cubic feet 

U.S.—United States 

UMRA—Unfunded Mandates Reform Act of 

1995 

WWW—worldwide web 

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 This Action 

C. Legal Authority 

D. How do these amendments apply to 

2014 and 2015 reports? 

II. Summary of Final Revisions and Other 

Amendments to Subpart W and 

Responses to Public Comment 

A. Summary of Final Revisions to Provide 

Consistency Throughout Subpart W 

B. Summary of Final Revisions to 

Calculation Methods and Reporting 

Requirements 

C. Summary of Final Revisions to Missing 

Data Provisions 

D. Summary of Final Amendments to Best 

Available Monitoring Methods 

E. Summary of Final Additions of New 

Data Elements and Revisions to 

Reporting Requirements 

III. Final Confidentiality Determinations 

A. Summary of Final Confidentiality 

Determinations for New or Revised 

Subpart W Data Elements 

B. Summary of Public Comments and 

Responses on the Proposed 

Confidentiality Determinations 

IV. Impacts of the Final Amendments to 

Subpart W 

A. Impacts of the Final Amendments 

B. Summary of Comments and Responses 

on the Impacts of the Proposed Rule 

V. Statutory and Executive Order Reviews 

A. Executive Order 12866: Regulatory 

Planning and Review and Executive 

Order 13563: Improving Regulation and 

Regulatory 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 

Concerning Regulations That 

Significantly Affect Energy Supply, 

Distribution or Use 

I. National Technology Transfer and 

Advancement Act (NTTAA) 

J. Executive Order 12898: Federal Actions 

to Address Environmental Justice in 

Minority Populations and Low-Income 

Populations 

K. Congressional Review Act 

I. Background 

A. Organization of This Preamble 

Section I of this preamble provides 

background information regarding the 

origin of the final 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 

final revisions to Part 98, subpart W 

(Petroleum and Natural Gas Systems) 

(hereinafter referred to as ‘‘subpart W’’), 

including a summary of the major 

comments that the EPA considered in 


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the development of this final rule. 

Section III of this preamble discusses 

the final confidentiality determinations 

for new or substantially revised (i.e., 

requiring additional or different data to 

be reported) data reporting elements, as 

well as a revised confidentiality 

determination for one existing data 

element. Section IV of this preamble 

discusses the impacts of the final 

amendments to subpart W. Finally, 

Section V of this preamble describes the 

statutory and executive order 

requirements applicable to this action. 

B. Background on This Action 

On October 30, 2009, the EPA 

published Part 98 for collecting 

information regarding 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 30, 2010, 

finalizing the requirements for the 

Petroleum and Natural Gas Systems 

source category at 40 CFR part 98, 

subpart W (75 FR 74458) (hereinafter 

referred to as ‘‘the subpart W 2010 final 

rule’’). Following promulgation, the 

EPA finalized several actions revising 

subpart W (76 FR 22825, April 25, 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, November 29, 2013; 

79 FR 63750, October 24, 2014). 

On March 10, 2014, the EPA proposed 

the ‘‘Revisions and Confidentiality 

Determinations for Petroleum and 

Natural Gas Systems; Proposed Rule’’ 

(79 FR 13394) to make revisions to 

certain provisions of subpart W, 

including the clarification and 

correction of certain calculation 

methods, monitoring, and reporting 

requirements for which errors were 

identified during the course of 

implementation. At that time, the EPA 

also proposed confidentiality 

determinations for new and 

substantially revised (i.e., requiring 

additional or different data to be 

reported) data elements contained in the 

proposed amendments, as well as a 

revised confidentiality determination 

for one existing data element. The 

public comment period for these 

proposed rule amendments ended on 

April 24, 2014. 

In this action, the EPA is finalizing 

certain revisions to the subpart W 

calculation, monitoring, and reporting 

requirements with some changes made 

in response to public comments and one 

clarifying edit, as proposed, to a 

definition in the general provisions (Part 

98, subpart A) that applies to subpart W 

reporters. Responses to comments 

submitted on the proposed amendments 

can be found in Sections II, III, and IV 

of this preamble as well as in the 2014 

response to comment document in 

Docket Id. No. EPA–HQ–OAR–2011– 

0512. 

C. Legal Authority 

The EPA is finalizing 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 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. 

In addition, pursuant to sections 114, 

301, and 307 of the CAA, the EPA is 

publishing final confidentiality 

determinations for the new or 

substantially revised data elements and 

a revised confidentiality determination 

for one existing data element, required 

by these amendments. Section 114(c) 

requires that the EPA make information 

obtained under section 114 available to 

the public, except for information that 

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 do these amendments apply to 

2014 and 2015 reports? 

These amendments are effective on 

January 1, 2015. Thus, beginning on 

January 1, 2015, facilities must follow 

the revised methods in subpart W, as 

amended, to calculate emissions 

occurring during the 2015 calendar year. 

The first annual reports of emissions 

calculated using the amended 

requirements will be those submitted by 

March 31, 2016, covering the 2015 

calendar year. For the 2014 calendar 

year, reporters will continue to calculate 

emissions and other relevant data for 

the reports that are submitted according 

to the requirements in Part 98 that are 

applicable to the 2014 calendar year 

(i.e., the requirements in place until the 

effective date of this final rule). For this 

reason, we determined that it was not 

appropriate to revise Table A–7 to 

subpart A of Part 98 to reflect the 

revised reporting requirement section 

references in this final rule. For the 

2011 through 2014 calendar years, 

subpart W reporters must report any 

data that are inputs to emissions 

equations according to the requirements 

in 40 CFR 98.3(c)(vii) and in Table A– 

7 to subpart A of Part 98 following the 

requirements in Part 98 that are 

applicable for that calendar year. For 

more information on the reporting of 

2011 through 2014 data that are inputs 

to emissions equations, see 79 FR 63750 

(October 24, 2014). 

As noted in Section II.D of this 

preamble, we are providing short-term 

transitional best available monitoring 

methods (BAMM) for reporters for 

emission sources that are subject to new 

monitoring or measurement 

requirements as part of these final 

revisions. These reporters have the 

option of using BAMM from January 1, 

2015, to March 31, 2015, without 

seeking prior EPA approval for certain 

parameters that cannot reasonably be 

measured according to the monitoring 

and quality assurance/quality control 

(QA/QC) requirements of 40 CFR 

98.234. Reporters also have the 

opportunity to request an extension for 

the use of BAMM from April 1, 2015, 

through December 31, 2015; those 

owners or operators must submit a 

request to the EPA by January 31, 2015. 

II. Summary of Final Revisions and 

Other Amendments to Subpart W and 

Responses to Public Comment 

The EPA is finalizing technical 

corrections, clarifying revisions, and 

other amendments to subpart W. These 

final amendments improve the quality 

and consistency of the collected data, 

and many of the changes are in response 

to feedback received from stakeholders 

during program implementation. These 

final amendments include changes to 

clarify or simplify calculation methods 

for certain sources at a facility; revisions 

to units of measure, terms, and 

definitions in certain equations to 

provide consistency throughout the 

rule, provide clarity, or better reflect 

facility operations; revisions to 

reporting requirements to clarify and 

align more closely with the calculation 

methods and to clearly identify the data 

that must be reported; and other 

revisions identified as a result of 

working with the affected sources. 

Sections II.A through II.E of this 

preamble describe the corrections and 

other amendments that we are finalizing 

in this rulemaking. Section II.A 

describes revisions which provide 

consistency throughout subpart W, 

including revisions to definitions. 

Section II.B describes the final revisions 

to calculation methods and reporting 

requirements for the emission source 

types identified in subpart W. Section 

II.C describes the final revisions to the 


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missing data procedures of subpart W. 

Subpart II.D provides a summary of the 

final amendments to the best available 

monitoring requirements. Finally, 

Section II.E describes the final additions 

of new data elements and revisions to 

reporting requirements. The 

amendments described in each section 

are followed by a summary of the major 

comments on those amendments and 

the EPA’s responses. See the 2014 

response to comment document in 

Docket Id. No. EPA–HQ–OAR–2011– 

0512 for a complete listing of all 

comments and the EPA’s responses. 

In addition to the specific revisions or 

amendments discussed in this section of 

the preamble, the EPA is finalizing 

minor technical revisions to subpart W. 

These revisions improve readability, 

create consistency in terminology, and/ 

or correct typographical or other errors 

in subpart W to improve the final rule. 

These final revisions are further 

explained in the memorandum, ‘‘Minor 

Technical Corrections to Subpart W, 

Greenhouse Gas Reporting Rule: 2014 

Revisions and Confidentiality 

Determinations for Petroleum and 

Natural Gas Systems; Final Rule’’ and 

the 2014 response to comment 

document in Docket Id. No. EPA–HQ– 

OAR–2011–0512. 

A. Summary of Final Revisions To 

Provide Consistency Throughout 

Subpart W 

This section includes minor cascading 

revisions that affect multiple 

requirements of subpart W. Sections 

II.A.1 through II.A.3 describe the 

amendments we are finalizing in this 

rulemaking and, if major comments 

were received, provide a summary of 

the major comments and the EPA’s 

responses. 

1. Consistency in Units of Measure for 

Emissions Reporting 

The EPA is amending 40 CFR 98.236 

to revise the reporting of GHG emissions 

from units of metric tons of carbon 

dioxide equivalent (CO2e) of each 

reported GHG to metric tons of each 

reported GHG. Specifically, we are 

revising 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 (N2O), 

as applicable, instead of reporting each 

gas in metric tons of CO2e. The 

cumulative GHG emissions in units of 

metric tons of CO2e across all pollutants 

will also be reported as required in the 

general provisions at 40 CFR 

98.3(c)(4)(i). These changes increase 

consistency between the reporting 

requirements for subpart W and the rest 

of Part 98, which generally requires the 

reporting of metric tons of individual 

GHGs. The EPA received only 

supportive comments to these revisions. 

The final amendments remove a 

reference to CO2e in the introductory 

paragraph of 40 CFR 98.236(a) that was 

inadvertently retained in the proposal. 

Otherwise, these revisions are finalized 

as proposed. 

2. Onshore Production Source Category 

Definition 

a. Summary of Final Revisions 

We are finalizing, with minor changes 

from proposal, amendments to 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. As proposed, we are 

adding references to engines, boilers, 

heaters, flares, and separation and 

processing equipment, and we are 

removing references to gravity 

separation equipment and auxiliary 

non-transportation-related equipment 

for being redundant with other sources 

specified in the definition. In this final 

rule, we are not including the reference 

to ‘‘maintenance and repair equipment’’ 

that was included in the proposed rule 

after considering public comments 

indicating confusion regarding that 

proposed text. Thus, the first sentence 

of 40 CFR 98.230(a)(2) reads, ‘‘Onshore 

petroleum and natural gas production 

means all equipment on a single wellpad 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-selfpropelled equipment, which includes 

well drilling and completion 

equipment, workover 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).’’ 

b. Summary of Comments and 

Responses 

This section summarizes the major 

comments and responses related to the 

proposed amendments to the source 

category definition of ‘‘onshore 

petroleum and natural gas production.’’ 

See the 2014 response to comment 

document in Docket Id. No. EPA–HQ– 

OAR–2011–0512 for a complete listing 

of all comments and the EPA’s 

responses. 

Comment: Two commenters 

supported part of the proposed revisions 

to the source category definition of 

‘‘onshore petroleum and natural gas 

production’’ at 40 CFR 98.230(a)(2). 

These commenters supported the 

removal of the term ‘‘auxiliary nontransportation related equipment’’ but 

objected to the addition of the term 

‘‘maintenance and repair equipment.’’ 

One commenter asserted that based on 

the current rule language, maintenance 

and repair equipment is not included in 

the onshore production industry 

segment because this equipment is not 

directly used in the production, 

extraction, recovery, lifting, 

stabilization, separation, or treating of 

petroleum and natural gas. Two 

commenters pointed to the description 

of stationary or portable fuel 

combustion equipment in 40 CFR 

98.232(c)(22), which includes only 

emissions from equipment that is 

‘‘integral to the extraction, processing, 

or movement of oil or natural gas.’’ 

These commenters asserted that 

maintenance and repair equipment is 

not integral. The commenters stated that 

the proposed rule expands the 

definition, which places an undue 

burden on industry because emissions 

from maintenance and repair 

equipment, such as welding machines 

and pressure washers, are small relative 

to integral equipment like prime 

movers, and the equipment is frequently 

moved between well sites and tracking 

is difficult. The commenters requested 

that the EPA remove the term 

‘‘maintenance and repair equipment’’ 

from the final definition. 

Response: The EPA recognizes that, 

by specifically including reference to 

maintenance and repair equipment 

within the parenthetical, some reporters 

may misinterpret that to mean all 

maintenance and repair equipment, 

regardless of whether or not that 

equipment is actually used in the 

production, extraction, recovery, lifting, 

stabilization, and separation or treating 

of petroleum and/or natural gas. This 

was not our intent. To reduce the 

potential for confusion, we are removing 

the reference to ‘‘maintenance and 

repair equipment’’ from the source 

category definition for the onshore 

petroleum and natural gas production 

segment in this final rule. However, the 

EPA notes that the parenthetical list is 

not an all-inclusive list (‘‘. . . including 

but not limited to . . .’’) and, as noted 

at 40 CFR 98.232(c)(22), if the facility 

has maintenance and repair equipment 

that is integral to the continued 

production, extraction, recovery, lifting, 

stabilization, separation or treating of 

petroleum and/or natural gas, then it 

would be covered by the onshore 

petroleum and natural gas production 

segment. 


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With respect to the need to determine 

combustion emissions from 

maintenance and repair equipment, 40 

CFR 98.232(c)(22) requires emissions 

‘‘. . . from stationary or portable fuel 

combustion equipment that cannot 

move under its own power or drive 

train, and that is located at an onshore 

petroleum and natural gas production 

facility . . .’’ to be reported. 40 CFR 

98.232(c)(22) further specifies that 

‘‘[s]tationary or portable equipment are 

the following equipment, which are 

integral to the extraction, processing, or 

movement of oil or natural gas: Well 

drilling and completion equipment, 

workover equipment, natural gas 

dehydrators, natural gas compressors, 

electrical generators, steam boilers and 

process heaters.’’ The list provided in 40 

CFR 98.232(c)(7)(22) is not open-ended 

and few pieces of ‘‘maintenance and 

repair equipment’’ would qualify as 

‘‘stationary or portable equipment’’ for 

which combustion emissions must be 

calculated and reported. If the 

maintenance and repair equipment have 

applicable combustion emissions, 

reporters must report the emissions 

from this equipment provided that it 

includes external combustion sources 

with rated heat capacity greater than 5 

million British thermal units (mmBtu) 

per hour or internal fuel combustion 

sources with rated heat capacity greater 

than 1 mmBtu per hour (or 130 

horsepower (hp)), as specified in 40 CFR 

98.233(z). 

3. Definition of Sub-Basin Category 

a. Summary of Final Revisions 

The EPA is finalizing, as proposed, 

revisions to the definition of sub-basin 

category at 40 CFR 98.238. Specifically, 

we have defined 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 greater than 0.1 

millidarcy permeability and tight gas 

reservoirs with less than or equal to 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.’’ 

b. Summary of Comments and 

Responses 

The EPA received only supportive 

comments regarding these revisions, 

therefore, there are no changes from 

proposal to the final rule based on these 

comments. 

B. Summary of Final Revisions to 

Calculation Methods and Reporting 

Requirements 

The final amendments described in 

this section include technical revisions 

and corrections to the calculation and 

reporting requirements of subpart W. In 

general, these revisions provide greater 

flexibility and potentially reduce 

burden to facilities, and they increase 

the clarity and congruency of the 

calculation and reporting requirements. 

These final amendments also include 

organizational revisions to the reporting 

requirements in 40 CFR 98.236. These 

revisions restructure 40 CFR 98.236 to 

more closely align the reporting 

requirements with the calculation 

methods, clarify the data elements to be 

reported, and improve data utility. As 

proposed, we are reorganizing the 

reporting section by source type and, for 

each industry segment, listing which 

source types must be reported. We are 

also finalizing the addition of new data 

elements which would improve the 

quality of the data reported. These 

additional data elements are discussed 

in Section II.E of this preamble. 

The final amendments to the 

calculation and reporting requirements 

in subpart W are described in this 

section by emission source type (e.g., 

natural gas pneumatic device venting, 

acid gas removal vents, etc.). The 

amendments for each source type are 

followed by a summary of the major 

comments, if any, on those amendments 

and the EPA’s responses. See the 2014 

response to comment document in 

Docket Id. No. EPA–HQ–OAR–2011– 

0512 for a complete listing of all 

comments and the EPA’s responses. 

Additional minor corrections, including 

minor edits to the calculation 

requirements of the final rule, are 

included in the memorandum, ‘‘Minor 

Technical Corrections to Subpart W, 

Greenhouse Gas Reporting Rule: 2014 

Revisions and Confidentiality 

Determinations for Petroleum and 

Natural Gas Systems; Final Rule’’ in 

Docket Id. No. EPA–HQ–OAR–2011– 

0512. Further information on the final 

changes to the reporting section may be 

found in the memorandum, ‘‘Final 

Revisions to the Subpart W Reporting 

Requirements in the ‘Greenhouse Gas 

Reporting Rule: 2014 Revisions and 

Confidentiality Determinations for 

Petroleum and Natural Gas Systems; 

Final Rule’ ’’ in Docket Id. No. EPA– 

HQ–OAR–2011–0512. 

1. Natural Gas Pneumatic Device 

Venting 

a. Summary of Final Revisions 

We are finalizing revisions to 

Equation W–1 in 40 CFR 98.233(a) to 

sum the natural gas pneumatic device 

venting emissions across all types of 

pneumatic devices with minor 

revisions. We are revising the 

summation symbol to remove the ‘‘i’’ at 

the bottom of the summation symbol, 

which was inadvertently included with 

the summation symbol. This revision is 

needed to clarify that the summation is 

across different types of pneumatic 

devices (designated by ‘‘t’’) and not 

across different GHGs (designated by 

‘‘i’’). We are finalizing revisions to 40 

CFR 98.233(a)(1), (a)(2), and (a)(3) as 

proposed to simplify how ‘‘Countt’’ of 

Equation W–1 (total number of natural 

gas pneumatic devices of type ‘‘t’’) must 

be calculated each year as new devices 

are added. For the onshore petroleum 

and natural gas production industry 

segment, reporters continue to have the 

option in the first two reporting years to 

estimate ‘‘Countt’’ using engineering 

estimates. The EPA is also finalizing the 

reporting requirements with minor 

revisions from proposal. Specifically, 

the EPA is clarifying that certain 

reporting requirements in 40 CFR 

98.236(b)(1) and (2) should be reported 

by device type. These revisions clarify 

our original intent and address public 

comments received. 

b. Summary of Comments and 

Responses 

Comment: One commenter noted that 

it appears that the EPA is removing the 

requirement to report information 

separately for each pneumatic controller 

type (continuous high bleed, continuous 

low bleed, intermittent bleed) and is 

instead requesting that all information 

from all three categories be lumped 

together in the proposed revisions to 40 


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CFR 98.236(b). According to the 

commenter, this seems like a backwards 

step in data collection and, given the 

current high interest in pneumatic 

controllers in oil and gas sector studies 

and by the EPA in technical white 

papers on the oil and gas sector, it 

seems illogical for the EPA to stop 

collecting this device-type-specific 

information. The commenter also noted 

a discrepancy between the proposed 

rule text at 40 CFR 98.236(b), which 

says ‘‘you must report the information 

specified in paragraphs (b)(1) through 

(b)(4) of this section’’ while the 

memorandum entitled ‘‘Revisions to the 

Subpart W Reporting Requirements as 

proposed in the Greenhouse Gas 

Reporting Rule: Revisions and 

Confidentiality Determinations for 

Petroleum and Natural Gas Systems; 

Proposed Rule’’ says ‘‘you must report 

the information specified in paragraphs 

(b)(1) through (b)(4) of this section for 

each device type.’’ 

Response: The EPA agrees with the 

commenter that certain reporting 

elements in 40 CFR 98.236(b) should be 

reported by device type. We removed 

the phrase ‘‘for each device type’’ from 

paragraph 40 CFR 98.236(b) prior to 

proposal because the reporting elements 

in paragraphs (b)(3) and (b)(4) are 

aggregate emissions across the three 

device types (‘‘. . . combined, 

calculated using Equation W–1’’). It was 

not our intent to collect aggregated data 

regarding the number of pneumatic 

devices. For example, the reporting 

element in paragraph 40 CFR 

98.236(b)(2) specifically indicates that 

the reporting element is ‘‘Tt’’ in 

Equation W–1, which is specific to the 

type of pneumatic device. To address 

this issue, we are revising paragraphs 

(b)(1)(i), (b)(1)(ii)(A) and (B), and (b)(2) 

to indicate that these reporting elements 

must be reported for each type of 

pneumatic device. These data will allow 

the EPA to verify the aggregate 

emissions calculated using Equation W– 

1 and perform more detailed analysis of 

emissions by device type. 

2. Acid Gas Removal Vents 

a. Summary of Final Revisions 

For acid gas removal (AGR) vents, we 

are finalizing several technical revisions 

as proposed and adding minor clarifying 

revisions to address public comments 

received. We are finalizing minor 

clarifying edits to 40 CFR 98.233(d) as 

proposed to clearly label each 

calculation method and to clarify 

provisions by providing references to 

equations where appropriate. We are 

also finalizing the proposed revisions to 

the parameters ‘‘VolCO2’’ in 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. As proposed, we 

are specifying 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. 

In response to public comments, we 

are making four minor corrections and 

clarifying revisions to the calculation 

and reporting requirements for AGR 

units. First, we are removing an errant 

proposed requirement in 40 CFR 

98.236(d)(10) to calculate annual mass 

emissions ‘‘at standard conditions.’’ 

Second, in response to a comment that 

the sub-basin identification (ID) 

reporting requirement in 40 CFR 

98.236(d)(1)(vi) is unclear when an AGR 

unit treats gas from wells in more than 

one sub-basin, we are revising the data 

element to require reporting of the subbasin ID ‘‘that best represents the wells 

supplying gas to the unit.’’ Third, in 

response to comments on the proposed 

missing data procedures for AGR units 

(proposed 40 CFR 98.235(a), we are 

adding the clause ‘‘. . . for each quarter 

that the AGR unit is operating . . .’’ in 

paragraphs 40 CFR 98.233(d)(6), (7), and 

(8)(ii) to clarify that quarterly samples 

are only required to be collected for 

quarters when the unit is operated. 

Fourth, in response to a comment on the 

proposed confidentiality determinations 

for AGR units, we are correcting the 

reporting requirements for the amount 

of CO2 from AGR units that is recovered 

and transferred outside the facility (40 

CFR 98.236(d)(1)(iv)); the requirement 

to report this quantity ‘‘under subpart 

PP’’ was inadvertently omitted from the 

proposed rule. See Section II.C of this 

preamble for additional discussion of 

changes to the missing data procedures 

related to AGR units, and see Section 

III.B of this preamble for additional 

discussion of the confidentiality 

determination for the data element 

related to reporting the amount of CO2

recovered and transferred outside the 

facility. 

b. Summary of Comments and 

Responses 

The EPA did not receive any major 

comments on the proposed revisions to 

the calculation and reporting 

requirements for AGR units. See the 

2014 response to comment document in 

Docket Id. No. EPA–HQ–OAR–2011– 

0512 for a complete listing of all 

comments and responses. 

3. Dehydrators 

a. Summary of Final Revisions 

The EPA is clarifying that Calculation 

Method 1 in 40 CFR 98.236(e)(1) is not 

applicable to desiccant dehydrators. We 

proposed this clarification by including 

the word ‘‘absorbent’’ to describe the 

types of dehydrators for which 

Calculation Method 1 applies. We 

received comment that the term 

‘‘absorbent dehydrators’’ was not a 

common term used by industry and was 

not defined in the rule. We are 

finalizing amendments to both 40 CFR 

98.236(e)(1) and (e)(3) to clarify our 

original intent that Calculation Method 

1 is applicable to glycol (liquid 

absorbent) dehydrators and that 

emissions from desiccant dehydrators of 

any size should be determined using 

Calculation Method 3 in 40 CFR 

98.236(e)(3). We are finalizing revisions 

as proposed to clarify that the 0.4 

million standard cubic feet (MMscf) per 

day throughput relates to the natural gas 

throughput of the dehydrator for 

determining the applicability of 

Calculation Method 1. We are finalizing 

revisions to clarify the calculation 

methods for dehydrators to provide for 

the adjustment of emissions vented to a 

vapor recovery system as proposed. We 

are finalizing clarifications to the 

calculation of emissions when vented to 

a flare with minor revisions to those 

proposed. Specifically, we are including 

reference to 40 CFR 98.233(e)(5) in 

paragraph (e)(6)(i) in the event a portion 

of the dehydrator vent emissions are 

recovered and a portion are vented to a 

flare. Finally, we are finalizing, as 

proposed, clarification to the reporting 

requirements in 40 CFR 98.236(e)(2) for 

glycol dehydrators with an annual 

average daily natural gas throughput 

less than 0.4 MMscf per day to account 

for scenarios in which a dehydrator may 

be vented to more than one emission 

point (e.g., with one vent routed to a 

flare and one vent routed to vapor 

recovery). 

b. Summary of Comments and 

Responses 

Comment: One commenter objected to 

the term ‘‘absorbent dehydrator.’’ The 

commenter stated that this is not a term 

used by industry, is not defined in the 

rule, and may cause confusion with 

desiccant dehydrator requirements as 

they use an absorbent. The commenter 

recommended the term ‘‘glycol 

dehydrator’’ be used rather the proposed 

‘‘absorbent dehydrator’’ term. 

Response: The EPA agrees with the 

commenter in that desiccant 

dehydrators use a solid absorbent, so the 

term ‘‘absorbent dehydrator’’ is 


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ambiguous. We considered amending 

the descriptive clause to ‘‘liquid 

absorbent’’ dehydrators; however, based 

on available information, liquid 

absorbent systems use glycol and the 

term glycol dehydrators is already used 

to describe the dehydrators for which 

Calculation Method 2 is applicable. 

Therefore, to clarify our original intent, 

we are replacing the proposed 

‘‘absorbent dehydrator’’ term with the 

term ‘‘glycol dehydrator’’ in the first 

sentence in 40 CFR 98.236(e)(1). We are 

also revising the first sentence in 40 

CFR 98.233(e)(3) to begin as follows: 

‘‘For dehydrators of any size that use 

desiccant, you must calculate emissions 

. . .’’ These edits clarify our original 

intent and address the commenter’s 

concerns regarding the proposed 

‘‘absorbent dehydrator’’ term. 

4. Well Venting for Liquids Unloading 

a. Summary of Final Revisions 

As proposed, the EPA is revising the 

calculation and reporting requirements 

for well venting from liquids unloading. 

These revisions include allowances for 

annualizing venting data for facilities 

that calculate emissions using a 

recording flow meter (Calculation 

Method 1 at 40 CFR 98.233(f)(1)); 

revisions to Calculation Method 1 at 40 

CFR 98.233(f)(1) and reporting 

requirements at 40 CFR 98.236 to 

separate the calculation and reporting of 

emissions from wells that have plunger 

lifts and wells that do not have plunger 

lifts; and clarification of the term ‘‘SPp’’ 

in Equation W–8 (40 CFR 98.233(f)(2)) 

to specify 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 subbasin where the casing pressure is 

known. 

b. Summary of Comments and 

Responses 

The EPA received supportive 

comments for the proposed revisions 

and did not receive major comments 

opposing the proposed revisions to the 

calculation and reporting requirements 

for well venting from liquids unloading. 

The EPA is not making any changes to 

the proposed amendments in the final 

rule as a result of public comments. See 

the 2014 response to comment 

document in Docket Id. No. EPA–HQ– 

OAR–2011–0512 for a complete listing 

of all comments and responses. 

5. Gas Well Completions and Workovers 

a. Summary of Final Revisions 

The EPA is finalizing several 

definitions pertinent to gas well 

completions and workovers. The EPA is 

finalizing amendments to 40 CFR 98.238 

to add definitions for ‘‘reduced 

emissions completion’’ and ‘‘reduced 

emissions workover’’ with minor 

revisions from the proposed definitions. 

The proposed definitions of these terms 

implied that there would be no direct 

releases to the atmosphere. Public 

comments indicated that this phrase 

was too restrictive and we have revised 

the definition to clarify that a ‘‘reduced 

emissions completion’’ or a ‘‘reduced 

emissions workover’’ will have de 

minimis venting to the atmosphere and 

may have short periods of flaring. The 

EPA is finalizing as proposed the 

definition of ‘‘well completions’’ in 40 

CFR 98.6 of subpart A to delete the term 

‘‘re-fracture’’ as this term applies to an 

already producing well and is 

considered a well workover, not a well 

completion, for the purposes of part 98. 

We are also revising the reporting 

requirements for gas well completions 

and workovers to differentiate between 

different well type combinations in each 

sub-basin category, as proposed. A well 

type combination is a unique 

combination of the following factors: 

Vertical or horizontal, with flaring or 

without flaring, and reduced emissions 

completion (REC)/workover or no REC/ 

workover. 

As proposed, we are revising Equation 

W–10A, the time variable ‘‘Tp’’ in 

Equation W–10A and W–10B, the 

calculation section at 40 CFR 98.233(g) 

and (h), and Equation W–13 in 40 CFR 

98.233(h) and adding new Equation W– 

13B in 40 CFR 98.233(h). We are 

revising 40 CFR 98.233(g)(1) and (g)(2) 

as proposed to clarify measurement 

requirements. We are also finalizing 

revisions as proposed for the parameter 

‘‘PRs,p’’ in 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. 

The final rule also corrects two errors 

in the proposed reporting requirements 

in 40 CFR 98.236(g)(5)(i) so that the 

final reporting requirements are 

consistent with the variables used in the 

revised Equation W–10A. First, the final 

rule uses the term ‘‘flowback’’ instead of 

‘‘backflow.’’ Second, instead of 

requiring reporting of the ‘‘cumulative 

backflow time,’’ which is an artifact of 

requirements in the subpart W 2010 

final rule, the final 40 CFR 

98.236(g)(5)(i) requires reporting of the 

cumulative gas flowback time from 

when gas is first detected until 

sufficient quantities are present to 

enable separation (‘‘Tp,i’’ in Equation W– 

10A) and the cumulative flowback time 

after sufficient quantities of gas are 

present to enable separation (‘‘Tp,s’’ in 

Equation W–10A). 

b. Summary of Comments and 

Responses 

This section summarizes the major 

comments and responses related to the 

proposed amendments to gas well 

completions and workovers. See the 

2014 response to comment document in 

Docket Id. No. EPA–HQ–OAR–2011– 

0512 for a complete listing of all 

comments and responses. 

Comment: Two commenters asserted 

that the proposed rule significantly 

increases the burden by expanding the 

definition of well type in 40 CFR 

98.233(g)(2) to differentiate between the 

scenarios of with or without flaring and 

with REC/workover or without REC/

workover. The commenters stated that 

expanding the well type definition 

increases the maximum number of 

measurement combinations to be 

reported from 10 (five formation types 

and two well types) to 40 (five 

formation types and eight well types). 

Additionally, one commenter stated that 

it is difficult for reporters to identify 

and plan for which wells to measure, 

because the reporter cannot predict 

whether a well will need a flare or a 

vent until after beginning the actual 

flowback. The commenter noted that 

implementation of 40 CFR part 60, 

subpart OOOO, will sharply reduce, but 

not eliminate, the number of flowbacks 

where gas is not flared and/or RECs are 

not performed; therefore, these 

scenarios will still be present and would 

need to be measured. Another 

commenter requested that the EPA 

reconsider splitting the reporting and 

measurement categories for well 

completions and workovers because 

reporters have established data 

collection and management systems 

based on the existing well types. The 

commenter stated that the proposed 

changes would double or quadruple the 

number of required measurements or 

calculations, input data management, 

and reporting requirements. One 

commenter supported the changes in 

the data collection, stating that 

disaggregated data will help distinguish 

emissions by well type and control 

technology, facilitate a deeper 

understanding of the factors affecting oil 

and gas sector emissions, and improve 

the data for use in the Inventory of U.S. 

Greenhouse Gas Emissions and Sinks. 

Response: In the final rule, the EPA is 

maintaining the requirement to measure 

emissions separately per sub-basin and 

well type combination instead of 

aggregations of these distinct 

operational practices. As some 

commenters noted, the disaggregated 


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data will improve data quality for 

emissions from gas well completions 

and workovers with hydraulic 

fracturing. We disagree with some of the 

commenters that the new requirements 

will impose a significant additional 

burden on reporters. The EPA expects 

that operational practices will generally 

be the same in a given sub-basin and 

considers it unlikely that a reporter 

would conduct drilling activities for a 

given sub-basin in all the different well 

type combinations of vertical or 

horizontal, with flaring or without 

flaring, and REC/workover or no REC/

workover. For example, gas well 

hydraulic fracturing focused on 

horizontal drilling in a shale gas 

formation in a county using reduced 

emissions completions and flaring 

would constitute one category. As one 

commenter noted, owners or operators 

of gas wells must comply with 40 CFR 

part 60, subpart OOOO. While some of 

the other categories may be present for 

some reporters, compliance with 

subpart OOOO will result in most 

reporters being in the category of 

reduced emissions completions with 

flaring. Additionally, subpart W 

provides flexibility by allowing 

reporters to determine flowback rates 

using engineering calculations provided 

in Equations W–11A or W–11B. 

Comment: One commenter asked 

whether the proposed definition for REC 

was intended to be consistent with the 

definition used in 40 CFR part 60, 

subpart OOOO. The commenter 

requested that if this is the EPA’s intent, 

then the definition should be expanded 

to clarify that there may be some degree 

of venting during some portion of the 

flowback period. The commenter stated 

that the proposed Part 98 definition 

does not acknowledge that flowback is 

vented, and that the definition should 

include clarification. The commenter 

noted that, as proposed, the definition 

of ‘‘reduced emissions completion’’ 

would result in no RECs reported due to 

the phrase ‘‘no direct release to the 

atmosphere.’’ In addition, the 

commenter stated that the subpart W 

definition does not provide for flaring to 

occur on wells with RECs. The 

commenter requested that the EPA 

modify the definition for reduced 

emission completions to harmonize 

with the revised calculation approach 

for completions and workovers with 

hydraulic fracturing, which addresses 

the small amount of venting during 

initial flowback and provides for flaring 

associated with well completions and 

workovers. 

Response: We agree with the 

commenter that there can be a small 

amount of venting during the initial 

flowback, and that in some situations 

flaring is conducted. In the final rule we 

are revising the definitions of ‘‘reduced 

emissions completion’’ and ‘‘reduced 

emissions workover’’ to clarify the 

venting and flaring activities that may 

occur. 

6. Blowdown Vents 

a. Summary of Final Revisions 

The EPA is finalizing, with some 

modifications, the proposed revisions to 

include a compressibility term in 

Equations W–14A and W–14B for 

calculating emissions from blowdown 

vents and also in Equations W–33 and 

W–34 to convert volumetric emissions 

at actual conditions to standard 

conditions. The EPA proposed to allow 

reporters to use a compressibility factor 

of 1 under certain temperature and 

pressure conditions, otherwise a sitespecific compressibility factor must be 

calculated and used for each blowdown 

event or conversion to standard 

conditions. Commenters indicated that 

these requirements posed a significant 

burden on reporters without 

significantly improving the calculated 

emissions. After considering the public 

comments, we are finalizing the 

inclusion of the compressibility term in 

Equations W–14A, W–14B, W–33 and 

W–34, but we are optionally allowing 

reporters to use a default value of 1 or 

a site-specific compressibility factor 

regardless of the temperature and 

pressure conditions. 

The EPA is finalizing the equipment 

type categories and the reporting 

requirements for blowdown vents with 

minor modifications to those proposed. 

In the final rule, we have incorporated 

the term ‘‘equipment or event type’’ 

rather than simply ‘‘equipment type’’ 

where appropriate to include reference 

to emergency shutdown blowdown 

activities. We clarified the ‘‘emergency 

shutdown’’ category to include all 

emergency shutdown blowdown 

emissions regardless of equipment type. 

We also revised the category proposed 

as ‘‘station piping’’ to be ‘‘facility 

piping’’ to be more applicable to the 

onshore natural gas processing and 

liquefied natural gas (LNG) import and 

export equipment industry segments; 

we also clarified the distinction between 

‘‘facility piping’’ and ‘‘pipeline 

venting.’’ We also revised the category 

proposed as ‘‘all the other blowdowns 

greater than or equal to 50 cubic feet’’ 

category to ‘‘all other equipment with a 

physical volume greater than or equal to 

50 cubic feet’’ to clarify it is the physical 

volume of the equipment, not the 

blowdown volume (converted to 

standard conditions), to which the 50 

cubic feet threshold applies. 

The EPA is also adding an optional 

calculation method (40 CFR 

98.233(i)(3)) for blowdown emissions 

for situations where a flow meter is in 

place and including associated reporting 

requirements in 40 CFR 98.236. If a flow 

meter is in place to measure emissions, 

the emissions are reported on a facility 

basis and would not be aggregated by 

emission type per 40 CFR 98.236(i)(2). 

These revisions are finalized with minor 

revisions to clarify that reporters may 

use flow meters for some blowdown 

stacks and use equipment or event type 

calculations for other blowdown vent 

stacks at the same facility. 

b. Summary of Comments and 

Responses 

This section summarizes the major 

comments and responses related to 

blowdown vent emissions. See the 2014 

response to comment document in 

Docket Id. No. EPA–HQ–OAR–2011– 

0512 for a complete listing of all 

comments and responses. 

Comment: Three commenters 

opposed the proposed mandatory use of 

a compressibility factor (Z) in equations 

W–14A, W–14B, W–33, and W–34. The 

commenters stressed that requiring the 

calculation of Z places a significant 

burden on industry without producing a 

substantive benefit in terms of increased 

data and emissions accuracy. One 

commenter also claimed that the 

inclusion of a mandatory 

compressibility factor would result in 

inconsistencies with prior year reports. 

The three commenters supported 

allowing the optional use of a 

compressibility factor that would not 

impose new burdens but would provide 

greater flexibility to reporters. One 

commenter asserted that some 

companies already use a compressibility 

term in their blowdown emission 

calculations, and some reporters have 

existing company algorithms and 

programs used to track blowdown 

venting and calculations emissions that 

account for compressibility. Another 

commenter stated that mandating the 

use of the compressibility factor in the 

blowdown vent calculations would 

require changes to these existing 

systems and increase implementation 

costs. The commenters argued that the 

EPA has not considered or justified 

these costs. 

One commenter noted that the 

proposed conditions for using the 

compressibility term would require the 

calculation of Z for nearly all equipment 

blowdown calculations at transmission 

and storage facilities. The commenter 

stated that transmission pipelines 


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typically operate in the range of about 

500 to about 1,000 pounds per square 

inch gauge (psig), therefore the 

proposed rule would require a 

calculated value of Z for most, if not all, 

transmission segment blowdown 

emission calculations. One commenter 

asserted that the EPA has not 

demonstrated that inclusion of the 

compressibility factor will significantly 

or cost-effectively reduce the overall 

uncertainty of the blowdown vent 

emission estimates. The commenter 

disagreed with the EPA’s assessment of 

uncertainty and argued that the 

potential uncertainty introduced by 

failure to use a compressibility factor is 

only on the order of 10 percent. 

Response: The EPA evaluated the 

commenters’ concerns and is changing 

the requirements from proposal. We 

have revised the final rule to allow 

reporters the option to use a default 

compressibility factor or a site-specific 

factor instead of being required to use a 

site specific factor for specific 

temperature and pressure ranges. We 

maintain that the accuracy of the 

emission calculation is improved if a 

compressibility factor is included. 

However, we also recognize the 

commenters’ concern that, for many 

reporters, programs and algorithms are 

already in place that do not include the 

site-specific factor in the calculations, 

and any revision would incur additional 

burden and cost in updating the 

programs and algorithms. We agree with 

the commenters’ suggestion to allow the 

optional use of site-specific 

compressibility factors. This approach 

allows for improved accuracy for 

facilities that have processes in place to 

determine site-specific compressibility 

factors, while not increasing the burden 

to facilities that do not. Therefore, in 

this final rule, reporters may use either 

a default value of 1 or a site-specific 

compressibility factor regardless of the 

temperature or pressure range of the 

system. 

Comment: Several commenters 

supported the use of equipment type 

categories for aggregating and reporting 

blowdown emissions, but one of these 

commenters stated that the rule should 

allow reporters to optionally report 

emissions by unique blowdown 

volumes. Two commenters requested 

clarification of several of the blowdown 

categories. First, the commenters 

recommended that the seven categories 

be called ‘‘equipment/event types’’ to 

more accurately describe the 

‘‘emergency shutdown’’ category. The 

commenters suggested that the EPA 

clarify that emergency shutdown 

blowdown emissions should always be 

categorized under the ‘‘emergency 

shutdown’’ category, regardless of the 

type of equipment that is blown down 

and that the EPA should clarify the 

distinction between ‘‘station piping’’ 

(i.e., within the compressor station 

boundary) and ‘‘pipeline venting’’ (i.e., 

pipe external to the compressor station 

that is vented within the station 

boundary). Finally, the commenters 

recommended that the category ‘‘all 

other blowdowns greater than or equal 

to 50 cubic feet’’ should be ‘‘all other 

equipment with a physical volume 

greater than or equal to 50 cubic feet.’’ 

One commenter also recommended that 

the EPA include clarification that, if a 

blowdown event results in emissions 

across multiple equipment types and 

the emissions cannot be apportioned to 

the different equipment types, then the 

reporter may categorize the emissions to 

the equipment type that represents the 

largest portion of the emissions from the 

blowdown event. 

Response: The EPA disagrees with the 

one commenter’s suggestion to make the 

blowdown categories optional. The 

EPA, as well as other commenters, have 

agreed that the requirement reduces 

burden and simplifies the rule. 

Providing the categories as optional to 

reporters would result in 

inconsistencies in the reported data and 

may limit the EPA’s ability to compare 

and review information between 

reporters. The EPA agrees with the 

commenters that further clarification 

would be helpful regarding the 

categories for reporting blowdown 

emissions. In the final rule, we have 

incorporated the term ‘‘equipment or 

event type’’ when referring to all seven 

categories to more clearly include 

emergency shutdown blowdown 

activities. We also revised the 

emergency shutdown category to 

indicate that this category includes 

emergency shutdown blowdown 

emissions regardless of equipment type. 

In reviewing the commenters’ suggested 

clarification of station piping and 

pipeline venting, we found that the 

nomenclature was very specific to 

onshore natural gas transmission 

compression industry segment, but 

blowdown emissions may also be 

reported for the onshore natural gas 

processing and LNG import and export 

equipment industry segments. 

Therefore, we have revised the ‘‘station 

piping’’ category to be ‘‘facility piping.’’ 

We have also clarified that station 

piping refers to ‘‘piping within the 

facility boundary other than physical 

volumes associated with distribution 

pipelines’’ and that pipeline venting 

refers to ‘‘physical volumes associated 

with distribution pipelines vented 

within the facility boundary.’’ We also 

revised the category proposed as ‘‘all the 

other blowdowns greater than or equal 

to 50 cubic feet’’ category to ‘‘all other 

equipment with a physical volume 

greater than or equal to 50 cubic feet’’ 

to clarify it is the physical volume of the 

equipment, not the blowdown volume 

(converted to standard conditions), to 

which the 50 cubic feet threshold 

applies. Finally, we are incorporating 

the commenter’s suggestion to specify 

that if a blowdown event results in 

emissions across multiple equipment 

types and the emissions cannot be 

apportioned to the different equipment 

types, then the reporter may categorize 

the emissions to the equipment type 

that represents the largest portion of the 

emissions from the blowdown event. 

We note that the phrase ‘‘equipment 

type’’ is correct here because this 

assignment would only be necessary if 

the blowdown event is not associated 

with an emergency shutdown. 

Comment: One commenter 

recommended that the rule should 

clearly indicate that both the method for 

determining emissions from blowdown 

vent stacks using a flow meter and the 

method for determining emissions from 

blowdown vent stacks according to 

equipment type can be used for different 

blowdown emission sources at a given 

facility. The commenter also 

recommended that the rule clearly 

indicate that, when a flow meter is used, 

that it is not necessary to categorize 

emissions by equipment type. 

Response: The EPA has evaluated the 

commenter’s suggestions and agrees that 

the changes would clarify the rule. In 

the final rule, the EPA is clarifying in 40 

CFR 98.233(i) that the facility may use 

the equipment/event type method for 

some blowdown vent stacks and use the 

flow meter for other blowdown vent 

stacks. We are also clarifying the 

reporting requirements in 40 CFR 

98.236(i) to accommodate reporting 

when both calculation methods are 

used. Facility owners or operators must 

report by the equipment/event type 

categories for the blowdown stack vents 

that use the equipment or event type 

calculation method and they must 

report the cumulative emissions for all 

blowdown vent stacks that use flow 

meters to determine blowdown 

emissions. 

Comment: Two commenters 

recommended a change to the emissions 

calculations for blowdown volumes. 

The commenters asserted that the 

current order of calculations for 

blowdown vents is incorrect. The 

commenters noted that gases in the 

same equipment can have very different 

compositions, and that the 


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presumptions in the proposed rule, 

which would apply the same gas 

composition to all equipment types, 

would not represent actual emissions. 

The commenters suggested that 

emissions be summed into equipment 

types after applying applicable gas 

compositions (i.e., after application of 

40 CFR 98.233(u) and (v)) to each 

individual unique physical volume. 

Response: The EPA evaluated the 

order of the emissions calculations for 

blowdown volumes presented in the 

proposed rule and agrees that, for 

certain industry segments, the order of 

calculations would introduce 

inaccuracies and create confusion over 

which gas compositions to use in the 

calculation. For certain industry 

segments, such as onshore natural gas 

transmission compression and LNG 

import and export equipment, the order 

of the summation does not introduce 

inaccuracies because the gas 

composition is expected to be the same 

in all equipment at the facility. 

Therefore, in the final rule, the EPA has 

revised the order of calculations to first 

require that the CH4 and CO2 volumetric 

and mass emissions be calculated for 

each physical volume (e.g., the inlet 

volume) associated with each 

equipment or event category. The total 

annual CH4 and CO2 mass emissions 

must then be calculated for each 

equipment or event category by 

summing the CH4 and CO2 mass 

emissions for all unique physical 

volumes associated with the equipment 

or event category. These changes allow 

reporters to apply the appropriate gas 

composition for each physical volume 

prior to aggregating emissions by 

equipment or event type. However, the 

final rule also allows reporters in the 

onshore natural gas transmission 

compression and LNG import and 

export equipment sectors to elect to sum 

their natural gas volumetric emissions 

first and then apply composition data to 

determine CH4 and CO2 volumetric and 

mass emissions since the composition 

data is expected to be the same for all 

volumes. 

7. Onshore Production Storage Tanks 

a. Summary of Final Revisions 

We are finalizing revisions to the 

introductory text at 40 CFR 98.233(j) 

with minor modifications to those 

proposed to clarify the calculation 

methods that must be used for onshore 

production storage tanks. We are also 

finalizing amendments to 40 CFR 

98.233(j)(6), with minor modifications 

to those proposed. We received 

comment that the proposed revisions to 

40 CFR 98.233(j)(6) appeared to expand 

the applicability of this requirement to 

all tanks rather than tanks with an 

annual average daily throughput of 10 

barrels per day or more. This was an 

inadvertent error. Therefore, we are 

clarifying in this final rule, both in the 

40 CFR 98.233(j) introductory text and 

40 CFR 98.233(j)(4), that you must 

calculate emissions from dump valve 

leakage only if you use Calculation 

Method 1 or Calculation Method 2. We 

are also revising the parameter ‘‘En’’ in 

Equation W–16 from the proposed rule 

to remove the reference to Calculation 

Method 3, which was erroneously 

included in the proposed rule. 

In reviewing the comments received 

on the proposed rule, we noted 

inconsistencies in Calculation Method 2 

between the calculation method 

described in 40 CFR 98.233(j)(2) and the 

implementation of that method as 

described in paragraphs (j)(2)(i) and 

(j)(2)(ii). In the proposed rule, we 

attempted to consolidate within 

Calculation Method 2 the calculation 

methods for storage tanks receiving oil 

directly from the production well 

without passing through a wellhead 

separator and storage tanks receiving oil 

from a wellhead separator. The 

introductory text in the proposed 

paragraph (j)(2) references composition 

at the separator temperature and 

pressure, which is appropriate if there is 

a separator, but it also requires use of 

either paragraphs (j)(2)(i) and (j)(2)(ii), 

both of which describe composition at 

the wellhead, which is only appropriate 

if there is not a separator. Therefore, we 

are revising Calculation Method 2 to 

more clearly designate that the 

composition at separator temperature 

and pressure should be used if the 

storage tank receives oil after passing 

through a separator and to use the 

wellhead composition if the tank 

receives oil directly from the well. 

We are finalizing the amendments to 

the reporting requirements for onshore 

production storage tanks as proposed 

(except as described in Section III.A. of 

this preamble). 

b. Summary of Comments and 

Responses 

This section summarizes the major 

comments and responses related to 

onshore production storage tanks. See 

the 2014 response to comment 

document in Docket Id. No. EPA–HQ– 

OAR–2011–0512 for a complete listing 

of all comments and responses. 

Comment: Two commenters objected 

to proposed revisions in 40 CFR 

98.233(j)(6) that appeared to expand the 

reporting of emissions from stuck dump 

valves to all tanks, including those with 

throughput less than 10 barrels per day. 

One commenter considered this 

expansion in reporting to be 

burdensome and costly, given the 

investments already made to manage 

data collection in response to the 

original rule. 

Response: We agree with the 

commenters that the calculation 

methods in (j)(6), as proposed, would 

apply to all storage tanks that have 

dump valves that are not closing 

properly, while Equation W–16 

previously did not consider emissions 

from storage tanks with throughput less 

than 10 barrels per day. It was not the 

EPA’s intent to require reporting of 

emissions from stuck dump valves to 

storage tanks with a throughput less 

than 10 barrels per day. Therefore, we 

are clarifying in 40 CFR 98.233(j) and 40 

CFR 98.233(j)(6) that you must calculate 

emissions from dump valve leakage 

only if you use Calculation Method 1 or 

Calculation Method 2 (applicable for 

storage tanks with a throughput of 10 

barrels per day or more). We are also 

revising the parameter ‘‘En’’ in Equation 

W–16 from the proposed rule to remove 

the reference to Calculation Method 3, 

which was erroneously included in the 

proposed rule. 

8. Transmission Storage Tanks 

a. Summary of Final Revisions 

We are finalizing revisions to the 

provisions for transmission storage 

tanks in 40 CFR 98.233(k) with minor 

modification to those proposed to 

reorder the calculations in response to 

comments received. We are finalizing 

the amendments to the reporting 

requirements for transmission storage 

tanks with minor revisions to correct 

section number references to the 

reordered paragraphs in 40 CFR 

98.233(k) and other editorial revisions 

in response to comments received. 

b. Summary of Comments and 

Responses 

Comment: One commenter noted that 

the order of the requirements in 40 CFR 

98.233(k) were confusing and should be 

changed to match the actual calculation 

progression. The commenter noted that 

cross-references in the reporting section 

at 40 CFR 98.236(k) will need to be 

revised if the calculation order is 

revised. 

Response: We reviewed the proposed 

calculation order and agree with the 

commenter that the calculation order 

should be clarified. We moved the 

calculations for determining annual 

emissions proposed at 40 CFR 

98.233(k)(2)(iii) and (k)(2)(iv) to a new 

paragraph 40 CFR 98.233(k)(4) and 

renumbered the flare calculation 


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paragraph from (k)(4) to (k)(5). We made 

corresponding revisions to the crossreferences in 40 CFR 98.236(k). 

9. Associated Gas Venting and Flaring 

a. Summary of Final Revisions 

In order to improve data quality and 

avoid over-estimating emissions, the 

EPA is finalizing revisions to Equation 

W–18 (40 CFR 98.233(m)(3)) to add the 

term ‘‘SGp,q’’ as proposed 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. The EPA is not finalizing the 

addition of the proposed term ‘‘EREp,q’’ 

for emissions reported under other 

sources, because the overlap in 

emissions reported elsewhere has been 

determined by the EPA to be negligible 

and because commenters have 

identified these emissions as potentially 

burdensome to track. The EPA is also 

finalizing revisions as proposed to the 

term ‘‘GORp,q’’ and the emission result 

‘‘Es,n’’ in Equation W–18 to specify that 

the gas-to-oil ratio (GOR) and the result 

of the calculation are calculated at 

standard conditions rather than actual 

conditions. 

The EPA also proposed to add a 

definition for the term ‘‘Associated gas 

venting or flaring’’ to clarify what is 

included in this source. We are 

finalizing these amendments as 

proposed. 

b. Summary of Comments and 

Responses 

This section summarizes the major 

comments and responses related to 

associated gas venting and flaring. See 

the 2014 response to comment 

document in Docket Id. No. EPA–HQ– 

OAR–2011–0512 for a complete listing 

of all comments and responses. 

Comment: One commenter disagreed 

with the addition of the term ‘‘EREp,q’’ 

to equation W–18 for ‘‘emissions 

reported elsewhere’’. The commenter 

stated that including the term would 

significantly increase the burden, 

provide little increase in the accuracy of 

reported emissions, and, due to the 

difference in methods used to account 

for the equation parameters, may result 

in the calculation of negative volumes. 

The commenter recommended removing 

the term and revising the definition of 

the summation term for the equation to 

indicate that it applies to associated gas 

not reported elsewhere, consistent with 

the new definition for associated gas 

venting and flaring. 

Response: The EPA included the term 

‘‘EREp,q’’ in Equation W–18 of the 

proposed rule to harmonize with the 

proposed definition of ‘‘associated gas 

venting or flaring,’’ which was defined 

to exclude venting or flaring resulting 

from activities that are reported 

elsewhere, such as tank venting. 

Equation W–18 calculates associated gas 

emissions based on the gas-to-oil ratio 

(GOR) and volume of oil produced 

during the venting or flaring period. 

After considering the public comments, 

we determined that the potential for 

double-counting emissions using 

Equation W–18 with emissions reported 

elsewhere was minimal, particularly 

given the proposed definition of 

‘‘associated gas venting or flaring.’’ For 

example, the EPA determined that the 

emissions as calculated using Equation 

W–18 are not expected to include or 

double-count emissions from onshore 

production storage tanks receiving oil 

from a separator at the wellhead. If 

onshore production storage tanks 

receive oil directly from the wellhead, 

these emissions are accounted for in the 

provisions for onshore production 

storage vessels, and these emissions 

would not constitute ‘‘associated gas 

venting or flaring’’ as defined in the 

proposal. Therefore, we concluded that 

the ‘‘EREp,q’’ term was not needed in 

Equation W–18. We are revising the 

proposed Equation W–18 to remove the 

‘‘EREp,q’’ term, and we are finalizing the 

definition of ‘‘associated gas venting or 

flaring’’ as proposed. 

10. Flare Stack Emissions 

The EPA is finalizing revisions as 

proposed to simplify and clarify the 

calculation requirements for flare stack 

emissions in order to improve the 

accuracy of the collected data. As 

proposed, we are amending the 

calculation method for emissions from a 

flare stack to revise the calculations to 

standard conditions and to account for 

the fraction of emissions that are not 

combusted when sent to an unlit flare. 

The fraction of feed gas sent to an unlit 

flare is determined by using engineering 

estimates and process knowledge. 

The EPA is finalizing amendments, as 

proposed, to include flare stack 

emissions to the list of sources for 

which emissions must be calculated for 

the onshore natural gas transmission 

compression, underground natural gas 

storage, LNG storage, and the LNG 

import and export equipment industry 

segments. The EPA did not receive 

major comments on these provisions 

and is not making any changes to the 

final rule as a result of public 

comments. See the 2014 response to 

comment document in Docket Id. No. 

EPA–HQ–OAR–2011–0512 for a 

complete listing of all comments and 

responses. 

11. Centrifugal and Reciprocating 

Compressors 

a. Summary of Final Revisions 

The EPA is finalizing amendments to 

the monitoring requirements for 

compressors with revisions to the 

proposed requirements. First, we are 

finalizing changes to the centrifugal and 

reciprocating compressor calculation 

sections (40 CFR 98.233(o) and (p)) to 

allow for the measurement of combined 

volumetric emissions from a manifolded 

group of compressor sources. In the 

proposed rule, reporters that had 

manifolded compressors were required 

to take at least three measurements per 

year and report the average of the 

measurements. In this final rule, we are 

requiring reporters to take a single 

measurement per year from manifolded 

compressors, which is commensurate 

with the measurement frequency for 

compressors that are not part of a 

manifold group of compressors. In the 

proposed rule, measurements from 

manifolded compressors were required 

to be taken before emissions are 

comingled with other non-compressor 

emission sources. We received 

comments that this requirement would 

often require new sampling ports in 

unsafe locations. In this final rule, we 

are changing this requirement to read as 

follows: ‘‘Measure at a single point in 

the manifold downstream of all 

compressor inputs and, if practical, 

prior to comingling with other noncompressor emission sources’’. 

The proposed rule inadvertently 

removed the use of acoustic device 

measurement for blowdown valve 

leakage for centrifugal and reciprocating 

compressors. It was not the EPA’s intent 

to remove these provisions. As noted in 

the subpart W 2010 final rule and 

reiterated by commenters, the EPA has 

allowed the use of acoustic device 

measurement to address concerns 

regarding safety or inaccessibility issues 

for some vent measurements. As a 

result, we are allowing for 

quantification of emissions due to leaks 

from compressor blowdown valve 

leakage using an acoustic leak detection 

device. In this final rule, we are 

allowing the use of screening methods 

in 40 CFR 98.234(a) to determine 

whether quantitative emissions 

measurements are needed. We are 

finalizing the proposed reporting 

requirements for individual 

compressors and for manifolded 

compressors with minor changes 

intended to improve clarity. 

We are also finalizing four definitions 

in 40 CFR 98.238 to support the 

addition of the calculation method for 

manifolded vents. We are finalizing the 


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definitions of ‘‘compressor mode,’’ 

‘‘manifolded compressor source,’’ and 

‘‘manifolded group of compressor 

sources’’ as proposed. The EPA received 

comments asserting that the fourth 

proposed definition for ‘‘compressor 

source’’ was unnecessarily vague. To 

address this concern, we are finalizing 

a revised definition of ‘‘compressor 

source’’ that includes detailed 

information regarding the types of 

emissions sources covered within the 

definition. We are finalizing the 

definition for ‘‘compressor source’’ to 

mean ‘‘the source of certain venting or 

leaking emissions from a centrifugal or 

reciprocating compressor. For 

centrifugal compressors, ‘‘source’’ refers 

to blowdown valve leakage through the 

blowdown vent, unit isolation valve 

leakage through an open blowdown vent 

without blind flanges, and wet seal oil 

degassing vents. For reciprocating 

compressors, ‘‘source’’ refers to 

blowdown valve leakage through the 

blowdown vent, unit isolation valve 

leakage through an open blowdown vent 

without blind flanges, and rod packing 

emissions.’’ 

For compressors that are routed to an 

operational flare, we are finalizing 

revisions as proposed to allow operators 

to calculate and report emissions with 

other flare emissions. As we proposed, 

reporters must still 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 (o)(2) and (p)(1) 

and (p)(2)). 

The EPA is also finalizing several 

changes with regard to mode-specific 

measurements as proposed. We are 

finalizing as proposed the revisions to 

the requirements to measure each 

compressor in the not-operatingdepressurized (NOD) mode at least once 

in any 3 consecutive calendar years 

provided that the measurement can be 

taken during a scheduled shutdown 

and, if there is no scheduled shutdown 

within three consecutive calendar years, 

the measurement must be made at the 

next scheduled depressurized 

compressor shutdown. We have 

included additional clarification in this 

final rule that a scheduled shutdown 

means a shutdown that requires a 

compressor to be taken off-line for 

planned or scheduled maintenance. A 

scheduled shutdown does not include 

instances when a compressor is taken 

offline due to a decrease in demand but 

must remain available. We are not 

finalizing the proposed requirement to 

perform a measure for each operating 

mode once every three years. 

We are also finalizing provisions, as 

proposed, that clarify that for reporters 

that elect to conduct ‘‘as found’’ 

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. Finally, we are restructuring 

and revising the centrifugal and 

reciprocating compressor sections (40 

CFR 98.233(o) and 40 CFR 98.233(p)), as 

proposed, in order to improve clarity for 

reporters. 

b. Summary of Comments and 

Responses 

This section summarizes the major 

comments and responses related to 

centrifugal and reciprocating 

compressors. See the 2014 response to 

comment document in Docket Id. No. 

EPA–HQ–OAR–2011–0512 for a 

complete listing of all comments and 

responses. 

Comment: Several commenters stated 

that the proposed rule did not address 

reporter concerns about measuring 

emissions from compressors. Several 

commenters requested that the EPA 

consider developing industry-wide 

emission factors to replace the current 

measurement-based approach in subpart 

W. One commenter requested that the 

EPA use data from outside studies and 

leverage the data collected from 2011 

and 2012 to develop emissions factors 

and remove the annual measurement 

requirement after a reasonable 

timeframe. Another commenter 

requested that the EPA use emission 

factors that reflect the recently enacted 

New Source Performance Standards 

(NSPS) for the natural gas industry (40 

CFR part 60, subpart OOOO). Two 

commenters suggested that reporter 

emission factors developed for 

individual compressors should be used 

when compressor sources are comingled 

with other non-compressor emission 

sources. 

Response: The EPA appreciates the 

suggestions provided by the 

commenters and agrees that credible 

and accurate emission factors can 

provide a cost-effective means of 

calculating GHG emissions for purposes 

of reporting under Part 98. In particular, 

the EPA is willing to consider an 

emission factor approach under Part 98 

for compressors. 

As part of the development of the 

subpart W 2010 final rule, the EPA had 

previously considered using an 

emission factor approach for 

compressors. The EPA found that 

although a 1996 Gas Research Institute 

study on methane emissions from the 

natural gas industry provides much of 

the current knowledge on which 

emission factors from this sector are 

based, information on compressors was 

not necessarily reflective of current 

operational conditions for purposes of 

GHG reporting and therefore additional 

measurement data were needed in order 

to understand emissions related to 

specific modes of operation for 

compressors. 

The EPA agrees that facilities have 

collected data under part 98 related to 

centrifugal and reciprocating 

compressors that can be used to inform 

an emission factor. However, the data 

which are inputs to emissions equations 

have not yet been reported to the EPA 

because they are deferred for reporting 

until 2015. The deferred reporting 

elements include the reporter-specific 

emission factors that are used to 

calculate emissions and the total time 

that a compressor is in a particular 

mode. The reporter-specific emission 

factors provide information on how 

measured data are applied to a 

reporter’s other compressors that were 

not measured in a particular mode, and 

these factors are applied to all 

compressors for the total time each 

compressor is operated in each mode. 

Therefore the deferred data provide 

important information that could help 

inform the development of emission 

factors for each mode of operation. The 

EPA intends to analyze this deferred 

information after it is received in 2015. 

The EPA notes that the prevalence of 

BAMM in the reported data can affect 

cross-facility comparisons for 

developing emission factors, but the 

effect of BAMM cannot be fully 

analyzed until the inputs data are 

reported. 

In addition, the data that will be 

reported under these final rule 

amendments will provide additional 

data that can inform the development of 

emission factors, such as information on 

the power output of the compressor 

driver. Furthermore, the compressor 

revisions that are being finalized in this 

rule will improve the quality of the 

reported data and address technical 

issues received from stakeholders 

during program implementation. The 

EPA also plans to review information 

that will be made available in the near 

future through outside studies. 

The EPA is committed to working 

with stakeholders to review regulatory 

requirements, methods, and the quality 

of the information reported. The EPA 

looks forward to reviewing the deferred 

Part 98 data, data that will be reported 

under these revisions and data from 


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outside studies in order to determine if 

appropriate emission factors can be 

developed, and, if so, the EPA may 

revise the calculation and reporting 

requirements for compressors in a future 

rulemaking. 

Comment: Several commenters 

objected to the requirements for 

measuring emissions from manifolded 

compressor sources. Two commenters 

asserted that the proposed rule fails to 

address issues that may preclude 

measurement from manifolded 

compressor sources (e.g., unsafe to 

access and technically infeasible 

measurement locations, or vent gas from 

manifolded compressor sources that is 

comingled with gas from other emission 

sources) and two commenters noted that 

compressor vents are sometimes 

manifolded such that obtaining 

measurements of individual 

compressors is not possible; one of these 

commenters requested that these 

manifolded compressors be exempt 

from emissions measurements. 

One commenter stated that the EPA 

has not addressed the burden associated 

with installing sampling ports on 

manifolded configurations. Another 

commenter objected to the proposed 

rule requirements specifying that 

manifolded compressor source 

emissions must be measured at a single 

point in the manifold downstream of all 

compressor inputs and where emissions 

cannot be comingled with other noncompressor emission sources; this 

commenter asserted that for compressor 

sources with emissions comingled with 

other sources, a sample port would need 

to be installed prior to the comingling 

of gases from the compressor sources 

and the non-compressor sources and 

could require the shutdown of all 

associated equipment. 

Multiple commenters opposed the 

proposed requirements to conduct three 

measurements per year for manifolded 

compressors. One commenter claimed 

that the requirement to collect three 

measurements appears to be arbitrary 

and is not supported by 2011 or 2012 

reported data. The commenter 

contended that the EPA has failed to 

explain how manifolded source-mode 

emissions data are expected to be 

different from other compressor source 

emissions data or why three 

measurements are expected to reduce 

measurement uncertainty associated 

with dissimilar measurements. Three 

commenters stated that the EPA did not 

address the cost and potential logistical 

problems associated with the 

mobilization of a test team two 

additional times per year (i.e., total of 

three times a year) to conduct 

measurements on manifolded 

compressor sources. One commenter 

argued that the proposed requirements 

do not address concerns regarding the 

burden and costs associated with the 

installation of sample ports, or 

shutdown complications for port 

installation. One commenter argued that 

the EPA misrepresented the rule 

revision as a positive change beneficial 

to industry and a reduction in burden. 

Response: The EPA disagrees with 

commenters who object to the need to 

independently categorize compressor 

source measurements from manifolded 

compressors; however, we acknowledge 

that some of the proposed clarifications 

inadvertently increased the stringency 

of the rule. The subpart W 2010 final 

rule included provisions that required 

the measurement of emissions from all 

vents, including emissions from 

individual compressors manifolded to 

common vents. The proposed rule 

changes do not alter that requirement 

and were intended to help current 

reporters to comply with subpart W. 

The existing 2010 measurement 

requirements apply to the vent from the 

manifolded system without mention of 

co-mingled emission sources. We prefer 

and encourage measurements of 

manifolded compressors to be 

performed prior to co-mingling with 

other sources, as proposed. However, 

based on comments, we recognize that 

this may not be possible for certain 

installations. Therefore, we are not 

finalizing this provision as proposed. 

Instead, we are revising the requirement 

from the proposed rule so that the final 

rule reads as follows ‘‘Measure at a 

single point in the manifold 

downstream of all compressor inputs 

and, if practical, prior to comingling 

with other non-compressor emission 

sources’’. We are also adding a reporting 

element for compressor measurements 

of manifolded systems to indicate 

whether the measurement location is 

prior to comingling with other noncompressor emission sources. 

We proposed that reporters that had 

manifolded compressors be required to 

take at least three measurements per 

year and report the average of the 

measurements. In this final rule, we are 

requiring reporters to take a single 

measurement per year from manifolded 

compressors, which is commensurate 

with the measurement frequency for 

compressors that are not part of a 

manifolded group of compressors and 

consistent with the existing 2010 

measurement requirements. 

Comment: Three commenters 

requested that the EPA improve the 

definition of ‘‘compressor source’’ in 40 

CFR 98.238 for clarity. One commenter 

contended that the proposed definition 

is not sufficiently clear to manage 

compliance and could lead to broad 

interpretation to sources not specifically 

called out in the rule. The commenter 

requested that the definition for 

‘‘compressor source’’ be revised to 

specifically list the required sources. 

Response: The EPA agrees with 

commenters that the proposed 

definition for ‘‘compressor source’’ 

could be read as potentially ambiguous 

and create confusion with regards to 

compliance with Part 98. Therefore, we 

are clarifying the definition of 

‘‘compressor source’’ in this final rule to 

specify the applicability of the rule to 

specific compressor emission sources. 

We are finalizing the definition for 

‘‘compressor source’’ to mean ‘‘the 

source of certain venting or leaking 

emissions from a centrifugal or 

reciprocating compressor. For 

centrifugal compressors, ‘‘source’’ refers 

to blowdown valve leakage through the 

blowdown vent, unit isolation valve 

leakage through an open blowdown vent 

without blind flanges, and wet seal oil 

degassing vents. For reciprocating 

compressors, ‘‘source’’ refers to 

blowdown valve leakage through the 

blowdown vent, unit isolation valve 

leakage through an open blowdown vent 

without blind flanges, and rod packing 

emissions.’’ These revisions clearly 

delineate the emission sources for 

which reporters must measure and 

account for emissions in the final rule. 

Comment: Several commenters 

opposed the proposed requirements to 

measure compressors in the NOD mode 

once every 3 years, provided that a 

measurement can be taken during a 

scheduled shutdown. Three 

commenters requested that the EPA 

eliminate the requirement to measure 

compressors in the NOD mode in its 

entirety. One commenter argued that the 

proposed rule fails to provide sufficient 

justification to continue to require NOD 

mode measurements every three years. 

Another commenter argued that based 

on the monitoring data collected to date, 

the NOD mode compressor emissions 

are minimal, and the monitoring 

requirements are not cost effective. 

Another commenter stated that the 

measurements collected in 2011 and 

2012 show that transmission and storage 

sources completed hundreds of 

measurements in the NOD mode, with 

about the same number of ‘‘as found’’ 

tests completed in shutdown mode as 

other modes. 

Response: The EPA disagrees with 

commenters opposed to the proposed 

requirements to measure compressors in 

the NOD mode. The EPA established the 

requirements to measure compressors in 

the NOD mode once every 3 years as 


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part of the subpart W 2010 final rule. As 

the EPA previously noted (75 FR 18608, 

April 12, 2010), depending on 

operational practices, the various 

operating modes of centrifugal and 

reciprocating compressors may have 

significantly different emissions. The 

EPA noted at that time that unit 

isolation valves and compressor 

blowdown valves can have excessive 

leakage, especially when a compressor 

is not in operation. Following 

consideration of commenter input, the 

EPA finalized as part of the subpart W 

2010 final rule these provisions to 

require measurements in the NOD mode 

once every 3 years. 

The EPA reviewed the 2011, 2012 and 

2013 reported emissions data for 

compressors and determined that 

compressor emissions from the NOD 

mode can contribute to a significant 

amount of the measured emissions for 

centrifugal compressors and 

reciprocating compressors. For more 

information, see the memorandum, 

‘‘Greenhouse Gas Reporting Rule: 

Technical Support for 2014 Revisions 

and Confidentiality Determinations for 

Petroleum and Natural Gas Systems; 

Final Rule’’ in Docket Id. No. EPA–HQ– 

OAR–2011–0512. Therefore, we are not 

removing the requirement to measure 

emissions from compressors in the NOD 

mode in this final rule. 

Comment: Several commenters stated 

that the EPA has not considered 

logistical issues in developing the 

requirements to measure compressors in 

the NOD mode once every 3 years, 

provided that a measurement can be 

taken during a scheduled shutdown. 

One commenter claimed that the 

proposed ‘‘scheduled shutdown’’ 

exception to the three-year requirement 

does not avoid the costs associated with 

mandatory testing in the NOD mode, 

such as out-of-sequence scheduling 

costs or the obligation to maintain 

records on compressor shutdown testing 

status. Two commenters stated that 

operators would likely force unit 

shutdowns while the measurement 

contractor is on site, which could result 

in the emissions of additional GHGs. 

One commenter supported the 

proposed revision to allow the 

measurement to be taken during the 

next scheduled depressurized 

shutdown, however, the commenter 

asked that the scheduled shutdown not 

include instances when a scheduled 

compressor shutdown is only for a short 

duration, such that it is not possible to 

complete the measurement, or when a 

‘‘scheduled shutdown’’ may occur 

without sufficient lead time to arrange 

for or mobilize a measurement team. 

Four commenters stressed that the 

proposed rule did not clearly define 

what constitutes a shutdown or 

‘‘scheduled shutdown.’’ Another 

commenter noted that transmission 

compressors often start up and 

‘‘shutdown’’ to meet demands; the 

commenter stated that it is not clear if 

this type of ‘‘shutdown’’ would be 

included under the proposed rule text. 

One commenter requested that the EPA 

provide a definition for the term 

‘‘scheduled shutdown’’ that includes a 

shutdown of longer duration and likely 

associated with major maintenance and 

unit unavailability. Another commenter 

requested that the definition refer to a 

major maintenance outage that is 

scheduled months in advance, as 

opposed to a shutdown scheduled in 

direct response to a particular event 

(e.g., in response to change in demand 

or operational disruption). One 

commenter argued that even if a 

scheduled shutdown refers to extended 

compressor shutdown for major 

maintenance, facilities would still face 

scheduling and logistical issues as well 

as increased costs. 

One commenter responded to the 

EPA’s request for comment on the 

option of requiring measurements in the 

NOD mode every five years rather than 

every three years. The commenter 

requested that the EPA extend the 

monitoring frequency to once every five 

years but noted that this change may not 

result in a unit being available at a 

specific time. The commenter suggested 

that emission factors be developed for 

the NOD mode as soon as feasible. 

Response: The EPA is aware of 

commenter concerns regarding the need 

to shut down, purge, and blow down 

emissions from compressors in order to 

conduct emissions measurements. We 

are reducing the burden on facilities by 

augmenting the three-year measurement 

requirement to specify that reporters 

must take a measurement in the NOD 

mode within three years or at the next 

scheduled shutdown. If three 

consecutive calendar years occur 

without measuring the compressor in 

the NOD mode, then we are requiring 

that the NOD mode measurement must 

be made at the next scheduled 

depressurized compressor shutdown. 

We agree with commenters that 

indicated that the term ‘‘scheduled 

shutdown’’ was potentially nebulous 

and requires clarification. Therefore, we 

are clarifying in this final rule that a 

scheduled shutdown means a shutdown 

that requires a compressor to be taken 

off-line for planned or scheduled 

maintenance. This may include 

maintenance such as replacement of 

compressor rod packing for 

reciprocating compressors or 

replacement of wet or dry seals in 

centrifugal compressors. A scheduled 

shutdown does not include instances 

when a compressor is taken offline due 

to a decrease in demand but remains 

available to meet increases in demand. 

These final revisions clarify that 

operators do not have to plan a 

shutdown of their equipment solely to 

take a measurement of their compressor 

in the NOD mode but may take the 

measurement as part of regular planned 

maintenance. These revisions also 

clarify that the compressor must be 

depressurized. These provisions will 

ensure that facilities have sufficient 

time to mobilize a test team and 

coordinate testing to occur during 

periods of planned shutdown. 

Therefore, this will reduce the need for 

reporters to schedule additional 

shutdowns outside of planned 

maintenance, reducing compliance 

costs. Although the EPA considered 

extending the period to collect 

measurements in the NOD mode to 

every 5 years, it would not necessarily 

alleviate reporter concerns regarding the 

need to schedule a shutdown solely for 

emissions measurements. As the EPA 

has previously noted in finalizing the 

subpart W 2010 final rule, three years is 

generally accepted as the period during 

which compressors would be shut down 

for regular maintenance. Therefore, we 

have determined that the final 

provisions provide an adequate 

extension for reporters for which the 

maintenance period extends beyond 3 

years, while ensuring that the EPA 

collects the data in a timely manner as 

it comes available. 

Comment: Two commenters objected 

to the proposed requirement to 

complete operating-mode measurements 

every three years or the next year that 

compressor operation exceeds 2,000 

hours. These commenters stated that the 

EPA has not justified the need for or 

explained the benefit of this 

requirement in the proposed rule or the 

technical support document. Both 

commenters remarked that the subpart 

W measurement data currently reported 

includes hundreds of operating-mode 

tests completed within the first two 

years. One commenter stated that, at a 

minimum, the EPA should review and 

analyze 2011–2013 data to ascertain the 

need for such requirements. One 

commenter asserted that the proposed 

time interval has no basis. Two 

commenters stated that the proposed 

requirement would unnecessarily 

increase compliance costs in excess of 

EPA’s presumed costs for completing 

measurements. 

Multiple commenters requested that 

compressor measurements be completed 


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‘‘as found’’ without mandating modespecific measurements. Three 

commenters noted that because the 

annual as-found measurements have 

already generated data in all three 

modes, further mode- and time-specific 

testing does not result in additional 

meaningful emissions data. The 

commenters urged that the proposed 

rule failed to justify the need for further 

mode- and time-specific testing 

requirements. 

Response: The EPA proposed this 

change in order to ensure data for all 

compressor operating modes would be 

collected for all compressors. After 

considering comments and further 

reviewing the available reported data, 

the EPA concluded that additional 

mode specific measurements to ensure 

characterization of modes other than 

not-operating-depressurized mode are 

not necessary. Therefore, we are not 

finalizing the proposed requirement to 

perform a measure for each operating 

mode once every three years. 

Comment: Five commenters objected 

to revisions in the proposed rule that 

appeared to eliminate the use of the 

acoustic method for blowdown valve 

leakage measurements for centrifugal 

compressors in operating-mode and for 

reciprocating compressors in operating 

mode or standby-pressurized-mode. The 

commenters noted that EPA had added 

a provision for leak rate quantification 

to the existing subpart W rule in 

response to comments on the reproposed subpart W rule, in order to 

address concerns regarding safety or 

inaccessibility issues for some vent 

measurements. Commenters stated that 

the EPA had previously included this 

method to ensure safety in the 

collection of data from certain sources. 

One commenter noted that in the first 

three reporting years, many reporters 

have relied on the acoustic method for 

reciprocating compressor and 

centrifugal compressor measurements of 

isolation valve and blowdown valve 

leakage and condensate tank dump 

valve leakage. Several commenters 

requested that this method not be 

eliminated unless other alternative rule 

requirements, such as the use of an 

infrared camera for screening, are 

implemented. 

Three commenters recommended that 

the EPA consider allowing the use of an 

infrared (IR) camera for screening vents 

that require measurement. These 

commenters requested that the rule 

include additional viable measurement 

methods and contended that an IR 

camera option would provide flexibility 

for reporters. One commenter noted that 

the IR camera could be used to screen 

for leaks from compressor isolation 

valves, blowdown valves, or rod 

packing released through a vent and 

identify whether vent measurement is 

needed. The commenter asserted that 

this method would be invaluable for 

screening vents that are unsafe or 

impractical to access. The commenter 

stated that several companies have 

received approval of BAMM requests to 

use the IR camera to screen these 

compressor sources for emissions. 

Response: The EPA agrees with 

commenters that the acoustic device 

measurement method should not be 

eliminated from the final rule. During 

the revision of the centrifugal and 

reciprocating compressor calculation 

and monitoring requirements, the use of 

the acoustic device measurement for 

blowdown valve leakage for centrifugal 

and reciprocating compressors was 

erroneously removed. The EPA has 

previously allowed the use of acoustic 

device measurement to address 

concerns regarding safety or 

inaccessibility issues for some vent 

measurements, and we are aware that 

many reporters have relied upon 

acoustic device measurement to comply 

with the rule. The EPA understands the 

safety and inaccessibility concerns 

raised by commenters, and we did not 

intend to remove these provisions or to 

reduce flexibility for reporters in the 

proposed rule. In this final rule, we are 

maintaining provisions that allow for 

quantification of emissions due to leaks 

from compressor blowdown valve 

leakage using an acoustic leak detection 

device. Specifically, we have included 

these provisions in 40 CFR 

98.233(o)(2)(i)(C) and 40 CFR 

98.233(p)(2)(i)(C) of the final rule. 

The EPA also agrees with the 

commenters’ suggestion to allow for the 

use of optical gas imaging equipment or 

an infrared (IR) camera for compressor 

vent screening. The EPA has reviewed 

the methods in 40 CFR 98.234(a) and 

determined that these methods are 

appropriate for pre-screening for leakage 

from compressor vents. The use of an IR 

camera is currently allowed under 

subpart W to screen for dump valve 

leakage through tank vents in 40 CFR 

98.233(k) and is a proven tool for 

identifying leakage from these emissions 

sources. Therefore, we have determined 

that it would be appropriate to allow the 

use of the methods in 40 CFR 98.234(a) 

for pre-screening of emissions from 

isolation valves, blowdown valves, or 

rod packing released through a vent, 

provided that sources conduct followup measurements if leaks are detected. 

The EPA agrees with commenters that 

this method would provide flexibility 

for reporters. We are finalizing 

provisions in 40 CFR 98.233(o)(2)(i)(D) 

and 40 CFR 98.233(p)(2)(i)(D) to allow 

the use of the methods in 40 CFR 

98.234(a) to allow for pre-screening for 

leaks from compressor isolation valves, 

blowdown valves, or rod packing 

released through a vent. Reporters may 

use this method to identify whether 

further vent measurement is needed. If 

any emissions are detected, then 

reporters are required to use one of the 

methods currently specified in subpart 

W (acoustic leak detection device, 

calibrated bagging or high volume 

sampler, or temporary meter such as a 

vane anemometer) to quantify 

emissions. If no emissions are detected, 

the reporter would not be required to 

follow-up with a measurement to 

quantify emissions. We do not 

anticipate that these final revisions will 

negatively impact the quality of the data 

collected, as reporters will continue to 

use the existing measurement methods 

under subpart W to quantify emissions 

that are detected using the IR camera. 

12. Natural Gas Distribution: Leak 

Detection Equipment and Emissions 

From Components 

a. Summary of Final Revisions 

The EPA is finalizing, with minor 

revisions from the proposed rule, 

amendments to revise Equations W– 

30A, W–30B, W–31, W–32A and W–32B 

to place the natural gas distribution 

facility meter/regulator run emission 

factors calculation in 40 CFR 98.233(q) 

instead of 40 CFR 98.233(r) while also 

clarifying that the emission factor is 

calculated separately for CO2 and CH4

and is on a meter/regulator run 

operational hour basis instead of a 

meter/regulator run component basis. 

The proposed rule inadvertently 

omitted appropriate provisions for 

calculating and reporting emissions 

from equipment leaks at above-grade 

transmission-distribution stations that 

are not surveyed during the reporting 

year as noted in the public comments 

received. Therefore, the EPA is 

finalizing minor revisions to Equations 

W–31 and W–32B as well as 40 CFR 

98.233(q) introductory text, (q)(8)(ii) and 

(iii), and adding paragraph (q)(9) to 

specify how emissions from equipment 

leaks at above-grade transmission 

stations not surveyed during the 

reporting year are to be calculated. In 

the final rule, facilities must calculate 

annual emissions from above-grade 

transmission-distribution transfer 

stations surveyed during the calendar 

year 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 emission factors for aboveVerDate Sep<11>2014 19:29 Nov 24, 2014 Jkt 235001 PO 00000 Frm 00016 Fmt 4701 Sfmt 4700 E:\FR\FM\25NOR4.SGM 25NOR4

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Federal Register / Vol. 79, No. 227 / Tuesday, November 25, 2014 / Rules and Regulations 70367 

grade 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 used to develop 

the annual facility meter/regulator run 

population emission factors for CO2 and 

CH4 using Equation W–31. Paragraph 40 

CFR 98.233(q)(8)(iii) was revised from 

proposal to provide more specificity on 

how the emission factors from Equation 

W–31 must be recalculated as additional 

equipment leak survey data become 

available from above-grade 

transmission-distribution transfer 

stations that use a multiple year 

equipment leak survey cycle. To 

calculate annual emissions from abovegrade metering-regulating stations that 

are not above-grade transmissiondistribution transfer stations and from 

all above-grade transmissiondistribution transfer stations at facilities 

that use a multiple year equipment leak 

survey cycle must use the emission 

factors (calculated in Equation W–31) in 

the annual emissions calculation of 

Equation W–32B in 40 CFR 98.233(r). 

The primary difference from proposal is 

that the calculations for above-grade 

transmission-distribution transfer 

stations that elect to use a multiple year 

equipment leak survey cycle, which 

were inadvertently omitted, are now 

specified in the new paragraph at 40 

CFR 98.233(q)(9). Completing the 

calculations for all above-grade 

transmission-distribution transfer 

stations allows for more unified 

reporting of the emissions for all abovegrade transmission-distribution transfer 

stations 40 CFR 98.236(q). 

As proposed, emissions from belowgrade 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. 

The EPA is also finalizing the 

definition of ‘‘meter/regulator run’’ with 

minor revisions from the proposed rule. 

The revisions clarify that the term 

‘‘meter/regulator run’’ refers only to 

components in the natural gas 

distribution industry segment. The final 

definition of ‘‘meter/regulator run’’ 

reads as follows: ‘‘Meter/regulator run 

means a series of components used in 

regulating pressure or metering natural 

gas flow, or both, in the natural gas 

distribution industry segment. At least 

one meter, at least one regulator, or any 

combination of both on a single run of 

piping is considered one meter/

regulator run.’’ 

b. Summary of Comments and 

Responses 

This section summarizes the major 

comments and responses related to leak 

detection equipment and emissions 

from components for the natural gas 

distribution segment. See the 2014 

response to comment document in 

Docket Id. No. EPA–HQ–OAR–2011– 

0512 for a complete listing of all 

comments and responses. 

Comment: One commenter noted that 

proposed text for 40 CFR 98.233(q)(8)(i) 

allows all distribution facility abovegrade transmission-distribution transfer 

stations to be surveyed over multiple 

years up to a five-year cycle, while the 

emission calculation requirements of 40 

CFR 98.233(q) and emission reporting 

requirements of 40 CFR 98.236(q)(2) 

only apply to equipment leaks at abovegrade transmission-distribution stations 

surveyed during the reporting year. The 

commenter noted that emissions for 

equipment leaks at the above-grade 

transmission-distribution transfer 

stations not surveyed during the 

reporting year are not calculated or 

reported. The commenter suggested 

revising the associated text and 

equations to calculate these emissions 

using Equation W–32B and the emission 

factors calculated using Equation W–31. 

Response: The commenter is correct 

that the proposed revisions 

inadvertently omitted provisions for 

calculating and reporting emissions 

from above-grade transmissiondistribution transfer stations that were 

not surveyed in the first cycle of a 

multi-year cycle. In this final rule, 

natural gas distribution facilities may 

choose to conduct equipment leak 

surveys at all above-grade transmissiondistribution transfer stations over 

multiple years, not exceeding a five year 

period. To account for annual emissions 

from above-grade transmissiondistribution transfer stations that have 

not been surveyed in the current survey 

cycle (i.e., whose emissions were not 

calculated using Equation W–30), we 

are revising the language proposed in 40 

CFR 98.233(q)(8) and adding a 

paragraph (q)(9) to clarify that facilities 

must use the emission factors 

(calculated in Equation W–31) in the 

annual emissions calculation of 

Equation W–32B in 40 CFR 98.233(r). 

Additionally, we are revising the term 

‘‘CountM,R’’ in Equation W–32B to 

include meter/regulator runs at abovegrade transmission-distribution transfer 

stations when required to be used 

according to the new paragraph at 40 

CFR 98.233(q)(9). We are finalizing 

harmonizing edits to 40 CFR 98.236(q) 

and removing some reporting elements 

in 40 CFR 98.236(r) to clarify the 

applicability of the reporting 

requirements for equipment leaks at the 

above-grade transmission-distribution 

transfer stations and adding specific 

requirements for reporting elements 

when equipment leak surveys for abovegrade transmission-distribution transfer 

stations are performed using multiple 

year cycles. 

13. Calculation of GHG Emissions From 

Natural Gas Volume Emissions 

a. Summary of Final Revisions 

We are finalizing revisions as 

proposed to clarify onshore natural gas 

transmission compression, LNG storage, 

LNG import and export, and natural gas 

distribution facilities may use either 

site-specific composition or a default 

gas composition (95 percent CH4 and 1 

percent CO2) to calculate GHG 

emissions from natural gas volume 

emissions at 40 CFR 98.233(u)(2)(iii), 

(v), (vi) and (vii). We are also finalizing 

analogous revisions to 40 CFR 

98.233(u)(2)(iv) to clarify the option to 

use either site-specific composition data 

or a default gas composition (95 percent 

CH4 and 1 percent CO2) for underground 

natural gas storage facilities as well. The 

EPA requested comment on whether the 

use of site-specific composition data for 

calculating emissions should be 

required or optional. The EPA received 

comments supporting only the optional 

use of site-specific gas composition 

data; no commenters supported the 

mandatory use of site-specific gas 

composition data. 

We are also finalizing several 

clarifications regarding the need to 

calculate emissions for certain equations 

in actual conditions based on public 

comments received. The EPA intended 

that the existing provision in 40 CFR 

98.233(t) allowed for measurements to 

be made at standard conditions even 

when the equations specified actual 

conditions. However, we concluded that 

additional revisions could clarify this 

intent for reporters. First, we are 

finalizing revisions to the introductory 

text at 40 CFR 98.233 to read: ‘‘You 

must calculate and report the annual 

GHG emissions as prescribed in this 

section. For calculations that specify 

measurements in actual conditions, 

reporters may use a flow or volume 

measurement system that corrects to 

standard conditions and determine the 

flow or volume at standard conditions; 

otherwise, reporters must use average 

atmospheric conditions or typical 

operating conditions as applicable to the 

respective monitoring methods in this 

section.’’ Second, the introductory text 

at 40 CFR 98.236 is revised to read: ‘‘In 


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addition to the information required by 

§ 98.3(c), each annual report must 

contain reported emissions and related 

information as specified in this section. 

Reporters that use a flow or volume 

measurement system that corrects to 

standard conditions as provided in the 

introductory text in § 98.233 for data 

elements that are otherwise required to 

be determined at actual conditions, 

report gas volumes at standard 

conditions rather the gas volumes at 

actual conditions and report the 

standard temperature and pressure used 

by the measurement system rather than 

the actual temperature and pressure.’’ 

b. Summary of Comments and 

Responses 

Comment: Several commenters stated 

that requiring the conversion of gas flow 

rates from ‘‘standard conditions’’ to 

‘‘actual conditions’’ when applying 

required estimation methodology is 

burdensome and overly complicated. 

These estimations then have to be 

converted back into standard conditions 

for reporting under the regulatory 

requirements. Since instrumentation 

used in the industry typically measures 

gas flow rates in standard conditions, 

the commenters requested the EPA to 

revise Equations W–3, W–4A, W–4B, 

W–7, W–17A, W–17B, W–34, W–39A, 

and W–39B to reflect that the measured 

gas volumes and/or estimated gas 

volumes used in these equations, and 

the resulting emissions, are in standard 

conditions to better meet reporting 

requirements and consistency. 

Response: The EPA reviewed the 

existing provision in 40 CFR 98.233(t), 

which states that ‘‘[i]f equation 

parameters in § 98.233 are already at 

standard conditions, which results in 

volumetric emissions at standard 

conditions, then paragraph (t) does not 

apply,’’ and concluded that it effectively 

allows for measurement in either 

standard or actual conditions. However, 

in reviewing the calculation 

requirements in 40 CFR 98.233 and the 

reporting requirements in 40 CFR 

98.236, we understand that additional 

clarity could be provided. We recognize 

that there are automated flow or volume 

measurement systems that automatically 

convert measurements to standard 

conditions. It was not our intent to 

require facilities to convert these data to 

actual conditions to fulfill the certain 

calculation and reporting requirements, 

then convert the volumes back to 

standard conditions prior to 

determining GHG mass emissions. We 

disagree with the commenters’ 

suggestion that all of these equations 

should be expressed in standard 

conditions because not all facilities 

automatically correct the actual 

volumetric flow measured to standard 

conditions. Our intent was to provide an 

allowance to use either actual 

volumetric flow at the conditions 

present or volumetric flow corrected to 

standard conditions. In order to clarify 

this intent for reporters, we are 

finalizing revisions to the introductory 

text at 40 CFR 98.233 and 98.236 to 

clarify that use of systems that 

automatically correct to standard 

conditions is allowed. Specifically, the 

introductory text at 40 CFR 98.233 is 

revised to read, ‘‘You must calculate 

and report the annual GHG emissions as 

prescribed in this section. For 

calculations that specify measurements 

in actual conditions, reporters may use 

a flow or volume measurement system 

that corrects to standard conditions and 

determine the flow or volume at 

standard conditions; otherwise, 

reporters must use average atmospheric 

conditions or typical operating 

conditions as applicable to the 

respective monitoring methods in this 

section.’’ The introductory text at 40 

CFR 98.236 is revised to read, ‘‘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. 

Reporters that use a flow or volume 

measurement system that corrects to 

standard conditions as provided in the 

introductory text in § 98.233 for data 

elements that are otherwise required to 

be determined at actual conditions, 

report gas volumes at standard 

conditions rather the gas volumes at 

actual conditions and report the 

standard temperature and pressure used 

by the measurement system rather than 

the actual temperature and pressure.’’ 

Comment: Five commenters 

supported the option to use site-specific 

data while retaining the option to use 

the default methane and CO2

composition values currently specified 

in subpart W. Four of these commenters 

stated that the use of site-specific 

composition data should not be 

mandatory. One commenter noted that 

compressor stations are normally not 

equipped with gas chromatographs for 

determination of site-specific gas 

composition; the commenter stated that 

mandatory reporting of site-specific gas 

composition would require the 

collection of extended gas analyses 

annually at each compressor station. 

Two commenters remarked that 

requiring mandatory use of site-specific 

composition data would result in 

increased costs and burden to reporters. 

Other commenters stated that the 

optional use of site-specific composition 

data adds flexibility for operators 

already using site gas quality data for 

other reporting purposes. Two 

commenters remarked that retaining the 

use of default composition values 

simplifies reporting without 

compromising GHG emission estimates 

for operators. These commenters noted 

that natural gas composition values 

downstream of natural gas processing 

facilities are much less variable than 

upstream operations. 

Response: Paragraphs at 40 CFR 

98.233(u)(2)(iii) through (vii) previously 

specified that these facilities ‘‘may’’ use 

the default composition, but they did 

not clearly specify the alternative to the 

default. In the proposed rule, we 

clarified that the alternative to the 

default was ‘‘site specific engineering 

estimates based on best available data.’’ 

The EPA specifically requested 

comment on whether the use of sitespecific composition data for calculating 

emissions should be required or 

optional and solicited information on 

when a facility would not have sitespecific composition data available. As 

the commenters noted, determining sitespecific composition data based on 

measurement data would add burden to 

the industry, particularly where 

appropriate sampling and analysis 

equipment are not available. However, 

we note that the proposed language did 

not limit the site-specific composition to 

be based on site-specific measurement 

data, but rather ‘‘site specific 

engineering estimates based on best 

available data.’’ We agree with 

commenters that facilities should be 

allowed to use site-specific data when 

the data are available. We also agree 

with commenters that, when data are 

not available, the default values are 

reasonable alternatives for industries 

downstream of the processing plants. 

Therefore, after considering the 

information provided by commenters, 

the EPA is finalizing revisions in 40 

CFR 98.233(u)(2)(iii) through (vii) to 

clarify that natural gas transmission 

compression, underground natural gas 

storage, LNG storage, LNG import and 

export, and natural gas distribution 

facilities may use either site-specific 

composition data (based on engineering 

estimates) or the default gas 

compositions. 

14. Onshore Petroleum and Natural Gas 

Production and Natural Gas Distribution 

Combustion Emissions 

1. Summary of Final Revisions 

In this final rule, the EPA is clarifying 

that emissions and volume of fuel 

combusted must be reported for all 

internal combustion units that drive 


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compressors in 40 CFR 98.236. The EPA 

is revising this reporting requirement to 

be consistent with the emission 

estimation methods in 40 CFR 

98.233(z)(4), which specify that the 

exemption from reporting emissions for 

internal combustion units with a rated 

heat input capacity less than or equal to 

1 mmBtu per hour (130 hp) does not 

apply to internal fuel combustion 

sources that drive compressors. These 

revisions are finalized as proposed. We 

are also finalizing revisions to the 

description of the ‘‘HHV’’ term for 

Equation W–40 with minor revisions 

from the proposed rule. Specifically, we 

are finalizing that, for field gas or 

process vent gas, the reporter may use 

either the default higher heating value 

(HHV) or a site-specific HHV. 

2. Summary of Comments and 

Responses 

Comment: One commenter requested 

that the EPA modify the description of 

the term ‘‘HHV’’ used in Equation W– 

40 to allow the use of site-specific 

(measured) higher heating values for 

field gas or process vent gas, when the 

data are available, as an alternative to 

the currently specified default value. 

The commenter noted that allowing the 

use of site-specific HHV data would be 

similar to the proposed changes to allow 

site-specific GHG concentrations instead 

of default values. 

Response: We agree with the 

commenter that the use of measured 

higher heating values should be 

allowed, when available. It was not our 

intent to mandate the use of the HHV 

default value but to allow its use when 

measurement data were not available. 

Therefore, we are finalizing the 

description of the ‘‘HHV’’ term in 

Equation W–40 to read as follows: 

‘‘Higher heating value of fuel, mmBtu/ 

unit of fuel (in units consistent with the 

fuel quantity combusted). For field gas 

or process vent gas, you may use either 

a default higher heating value of 1.235 

× 10¥3 mmBtu/scf or a site-specific 

higher heating value.’’ 

C. Summary of Final Revisions to 

Missing Data Provisions 

1. Summary of Final Revisions 

The EPA is finalizing amendments to 

40 CFR 98.235, with revisions from the 

proposed rule, to clarify the procedures 

for addressing missing data. We 

proposed various missing data 

procedures for different types or 

frequencies of measurement data. For 

AGR vents, we proposed that missing 

quarterly samples must use the average 

of the value of the last four quarterly 

samples. We received comments on how 

to implement this requirement when 

less than four quarters of data are 

available (e.g., for new sources). Rather 

than establishing unique missing data 

procedures for this source, we are 

finalizing a requirement for these 

sources to use the ‘‘before’’ and ‘‘after’’ 

approach analogous to the missing data 

procedures proposed for continuous 

measurement data. Similarly, we are 

also finalizing, with minor revisions 

from proposal, the missing data 

requirements for measurement devices 

such as continuous flow monitors and 

composition analyzers to standardize 

these requirements to all measurements 

required by the rule except for annual 

measurement data. For stationary and 

portable combustion sources, we are 

finalizing amendments as proposed to 

require reporters to use the missing data 

procedures in subpart C of part 98. 

As proposed, the EPA is finalizing 

amendments to allow the use of best 

engineering estimates for any parameter 

that cannot be reasonably measured or 

obtained according to the requirements 

in subpart W for up to 6 months from 

the facility’s first date of subpart W 

applicability. We are also finalizing, 

with minor revisions from proposal, 

amendments to allow the use of best 

engineering estimates for any parameter 

that cannot be reasonably measured or 

obtained according to the requirements 

in subpart W for up to 6 months for 

facilities that are subject to subpart W 

and that acquire new sources from 

another facility that is not subject to 

reporting under subpart W. We 

originally proposed this amendment for 

new wells, but after reviewing the 

public comments received, we 

determined this allowance should be 

more broadly applied to any new 

emissions source acquired by the 

existing facility from another facility 

that is not subject to reporting under 

subpart W. Only data and calculations 

associated with those newly acquired 

sources fall under these provisions. 

We are finalizing missing data 

provisions for annual and biannual 

(once every two year) measurements 

that are similar to the previous missing 

data requirements in 40 CFR 98.235 as 

provided in the subpart W 2010 final 

rule. These provisions require repeat of 

the estimation or measurement as soon 

as possible, with allowance to use 

measurements made after December 31 

(in the subsequent year) as substitute 

values for the missing data in the 

reporting year. 

We are not finalizing the reporting 

requirements for use of missing data 

procedures as proposed. In the proposed 

rule, we required missing data elements 

to be reported with significant 

specificity, including dates in which 

substitution values were used, equations 

in which the substitute value is used, a 

description of the circumstances that 

led to missing data, a description of the 

procedure used to develop the 

substitute value, the missing data 

procedure citation claimed, and a 

description of how missing data 

procedures will be avoided in the 

future. After reviewing public 

comments, we determined that 

reporting for missing data should more 

closely align with the requirements in 

other Part 98 source categories as guided 

by the requirements in 40 CFR 

98.3(c)(8). We are finalizing reporting 

requirements to identify the data 

element for which missing data 

procedures were used and the number 

of hours (or required measurements) for 

which missing data procedures were 

used. We are also finalizing 

recordkeeping requirements regarding 

the use of missing data procedures to 

include some of the detail of the 

proposed reporting requirements. 

Specifically, reporters that use missing 

data procedures are required to keep a 

record listing the emission source type, 

a description of the circumstance that 

resulted in the need to use missing data 

procedures, the missing data provisions 

in 40 CFR 98.235 that apply, the 

calculation or analysis used to develop 

the substitute value, and the substitute 

value. 

2. Summary of Comments and 

Responses 

This section summarizes the major 

comments and responses related to 

missing data provisions. See the 2014 

response to comment document in 

Docket Id. No. EPA–HQ–OAR–2011– 

0512 for a complete listing of all 

comments and responses. 

Comment: Several commenters 

recommended that if BAMM is 

eliminated as proposed, then the 

missing data provisions should be 

expanded to include all case-specific 

monitoring circumstances for which the 

EPA has previously reviewed and 

approved BAMM requests from 2011 

through 2014, including (1) vent lines 

that cannot be safely or feasibly 

measured and where acoustic device 

measurement is not an option; (2) 

equipment and piping configurations 

that cannot be easily modified without 

incurring significant expense and 

operational delays; and (3) compressor 

measurement data in a specific mode. 

Response: The EPA has considered 

the implications of removing BAMM 

requirements and commenters’ 

concerns. Although the EPA indicated 

in the preamble to the proposed rule 


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that missing data procedures may 

provide clarity for reporters who may 

have unintentionally missed collecting 

required data, the missing data 

procedures are not intended to replace 

BAMM or to be used by reporters as 

BAMM. In the final rule, the EPA is 

finalizing multiple revisions to the rule 

that address commenter concerns 

related to BAMM. See Section II.D of 

this preamble for further discussion on 

BAMM. 

Comment: Four commenters 

suggested that missing data procedures 

be expanded beyond ‘‘activity data’’ 

specified in 40 CFR 98.235(g) to include 

emissions from locations that are 

required to be directly measured and 

other data such as temperature and 

pressure. The commenters asserted 

there are situations where standard 

measurement procedures cannot be 

conducted and alternatives are 

necessary. These commenters asked the 

EPA to clarify whether activity data 

include the data elements similar to 

those used in Equation W–6 (e.g., 

atmospheric pressure; pressure of the 

gas being discharged; percent of packed 

vessel volume that is gas; and the 

number of dehydrator openings in the 

calendar year). Other commenters asked 

that the missing data provisions 

specifically account for compressor vent 

and rod packing measurements. These 

commenters indicated it is not clear 

whether the EPA intended to include 

these measurements in 40 CFR 

98.235(g). 

Response: Activity data referred to in 

98.235(g) includes data that are not 

measured, such as counts of the number 

of dehydrator openings in the calendar 

year. The provisions proposed in 40 

CFR 98.233(g) were intended to cover 

only activity data values used in 

emissions calculations that could not be 

determined using the methods in 40 

CFR 98.233; it does not refer to values 

that are required to be measured. In our 

proposed revisions of the missing data 

provisions, the EPA inadvertently 

omitted missing data procedures for 

measurements conducted annually, 

such as compressor measurements, or 

biannually, such as flow measurements 

of well venting for liquids unloading 

and flowback determinations for gas 

well venting during completions and 

workovers with hydraulic fracturing. It 

was our intent to maintain the existing 

missing data procedures for these data 

elements, which entails re-measurement 

of the emissions source. The EPA 

expects all reporters to comply with 

annual measurement requirements as 

specified in 40 CFR 98.233, unless the 

missing data provisions for new 

facilities or newly acquired sources 

apply. However, the EPA agrees with 

the commenters that missing data 

procedures are needed for the annual 

measurements to accommodate a variety 

of issues that may arise during sampling 

and analysis, including sample breakage 

during shipping, equipment 

malfunction during analysis. Therefore, 

we have included in this final rule 

specific missing data procedures for all 

estimation and measurements that are 

required to be performed annually or 

biannually. These provisions are the 

same as the previous missing data 

requirements in 40 CFR 98.235 as 

provided in the subpart W 2010 final 

rule. These provisions require repeat of 

the estimation or measurement as soon 

as possible, with allowance to use 

measurements made after December 31 

(in the subsequent year) as substitute 

values for the missing data in the 

reporting year. 

Comment: One commenter 

recommended a clarification of the 

missing data provisions for transmission 

storage tanks in 40 CFR 98.235(b). The 

commenter pointed out that although 

the provisions indicated that leakage for 

the entire year should be assumed, it 

does not provide a leak rate. The 

commenter suggested that the 

provisions allow for the use of a default 

rate equal to the leak rate threshold of 

3.1 standard cubic feet (scf) per hour 

defined in 40 CFR 98.234(a)(5). 

Response: The commenter is correct 

in noting that the measured emissions 

rate is critical to the calculation and that 

the proposed missing data procedures in 

40 CFR 98.235(b) could be improved for 

calculating the emissions. The EPA 

disagrees that the default value of 3.1 scf 

per hour referenced by the commenter 

should be used. The value of 3.1 scf per 

hour in 40 CFR 98.234(a)(5) is the 

minimum level of a leak that can be 

detected with the acoustic leak 

detection device. If a leak is present, the 

leak can have a much higher flow rate 

than this value. In this case, assigning 

a default leak rate may grossly 

underestimate the emissions. As noted 

previously in this preamble section, the 

EPA has included in this final rule 

specific missing data procedures for all 

estimation and measurements that are 

required to be performed annually. 

These provisions require repeat of the 

estimation or measurement as soon as 

possible, with allowance to use 

measurements made after December 31 

(e.g., in the subsequent year) as 

substitute values for the missing data in 

the reporting year. 

Comment: Some commenters 

suggested 40 CFR 98.235(e) should be 

revised to allow best engineering 

estimates for the first reporting year for 

facilities that become newly subject to 

subpart W. One commenter pointed out 

that a late year event (e.g., unexpected 

blowdown in December) could result in 

a facility becoming newly subject to the 

rule. Two commenters asserted that 6 

months was not sufficient and that a 

facility would require the use of best 

engineering estimates for the initial 

reporting year because the previously 

not subject facility would not have been 

collecting all data required for subpart 

W reporting. These commenters argued 

that these provisions should be 

available to both newly affected 

facilities and subject facilities with new 

emissions sources. Similarly, other 

commenters requested that 40 CFR 

98.235(f) be broadened for all subpart W 

emission sources (rather than just wells) 

for the scenario where there is a change 

(e.g., new source, new acquisition) at a 

subject facility, and the reporter cannot 

reasonably acquire necessary data. One 

commenter provided an example of 

adding new compression capacity online late in the year at a transmission or 

storage facility to meet demands in the 

winter months. The commenter stressed 

that it would be difficult and overly 

burdensome to require vent 

measurements from newly installed 

compressors. Another commenter 

requested that 40 CFR 28.235(f) be 

applicable to newly acquired wells 

whether or not the well was subject to 

subpart W previously. 

Response: The EPA contends that 6 

months is enough time for a newly 

subject facility to begin using the 

methods required in 40 CFR 98.233. The 

reporting rule general provisions at 40 

CFR 98.2(h) recommend that facilities 

reassess applicability (including 

revising any relevant emissions 

calculations) whenever there is any 

change that could cause a facility to 

meet the applicability requirements of 

Part 98. Therefore, facilities which 

currently operate just under the 

reporting threshold for subpart W are 

aware of what changes would likely 

cause the facility to become subject to 

subpart W and should have an 

understanding of the calculation 

reporting requirements; although 

reporters may not be aware when an 

unexpected blowdown will occur, they 

would know whether an unexpected 

blowdown could cause them to be 

subject. The reporting rule general 

provisions at 40 CFR 98.3(b)(3) also 

state that if a facility becomes subject, 

the first annual report must cover the 

month during which the change that 

caused them to exceed the applicability 

limit occurred and the remainder of the 

year. Therefore, the facility does not 


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have to report measurements on the 

preceding months when no 

measurements were conducted. We 

have clarified 40 CFR 98.235(f) to 

specify that these missing data 

procedures apply to source types that 

were acquired from another company 

and were not previously subject to 

subpart W. These sources may require 

sampling ports to be installed or other 

modifications to accommodate 

measurements required in 40 CFR 

98.233. 

The EPA agrees that the proposed 

provisions in 40 CFR 98.235(e) and (f) 

should be extended to all subpart W 

emission sources, because issues that 

make it unreasonable to perform 

measurements for new wells may also 

exist for other subpart W emission 

sources. Therefore, we are finalizing 

these provisions to more broadly apply 

to ‘‘sources’’ rather than ‘‘wells.’’ 

The EPA disagrees that the proposed 

provisions in 40 CFR 98.235(f) should 

be extended to sources acquired from 

other companies that were previously 

subject to subpart W. The reporting rule 

general provisions in 40 CFR 98.4(h) 

provide for changes in owners and 

operators and provide that such owner 

or operator shall be responsible for the 

representations, actions, inactions, and 

submissions of the designated 

representative and any alternate 

designated representative of the facility 

or supplier. Therefore, reporters are 

responsible for gathering data in a 

timely manner for acquired sources. 

Also, for sources acquired from 

companies that were previously subject 

to subpart W, any necessary sampling 

ports or other modifications would have 

previously been made to the equipment 

to accommodate measurement. Because 

facilities typically spend several months 

planning the acquisition and 

installation of new equipment, we 

anticipate that any issues can be 

addressed during this time, before the 

equipment begins to operate. 

While we are not extending the 

missing data provisions proposed in 40 

CFR 98.235(e) and (f) to facilities 

already subject to subpart W, we 

acknowledge that there are special cases 

where new compressors can be added to 

an existing facility and it may not be 

possible to perform an ‘‘as found’’ 

measurement of that new compressor 

source during the calendar year, for 

example, if the compressor is installed 

in late December. To address this issue, 

we have revised the proposed 

amendments for compressors at 40 CFR 

98.233(o)(1)(i) and (p)(1)(i) to not 

require annual measurements of 

compressors installed after annual 

compressor measurements have already 

been conducted for all existing 

compressors at the facility. If not all of 

the existing compressors at the facility 

have been measured, then there is no 

additional burden associated with 

identifying and scheduling a testing 

crew for measuring the newly installed 

compressor. However, if a facility has 

already conducted their annual 

compressor measurements, requiring 

measurement of emissions for the newly 

installed compressor would impose a 

significant additional burden and may 

not be logistically possible within the 

calendar year. Therefore, in today’s final 

rule, an annual measurement of a newly 

installed compressor would not be 

required if annual compressor 

measurements have already been 

conducted for all existing compressors 

at the facility. In this case, no missing 

data provisions are needed or are 

applicable for these newly installed 

compressors. 

Comment: Several commenters took 

issue with the provisions in 40 CFR 

98.235(h) and portions of related 

reporting requirements in 40 CFR 

98.236(bb). The commenters objected to 

reporting a description of the unique or 

unusual circumstance that led to 

missing data use and a description of 

how the owner or operator will avoid 

the use of missing data in the future. 

The commenters argued that this would 

create an unneeded burden on reporters, 

go beyond the requirements of a 

reporting program, and are an overreach 

of the EPA’s authority. Other industries 

subject to Part 98 are not required to this 

level of detail. One commenter also 

asserted that aggregation of missing data 

values is appropriate. 

Response: Reporting elements for the 

missing data provisions are necessary 

for the EPA to understand what missing 

data substitute values were used; 

however, we agree with the commenter 

that the level of detail required in the 

proposed reporting requirements could 

become burdensome, especially for 

continuously monitored parameters. We 

reviewed the reporting requirements 

associated with the use of missing data 

procedures in the general provision 40 

CFR 98.3(c)(8) and other subparts in 

Part 98. Although we disagree that the 

proposed missing data reporting 

requirements go beyond the 

requirements of a reporting program or 

is an overreach of the EPA’s authority, 

we recognize that missing data can 

occur, such as due to calibration checks 

that indicate an instrument needs to be 

recalibrated. After considering the 

proposed reporting requirements in 

light of the comments received and the 

reporting provisions in other subparts, 

we determined that revisions were 

needed to the proposed missing data 

reporting requirements. In this final 

rule, we are requiring reporting of the 

use of missing data procedures 

following the general provision 

requirements in 40 CFR 98.3(c)(8), 

except we are providing for the 

reporting of number of times missing 

data procedures were used for an 

element that is not based on 

continuously monitored parameters. 

Comment: One commenter noted that 

the missing data procedures proposed in 

40 CFR 98.235(a) should be amended to 

accommodate new AGR vents that may 

not have four previously taken samples 

available. Another commenter indicated 

that 40 CFR 98.235(d) poses a problem 

where ‘‘before’’ or ‘‘after’’ values are not 

available for a data element that requires 

measurement. The commenter asserted 

that instances where a ‘‘before’’ or 

‘‘after’’ value is not available for 

substitution require additional 

flexibility to enable compliance. The 

commenter provided, as an example, a 

situation where information from a 

third-party equipment operator, such as 

a third-party operated dehydrator, is not 

received and no data are available to 

substitute. The commenter also noted 

that there may be instances where a well 

completion in a sub-basin category/

county/well-type combination is a 

single unique well and the measurement 

equipment necessary to measure 

flowback or calculate flowback 

malfunctions. The commenter argued 

that in this case, a reporter will not have 

‘‘before’’ data to substitute. 

Response: With respect to the missing 

data procedures for AGR vents, we agree 

with the commenter that additional 

clarification is needed, particularly to 

address new AGR vents that do not have 

four previous quarterly samples. In 

considering potential clarifications for 

the missing data procedures for AGR 

vents in light of the various scenarios of 

data availability, the missing data 

procedures for this source mirrored the 

procedures proposed in 40 CFR 

98.235(d). Furthermore, we determined 

that the use of the average of a ‘‘before’’ 

and ‘‘after’’ sample would provide as 

good an estimate of the missing data as 

the average of four ‘‘before’’ samples. 

Therefore, we are generalizing the 

proposed missing data procedures in 40 

CFR 98.235(d) to apply to all 

measurements that are required to be 

performed quarterly or more frequently. 

The provisions proposed at 40 CFR 

98.235(d) include specific provisions 

that can be used to determine the 

missing value in the absence of a 

‘‘before’’ or ‘‘after’’ measurement. We 

find that the proposed procedures are 

reasonable for any data element that is 


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required to be monitored quarterly or 

more frequently. The proposed 

provisions of 40 CFR 98.235(d) are not 

meant to address measurement data that 

are required annually or biannually or 

situations such as the supply of 

information by third-party vendors. 

Reporters should know what 

information is needed for the annual 

reports. If reporters elect to use thirdparty vendors for certain services, the 

information needed for the annual 

reports may be specified in the thirdparty contract or agreement to ensure 

the necessary information is provided. 

We are not including any missing data 

provision in the final rule to allow for 

use of third-party operators that do not 

provide the required information 

needed for determining the emissions 

from dehydrators or other emissions 

sources. 

D. Summary of Final Amendments to 

Best Available Monitoring Methods 

1. Summary of Final Revisions 

In this final rule, the EPA is removing 

all prior provisions in 40 CFR 98.234(f) 

for BAMM as proposed, but we are also 

adding transitional BAMM provisions 

for the 2015 calendar year after 

considering public comments. 

Specifically, we are revising 40 CFR 

98.234(f) to provide short-term 

transitional BAMM for reporters who 

are subject to new monitoring or 

measurement requirements as part of 

these final amendments. Reporters have 

the option of using BAMM from January 

1, 2015, to March 31, 2015, for certain 

parameters that cannot reasonably be 

measured according to the monitoring 

and QA/QC requirements of 40 CFR 

98.234. Specifically, the transitional 

2015 BAMM provisions cover the 

following data: 

• Well-related measurement data that 

cannot reasonably be measured for well 

venting for liquids unloading and gas 

well venting during well completions 

and workovers with hydraulic 

fracturing, from wells not previously 

measured. 

• Reciprocating compressor 

blowdown valve, isolation valve, and 

rod packing venting from manifolded 

vents, when conducting ‘‘as found’’ 

measurements according to revised 40 

CFR 98.233(p)(4) or (p)(5). 

• Centrifugal compressor blowdown 

valve, isolation valve, and wet seal oil 

degassing venting from manifolded 

vents, when conducting ‘‘as found’’ 

measurements according to revised 40 

CFR 98.233(o)(4) or (o)(5). 

For these parameters, reporters have 

the option to use BAMM from January 

1, 2015, to March 31, 2015, without 

seeking prior EPA approval. Reporters 

will also have the opportunity to request 

an extension for the use of BAMM 

beyond March 31, 2015; those owners or 

operators must submit a request to the 

Administrator by January 31, 2015. The 

EPA is not providing transitional 

BAMM for these revised requirements 

beyond December 31, 2015. The 

provision of 3 months of automatic 

transitional BAMM will allow reporters 

to prepare for data collection while 

automatically being able to use BAMM, 

which is consistent with BAMM 

schedules in prior Part 98 rulemakings. 

This additional time for reporters to 

comply with the revised monitoring 

methods in subpart W will allow 

facilities to install the necessary 

monitoring equipment during other 

planned (or unplanned) process unit 

downtime, thus avoiding process 

interruptions. 

We are also removing and reserving 

40 CFR 98.234(g). As described in the 

preamble to the proposed rule, we 

intended to remove and reserve this 

section but the removal of this section 

was not included in the regulatory text. 

These removed provisions are specific 

to the 2011 and 2012 reporting years, 

and the removal of this provision does 

not impact the reporting requirements 

for subsequent reporting years. 

2. Summary of Comments and 

Responses 

This section summarizes the major 

comments and responses related to best 

available monitoring methods. See the 

2014 response to comment document in 

Docket Id. No. EPA–HQ–OAR–2011– 

0512 for a complete listing of all 

comments and responses. 

Comment: Three commenters 

supported the removal of BAMM for 

natural gas distribution facilities 

beginning in the 2015 calendar year. 

One commenter stated that replacing 

BAMM with explicit reporting 

requirements for petroleum and natural 

gas systems will reduce transaction 

costs, improve compliance, improve 

access to information about the oil and 

gas sector, and increase confidence in 

the rule. A second commenter believed 

that by clarifying the reporting 

emissions from natural gas distribution 

facilities, there should be no need to use 

BAMM after January 1, 2015. A third 

commenter pointed out that BAMM was 

originally a transitional tool, and other 

industry-specific subparts of Part 98 

have eliminated BAMM. The 

commenter stated that the use of BAMM 

in 2012 created difficulties in 

comparing data across facilities and 

understanding discrepancies between 

GHG and other inventories. The 

commenter supported the addition of 

expanded missing data procedures and 

compliance pathways for facilities to 

use in the future. The commenter 

suggested that if operators require more 

flexibility than the ones EPA has 

proposed, that flexibility should be 

incorporated through a rulemaking 

effort rather than BAMM requests. 

Eight commenters disagreed with the 

removal of BAMM beginning in the 

2015 calendar year. Several commenters 

stated that eliminating BAMM would 

compromise compliance of impacted 

sources, especially in instances when it 

is not feasible to obtain a required 

measurement or where a direct 

measurement may be unsafe. These 

commenters requested the ongoing 

availability of BAMM or a revision of 

the missing data procedures for those 

instances where a reporter demonstrates 

a legitimate need. 

Commenters pointed out that access 

to alternative methods is necessary for 

regulations. Some of the commenters 

pointed out that the EPA has allowed 

alternative compliance and monitoring 

methods in other regulatory programs 

(e.g., NSPS in 40 CFR part 60, National 

Emission Standards for Hazardous Air 

Pollutants (NESHAP) in 40 CFR part 63, 

and the Acid Rain Program in 40 CFR 

part 75) and urged the EPA to create a 

replacement, such as robust missing 

data provisions, for BAMM if it is 

eliminated. Other commenters stated 

that subpart W includes additional and 

more complex measurements than other 

Part 98 source categories. Some 

commenters expressed the importance 

of BAMM for sources that subsequently 

become subject to GHG reporting or 

where unpredictable future events 

occur. One commenter considered the 

flexibility of alternative methods to be 

important in the development of new 

technology and asked that the EPA 

should consider allowances in those 

cases. The commenter provided 

example scenarios in which the 

commenter stated that BAMM or an 

alternative method should be required, 

although the scenarios are not 

necessarily ‘‘unique or unusual,’’ such 

as vent lines that are unsafe to access 

and are unable to be assessed with an 

acoustic device, operating modes that 

are rarely used, and facilities where a 

late year addition of a new source 

precludes the ability to gather data. 

Another commenter explained that 

future changes in operation or 

equipment may cause the facility to 

exceed the reporting threshold or create 

circumstances in which emission points 

meet the subpart W criteria, though that 

may not be known until the facility is 

surveyed. The commenter stated that 


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there may be time to resolve the 

situation before the monitoring 

deadline, but BAMM or a robust missing 

data provision would be needed. Two 

commenters asked that BAMM be 

allowed for newly acquired wells that 

were previously reported by prior 

owners and wells that have never 

reported, as both situations require the 

same level of effort to comply. 

Three commenters requested at least a 

6-month transitional BAMM following 

the final rule. The commenters 

requested adequate time to implement 

changes following the final rule. One 

commenter stated that a transitional 

BAMM of 6 months would allow 

flexibility to reporters, provide time for 

clarifications, allow for the development 

for the required systems, and 

accommodate issues regarding 

situations beyond the facility’s control 

which require BAMM. Another 

commenter stated that developing 

processes for monitoring data or 

activities that have never before been 

subject to federal or state reporting may 

take significant time and effort. The 

commenter pointed out that until the 

final rule has been issued, reporters will 

not be able to determine what is 

required and will not know if BAMM is 

needed. Another commenter stated that 

if BAMM is not extended, small 

operators without the resources to 

quickly implement the rule would be 

unfairly disadvantaged. 

Response: The EPA has considered 

the concerns raised by commenters in 

the development of this final rule. We 

are removing the prior BAMM 

requirements in 40 CFR 98.234(f) 

because we have determined that these 

provisions, which applied broadly to 

circumstances in which data collection 

methods did not meet safety regulations, 

were technically infeasible, or were 

counter to state, local, or federal 

regulations, are no longer necessary to 

comply with the final rule. As one 

commenter noted, BAMM was 

originally included in Part 98 as a 

transitional tool, and all other industryspecific subparts of Part 98 have 

eliminated BAMM from their 

monitoring options. The revisions in 

this final rule will resolve the need for 

BAMM for the scenarios mentioned 

above for subpart W and can, therefore, 

bring this subpart into alignment with 

the monitoring provisions in other 

industry-specific subparts by removing 

the current BAMM provisions. In the 

development of this final rule, the EPA 

reviewed BAMM request submittals for 

the 2014 reporting year. In our review, 

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 most 

common concerns raised in BAMM 

requests were associated with technical 

infeasibility including concerns related 

to having to shut down a facility to 

install access ports to conduct 

compressor measurements. Other 

concerns related to compressors routed 

to a flare, manifolded lines, and 

compressor vents that were unsafe or 

inaccessible to measure. As discussed in 

Section II.B.10 of this preamble, we are 

making several revisions in this final 

rule that will allow for the testing of 

these compressor vents. First, we are 

clarifying that operators do 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 that requires a compressor to 

be taken off-line for planned or 

scheduled maintenance. These 

provisions reduce the burden on 

reporters to schedule a shutdown solely 

for the purposes of conducting 

measurements. The EPA has also 

provided the option for facilities to 

conduct continuous measurements 

using a permanent meter. Next, we are 

providing for reporters to conduct a 

single annual ‘‘as found’’ measurement 

for manifolded compressors routed to a 

common vent, in lieu of a measurement 

for each individual compressor 

manifolded to the common vent. We are 

also allowing the use of an IR camera for 

pre-screening of emissions from 

blowdown valves on compressors in 

operating mode or standby-pressurized 

mode and for isolation valves on 

compressors in not-operatingdepressurized mode. The option to use 

an IR camera to screen for emissions, in 

addition to the current allowance for 

use of an acoustic measurement device, 

eases the burden on facilities with 

inaccessible or unsafe-to-measure 

valves. Finally, for compressors routed 

to a flare, we are finalizing provisions to 

allow operators to calculate and report 

emissions with other flare emissions. In 

this case, reporters are no longer 

required to sample compressors routed 

to a flare individually. 

The EPA is also addressing the most 

common scenarios for which BAMM 

was previously requested for other 

emission sources. For example, for 

blowdown vent emissions, the EPA 

previously approved BAMM requests 

for reporting data by unique physical 

volume. In this final rule, we are 

revising the reporting of blowdown 

emissions to aggregate emissions by 

equipment type, as discussed in Section 

II.B.6 of this preamble. Similarly, for 

well venting for liquids unloading, the 

final rule allows for annualizing of 

venting data to account for situations 

where it was not feasible to gather vent 

hours or the number of unloadings from 

all controllers on January 1 or December 

31, and it provides alternatives to 

determining the shut-in pressure 

required in Equation W–8. We have 

incorporated revisions in this final rule 

to address BAMM concerns for onshore 

production tanks and well completions 

and workovers. Additionally, we are 

finalizing missing data procedures that 

add clarity and specificity in how to 

treat and report missing data, including 

continuous measurements, periodic 

measurements and activity data. These 

missing data procedures are not 

intended to replace BAMM, however, 

they provide clarity for reporters who 

may have unintentionally missed 

collecting required data. These missing 

data procedures would also apply to 

facilities for which changes in operation 

or equipment may cause the facility to 

exceed the reporting threshold or result 

in creating circumstances in which 

emission points meet the subpart W 

criteria, as well as for newly acquired 

sources that were not previously 

reported under subpart W. We also note 

that there have been previous BAMM 

requests in which facilities noted 

technical concerns including instances 

where equipment modifications or 

installations were necessary. By the 

2015 reporting year, facilities will have 

had four years to implement any 

necessary changes in order to fully 

comply with subpart W, which we have 

determined to be sufficient time to make 

any equipment modifications or 

installations. Therefore, we are not 

including BAMM provisions for these 

scenarios in this final rule. 

Regarding the comment that other 

regulatory programs allow alternative 

compliance and monitoring methods, 

the EPA acknowledges that the 

provisions of NSPS and NESHAP allow 

facilities to request alternative 

monitoring and testing methods. 

However, the NSPS and NESHAP 

provisions typically require that specific 

monitoring methods be used (e.g. EPA 

Method 18 for gas compositional 

analysis), and they do not allow 

facilities to use alternative monitoring 

and testing methods without the method 

first being approved by the EPA. The 

EPA has provided a great deal of 

flexibility in the methods allowed in 

subpart W, such as certain provisions 

that allow the use of standard methods 

published by consensus-based standard 

organizations and that allow the use of 


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industry standard practice. Given the 

flexibility in the methods allowed under 

Part 98, we do not agree with the 

commenters. 

Although we are removing the current 

BAMM provisions of 40 CFR 98.234(f), 

the final rule introduces new short-term 

transitional BAMM provisions for 

certain parameters for the 2015 calendar 

year. The EPA agrees with commenters 

that some facilities may need to obtain 

the necessary equipment to conduct 

measurements as required under the 

revised calculation methods in this final 

rule. Thus, under the final rule, 

reporters have the option of using 

BAMM for certain parameters that 

cannot be reasonably measured 

according to the monitoring and QA/QC 

requirements of 40 CFR 98.234. For 

example, we are revising the emission 

estimation methods for well 

completions and workovers from wells 

with hydraulic fracturing to separate 

reporting by well completions and 

workovers and by the sub-basin and 

well-type combination. In some cases, 

we expect reporters will be required to 

measure existing wells of a well-type 

combination for which they have not 

previously reported separately. In this 

case, reporters have the option to use 

BAMM for well-related data (i.e., initial 

and average flowback rates for 

Calculation Method 1 or pressures 

upstream and downstream of the choke 

for Calculation Method 2). Other 

situations where the final rule provides 

an option to use BAMM in the 2015 

calendar year are for determining vented 

gas flow when using Calculation 

Method 1 to estimate emissions from 

liquids unloading, and for determining 

vented emissions from compressor 

sources that are manifolded. 

In some cases, although we are 

revising emissions calculation methods 

in the final rule, we are not providing 

the BAMM option because the 

underlying measurement methods have 

not changed. For example, although we 

have separated the calculation of 

emissions from completions and 

workovers from wells without hydraulic 

fracturing in 40 CFR 98.233(h), reporters 

are still collecting the same well data 

and measurements. We are not 

providing BAMM in this case or in 

similar cases where reporters would not 

be required to change their data 

collection methods. 

We are not providing the BAMM 

option for parameters in revised 

calculation methods where the rule 

already provides alternatives to direct 

measurements. For example, the final 

rule requires facilities in the onshore 

natural gas transmission compression, 

underground natural gas storage, LNG 

storage, and LNG import export industry 

segments to report emissions from flares 

based on using the calculation methods 

for flare stacks. BAMM is not needed in 

this case because 40 CFR 98.233(n)(1) 

specifies that flare gas flow may be 

estimated using engineering 

calculations based on process 

knowledge, company records, and best 

available data. Similarly, 40 CFR 

98.233(n)(2) specifies that as an 

alternative to using a continuous gas 

composition analyzer on the flare gas, a 

reporter in the four industry segments 

now required to report flare emissions 

may use a representative composition 

determined by engineering calculation 

based on process knowledge and best 

available data. The BAMM option also 

is not being provided for activity data 

such as completion or workover counts 

and venting or operating time because 

the final rule does not specify 

monitoring equipment that must be 

used for measuring these parameters. 

The final rule allows reporters to use 

BAMM for the specified parameters 

during the January 1, 2015 to March 31, 

2015 time period without seeking prior 

EPA approval. By automatically 

allowing BAMM until March 31, 2015, 

this schedule allows additional time 

following the publication of the final 

rule for reporters to prepare for data 

collection and install the necessary 

monitoring equipment. The final rule 

also provides for reporters the option to 

request an extension for the use of 

BAMM beyond March 31, 2015, but no 

further than December 31, 2015. 

Reporters who request an extension 

must submit a request to the 

Administrator by January 31, 2015, and 

demonstrate to the Administrator’s 

satisfaction that it is not reasonably 

feasible to acquire, install, and operate 

a required piece of monitoring 

equipment by April 1, 2015, to receive 

approval to use BAMM beyond March 

31, 2015. In these cases, the 

Administrator will only approve BAMM 

for the parameters specified in Section 

II.D.1 of this preamble. We anticipate 

that the number of BAMM requests 

approved for the 2015 calendar year will 

be limited and will not greatly impact 

the quality of the data collected in 2015. 

E. Summary of Final Additions of New 

Data Elements and Revisions to 

Reporting Requirements 

1. Summary of Final Revisions 

We are finalizing the addition of 

several data elements to 40 CFR 98.236, 

with revisions from the proposed rule 

based on review of comments and other 

considerations. Although the EPA 

received comments objecting to the 

proposed addition of these data 

elements, these new data elements are 

based on data that are already collected 

by the reporter or are readily available 

to the reporter. The reporting of these 

data elements will improve the quality 

of the data reported, improve the 

verification of reported emissions, and 

reduce the amount of correspondence 

with reporters that is associated with 

follow-up and revision of annual 

reports. 

After proposal, we determined that 

some proposed data elements could be 

removed to lessen reporter burden. For 

offshore production facilities, the final 

rule requires reporting of the total 

quantity of oil handled at the offshore 

platform, which includes the quantity 

from blended oil/condensate streams; 

this reporting element replaces the 

proposed requirements to report the 

amount of oil and the amount of 

condensate separately. Additionally, we 

are not finalizing the proposed 

requirements to report the model name, 

description, and installation year for 

each compressor. 

As a result of comments received on 

the proposed rule, we are adding 

requirements to report two data 

elements for centrifugal and 

reciprocating compressors. Affected 

facilities with centrifugal or 

reciprocating compressors will be 

required to indicate whether the 

measured volume of flow from the 

compressor includes blowdown 

emissions, according to 40 CFR 

98.236(o)(4)(iii) and 40 CFR 98.236 

(p)(4)(iii), respectively. 

2. Summary of Comments and 

Responses 

This section summarizes the major 

comments and responses related to the 

addition of new reporting requirements 

in 40 CFR 98.236(aa). See the 2014 

response to comment document in 

Docket Id. No. EPA–HQ–OAR–2011– 

0512 for a complete listing of all 

comments and responses. 

Comment: One commenter questioned 

the proposal’s requirements to report 

information that does not address 

emissions but instead requires ancillary 

information such as compressor ratings. 

The commenter considered these new 

measurement and reporting 

requirements to go beyond the authority 

of the EPA under CAA Sections 114 and 

208, making the changes arbitrary and 

capricious if finalized. The commenter 

considered the proposed reporting 

requirement changes to be an overreach 

for an emissions reporting program and 

points out that 40 CFR 98.236(aa) in 

particular appears to be using Part 98 as 

a vehicle to construct detailed profile of 


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the oil and gas production sector. The 

commenter considered the proposed 

changes to unnecessarily expand the 

measurements and reporting 

requirements from the existing Part 98 

and points out examples. 

Multiple commenters provided 

examples of data elements that they 

stated are not within the scope of Part 

98 because they are not directly related 

to emissions quantification or are 

redundant: For transmission storage 

tank vent stack, whether scrubber dump 

leakage is occurring for the underground 

storage vent—§ 98.236(k)(l)(iii); year 

compressor was installed— 

§ 98.236(p)(1)(xiv); compressor model 

name and description— 

§ 98.236(p)(1)(xv); date of last rod 

packing—§ 98.236(p)(1)(xvi); average 

time surveyed components were found 

leaking and operational— 

§ 98.236(q)(2)(iii); average upstream 

pipeline pressure, psig— 

§ 98.236(aa)(4)(iv); average downstream 

pipeline pressure, psig— 

§ 98.236(aa)(4)(v); quantity of gas 

injected into storage—§ 98.236(aa)(5)(i); 

quantity of gas withdrawn from 

storage—§ 98.236(aa)(5)(ii); number of 

compressors—§ 98.236(aa)(4)(ii); total 

compressor power rating for all 

compressors combined, hp— 

§ 98.236(aa)(4)(iii); and total storage 

capacity for underground natural gas 

storage facilities—§ 98.236(aa)(5)(iii). 

One commenter stated that the EPA 

should explain or justify the need for 

addition of these data elements. 

Multiple commenters stated that the 

new reporting requirements are not 

relevant for quantifying emissions and 

developing this information in order to 

report represents a substantial burden. 

Response: The EPA disagrees with 

commenters that the proposed data 

elements are beyond the authority of the 

EPA under CAA section 114. CAA 

section 114 authorizes the EPA to gather 

the information under this rule. 

Specifically, section 114 provides for 

the gathering of information from direct 

sources of GHG emissions, as long as 

that information is for purposes of 

carrying out any provision of the CAA. 

CAA section 208 applies to mobile 

sources, which are not covered by 

subpart W. 

The additional reporting requirements 

included in this final rule provide 

production, capacity, and operational 

information for sources subject to 

subpart W and are similar to the data 

collected under other subparts of Part 

98. These data elements are useful for 

the verification of existing data. For 

example, production, capacity, or 

operational information may be used to 

normalize the data collected and 

adequately characterize emissions 

sources. Therefore, the EPA is finalizing 

these reporting requirements as 

proposed, with minor clarifications. 

Further information on the final changes 

to the reporting section may be found in 

the memorandum, ‘‘Final Revisions to 

the Subpart W Reporting Requirements 

in the ‘‘Greenhouse Gas Reporting Rule: 

2014 Revisions and Confidentiality 

Determinations for Petroleum and 

Natural Gas Systems; Final Rule’’ in 

Docket Id. No. EPA–HQ–OAR–2011– 

0512. 

III. Confidentiality Determinations 

A. Summary of Final Confidentiality 

Determinations for New or Revised 

Subpart W Data Elements 

In the proposed rule, we assigned 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. For 

data elements the EPA assigned to a 

direct emitter category with a 

categorical determination, the EPA 

proposed that the categorical 

determination for the category be 

applied to the proposed new or revised 

data element. 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 

proposed 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. 

We also proposed individual 

confidentiality determinations for 11 

new or substantially revised data 

elements without making a data 

category assignment and we proposed to 

revise the confidentiality determination 

for one existing subpart W data element. 

Refer to the preamble to the proposed 

rule (79 FR 13394, March 10, 2014) for 

additional information regarding the 

proposed confidentiality 

determinations. 

With consideration of the data 

provided by commenters, the EPA is 

finalizing the confidentiality 

determinations as proposed for all but 7 

of the new and substantially revised 

data elements that were proposed. 

Specifically, the EPA is finalizing the 

proposed decision to require each of the 

new data elements and the one existing 

data element for which we revised the 

confidentiality determination be 

designated as ‘‘not CBI’’, with the 

exception of seven new data elements 

for which we have subsequently 

identified potential confidentiality 

concerns, as discussed in this section. 

The seven data elements with revised 

confidentiality determinations apply to 

onshore natural gas plants and natural 

gas transmission facilities. 

For onshore natural gas plants, the 

EPA has revised the determination for 

the following four data elements: The 

quantity of natural gas received at the 

gas processing plant in the calendar year 

(reported under 40 CFR 98.236(aa)(3)(i)), 

the quantity of processed (residue) gas 

leaving the gas processing plant 

(reported under 40 CFR 

98.236(aa)(3)(ii)), the quantity of natural 

gas liquids (NGL) (bulk and 

fractionated) received (reported under 

40 CFR 98.236(aa)(3)(iii)), and the 

quantity of NGL (bulk and fractionated) 

leaving the plant (reported under 40 

CFR 98.236(aa)(3)(iv)). In the proposal, 

we indicated that we designated the 

annual quantity of natural gas received 

at a gas plant and the annual quantity 

of residue gas leaving a gas plant to be 

‘‘not CBI’’ because the average annual 

flow and plant utilization rate are 

published on the Energy Information 

Administration’s (EIA’s) Web site and 

are already in the public domain. 

However, upon reexamination we 

determined that reporting to EIA of the 

amount of natural gas received is less 

frequent than that required under 

subpart W and we have not identified 

any reliable public sources of the 

quantity of residue gas produced. Thus, 

we have decided to maintain the annual 

quantity of natural gas received at gas 

plants and the annual quantity of 

processed (residue) gas leaving gas 

plants as confidential. 

We indicated in the proposal that the 

two NGL data elements were aggregated 

values for all NGL received and all NGL 

supplied by a natural gas processing 

plant. We also explained that this 

information would not cause 

competitive harm to reporters because 

the data for individual NGL products 

(which would be likely to cause 

competitive harm) would not be 

disclosed. While most plants receive 

and supply several different NGL 

products, we have identified a few 

plants that receive and/or supply only 

one NGL product. For example, some 

plants remove only ethane from the 

natural gas received. For this subset of 

plants, the quantity to be reported under 

subpart W is identical to the quantity 

reported under subpart NN, which the 

EPA determined to be CBI (see 76 FR 

30782, May 26, 2011). Thus, the EPA 

has decided not to make a 

confidentiality determination for 40 

CFR 98.236(aa)(3)(iii) and (aa)(3)(iv). 


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The confidentiality status of these data 

elements will be evaluated on a case-bycase basis, in accordance with the 

existing CBI regulations in 40 CFR part 

2, subpart B, upon receipt of a public 

request for these data elements. 

For the natural gas transmission 

sector, the EPA has revised the 

confidentiality determination in this 

action for three data elements: The 

quantity of gas transported through a 

compressor station (reported under 40 

CFR 98.236(aa)(4)(i)) and the average 

upstream and downstream pressures 

(reported under 40 CFR 98.236(aa)(4)(iv) 

and (v), respectively). We proposed that 

these data elements be designated as 

‘‘not CBI.’’ We noted that the natural gas 

transmission sector was heavily 

regulated by the Federal Energy 

Regulatory Commission (FERC) and 

state commissions due to a lack of 

competition between companies. We 

further noted that FERC controls 

pricing, sets rules for business practices, 

and is responsible for approving the 

location, construction, and operations of 

companies operating in this sector. 

However, we received comments from 

this industry sector noting that FERC 

Order 636 had introduced greater 

competition to this sector and that some 

companies charge customers less than 

the FERC approved rates because of 

competitive market pressures. The three 

data elements identified above would 

provide information on the quantity of 

gas transported by a specific pipeline. 

This information may potentially cause 

competitive harm to some pipeline 

companies operating in more 

competitive market areas. Since the 

determination would depend on the 

particular market conditions for each 

company, the EPA was not able to make 

a determination for these data elements 

that would apply for all reporters. Thus, 

the EPA has decided not to make a 

confidentiality determination for 40 

CFR 98.236(aa)(4)(i), (iv) and (v). The 

confidentiality status of these data 

elements will be evaluated on a case-bycase basis, in accordance with the 

existing CBI regulations in 40 CFR part 

2, subpart B, upon receipt of a public 

request for these data elements. 

The EPA received several comments 

questioning the proposed determination 

that several new or revised data 

elements should be treated as nonconfidential. Specifically, we received 

comments requesting that the EPA 

classify certain data elements associated 

with exploratory wells (delineation and 

wildcat wells) as CBI for a period of at 

least 24 months from the start of 

exploration. These comments and the 

EPA’s responses are summarized in 

Section III.B of this preamble. Based on 

consideration of these comments and 

consistent with the EPA’s previous 

decisions related to exploratory wells 

under Part 98 (79 FR 63750, October 24, 

2014), the EPA is revising the final rule 

to provide reporters with the option to 

delay reporting of 12 data elements for 

two reporting years in situations where 

exploratory wells are the only wells in 

a sub-basin. For a given sub-basin, in 

situations where wildcat wells and/or 

delineation wells are the only wells in 

a sub-basin that can be used for the 

required measurement, the following 

data elements associated with the 

delineation or wildcat well may be 

delayed for two reporting years: (1) 

Cumulative flowback time for each subbasin (40 CFR 98.236(g)(5)(i)); (2) 

measured flowback rate for each subbasin (40 CFR 98.236(g)(5)(ii)); (3) 

average daily gas production rate for all 

completions without hydraulic 

fracturing in the sub-basin without 

flaring (40 CFR 98.236(h)(1)(iv)); (4) 

average daily gas production rate for all 

completions without hydraulic 

fracturing in the sub-basin with flaring 

(40 CFR 98.236(h)(2)(iv)); (5) if using 

Calculation Method 1 or 2 for 

atmospheric storage tanks, the total 

annual gas-liquid separator oil volume 

that is sent to atmospheric storage tanks 

in the sub-basin, in barrels; (6) if using 

Calculation Method 3 for atmospheric 

storage tanks, the total annual oil 

throughput that is sent to atmospheric 

tanks in the basin (40 CFR 

98.236(j)(2)(i)(A)); (7) if oil well testing 

is not performed where emissions are 

not vented to a flare, the average flow 

rate in barrels of oil per day for well(s) 

tested (40 CFR 98.236(l)(1)(iv); (8) 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 (40 CFR 

98.236(l)(2)(iv)); (9) if gas well testing is 

performed where emissions are not 

vented to a flare, average annual 

production rate in actual cubic feet per 

day for well(s) tested (40 CFR 

98.236(l)(3)(iii)); (10) if gas well testing 

is performed where emissions are 

vented to a flare, average annual 

production rate in actual cubic feet per 

day for well(s) tested. (40 CFR 

98.236(l)(4)(iii)); (11) volume of oil 

produced in the calendar year during 

the time periods in which associated gas 

was vented or flared (40 CFR 

98.236(m)(5)); and (12) total volume of 

associated gas sent to sales in the 

calendar year during time periods in 

which associated gas was vented or 

flared (40 CFR 98.236(m)(6))). 

Six of the 12 data elements for which 

reporting may be delayed by 2 years are 

inputs to emission equations and the 

EPA provided the same option in the 

EPA’s previous decisions related to 

exploratory wells under Part 98 (79 FR 

63750, October 24, 2014). Five of the 12 

data elements are inputs only when the 

applicable data are related to a single 

well (40 CFR 98.236(g)(5)(i), (h)(1)(iv), 

(h)(2)(iv), (m)(5), and (m)(6)), and one 

data element is never an input (40 CFR 

98.236(j)(2)(i)(A)). The EPA decided to 

treat all early disclosure concerns 

related to exploratory wells consistently 

throughout subpart W by providing the 

option to delay reporting by 2 years to 

all 12 data elements. For the six data 

elements that are not always inputs, the 

finalized confidentiality determinations 

of ‘‘not CBI’’ apply in situations where 

the data elements are not an input to an 

equation. Specifically, the ‘‘not CBI’’ 

determination applies to all situations 

that involve multiple non-exploratory 

wells or a mix of exploratory and nonexploratory wells, and the ‘‘not CBI’’ 

determinations also will apply to data 

elements related to multiple exploratory 

wells once the data are reported to the 

EPA following the 2 year delay. For the 

situations when the data elements are 

used as inputs to equations, the EPA is 

assigning them to the ‘‘Inputs to 

Emission Equations’’ data category and 

is not making confidentiality 

determinations for these data. 

In response to public comments, the 

EPA has added eight new data elements 

related to compressors as reporting 

requirements and has assigned them to 

the ‘‘Unit/Process ‘Static’ Characteristics 

That Are Not Inputs to Emission 

Equations’’ data category. Two of the 

new data elements require reporters to 

indicate whether compressor blowdown 

emissions are included in the measured 

volume of flow from compressor sources 

that are monitored continuously. Four 

of the new data elements require 

reporters to indicate whether 

measurements for manifolded groups of 

compressor sources are located prior to 

or after comingling with noncompressor emissions. These six data 

elements apply to both centrifugal 

compressors and reciprocating 

compressors, and they are located in 40 

CFR 98.236(o)(3)(i)(F), (o)(4)(iii), 

(o)(4)(iv), (p)(3)(i)(F), (p)(4)(iii), and 

(p)(4)(iv). For each centrifugal and 

reciprocating compressor equipped with 

blind flanges, the other two new data 

elements require reporters to provide 

the dates when the blind flanges were 

in place, and these elements are located 

in 40 CFR 98.236(o)(1)(x) and (p)(1)(xii). 

All eight of the new data elements are 

the same type of data as other data 

elements included in this category in 


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the March 2014 proposal such as the 

data element that requires reporters to 

indicate whether any compressor source 

emissions are routed to a flare. Like 

other data elements in this category, the 

new data elements do not vary with 

time or with the operation of the 

compressor. Additionally, the new data 

elements describe only an aspect of the 

compressor design and emissions 

handling technique that reveals no 

sensitive information that would be 

likely to cause substantial harm to any 

type of natural gas facility. The March 

2014 proposal addressed the same type 

of data elements. We conclude that it is 

appropriate to assign the data elements 

to this data category and finalize our 

determination that these data elements 

are ‘‘not CBI’’ in this action. 

The EPA has determined that we 

inadvertently omitted proposing 

confidentiality determinations for 12 

new data reporting elements. The 

measured scrubber dump valve leak rate 

vented directly to atmosphere (40 CFR 

98.236(k)(2)(ii)), the measured scrubber 

dump valve leak rate vented to flare (40 

CFR 98.236(k)(3)(ii)), and the annual 

CO2 and CH4 emissions from above 

grade metering-regulating stations that 

are not above grade transmissiondistribution transfer stations (40 CFR 

98.236(r)(2)(v)(A) and (r)(2)(v)(B), 

respectively) are data representing 

emissions to the atmosphere. The March 

2014 proposal addressed numerous 

similar elements and assigned them to 

the ‘‘Emissions’’ data category, which 

has a categorical confidentiality 

determination of ‘‘not CBI.’’ We 

conclude that it is appropriate to assign 

the four previously omitted data 

elements to the ‘‘Emissions’’ data 

category and finalize our determination 

that these data elements are ‘‘not CBI’’ 

in this action. 

Five of the new data elements for 

which we did not propose 

confidentiality determinations in the 

proposed rule are similar to data 

elements that were assigned to the 

‘‘Unit/Process Operating Characteristics 

That are Not Inputs to Emission 

Equations’’ data category. For example, 

the type of control device for emissions 

from glycol dehydrators with an annual 

average daily natural gas throughput 

less than 0.4 MMscf per day (40 CFR 

98.236(e)(2)(iii)) is the same as the data 

element in 40 CFR 98.236(e)(3)(i) for 

reporting the type of control device used 

to control emissions from dehydrators 

that use desiccant. The number of 

atmospheric tanks in the sub-basin that 

did not control emissions with flares (40 

CFR 98.236(j)(2)(ii)(B)) and the number 

of atmospheric tanks in the sub-basin 

that controlled emissions with flares (40 

CFR 98.236(j)(2)(iii)(B)) are comparable 

to the data elements in 40 CFR 

98.236(e)(2) and (e)(3) for the counts of 

dehydrators that vent to atmosphere, 

flare, vapor recovery, or other types of 

control devices. The duration of time 

that a scrubber dump valve leak 

occurred (40 CFR 98.236(k)(2)(iii)) and 

the duration of time that flaring of a 

scrubber dump valve leak occurred (40 

CFR 98.236(k)(3)(iii)) are comparable to 

the data element in 40 CFR 

98.236(j)(3)(ii) for the total time that 

dump valves on gas-liquid separators 

did not close properly. Furthermore, as 

we noted in the discussion of the 

confidentiality determination for 40 

CFR 98.236(j)(3)(ii) in the preamble to 

the proposed rule, because 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, public 

disclosure of such information would 

not be likely to cause substantial 

competitive harm to reporters. The 

finalized confidentiality determinations 

for all of the data elements that are 

comparable to the five data elements 

that were inadvertently omitted from 

the analysis at proposal are ‘‘not CBI.’’ 

We conclude that it is appropriate to 

assign the five previously omitted data 

elements to the ‘‘Unit/Process Operating 

Characteristics That are Not Inputs to 

Emission Equations’’ data category and 

finalize our determination that these 

data elements are ‘‘not CBI’’ in this 

action. 

Three of the new data elements for 

which we did not propose 

confidentiality determinations in the 

proposed rule are identical to other data 

elements that were included in the 

analysis at proposal. The centrifugal 

compressor name or ID (40 CFR 

98.236(o)(2)(i)(A)), the centrifugal 

compressor source (40 CFR 

98.236(o)(2)(i)(B)), and the unique name 

or ID for the leak or vent (40 CFR 

98.236(o)(2)(i)(C)) are identical to the 

corresponding data elements for 

reciprocating compressors in 40 CFR 

98.236(p)(2)(i)(A), (p)(2)(i)(B), and 

(p)(2)(i)(C). These data elements for 

reciprocating compressors were 

assigned to the ‘‘Facility and Unit 

Identifier Information’’ data category, 

and the final confidentiality 

determination for these data elements is 

‘‘not CBI.’’ We conclude that it is 

appropriate to assign the three 

previously omitted data elements to the 

‘‘Facility and Unit Identifier 

Information’’ data category and finalize 

our determination that these data 

elements are ‘‘not CBI’’ in this action. 

As discussed in Section II.B.5 of this 

preamble, the final rule clarifies the 

reporting requirements for the time 

variable used in Equation W–10A (40 

CFR 98.236(g)(5)(i)). Specifically, the 

final rule requires reporting of both 

cumulative gas flowback time values 

used in the revised Equation W–10A 

(‘‘Tp,i’’ and ‘‘Tp,s’’), whereas the 

proposed rule inadvertently retained the 

current reporting of the single value that 

is used in Equation W–10A from the 

subpart W 2010 final rule. At proposal, 

the data element was determined to be 

an input. However, it is an input only 

when one completion or workover has 

been conducted in a particular subbasin and well type combination 

category. When data for completions or 

workovers for multiple wells are 

included in the calculation, it is a data 

element for which a confidentiality 

determination is required. The final data 

elements in 40 CFR 98.236(g)(5)(i) are 

similar to the data element in 40 CFR 

98.236(h)(2)(iii) for reporting the total 

number of hours of venting during 

completions without hydraulic 

fracturing. We assigned the data element 

in 40 CFR 98.236(h)(2)(iii) to the ‘‘Unit/ 

Process Operating Characteristics That 

are Not Inputs to Emission Equations’’ 

data category and proposed a 

confidentiality determination of ‘‘not 

CBI’’ because the cumulative venting 

time for multiple completions or 

workovers would not disclose 

information on individual wells and is 

not likely to cause substantial 

competitive harm. For the same reasons, 

we conclude that it is appropriate to 

assign the data elements in 40 CFR 

98.236(g)(5)(i), in the cases where they 

are not inputs to equations (i.e., when 

data for more than one well are used in 

Equation W–10A), to the ‘‘Unit/Process 

Operating Characteristics That are Not 

Inputs to Emission Equations’’ data 

category and finalize our determination 

that these data elements are ‘‘not CBI’’ 

in this action. In the situations where 

these data elements are used as an input 

to an equation, we are assigning them to 

the ‘‘Inputs to Emission Equations’’ data 

category and not making a 

confidentiality determination for these 

data. 

In the final rule, the EPA has also 

edited for clarity numerous reporting 

elements based on public comments. 

Portions of 40 CFR 98.236 also were 

rearranged to improve clarity in the 

final rule. These edits did not change 

the type of data to be reported and, thus, 

the confidentiality determinations do 

not need to be reassessed. All of the 

changes are documented in the 

Memorandum ‘‘Final Revisions to the 

Subpart W Reporting Requirements in 

the ‘Greenhouse Gas Reporting Rule: 


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2See the EIA Natural Gas Annual Respondent 

Query System at http://www.eia.gov/cfapps/ngqs/

ngqs.cfm?f_report=RP7. 

2014 Revisions and Confidentiality 

Determinations for Petroleum and 

Natural Gas Systems; Final Rule’ ’’ in 

Docket Id. No. EPA–HQ–OAR–2011– 

0512. 

B. Summary of Comments and 

Responses 

This section summarizes the major 

comments and responses related to the 

proposed categorical assignments and 

confidentiality determinations. See the 

2014 response to comment document in 

Docket Id. No. EPA–HQ–OAR–2011– 

0512 for a complete listing of all 

comments and responses. See the 

memorandum ‘‘Final Data Category 

Assignments and Confidentiality 

Determinations for Data Elements 

(excluding inputs to emission 

equations) in the ‘Greenhouse Gas 

Reporting Rule: 2014 Revisions and 

Confidentiality Determinations for 

Petroleum and Natural Gas Systems; 

Final Rule’ ’’ in Docket Id. No. EPA– 

HQ–OAR–2011–0512 for a complete 

listing of final data category assignments 

and confidentiality determinations, and 

a discussion of changes since proposal. 

Comment: Two commenters disagreed 

with the EPA’s statement that the 

natural gas transmission industry is 

‘‘inherently uncompetitive’’ or ‘‘less 

competitive than other industries.’’ One 

commenter pointed out that although 

interstate natural gas pipeline rates are 

established on a cost-of-service basis by 

FERC, the FERC-issued Order 636 has 

fostered a competitive culture by 

unbundling pipeline merchant and 

transportation services. The commenter 

argued that pipelines face multiple 

forms of competition which affect 

service offerings and prices, including: 

Competition with alternative fuels, 

competition between gas supply basins, 

and competition among pipelines. The 

commenter argued that pipelines 

sometimes charge customers less than 

the FERC-approved maximum tariff rate 

due to competitive market conditions. 

Another commenter stated that they 

operate in markets in which other 

natural gas pipeline companies 

regularly compete for pipeline business 

through discounting and other 

competitive market practices. Both 

commenters stated that the release of 

specific operational data could result in 

substantial harm to a pipeline operator’s 

competitive position. 

Response: The EPA agrees with 

commenters that Order 636 did increase 

competition. We note, however, that 

many of the data elements are already 

publicly available from other sources. 

The number of compressors (reported 

under 40 CFR 98.236(aa)(4)(ii)) and the 

total compressor power rating (reported 

under 40 CFR 98.236(aa)(4)(iii)) are also 

available to the public through state and 

federal construction and operating 

permits and FERC. The quantity of gas 

injected into underground storage 

(reported under 40 CFR 98.236(aa)(5)(i)), 

the quantity of gas withdrawn from 

underground storage (reported under 40 

CFR 98.236(aa)(5)(ii)), the quantity of 

LNG injected into storage (reported 

under 40 CFR 98.236(aa)(8)(ii)), the 

quantity of LNG withdrawn from storage 

(reported under 40 CFR 98.236(aa)(8)(ii), 

the total underground storage capacity 

(reported under 40 CFR 

98.236(aa)(5)(iii)) and the total LNG 

storage capacity (reported under 40 CFR 

98.236(aa)(8)(iii)) are reported annually 

to the EIA on forms EIA–176 (Annual 

Report of Natural and Supplemental Gas 

Supply) and EIA–191 (Monthly 

Underground Gas Storage Report). The 

EIA publishes this data on their Web 

site.2 Since these data elements are 

already in the public domain, they are 

not entitled to confidential treatment 

under 40 CFR 2.208. We are therefore 

finalizing as proposed the determination 

that these data elements are ‘‘not CBI.’’ 

We have not identified any reliable 

public sources for the following data 

elements: The quantity of gas 

transported through a compressor 

station (reported under 40 CFR 

98.236(aa)(4)(i)) and the average 

upstream and downstream pressures 

(reported under 40 CFR 98.236(aa)(4)(iv) 

and (v), respectively). These data 

elements provide information on the 

quantity of gas transported by a specific 

pipeline and disclosure of this data may 

potentially cause competitive harm to 

some pipeline companies operating in 

more competitive market areas. Since 

the determination would depend on the 

particular market conditions for each 

company, the EPA was not able to make 

a determination for these data elements 

that would apply for all reporters. Thus, 

the EPA has decided not to make a 

confidentiality determination for 40 

CFR 98.236(aa)(4)(i), (iv) and (v). The 

confidentiality status of these data 

elements will be evaluated on a case-bycase basis, in accordance with the 

existing CBI regulations in 40 CFR part 

2, subpart B, upon receipt of a public 

request for these data elements. 

Comment: One commenter supported 

classifying as CBI, information in 40 

CFR 98.236(d)(1)(iv) on whether any 

CO2 emissions from the AGR unit are 

recovered and transferred outside the 

facility. The commenter stated that the 

data element is directly linked to 

multiple data elements associated with 

industrial CO2 production plants and 

import/exporter of CO2 that have been 

previously determined to be CBI under 

subpart PP (Suppliers of Carbon 

Dioxide). 

Response: The EPA has reviewed the 

data element referenced by the 

commenter. The EPA notes that 40 CFR 

98.236(d)(1)(iv) includes two data 

elements. First, reporters must indicate 

whether CO2 emissions are recovered 

from the AGR units and transferred 

offsite (as proposed). Second, reporters 

must supply the quantity of CO2

emissions that are collected and 

transferred offsite. The second data 

element in the proposed rule 

inadvertently removed text stating that 

reporters should report this information 

under subpart PP. It would be 

redundant to report the quantity of CO2

emissions that are collected and 

transferred offsite under both subpart PP 

and subpart W. In this final rule, we are 

providing that if any CO2 emissions 

from the AGR unit were recovered and 

transferred outside the facility, then the 

facility must report the annual quantity 

of CO2 that was recovered and 

transferred outside the facility under 

subpart PP. 

Thus, the proposed rule only 

included one new data element 

(‘‘Whether any CO2 emissions are 

recovered and transferred outside the 

facility’’) for which a confidentiality 

determination was proposed. The EPA 

has determined that the data element is 

not the same data element as reported 

under subpart PP. Therefore, we are 

finalizing as proposed our 

determination that the data element is 

‘‘not CBI.’’ The EPA disagrees with the 

commenters’ assertion that the proposed 

determination for ‘‘whether CO2

emissions are recovered from the AGR 

units and transferred offsite’’ is 

inconsistent with the determination 

made for data elements reported under 

subpart PP. None of the data elements 

reported under subpart PP are similar to 

this data element. The determinations 

for subpart PP were made with regard to 

quantities of CO2 from production wells 

and to the quantities of CO2 collected 

and transferred offsite from industrial 

production facilities. Furthermore, this 

data element reveals only that the 

facility has an AGR unit (currently 

publicly available in permits) and that 

CO2 is collected as a byproduct and 

transferred offsite. Since the CO2 is only 

a by-product of the process, the EPA has 

determined that disclosure of this 

information would not cause substantial 

competitive harm. 

Comment: Five commenters requested 

that the EPA review confidentiality 


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determinations for consistency with 

data elements that are found in both 

subpart NN and subpart W. Several of 

these commenters provided citations in 

subpart NN for data elements that have 

been given a determination of CBI 

which also appear in 40 CFR 

98.236(aa)(3)(i) through 40 CFR 

98.236(aa)(3)(vii) in the proposed rule 

with a ‘‘non-CBI’’ determination. 

Response: The EPA has reviewed the 

confidentiality determinations for 

subparts W and NN and has determined 

that two data elements in subpart NN 

have confidentiality determinations that 

are inconsistent with those proposed for 

subpart W. The first is the quantity of 

natural gas withdrawn from storage in a 

calendar year (reported under 40 CFR 

98.236(aa)(5)(i)), which was proposed to 

be ‘‘not CBI’’ for all underground storage 

operators. Under subpart NN, local 

distribution companies report the 

volume of natural gas withdrawn from 

on-system storage and the annual 

volume of LNG withdrawn from storage 

and vaporized for delivery on the 

distribution system (40 CFR 

98.406(b)(3)), for which we previously 

made a determination of CBI. However, 

review of publicly available data 

undertaken during the preparation of 

the proposal for this action found that 

gas withdrawals from underground 

storage are reported to the EIA on form 

EIA–176 (Annual Report of Natural And 

Supplemental Gas Supply and 

Disposition). As we noted in the 

proposal, the EIA considers all 

information submitted on EIA–176 to be 

non-proprietary information and 

publishes the quantity of natural gas 

withdrawn from storage on their Web 

site. Since the quantity of natural gas 

withdrawn from storage is publicly 

available, this data element is not 

entitled to confidential treatment under 

the provisions in 40 CFR 2.208. The 

EPA notes that this final rule relates to 

calculation and reporting requirements 

for subpart W and not subpart NN, and 

therefore inconsistencies with respect to 

subpart NN are not addressed by this 

rule. 

The second data element is the 

quantity of gas received at a gas 

processing plant (reported by natural 

gas processing plants under 40 CFR 

98.236(aa)(3)(i)), which we proposed as 

‘‘not CBI.’’ Plants that fractionate 

natural gas into its constituent NGL are 

required to report the volume of natural 

gas received by their plant for 

processing (see 40 CFR 40 CFR 

98.406(a)(3)). In a previous notice, we 

determined that the data element 

required by 40 CFR 98.406(a)(3) was 

entitled to confidential treatment under 

40 CFR 2.208 because it provided 

information regarding raw material 

consumption that we believed was not 

already in the public domain and could 

potentially cause competitive harm if 

disclosed. During the preparation of the 

proposal for this action, the EPA found 

that detailed plant-level information is 

reported by all natural gas plants to the 

EIA on Schedule A of form EIA–757 

(Natural Gas Processing Plant Survey) 

once every 3 years. The information 

reported includes the annual average 

natural gas flow in million cubic feet 

per day entering a natural gas plant 

(including plants that also fractionate 

natural gas). EIA considers the 

information on annual average natural 

gas flows entering a plant to be nonproprietary information that it makes 

available to the public. However, 

because the information reported to EIA 

is on a different frequency than that 

required under subpart W, we have 

determined that the quantity of natural 

gas received at a gas processing plant 

under 40 CFR 98.236(aa)(3)(i) is entitled 

to confidential treatment under the 

provisions of 40 CFR 2.208. These data 

provide detailed information regarding 

the quantities of natural gas processed 

that would be likely to cause 

competitive harm if disclosed as it 

provides sensitive information on 

market share. Thus, in this final action 

we are changing the determination for 

40 CFR 98.236(aa)(3)(i) from ‘‘not CBI’’ 

to ‘‘CBI.’’ 

The other data elements specifically 

mentioned by commenters are either not 

the same as those reported under 

subpart NN or they have determinations 

that are consistent with those in subpart 

NN. For example, commenters noted 

that the quantity of NGL (bulk and 

fractionated) received (reported under 

40 CFR 98.236(aa)(3)(iii) and the 

quantity of NGL (bulk and fractionated) 

leaving the plant (reported under 40 

CFR 98.236(aa)(3)(iv)) are the same as 

the data elements reported under 40 

CFR 98.406(a)(2) and (a)(1), 

respectively. However, the commenters 

are mistaken. Under subpart W, the data 

elements reported are actually 

aggregated totals for all NGL products 

received and all NGL products supplied. 

Under subpart NN, facilities report the 

quantities of each individual product. 

The subpart NN data elements were 

previously determined to be entitled to 

confidential treatment because they 

provide detailed information regarding 

the quantities of individual products 

that would be likely to cause 

competitive harm if disclosed as it 

provides sensitive information on 

market share. Since the NGL data 

reported under subpart W is in an 

aggregated form, the quantities of 

individual products is not disclosed and 

therefore does not pose the same risk of 

causing competitive harm to the 

reporters. The only exception is in 

situations where the plant is known to 

receive or supply only one NGL 

product. In these situations, the EPA has 

decided not to make a confidentiality 

determination for 40 CFR 

98.236(aa)(3)(iii) and (aa)(3)(iv). 

Comment: One commenter expressed 

concern about reporting information on 

exploratory wells in subpart W, 

especially when the wells are located in 

step-out areas where no prior reporting 

exists for a given sub-basin (including 

vertical or horizontal wells). The 

commenter explained that the problem 

occurs when an exploratory well is the 

sole well in a sub-basin (including 

vertical or horizontal wells) and is not 

reported in combination with other 

wells, thereby shielding any individual 

well’s contribution. The commenter 

noted that its concerns are related to the 

timing of releasing the information to 

the public, as the commenter stated that 

the information is most sensitive if it is 

made available too early during the 

exploration or initial development 

stages. The commenter stated that the 

success of a well in exploratory areas 

could be inferred if detailed data are 

provided to the public too soon during 

the exploration and assessment period. 

The commenter provided an example of 

such an occurrence: An exploratory well 

completed in December of the reporting 

year, data reported to the EPA by end 

of March of the following year and then 

released by the EPA to the public within 

a few months during the same year. The 

commenter stated that early release of 

data regarding operating characteristics 

of such wells, including post-flowback 

flaring/venting volumes, could cause 

competitive harm if made publicly 

available too early. 

The commenter noted that Federal 

law and State codes allow companies to 

designate as confidential the data 

obtained from exploratory wells, 

especially in new discovery areas or 

areas that are being explored for 

development. The commenter further 

noted that the original intent of State oil 

and gas commissions to allow 

withholding of select drilling and 

production information from early 

release to the public was to allow 

competitive exploration by searching for 

new pockets of oil or gas and 

experimenting with new tools and 

techniques. The commenter stated that 

releasing data on such wells through 

Part 98—despite the fact that they are 

held confidential by other regulatory 

bodies—could cause substantial 


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competitive harm and lead to a loss of 

investment value. The commenter 

explained that competitive harm could 

occur if the public could obtain detailed 

high-resolution operational information 

on a well-by-well basis and on a daily 

or weekly basis. 

The commenter requested that the 

EPA categorically determine that all 

information associated with exploratory 

wells, with the exception of well ID and 

location, be classified as CBI for a 

period of at least 24 months from the 

start of exploration. The commenter 

recommended either of two suggested 

approaches under Part 98: (1) 

Companies would report all data to the 

EPA as mandated by subpart W, but the 

EPA would hold the reported data as 

CBI and not include it in its public data 

release for at least 24 months (this could 

be accomplished by a flagging system 

(or a ‘‘radio button’’) in the Electronic 

Greenhouse Gas Reporting Tool that 

could also allow for a short informative 

text on why that particular well 

information is to be maintained 

confidential); or (2) the EPA could set 

up a deferral system where initial data 

on exploratory wells will be well ID and 

location information and the remaining 

data would be backfilled by companies 

after a period of 24 months. The 

commenter added that neither option 

would require case-by-case review of 

companies’ information, and both are 

consistent with the approach taken by 

state oil and gas commissions and are 

protective of companies’ commercial 

investment interests. The commenter 

identified the following data elements 

as potentially sensitive when reported 

for exploratory wells: 

• Sub-basin ID. (40 CFR 98.236(g)(1)) 

• Well type. (40 CFR 98.236(g)(2)) 

• Cumulative backflow time, in 

hours, for each sub basin. (40 CFR 

98.236(g)(5)(i)) 

• Vented natural gas volume, in 

standard cubic feet, for each well in the 

sub-basin. (40 CFR 98.236(g)(6)) 

• Annual gas emissions, in standard 

cubic feet. (40 CFR 98.236(g)(7)) 

• For each sub-basin with gas well 

completions without hydraulic 

fracturing and without flaring, Subbasin ID. (40 CFR 98.236(h)(1)(i)) 

• For each sub-basin with gas well 

completions without hydraulic 

fracturing and without flaring, average 

daily gas production rate for all 

completions without hydraulic 

fracturing in the sub-basin without 

flaring, in standard cubic feet per hour. 

(40 CFR 98.236(h)(1)(iv)) 

• For each sub-basin with gas well 

completions without hydraulic 

fracturing and with flaring, Sub-basin 

ID. (40 CFR 98.236(h)(2)(i)) 

• For each sub-basin with gas well 

completions without hydraulic 

fracturing and with flaring, average 

daily gas production rate for all 

completions without hydraulic 

fracturing in the sub-basin with flaring, 

in standard cubic feet per hour. (40 CFR 

98.236(h)(2)(iv)) 

• At the basin level for atmospheric 

tanks where emissions were calculated 

using Calculation Method 3, the total 

annual oil throughput that is sent to 

atmospheric tanks in the basin, in 

barrels. (40 CFR 98.236(j)(2)(i)(A)) 

• 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. (40 CFR 

98.236(l)(1)(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. (40 CFR 

98.236(l)(2)(iv)) 

• 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. (40 CFR 98.236(l)(3)(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. (40 CFR 98.236(l)(4)(iii)) 

• If associated gas was vented or 

flared during the calendar year, Subbasin ID. (40 CFR 98.236(m)(1)) 

• For each sub-basin, indicate 

whether any associated gas was vented 

without flaring. (40 CFR 98.236(m)(2)) 

• For each sub-basin, indicate 

whether any associated gas was flared. 

(40 CFR 98.236(m)(3)) 

• Volume of oil produced, in barrels, 

in the calendar year during the time 

periods in which associated gas was 

vented or flared. (40 CFR 98.236(m)(5)) 

• 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. (40 CFR 98.236(m)(6)) 

• Formation type. (40 CFR 

98.236(aa)(1)(ii)(C)) 

• For each sub-basin category, the 

number of producing wells at the end of 

the calendar year. (40 CFR 

98.236(aa)(1)(ii)(D)) 

• For each sub-basin category, the 

number of wells completed during the 

calendar year. (40 CFR 

98.236(aa)(1)(ii)(G)) 

• For offshore production, the 

quantity of gas produced from the 

offshore platform in the calendar year 

for sales. (40 CFR 98.236(aa)(2)(i)) 

Response: The EPA reviewed the data 

elements identified by the commenter as 

having disclosure concerns for 

exploratory wells (delineation wells and 

wildcat wells). After further 

investigation in response to the 

comment received, review of state laws 

protecting these types of data, and 

consistent with the EPA’s previous 

decisions related to exploratory wells 

under Part 98 (79 FR 63750, October 24, 

2014), the EPA has determined that, in 

the following situations which were not 

specifically considered in the proposed 

rule, early public disclosure of some of 

the data elements associated with 

wildcat wells and/or delineation wells 

could reveal the well productivity, 

thereby resulting in the loss of 

investment value: 

• For gas well completions or 

workovers with hydraulic fracturing, 

where wildcat wells and/or delineation 

wells are the only wells in a sub-basin 

that can be used for the measurement; 

• For gas well completions without 

hydraulic fracturing, where wildcat 

wells and/or delineation wells are the 

only wells in a sub-basin that can be 

used for the measurement; 

• For onshore production storage 

tanks, where wildcat wells and/or 

delineation wells are the only wells in 

a sub-basin or basin; 

• For well testing, where wildcat 

wells and/or delineation wells are the 

only wells in a sub-basin that are tested; 

• For associated gas venting and 

flaring, where wildcat wells and/or 

delineation wells are the only wells in 

a sub-basin; 

The data elements that could reveal 

well productivity for wildcat and/or 

delineation wells in the applicable 

situations listed above are as follows: 

• Cumulative flowback time, in 

hours, for each sub basin. (40 CFR 

98.236(g)(5)(i)) 

• For the measured well(s), the 

flowback rate, in standard cubic feet per 

hour, for each sub-basin. (40 CFR 

98.236(g)(5)(ii)) 

• For each sub-basin with gas well 

completions without hydraulic 

fracturing and without flaring, average 

daily gas production rate for all 

completions without hydraulic 

fracturing in the sub-basin without 

flaring, in standard cubic feet per hour. 

(40 CFR 98.236(h)(1)(iv)) 

• For each sub-basin with gas well 

completions without hydraulic 

fracturing and with flaring, average 

daily gas production rate for all 

completions without hydraulic 

fracturing in the sub-basin with flaring, 

in standard cubic feet per hour. (40 CFR 

98.236(h)(2)(iv)) 

• At the sub-basin level for 

atmospheric tanks where emissions 

were calculated using Calculation 

Method 1 or 2, the total annual gasVerDate Sep<11>2014 19:29 Nov 24, 2014 Jkt 235001 PO 00000 Frm 00030 Fmt 4701 Sfmt 4700 E:\FR\FM\25NOR4.SGM 25NOR4

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liquid separator oil volume that is sent 

to atmospheric storage tanks, in barrels. 

(40 CFR 98.236(j)(1)(iii)) 

• At the basin level for atmospheric 

tanks where emissions were calculated 

using Calculation Method 3, the total 

annual oil throughput that is sent to 

atmospheric tanks in the basin, in 

barrels. (40 CFR 98.236(j)(2)(i)(A)) 

• 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. (40 CFR 

98.236(l)(1)(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. (40 CFR 

98.236(l)(2)(iv)) 

• 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. (40 CFR 98.236(l)(3)(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. (40 CFR 98.236(l)(4)(iii)) 

• Volume of oil produced, in barrels, 

in the calendar year during the time 

periods in which associated gas was 

vented or flared. (40 CFR 98.236(m)(5)) 

• 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. (40 CFR 98.236(m)(6)) 

These 12 data elements are 

themselves a very small subset of data 

elements collected in subpart W. 

Further, wildcat and delineation wells 

represent a relatively small percentage 

of the wells being reported under Part 

98 for these data elements. As a result, 

in the interim period before these data 

are reported to the EPA, the EPA will be 

able to verify the majority of the 

emissions using data elements that will 

be reported to the EPA. For the 12 data 

elements that may be delayed for 2 

years, the EPA will verify emissions 

using other data reported to the EPA, 

and will conclude verification upon 

receipt of the data. The EPA agrees with 

the commenter that a two year delay of 

reporting is sufficient to prevent early 

public disclosure of these data and will 

provide sufficient time for the reporter 

to thoroughly conduct an assessment of 

the well. Given the results of this 

evaluation, the EPA determined that, for 

these 12 data elements, in those cases 

where a reporter has delineation wells 

or wildcat wells in cases where wildcat 

wells and/or delineation wells in a subbasin and these wells meet one of the 

five situations described above, 

reporters should be provided an option 

to delay reporting of the given data 

element for two reporting years starting 

in 2015. In such cases, if the two-year 

delay in reporting is used, the reporter 

must report the following information in 

the current reporting year: indicate for 

each delayed reporting element that one 

of the five situations listed above is true 

(e.g., for gas well completions or 

workovers with hydraulic fracturing, 

wildcat wells and/or delineation wells 

are the only wells in a sub-basin that 

can be used for the measurement). In 

addition, when reporters report the 

delayed data elements to emission 

equations after the 2 year delay, they 

must also report the American 

Petroleum Institute (API) well ID 

numbers for the applicable wildcat and/ 

or delineation wells in the sub-basin for 

which the reporting element was 

delayed. For example, if a delineation or 

wildcat well is completed in 2015 in a 

sub-basin that has only delineation or 

wildcat wells or these are the only wells 

for which measurements can be made, 

then the reporter may (1) elect to report 

these 12 data elements in their 2015 

annual report submitted by March 31, 

2016; or (2) elect to delay reporting of 

these data elements for up to two years. 

If the reporter elects to delay reporting, 

then the API well ID numbers for the 

wildcat and delineation wells in the 

sub-basin for which reporting has been 

delayed must be reported by March 31, 

2016 and the data elements delayed 

from reporting must be reported no later 

than March 31, 2018. 

The following data elements meet the 

definition of emission data in 40 CFR 

2.301(a)(2)(i) because they are actual 

volumes of gas emitted by the facility: 

volume of natural gas vented (reported 

under 40 CFR 98.236(g)(6)) and annual 

gas emissions (reported under 40 CFR 

98.236(g)(7)). Under CAA section 114(c), 

the EPA must make available emission 

data, whether or not such data are CBI. 

For these data elements that are 

assigned to the ‘‘Emissions’’ data 

category, the commenter did not claim 

or provide any justification for why 

these data elements do not meet the 

definition of emission data. 

For the remaining data elements 

identified by the commenter as 

potentially sensitive with respect to 

delineation and wildcat wells, the EPA 

disagrees that public disclosure of these 

data elements in the time period 

following annual reporting would reveal 

well productivity, thereby resulting in 

the loss of investment value to the 

reporter. The sub-basin ID (reported 

under 40 CFR 98.236(g)(1), (h)(1)(i), 

(h)(2)(i), and (m)(1)) and number of 

wells can be discerned from the well 

IDs, which are publicly available for all 

wells and provide the location of the 

well and the name of the drilling 

company. Since the location of the well 

can be discerned from the well ID, the 

type of formation (reported under 40 

CFR 98.236(aa)(1)(ii)(C)) can be 

determined through publicly available 

information such as U.S. Geological 

Survey reports. The well type (reported 

under 40 CFR 98.236(g)(2)), including 

whether hydraulic fracturing is used, 

can be inferred from the formation type. 

Similarly, although indicating whether 

the well vents or flares associated gas 

emissions (reported under 40 CFR 

98.236(m)(2) and (m)(3)) identifies the 

well as an oil well, this information can 

also be concluded from the formation 

type, which, as previously mentioned, 

may be determined through publicly 

available information. The number of 

producing wells at the end of the 

calendar year (reported under 40 CFR 

98.236(aa)(1)(ii)(D)) and the number of 

wells completed during the calendar 

year (reported under 40 CFR 

98.236(aa)(1)(ii)(G)) are reported for subbasins with production wells. 

Information regarding production wells 

is available from state databases. Since 

these data elements are either not 

sensitive or can be easily inferred from 

information already in the public 

domain, the EPA has determined that 

release of this information would not 

result in competitive harm. 

IV. Impacts of the Final Amendments to 

Subpart W 

A. Impacts of the Final Amendments 

The final amendments to subpart W 

include technical corrections and 

revisions to the calculation, monitoring, 

and reporting requirements that do not 

significantly increase the burden of data 

collection and improve the accuracy of 

the data reported. In general, these 

revisions provide greater flexibility for 

reporters and increase the clarity and 

congruency of the calculation and 

reporting requirements. These final 

amendments do not impart significant 

additional burden to reporters and in 

some cases reduce burden to reporters 

and regulators. 

First, the following revisions to the 

calculation and monitoring 

requirements of subpart W are 

anticipated to decrease the burden or 

have no impact on the burden relative 

to the burden to comply with the 

current rule: 

• Allowing for the use of either sitespecific composition data or a default 

gas composition for natural gas 

transmission compression, underground 

natural gas storage, LNG storage, LNG 


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import and export, and natural gas 

distribution facilities. 

• For well venting from liquids 

unloading, allowing the measurement 

period to differ slightly from the 

standard calendar year combined with 

annualizing the resulting venting data 

for facilities that calculate emissions 

using a recording flow meter. 

• Allowing for the option to use a 

site-specific compressibility factor for 

calculation of emissions from 

blowdown vents and for conversion of 

volumetric emissions at actual 

conditions to standard conditions. 

• Revising calculation methods for 

onshore production storage tanks to 

require quantification of emissions from 

well pad gas-liquid separator liquid 

dump valves only if the dump valve is 

determined to not be closing properly. 

• Including a term 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. The term is already being 

calculated elsewhere and/or can be 

estimated. 

• Deciding against finalizing the 

addition of the term ‘‘EREp,q’’ for 

emissions reported under other sources; 

therefore, reporters will not be required 

to track these emissions. 

• Removing vented compressor 

emissions routed to a flare from the 

compressor emissions total and 

retaining the requirement to report 

uncontrolled vented emissions from 

compressors. 

• Addressing reporter concerns 

related to measuring centrifugal and 

reciprocating compressor emissions that 

are routed to a common vent manifold 

or flare header. Reporters were 

previously required to conduct 

emissions measurements for each 

individual compressor routed to the 

common vent. The final rule requires 

only a single annual emissions 

measurement at the common vent for 

groups of manifolded compressors. We 

are not finalizing the proposed 

requirement to conduct measurement of 

manifolded compressor source 

emissions before comingling with 

emissions from other sources. 

• Revising requirements to conduct 

measurements in the not-operatingdepressurized mode once every three 

years or at the next scheduled 

depressurized shutdown (for centrifugal 

compressors) or at the next scheduled 

shutdown when the compressor rod 

packing is replaced (for reciprocating 

compressors). We are not finalizing the 

proposed requirement to conduct testing 

in the operating-mode once every 3 

years. 

• Revising calculation methods for 

the natural gas distribution segment to 

clarify the calculation methodologies 

and reporting requirements for above 

grade metering-regulating stations. 

• Removing the existing best 

available monitoring method (BAMM) 

provisions in 40 CFR 98.234(f) and 

providing transitional BAMM for the 

2015 calendar year. Removing the 

existing provisions does not add to 

previous burden estimates for subpart W 

reporters; these estimates were prepared 

based on all reporters complying with 

the monitoring methods in 40 CFR 

98.234 without BAMM. The transitional 

BAMM included in this final rule would 

allow facilities to obtain the necessary 

equipment to conduct measurements as 

required under the revised calculation 

methods in this final rule, and would 

not add to the burden estimates 

included in the proposed rule. (See 

further discussion in Section II.D of this 

preamble.) 

• Providing for the use of optical gas 

imaging as a screening tool to detect 

emissions from reciprocating and 

centrifugal compressors; measurement 

to quantify the emissions is required 

only if the screening detects emissions. 

• Providing clarified, specific missing 

data procedures that provide guidance 

for reporters when a measurement is 

inadvertently missed. 

Second, the following revisions to the 

calculation, monitoring, and reporting 

requirements of subpart W slightly 

increase the burden relative to the 

burden to comply with the current rule: 

• Revising the calculation and 

reporting requirements for completions 

and workovers to differentiate between 

completions and workovers with 

different well type combinations in each 

sub-basin category. 

• Revising the calculation and 

reporting requirements for onshore 

natural gas transmission compression, 

underground natural gas storage, LNG 

storage, and LNG import and export to 

include emissions from flare stacks. 

Finally, the following revisions to the 

reporting requirements for subpart W do 

increase the burden of data collection, 

but not significantly. As further 

discussed in Section II of this preamble, 

the EPA is finalizing the addition of 247 

new data elements, while substantially 

revising 13 data elements and deleting 

34 data elements that were required to 

be reported under Part 98. Although not 

previously required to be reported, 

many of these data elements are 

typically already collected by reporters, 

related to data that are already being 

reported, or are readily available to 

reporters. For example, some of the new 

reporting elements are required for use 

in subpart W equations used to calculate 

emissions and others are collected to 

differentiate between identical 

equipment types. 

These final additions improve the 

quality of the data reported by removing 

ambiguity for the reporter and do not 

increase burden significantly, since the 

reporting elements are already available. 

The EPA received multiple comments 

regarding the impacts of the proposed 

amendments. After evaluating these 

comments and reviewing other changes 

from proposal, the EPA revised the 

impacts assessment. The final 

amendments to subpart W are not 

expected to significantly increase 

burden. See the memorandum, 

‘‘Assessment of Impacts of the 2014 

Final Revisions to Subpart W’’ in Docket 

Id. No. EPA–HQ–OAR–2011–0512 for 

additional information. 

B. Summary of Comments and 

Responses 

This section summarizes the major 

comments and responses related to the 

impacts of the proposed amendments to 

subpart W of Part 98. See the 2014 

response to comment document in 

Docket Id. No. EPA–HQ–OAR–2011– 

0512 for a complete listing of all 

comments and responses. 

Comment: Several commenters stated 

that the EPA significantly oversimplified the impacts and 

underestimated the burden associated 

with the proposed rule. Specifically, 

commenters expressed concern that 

EPA has significantly underestimated 

the additional time and cost burden of 

the expanded reporting requirements. 

One commenter considered the 

implementation cost to be 

underestimated by an order of 

magnitude or more, providing an 

estimate of an additional $150,000 per 

company or more to initially identify, 

collect, document and report the new 

data elements with another $100,000 

per year. This commenter critiqued the 

‘‘Assessment of Impacts of 2014 

Proposed Revisions to Subpart W’’ and 

the information collection request (ICR) 

Supporting Statement and stated that 

many of the time and cost burdens 

should be much higher than the 

numbers included in these documents. 

The commenter stated that the cost 

estimates do not include management 

tasks including review of the proposed 

rule and final revisions, monitoring plan 

revisions, internal communications, 

coordination with technical staff, 

training, systems updates, or associated 

budgeting and planning. One concern 

was the assumption that 3 minutes 

would be required to find, document, 

and report each new data element. The 


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commenter pointed out that the estimate 

does not consider the level of effort 

required to determine who collects the 

data or how and where it is 

documented. Another commenter 

reported that their company had 

invested in a robust system to manage 

data collection and reporting according 

to the original rule requirements, and 

the revised changes would be 

burdensome and costly. 

Response: Although the commenter 

did not elaborate on the assumptions 

used to calculate the $150,000 initial 

cost or the $100,000 annual cost, the 

EPA disagrees with the magnitude of 

these costs. Overall, the EPA has 

determined that the cost estimates 

provided by the commenters do not take 

into consideration the completion of 

one-time activities that occurred in the 

first year of data collection. In the EPA’s 

cost estimates, we assumed the startup 

costs would be incurred during the first 

year of reporting, i.e., the 2011 reporting 

year. These costs included the labor 

burden of planning, registration, and 

installing required equipment to comply 

with the rule, as well as the initial costs 

of developing a data tracking system. 

The EPA maintains that allowing 3 

minutes per data element is accurate. 

All new reporting elements are related 

to emission sources for which 

information is already being gathered 

and reported under subpart W. The new 

elements include such information as 

the name or ID of the emission source, 

measurement dates, installation dates, 

maintenance dates, equipment counts, 

measurement counts, operating hours, 

etc. Most, if not all, of these elements 

can be gathered at the same time as 

required measurements are being taken. 

Comment: One commenter stated that 

the EPA cost analysis incorrectly 

assumes an incremental time of 10 

minutes for a technician to conduct 

each additional compressor source 

measurement for manifolded 

compressors. The commenter stated that 

this estimate fails to consider the time 

required to move personnel and 

equipment from compressor to 

compressor and the cautious pace of 

work and work practices (e.g., use of 

lanyard and/or other fall protection) for 

safely working at elevated locations. 

The commenter also pointed out that 

the measurement estimate appears to 

assume that the technician is working 

alone, reiterating that personnel do not 

work alone at elevated locations. The 

commenter further asserted that the 

EPA’s burden estimate for compressor 

testing appears to include costs only for 

the testing contractor and does not 

include facility and company costs 

including scheduling, coordination, and 

test team support. The commenter 

stated that the proposed rule fails to 

account for costs associated with three 

separate measurements. 

Response: The original burden 

estimate referenced by the commenter 

was an adjustment to the burden 

estimate for the subpart W 2010 final 

rule to reflect the proposed changes for 

manifolded compressors. For 

manifolded compressors, the EPA 

proposed that reporters may measure 

downstream of the manifold, in lieu of 

measuring each compressor source 

individually. Therefore, the 

measurement burden estimates assumed 

that the technician would be taking a 

single measurement at the manifold and 

that the level of effort associated with 

manifolded measurements are similar to 

the level of effort associated with 

measurements for individual 

compressors. 

Additionally, in this final rule, we are 

specifying that ‘‘as found’’ 

measurements from manifolded 

compressors be taken one time per year 

instead of three separate measurements 

per year as proposed. 

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 final 

amendments to subpart W. This analysis 

is contained in the memorandum 

‘‘Assessment of Impacts of the 2014 

Final 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 final rule have been 

submitted for approval to the Office of 

Management and Budget (OMB) under 

the Paperwork Reduction Act, 44 U.S.C. 

3501 et seq. The ICR document prepared 

by the EPA has been assigned OMB 

control number 2060–0629 and EPA ICR 

tracking number 2300.15. 

This action simplifies the existing 

reporting methods in subpart W, 

clarifies monitoring methods and data 

reporting requirements, and finalizes 

confidentiality determinations for 

reported data elements. The EPA is 

restructuring the reporting requirements 

for clarity and to align them with the 

calculation requirements by adding 247 

new data elements, substantially 

revising 13 data elements, and deleting 

34 data elements. 

OMB has previously 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 and EPA ICR 

tracking number 2300.12. 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. 

The information collection will result 

in an overall increase in annual burden 

of approximately 7,700 hours and 

$600,000. The estimated total projected 

cost and hour burden associated with 

reporting for subpart W are 

approximately $22,024,000 and 244,000 

hours, respectively. For the hour 

burden, the estimated average burden 

hours per response is 53.7 hours, the 

frequency of response is once annually, 

and the estimated number of likely 

respondents is 2,885. These 

amendments to subpart W affect the 

labor costs, not the capital costs and 

operation and maintenance (O&M) 

costs. Therefore, the estimated total 

capital and start-up cost of monitoring 

equipment and related facility/process 

modifications annualized over the 

expected useful life of the equipment 

remains at $796,000 per year, and the 

total O&M cost remains at $1,690,000 

per year. The total labor cost is 

$19,538,000 per year for all of subpart 

W. 

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. 


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For purposes of assessing the impacts 

of today’s final rule on small entities, 

small entity is defined as: (1) A small 

business as defined by the Small 

Business Administration’s regulations at 

13 CFR 121.201; (2) a small 

governmental jurisdiction that is a 

government of a city, county, town, 

school district or special district with a 

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

a small organization that is any not-forprofit enterprise which is independently 

owned and operated and is not 

dominant in its field. 

This action (1) amends monitoring 

and calculation methodologies in 

subpart W; (2) amends reporting 

requirements; (3) assigns subpart W data 

reporting elements into CBI data 

categories; and (4) amends a definition 

in subpart A. After considering the 

economic impacts of these final rule 

amendments on small entities, I certify 

that this action will not have a 

significant economic impact on a 

substantial number of small entities. 

The small entities directly regulated by 

this final rule include small businesses 

in the petroleum and gas industry, small 

governmental jurisdictions and small 

non-profits. The EPA has determined 

that some small businesses would be 

affected because their production 

processes emit GHGs exceeding the 

reporting threshold. 

This action includes final 

amendments that do not result in a 

significant burden increase on subpart 

W reporters. In some cases, the EPA is 

increasing flexibility in the selection of 

methods used for calculating GHGs, and 

is also revising certain methods that 

may result in greater conformance to 

current industry practices. In addition, 

the EPA is revising specific provisions 

to provide clarity on what information 

is being reported. These revisions would 

not significantly increase the burden on 

reporters while maintaining the data 

quality of the information being 

reported to the EPA. 

Although this final 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. As 

part of the process of finalizing the 

subpart W 2010 final 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 

EPA supports a ‘‘help desk’’ for the rule, 

which is available to answer questions 

on the provisions in the rule. Finally, 

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. 

D. Unfunded Mandates Reform Act 

(UMRA) 

This rule contains no 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 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 203 of 

UMRA because it contains no regulatory 

requirements that might significantly or 

uniquely affect small governments. This 

action (1) amends monitoring and 

calculation methodologies in subpart W; 

(2) amends reporting requirements, (3) 

assigns subpart W data reporting 

elements into CBI data categories; and 

(4) amends a definition in subpart A. 

The rule applies to few, if any, 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). 

Few, if any, state or local government 

facilities would be affected by the 

provisions in this 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. 

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. 

However, it will neither impose 

substantial new direct compliance costs 

on tribal governments, nor preempt 

Tribal law. This regulation would apply 

directly to petroleum and natural gas 

facilities that emit GHGs. 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 subpart W 2010 final 

rule published on November 30, 2010 

(75 FR 74458). 

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 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 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 


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standards (e.g., materials specifications, 

test methods, sampling procedures, and 

business practices) that are developed or 

adopted by voluntary consensus 

standards bodies. NTTAA directs EPA 

to provide Congress, through OMB, 

explanations when the Agency decides 

not to use available and applicable 

voluntary consensus standards. This 

action does not involve the use of any 

new technical standards. No changes are 

being finalized that affect the test 

methods currently in use for subpart W. 

Although the EPA is revising this final 

rule to allow for the use of additional 

measurement methods (optical gas 

imaging instrument) for pre-screening of 

compressor valve leakage, these 

revisions rely on existing technical 

standards in subpart W for similar 

emission sources. Therefore, the EPA is 

not considering the use of any new 

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 low-income 

populations in the United States. 

The EPA has determined that this rule 

will not have disproportionately high 

and adverse human health or 

environmental effects on minority or 

low-income populations because it does 

not affect the level of protection 

provided to human health or the 

environment. Instead, this rule 

addresses information collection and 

reporting procedures. 

K. Congressional Review Act 

The Congressional Review Act, 5 

U.S.C. 801 et seq., as added by the Small 

Business Regulatory Enforcement 

Fairness Act of 1996, generally provides 

that before a rule may take effect, the 

agency promulgating the rule must 

submit a rule report, which includes a 

copy of the rule, to each House of the 

Congress and to the Comptroller General 

of the United States. The EPA will 

submit a report containing this rule and 

other required information to the U.S. 

Senate, the U.S. House of 

Representatives, and the Comptroller 

General of the United States prior to 

publication of the rule in the Federal 

Register. A major rule cannot take effect 

until 60 days after it is published in the 

Federal Register. This action is not a 

‘‘major rule’’ as defined by 5 U.S.C. 

804(2). This rule will be effective on 

January 1, 2015. 

List of Subjects in 40 CFR Part 98 

Environmental protection, 

Administrative practice and procedure, 

Greenhouse gases, Reporting and 

recordkeeping requirements. 

Dated: November 13, 2014. 

Gina McCarthy, 

Administrator. 

For the reasons stated in the 

preamble, title 40, chapter I, of the Code 

of Federal Regulations is 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—GENERAL PROVISIONS 

■ 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—PETROLEUM AND 

NATURAL GAS SYSTEMS 

■ 3. Section 98.230 is amended by 

revising paragraph (a)(2) to read as 

follows: 

§ 98.230 Definition of the source category. 

(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-selfpropelled equipment, which includes 

well drilling and completion 

equipment, workover 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 paragraphs (c)(11), (d)(1), 

and (e)(1); 

■ b. Adding paragraph (e)(6); 

■ c. Revising paragraph (f)(1) and 

adding paragraph (f)(4); 

■ d. Revising paragraph (g)(1) and 

adding paragraph (g)(4); 

■ e. Revising paragraph (h)(1) and 

adding paragraph (h)(5); and 

■ f. Revising paragraphs (i)(1) through 

(i)(7). 

The revisions and additions read as 

follows: 

§ 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) * * * 

(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 the introductory text; 

■ b. Revising paragraphs (a) 

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

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. Removing paragraphs (j)(3) and 

(j)(4); 

■ f. Redesignating paragraphs (j)(5) 

through (j)(9) as paragraphs (j)(3) 

through (j)(7) and revising newly 

redesignated paragraphs (j)(3) through 

(j)(7); 

■ g. Revising paragraphs (k), (l), (m), (n), 

(o), (p), (q), and (r); 

■ h. Revising paragraphs (s)(2) 

introductory text, (s)(2)(i), (s)(3), and 

(s)(4); 

■ i. Revising paragraphs (t) introductory 

text, (t)(1), and (t)(2); 

■ j. Revising paragraphs (u) introductory 

text and (u)(2)(iii) through (vii); 

■ k. Revising paragraphs (v), (w) 

introductory text, (w)(1), and (w)(3) 

introductory text; 

■ l. Revising the parameters ‘‘MassCO2,’’ 

‘‘N,’’ and ‘‘Vv’’ to Equation W–37 in 

paragraph (w)(3); 

■ m. Revising the introductory text of 

paragraph (x) and paragraph (x)(1); 

■ n. Revising the parameter ‘‘Shl’’ to 

Equation W–38 in paragraph (x)(2); 

■ o. Revising paragraph (z)(1); 

■ p. Revising the parameters ‘‘Va,’’ 

‘‘YCO2,’’ ‘‘Yj,’’ and ‘‘YCH4’’ to Equations 

W–39A and W–39B in paragraph 

(z)(2)(iii); 

■ q. 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); 

■ r. Removing the parameter ‘‘GWP’’ of 

Equation W–40 in paragraph (z)(2)(vi). 

The revisions and additions read as 

follows: 

§ 98.233 Calculating GHG emissions. 

You must calculate and report the 

annual GHG emissions as prescribed in 

this section. For calculations that 

specify measurements in actual 

conditions, reporters may use a flow or 

volume measurement system that 

corrects to standard conditions and 

determine the flow or volume at 

standard conditions; otherwise, 

reporters must use average atmospheric 

conditions or typical operating 

conditions as applicable to the 

respective monitoring methods in this 

section. 

(a) Natural gas pneumatic device 

venting. Calculate CH4 and CO2

volumetric emissions from continuous 

high bleed, continuous low bleed, and 

intermittent bleed natural gas 

pneumatic devices using Equation W–1 

of this section. 

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. 

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 8,760 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. (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). 


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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 

8,760 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 deadsorbed 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 

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. 

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. 

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 PengRobinson equation of state and speciates 

CO2 emissions. A minimum of the 

following, determined for typical 

operating conditions over the calendar 

year by engineering estimate and 

process knowledge based on best 

available data, must be used to 

characterize emissions: 

(i) Natural gas feed temperature, 

pressure, and flow rate. 

(ii) Acid gas content of feed natural 

gas. 

(iii) Acid gas content of outlet natural 

gas. 

(iv) Unit operating hours, excluding 

downtime for maintenance or standby. 

(v) Exit temperature of natural gas. 

(vi) Solvent pressure, temperature, 

circulation rate, and weight. 

(5) 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 


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continuous gas analyzer or take 

quarterly gas samples from the vent gas 

stream for each quarter that the AGR 

unit is operating to determine VolCO2 in 

Equation W–3 of this section, according 

to the 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 for each quarter that the 

AGR unit is operating to determine VolI

in Equation W–4A or W–4B of this 

section, according to the 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 for each quarter that the AGR 

unit is operating to determine VolO in 

Equation W–4A or W–4B of this section, 

according to the methods set forth in 

§ 98.234(b). 

(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 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 glycol 

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 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 (D) of this section. 

(A) Use the GHG mole fraction as 

defined in paragraph (u)(2)(i) or (ii) of 

this section. 

(B) If the GHG mole fraction cannot be 

determined using paragraph (u)(2)(i) or 

(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. 

(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: 

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. For 

dehydrators of any size that use 

desiccant, you 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. 


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Where: 

Es,n = Annual natural gas emissions at 

standard conditions in cubic feet. 

H = Height of the dehydrator vessel (ft). 

D = Inside diameter of the vessel (ft). 

P1 = Atmospheric pressure (psia). 

P2 = Pressure of the gas (psia). 

p = pi (3.14). 

%G = Percent of packed vessel volume that 

is gas. 

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), (2), and (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) through (5) of this 

section, as applicable. 

(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. 

(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), (2), or (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. 

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-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. 

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 (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. 

(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. 


tkelley on DSK3SPTVN1PROD with RULES4ER25NO14.029</GPH> ER25NO14.030</GPH> ER25NO14.031</GPH>
70390 Federal Register / Vol. 79, No. 227 / Tuesday, November 25, 2014 / Rules and Regulations 

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 sub-basin. 

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. 

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. 

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 sub-basin. 

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. 

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. 

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 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 non-contiguous 

periods of venting or flaring. 


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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. 

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 per hour 

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 subbasin and well type combination as 

follows: Complete measurements or 

calculations for at least one completion 

or workover for less than or equal to 25 

completions or workovers for each well 

type combination 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 subbasin 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 subbasin 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 specified in 

paragraph (g)(1)(iv) of this section to 

determine the value of FRMi. The 

procedures specified in paragraphs 

(g)(1)(v) and (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 (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 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. 

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/(sec 2 * K). 

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

hour. 


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70392 Federal Register / Vol. 79, No. 227 / Tuesday, November 25, 2014 / Rules and Regulations 

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*10 5 = Conversion from m 3/second to 

ft3/hour. 

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. 

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 subbasin 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 subbasin and well type combination. 

Convert measured and calculated FRa

values 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. 

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 

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 subbasin 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) introductory 

text 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 (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. 

(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 (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. 


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Federal Register / Vol. 79, No. 227 / Tuesday, November 25, 2014 / Rules and Regulations 70393 

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 subbasin. 

f = Total number of well completions without 

hydraulic fracturing in a sub-basin 

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 (ii) of this section. 

(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 (3) of this section. 

You may use the method in paragraph 

(i)(2) of this section for some blowdown 

vent stacks at your facility and the 

method in paragraph (i)(3) of this 

section for other blowdown vent stacks 

at your facility. 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 (4) of this section. The 

requirements in this paragraph (i) do not 

apply to blowdown vent stack emissions 

from depressurizing to a flare, overpressure 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 or event type. If you elect to 

determine emissions according to each 

equipment or event type, using unique 

physical volumes as calculated in 

paragraph (i)(1) of this section, you must 

calculate emissions as specified in 

paragraph (i)(2)(i) of this section and 

either paragraph (i)(2)(ii) or, if 

applicable, paragraph (i)(2)(iii) of this 

section for each equipment or event 

type. Equipment or event types must be 

grouped into the following seven 

categories: Facility piping (i.e., piping 

within the facility boundary other than 

physical volumes associated with 

distribution pipelines), pipeline venting 

(i.e., physical volumes associated with 

distribution pipelines vented within the 

facility boundary), compressors, 

scrubbers/strainers, pig launchers and 

receivers, emergency shutdowns (this 

category includes emergency shutdown 

blowdown emissions regardless of 

equipment type), and all other 

equipment with a physical volume 

greater than or equal to 50 cubic feet. If 

a blowdown event resulted in emissions 

from multiple equipment types and the 

emissions cannot be apportioned to the 

different equipment types, then 

categorize the blowdown event as the 

equipment type that represented the 

largest portion of the emissions for the 

blowdown event. 

(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. 

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. 

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 nonGHG gases. 


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70394 Federal Register / Vol. 79, No. 227 / Tuesday, November 25, 2014 / Rules and Regulations 

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 

either a default compressibility factor of 

1, or a site-specific compressibility factor 

based on actual temperature and 

pressure conditions. 

Where: 

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. 

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 nonGHG gases. 

Za = Compressibility factor at actual 

conditions for natural gas. You may use 

either a default compressibility factor of 

1, or a site-specific compressibility factor 

based on actual temperature and 

pressure conditions. 

(ii) Except as allowed in paragraph 

(i)(2)(iii) of this section, calculate 

annual CH4 and CO2 volumetric and 

mass emissions from each unique 

physical volume that is blown down by 

using the annual natural gas emission 

value as calculated in either Equation 

W–14A or Equation W–14B of 

paragraph (i)(2)(i) of this section and the 

calculation method specified in 

paragraph (i)(4) of this section. Calculate 

the total annual CH4 and CO2 emissions 

for each equipment or event type by 

summing the annual CH4 and CO2 mass 

emissions for all unique physical 

volumes associated with the equipment 

or event type. 

(iii) For onshore natural gas 

transmission compression facilities and 

LNG import and export equipment, as 

an alternative to using the procedures in 

paragraph (i)(2)(ii) of this section, you 

may elect to sum the annual natural gas 

emissions as calculated using either 

Equation W–14A or Equation W–14B of 

paragraph (i)(2)(i) of this section for all 

unique physical volumes associated 

with the equipment type or event type. 

Calculate the total annual CH4 and CO2

volumetric and mass emissions for each 

equipment type or event type using the 

sums of the total annual natural gas 

emissions for each 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 as specified 

in paragraph (i)(2) of this section, you 

may use a flow meter and measure 

blowdown vent stack emissions for any 

unique physical volumes determined 

according to paragraph (i)(1) of this 

section to be greater than or equal to 50 

cubic feet. If you choose to use this 

method, you must measure the natural 

gas emissions from the blowdown(s) 

through the monitored stack(s) 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 (2) of this 

section. For wells flowing directly to 

atmospheric storage tanks without 

passing through a wellhead separator 

with throughput greater than or equal to 

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 gasliquid separators or directly to 

atmospheric storage tanks with 

throughput less than 10 barrels per day, 

use Calculation Method 3 as specified in 

paragraph (j)(3) of this section. If you 

use Calculation Method 1 or Calculation 

Method 2, 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 (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 


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in paragraphs (j)(1)(vii)(A) through (C) 

of this section. 

* * * * * 

(2) Calculation Method 2. Calculate 

annual CH4 and CO2 emissions using 

the methods in paragraph (j)(2)(i) of this 

section 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 emissions using the 

methods in paragraph (j)(2)(ii) of this 

section for wells with annual average 

daily oil production greater than or 

equal to 10 barrels per day that flow 

directly to atmospheric storage tanks. 

(i) Flow to storage tank after passing 

through a separator. Assume that all of 

the CH4 and CO2 in solution at separator 

temperature and pressure is emitted 

from oil sent to storage tanks. You may 

use an appropriate standard method 

published by a consensus-based 

standards organization if such a method 

exists or you may use an industry 

standard practice as described in 

§ 98.234(b) to sample and analyze 

separator oil composition at separator 

pressure and temperature. 

(ii) Flow to storage tank direct from 

wells. Calculate CH4 and CO2 emissions 

using either of the methods in paragraph 

(j)(2)(ii)(A) or (B) of this section. 

(A) If well production oil and gas 

compositions are available through your 

previous analysis, select the latest 

available analysis that is representative 

of produced oil and gas from the subbasin category and assume all of the CH4

and CO2 in both oil and gas are emitted 

from the tank. 

(B) If well production oil and gas 

compositions are not available, use 

default oil and gas compositions in 

software programs, such as API 4697 

E&P Tank, that most closely match your 

well production gas/oil ratio and API 

gravity and assume all of the CH4 and 

CO2 in both oil and gas are emitted from 

the tank. 

(3) Calculation Method 3. Calculate 

CH4 and CO2 emissions using Equation 

W–15 of this section: 

Where: 

Es,i = Annual total volumetric GHG emissions 

(either CO2 or CH4) at standard 

conditions in cubic feet. 

EFi = 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 (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. 

(6) If you use Calculation Method 1 or 

Calculation Method 2 in paragraph (j)(1) 

or (2) of this section, calculate emissions 

from occurrences of well pad gas-liquid 

separator liquid dump valves not 

closing during the calendar year by 

using Equation W–16 of this section. 

Where: 

Es,i,o = Annual volumetric GHG emissions at 

standard conditions from each storage 

tank in cubic feet that resulted from the 

dump valve on the gas-liquid separator 

not closing properly. 

En = Storage tank emissions as determined in 

paragraphs (j)(1), (j)(2) and, if applicable, 

(j)(4) of this section 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)(4) 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)(5) of this section. 

(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 (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 


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the optical gas imaging instrument or 

acoustic leak detection device detects a 

leak, then you must use one of the 

methods in either paragraph (k)(2)(i) or 

(ii) of this section. 

(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 (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). 

(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) Use the requirements specified in 

paragraphs (k)(4)(i) and (ii) of this 

section to quantify annual emissions. 

(i) Use the appropriate gas 

composition in paragraph (u)(2)(iii) of 

this section. 

(ii) 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. 

(5) Calculate annual emissions from 

storage tanks to flares as specified in 

paragraphs (k)(5)(i) and (ii) of this 

section. 

(i) Use the storage tank emissions 

volume and gas composition as 

determined in paragraphs (k)(1) through 

(4) 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 (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. 

(1) Determine the gas to oil ratio 

(GOR) of the hydrocarbon production 

from oil well(s) tested. Determine the 

production rate from gas well(s) tested. 

(2) If GOR cannot be determined from 

your available data, then you must 

measure quantities reported in this 

section according to one of the 

procedures specified in paragraph 

(l)(2)(i) or (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–17A (for oil wells) or 

Equation W–17B (for gas wells) of this 

section. 

Where: 

Ea,n = Annual volumetric natural gas 

emissions from well(s) testing in cubic 

feet under actual conditions. 

GOR = Gas to oil ratio in cubic feet of gas 

per barrel of oil; oil here refers to 

hydrocarbon liquids produced of all API 

gravities. 

FR = Average annual flow rate in barrels of 

oil per day for the oil well(s) being 

tested. 

PR = Average annual production rate in 

actual cubic feet per day for the gas 

well(s) being tested. 

D = Number of days during the calendar year 

that the well(s) is tested. 

(4) Calculate natural gas volumetric 

emissions at standard conditions using 

calculations in paragraph (t) of this 

section. 

(5) Calculate both CH4 and CO2

volumetric and mass emissions from 

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 

(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 

(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. 

(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 (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. 


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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 subbasin 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. 

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. 

(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 (ii) of this 

section. 

(i) Use the associated natural gas 

volume and gas composition as 

determined in paragraph (m)(1) through 

(4) of this section. 

(ii) Use the calculation 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 (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 (iii) of this section. 

(i) For onshore natural gas 

production, determine the GHG mole 

fraction using paragraph (u)(2)(i) of this 

section. 

(ii) For onshore natural gas 

processing, when the stream going to 

flare is natural gas, use the GHG mole 

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 industry segment 

required to report to flare stack 

emissions under § 98.232, 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. 

Where: 

Es,CH4 = Annual CH4 emissions from flare 

stack in cubic feet, at standard 

conditions. 

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. 

h = 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 unlit 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 (7) of this section are not 

required. 

(9) The flare emissions determined 

under this paragraph (n) must be 

corrected for flare emissions calculated 

and reported under other paragraphs of 


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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 (5) of this 

section; perform calculations specified 

in paragraphs (o)(6) through (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 (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 (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, paragraphs (o)(1) through (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 

measurement method specified in 

paragraph (o)(1)(i) or (ii) of this section. 

Manifolded compressor sources (as 

defined in § 98.238) must use a 

measurement method specified in 

paragraph (o)(1)(i), (ii), (iii), or (iv) of 

this section. 

(i) Centrifugal compressor source as 

found measurements. Measure venting 

from each compressor according to 

either paragraph (o)(1)(i)(A) or (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 (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 (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. 

(B) For a compressor measured in notoperating-depressurized-mode, you 

must measure volumetric emissions 

from isolation valve leakage as specified 

in either paragraph (o)(2)(i)(A), (B), or 

(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 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. For purposes of this 

paragraph, a scheduled shutdown 

means a shutdown that requires a 

compressor to be taken off-line for 

planned or scheduled maintenance. A 

scheduled shutdown does not include 

instances when a compressor is taken 

offline due to a decrease in demand but 

must remain available. 

(D) An annual as found measurement 

is not required in the first year of 

operation for any new compressor that 

begins operation after as found 

measurements have been conducted for 

all existing compressors. For only the 

first year of operation of new 

compressors, calculate emissions 

according to paragraph (o)(6)(ii) of this 

section. 

(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 

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), (ii), or (iv) of this 

section, you may elect to measure 

combined volumetric emissions from 

the manifolded group of compressor 

sources by conducting measurements at 

the common vent stack as specified in 

paragraph (o)(4) of this section. The 

measurements must be conducted at the 

frequency specified in paragraphs 

(o)(1)(iii)(A) and (B) of this section. 

(A) A minimum of one measurement 

must be taken for each manifolded 

group of compressor sources in a 

calendar year. 

(B) The measurement may be 

performed while the compressors are in 

any compressor mode. 

(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), (ii), or 

(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 

measurements from individual 

centrifugal compressor sources. If 

conducting measurements for each 

compressor source, you must determine 

the volumetric emissions from 

blowdown valves and isolation valves 

as specified in paragraph (o)(2)(i) of this 

section, and the volumetric emissions 

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 notoperating-depressurized-mode, 

determine the volumetric emissions 

using one of the methods specified in 

paragraphs (o)(2)(i)(A) through (D) of 

this section. 

(A) Determine 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) Determine the volumetric flow at 

standard conditions from the blowdown 


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vent using a temporary meter such as a 

vane anemometer according to methods 

set forth in § 98.234(b). 

(C) Use an acoustic leak detection 

device according to methods set forth in 

§ 98.234(a)(5). 

(D) You may choose to use any of the 

methods set forth in § 98.234(a) to 

screen for emissions. If emissions are 

detected using the methods set forth in 

§ 98.234(a), then you must use one of 

the methods specified in paragraph 

(o)(2)(i)(A) through (C) of this section. If 

emissions are not detected using the 

methods in § 98.234(a), then you may 

assume that the volumetric emissions 

are zero. For the purposes of this 

paragraph, when using any of the 

methods in § 98.234(a), emissions are 

detected whenever a leak is detected 

according to the methods. 

(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 

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 (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 

measurements from manifolded groups 

of centrifugal compressor sources. If 

conducting measurements for a 

manifolded group of compressor 

sources, you must measure volumetric 

emissions as specified in paragraphs 

(o)(4)(i) and (ii) of this section. 

(i) Measure at a single point in the 

manifold downstream of all compressor 

inputs and, if practical, prior to 

comingling 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 paragraphs (o)(4)(ii)(A) through (E) of 

this section. 

(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). 

(D) An acoustic leak detection device 

according to methods set forth in 

§ 98.234(a)(5). 

(E) You may choose to use any of the 

methods set forth in § 98.234(a) to 

screen for emissions. If emissions are 

detected using the methods set forth in 

§ 98.234(a), then you must use one of 

the methods specified in paragraph 

(o)(4)(ii)(A) through (o)(4)(ii)(D) of this 

section. If emissions are not detected 

using the methods in § 98.234(a), then 

you may assume that the volumetric 

emissions are zero. For the purposes of 

this paragraph, when using any of the 

methods in § 98.234(a), emissions are 

detected whenever a leak is detected 

according to the method. 

(5) Methods for continuous 

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 (iii) of this 

section. 

(i) Measure at a single point in the 

manifold downstream of all compressor 

inputs and, if practical, prior to 

comingling 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. 

(6) Method for calculating volumetric 

GHG emissions from as found 

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 

(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 

(B) of this section that was measured 

during the reporting year. 

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 

(B) of this section that was not measured 

during the reporting year. 


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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. 

EFs,m = 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 (B) of this section. These 

emission factors must be calculated 

annually and 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. 

Where: 

EFs,m = 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. 

MTs,m,p = 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 (MTs,m 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. 

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. 

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 

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. 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)(8) or paragraph (p)(8) 

of this section to calculate emissions 

from the manifolded group of 

compressor sources. 

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. 

Tg = Total time the manifolded group of 

compressor sources g had potential for 

emissions in the reporting year, in hours. 

Include all time during which at least 

one compressor source in the manifolded 

group of compressor sources g was in a 

mode-source combination specified in 

either paragraph (o)(1)(i)(A), (o)(1)(i)(B), 

(p)(1)(i)(A), (p)(1)(i)(B), or (p)(1)(i)(C) of 

this section. Default of 8760 hours may 

be used. 

MTs,g,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 GHG i 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 

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. 

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 GHG i 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 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. 

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 GHG i. 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 (iii) of this section. 

(i) Paragraphs (o)(1) through (11) 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(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 

(5) of this section; perform calculations 

specified in paragraphs (p)(6) through 

(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 (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 (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, paragraphs (p)(1) through (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 (ii) of this section. 

Manifolded compressor sources (as 

defined in § 98.238) must use a 

measurement method specified in 

paragraph (p)(1)(i), (ii), (iii), or (iv) of 

this section. 

(i) Reciprocating compressor source as 

found measurements. Measure venting 

from each compressor according to 

either paragraph (p)(1)(i)(A), (B), or (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 

paragraphs (p)(1)(i)(D) and (E) 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 (B) of this section, and 

measure volumetric emissions from 


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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 (B) of this 

section. 

(C) For a compressor measured in notoperating-depressurized-mode, you 

must measure volumetric emissions 

from isolation valve leakage as specified 

in either paragraph (p)(2)(i)(A), (B), or 

(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 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 at 

the next scheduled depressurized 

shutdown. For purposes of this 

paragraph, a scheduled shutdown 

means a shutdown that requires a 

compressor to be taken off-line for 

planned or scheduled maintenance. A 

scheduled shutdown does not include 

instances when a compressor is taken 

offline due to a decrease in demand but 

must remain available. 

(E) An annual as found measurement 

is not required in the first year of 

operation for any new compressor that 

begins operation after as found 

measurements have been conducted for 

all existing compressors. For only the 

first year of operation of new 

compressors, calculate emissions 

according to paragraph (p)(6)(ii) of this 

section. 

(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 

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), (ii), or (iv) of this 

section, you may elect to measure 

combined volumetric emissions from 

the manifolded group of compressor 

sources by conducting measurements at 

the common vent stack as specified in 

paragraph (p)(4) of this section. The 

measurements must be conducted at the 

frequency specified in paragraphs 

(p)(1)(iii)(A) and (B) of this section. 

(A) A minimum of one measurement 

must be taken for each manifolded 

group of compressor sources in a 

calendar year. 

(B) The measurement may be 

performed while the compressors are in 

any compressor mode. 

(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), (ii), or 

(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 

measurements from individual 

reciprocating compressor sources. If 

conducting measurements for each 

compressor source, you must determine 

the volumetric emissions from 

blowdown valves and isolation valves 

as specified in paragraph (p)(2)(i) of this 

section. You must determine the 

volumetric emissions from reciprocating 

rod packing as specified in paragraph 

(p)(2)(ii) or (iii) of this section. 

(i) For blowdown valves on 

compressors in operating-mode or 

standby-pressurized-mode, and for 

isolation valves on compressors in notoperating-depressurized-mode, 

determine the volumetric emissions 

using one of the methods specified in 

paragraphs (p)(2)(i)(A) through (D) of 

this section. 

(A) Determine 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 (d), 

respectively. 

(B) Determine 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) Use an acoustic leak detection 

device according to methods set forth in 

§ 98.234(a)(5). 

(D) You may choose to use any of the 

methods set forth in § 98.234(a) to 

screen for emissions. If emissions are 

detected using the methods set forth in 

§ 98.234(a), then you must use one of 

the methods specified in paragraphs 

(p)(2)(i)(A) through (C) of this section. If 

emissions are not detected using the 

methods in § 98.234(a), then you may 

assume that the volumetric emissions 

are zero. For the purposes of this 

paragraph, when using any of the 

methods in § 98.234(a), emissions are 

detected whenever a leak is detected 

according to the method. 

(ii) For reciprocating rod packing 

equipped with an open-ended vent line 

on compressors in operating-mode, 

determine the volumetric emissions 

using one of the methods specified in 

paragraphs (p)(2)(ii)(A) through (C) of 

this section. 

(A) Determine the volumetric flow at 

standard conditions from the openended vent line using calibrated bagging 

or high volume sampler according to 

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

respectively. 

(B) Determine the volumetric flow at 

standard conditions from the openended vent line using a temporary meter 

such as a vane anemometer, according 

to methods set forth in § 98.234(b). 

(C) You may choose to use any of the 

methods set forth in § 98.234(a) to 

screen for emissions. If emissions are 

detected using the methods set forth in 

§ 98.234(a), then you must use one of 

the methods specified in paragraph 

(p)(2)(ii)(A) and (p)(4)(ii)(B) of this 

section. If emissions are not detected 

using the methods in § 98.234(a), then 

you may assume that the volumetric 

emissions are zero. For the purposes of 

this paragraph, when using any of the 

methods in § 98.234(a), emissions are 

detected whenever a leak is detected 

according to the method. 

(iii) For reciprocating rod packing not 

equipped with an open-ended vent line 

on compressors in operating-mode, you 

must determine the volumetric 

emissions using the method specified in 

paragraphs (p)(2)(iii)(A) and (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 for compressors with 

a closed distance piece, conduct annual 

detection of gas emissions from the rod 

packing vent, distance piece vent, 

compressor crank case breather cap, or 

other vent emitting gas from the rod 

packing. 

(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 

measurement from individual 

reciprocating compressor sources. If you 

elect to conduct continuous volumetric 

emission measurements for an 


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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. 

(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 

measurements from manifolded groups 

of reciprocating compressor sources. If 

conducting measurements for a 

manifolded group of compressor 

sources, you must measure volumetric 

emissions as specified in paragraphs 

(p)(4)(i) and (ii) of this section. 

(i) Measure at a single point in the 

manifold downstream of all compressor 

inputs and, if practical, prior to 

comingling 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 (E) of 

this section. 

(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). 

(D) An acoustic leak detection device 

according to methods set forth in 

§ 98.234(a)(5). 

(E) You may choose to use any of the 

methods set forth in § 98.234(a) to 

screen for emissions. If emissions are 

detected using the methods set forth in 

§ 98.234(a), then you must use one of 

the methods specified in paragraph 

(p)(4)(ii)(A) through (D) of this section. 

If emissions are not detected using the 

methods in § 98.234(a), then you may 

assume that the volumetric emissions 

are zero. For the purposes of this 

paragraph, when using any of the 

methods in § 98.234(a), emissions are 

detected whenever a leak is detected 

according to the method. 

(5) Methods for continuous 

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 (iii) of this 

section. 

(i) Measure at a single point in the 

manifold downstream of all compressor 

inputs and, if practical, prior to 

comingling 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 

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 (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 (C) of this section that was 

measured during the reporting year. 

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. 

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), (B), or 

(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), (B), 

and (C) of this section that was not 

measured during the reporting year. 

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. 

EFs,m = 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 for the reporting 

year. 

(iii) Using Equation W–28 of this 

section, develop an emission factor for 


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each compressor mode-source 

combination specified in paragraph 

(p)(1)(i)(A), (B), and (C) of this section. 

These emission factors must be 

calculated annually and used in 

Equation W–27 of this section to 

determine volumetric emissions from a 

reciprocating compressor in the modesource combinations that were not 

measured in the reporting year. 

Where: 

EFs,m = 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. 

MTs,m,p = 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 (MTs,m 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), (B), or 

(C) of this section. 

(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. 

(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. 

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 

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. 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)(8) or paragraph (o)(8) of 

this section to calculate emissions from 

the manifolded group of compressor 

sources. 

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. 

Tg = Total time the manifolded group of 

compressor sources g had potential for 

emissions in the reporting year, in hours. 

Include all time during which at least 

one compressor source in the manifolded 

group of compressor sources g was in a 

mode-source combination specified in 

either paragraph (o)(1)(i)(A), (o)(1)(i)(B), 

(p)(1)(i)(A), (p)(1)(i)(B), or (p)(1)(i)(C) of 

this section. Default of 8760 hours may 

be used. 

MTs,g,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. 

(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. 


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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. 

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. 

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 (iii) of this section. 

(i) Paragraphs (p)(1) through (11) 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 not need to be 

reported. For industry segments listed 

in § 98.230(a)(3) through (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 Equation 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. If you chose to conduct 

equipment leak surveys at all above 

grade transmission-distribution transfer 

stations over multiple years, ‘‘n,’’ 

according to paragraph (q)(8)(i) of this 

section, then you must calculate the 

emissions from all above grade 

transmission-distribution transfer 

stations as specified in paragraph (q)(9) 

of this section. 

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 assumed 

to be 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 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 


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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 noncompressor 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 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 transmissiondistribution transfer stations and all 

metering-regulating stations that do not 

meet the definition of transmissiondistribution 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 transmissiondistribution transfer stations over 

multiple years ‘‘n’’, 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 of this section 

to determine the meter/regulator run 

population emission factors for each 

GHGi. 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. 

Where: 

EFs,MR,i = Meter/regulator run population 

emission factor for GHGi based on all 

surveyed above grade transmissiondistribution 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 transmissiondistribution 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, according to 

paragraph (q)(8)(i) of this section, whose 

results are 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 you chose to conduct 

equipment leak surveys at all above 

grade transmission-distribution transfer 

stations over multiple years, ‘‘n,’’ 

according to paragraph (q)(8)(i) of this 

section and you have submitted a 

smaller number of annual reports than 

the duration of the selected cycle period 

of 5 years or less, then all available data 

from the current year and previous years 

must be used in the calculation of the 

emission factor ‘‘EFs,MR,i’’ from Equation 

W–31 of this section. After the first 

survey cycle of ‘‘n’’ years is completed 

and beginning in calendar year (n+1), 

the survey will continue on a rolling 

basis by including the survey results 

from the current calendar year ‘‘y’’ and 

survey results from all previous (n–1) 

calendar years, such that each annual 

calculation of the emission factor 

‘‘EFs,MR,i’’ from Equation W–31 of this 

section is based on survey results from 

‘‘n’’ years. Upon completion of a cycle, 

you may elect to change the number of 

years in the next cycle period (to be 5 

years or less). If the number of years in 

the new cycle is greater than the number 

of years in the previous cycle, calculate 

‘‘EFs,MR,i’’ from Equation W–31 of this 

section in each year of the new cycle 

using the survey results from the current 

calendar year and the survey results 

from the preceding number years that is 

equal to the number of years in the 

previous cycle period. If the number of 

years, ‘‘nnew’’, in the new cycle is 

smaller than the number of years in the 

previous cycle, ‘‘n’’, calculate ‘‘EFs,MR,i’’ 

from Equation W–31 of this section in 

each year of the new cycle using the 

survey results from the current calendar 

year and survey results from all 

previous (nnew¥1) calendar years. 

(9) If you chose to conduct equipment 

leak surveys at all above grade 

transmission-distribution transfer 

stations over multiple years, ‘‘n,’’ 

according to paragraph (q)(8)(i) of this 

section, you must use the meter/

regulator run population emission 

factors calculated using Equation W–31 

of this section and the total count of all 

meter/regulator runs at above grade 

transmission-distribution transfer 

stations to calculate emissions from all 

above grade transmission-distribution 

transfer stations using Equation W–32B 

in paragraph (r) of this section. 


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(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 (r) and 

do not need to be reported. Tubing 

systems equal to or less than one half 

inch diameter are exempt from the 

requirements of paragraph (r) of this 

section and do not need to be reported. 

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)(ii) of this 

section. 

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 transmissiondistribution transfer stations or, when 

used to calculate emissions according to 

paragraph (q)(9) of this section, the 

annual volumetric emissions of GHGi

from all meter/regulator runs at 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 or, when used to calculate 

emissions according to paragraph (q)(9) 

of this section, the total number of 

meter/regulator runs at 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 

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 transmissiondistribution 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 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 


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service listed in Table W–6 of this 

subpart. 

(6) Natural gas distribution facilities 

must use the appropriate methane 

emission factors as described in 

paragraphs (r)(6)(i) and (ii) of this 

section. 

(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 transmissiondistribution transfer stations must use 

the emission factor for below grade 

metering-regulating stations. 

(ii) Above grade metering-regulating 

stations that are not above grade 

transmission-distribution 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 transmissiondistribution transfer stations are not 

required to calculate emissions for 

above grade metering-regulating stations 

and are not required to report GHG 

emissions in § 98.236(r)(2)(v). 

(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 250.304 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. 

(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 

250.304 to calculate and report 

emissions. 

(t) GHG volumetric emissions using 

actual conditions. If equation 

parameters in § 98.233 are already 

determined at standard conditions as 

provided in the introductory text in 

§ 98.233, 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) Calculate natural gas volumetric 

emissions at standard conditions using 

actual natural gas emission temperature 

and pressure, and Equation W–33 of this 

section for conversions of Ea,n or 

conversions of FRa (whether sub-sonic 

or sonic). 

Where: 

Es,n = Natural gas volumetric emissions at 

standard temperature and pressure (STP) 

conditions in cubic feet, except Es,n

equals FRs,p for each well p when 

calculating either subsonic or sonic 

flowrates under § 98.233(g). 

Ea,n = Natural gas volumetric emissions at 

actual conditions in cubic feet, except 

Ea,n equals FRa,p for each well p when 

calculating either subsonic or sonic 

flowrates under § 98.233(g). 

Ts = Temperature at standard conditions 

(60 °F). 

Ta = Temperature at actual emission 

conditions (°F). 

Ps = Absolute pressure at standard conditions 

(14.7 psia). 

Pa = Absolute pressure at actual conditions 

(psia). 

Za = Compressibility factor at actual 

conditions for natural gas. You may use 

either a default compressibility factor of 

1, or a site-specific compressibility factor 

based on actual temperature and 

pressure conditions. 

(2) Calculate GHG volumetric 

emissions at standard conditions using 

actual GHG emissions temperature and 

pressure, and Equation W–34 of this 

section. 

Where: 

Es,i = GHG i volumetric emissions at standard 

temperature and pressure (STP) 

conditions in cubic feet. 

Ea,i = GHG i volumetric emissions at actual 

conditions in cubic feet. 

Ts = Temperature at standard conditions 

(60 °F). 

Ta = Temperature at actual emission 

conditions (°F). 

Ps = Absolute pressure at standard conditions 

(14.7 psia). 

Pa = Absolute pressure at actual conditions 

(psia). 

Za = Compressibility factor at actual 

conditions for GHG i. 

You may use either a default 

compressibility factor of 1, or a sitespecific compressibility factor based on 

actual temperature and pressure 

conditions. 

* * * * * 

(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. 

* * * * * 

(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 


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site specific engineering estimates based 

on best available data. 

(iv) GHG mole fraction in natural gas 

stored in the underground natural gas 

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. 

(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 

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 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. 

Where: 

Massi = GHGi (either CH4, CO2, or N2O) mass 

emissions in metric tons. 

Es,i = GHGi (either CH4, CO2, or N2O) 

volumetric emissions at standard 

conditions, in cubic feet. 

ri = 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. 

(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 paragraph 

(z)(1)(i) of this section. 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 paragraph (z)(1)(i) 

of this section 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 paragraph (z)(2) 

of this section. If the fuel is field gas, 

process vent gas, or a blend containing 

field gas or process vent gas, calculate 

emissions according to paragraph (z)(2) 

of this section. 

(i) For fuels listed in Table C–1 or a 

blend containing one or more fuels 

listed in Table C–1, 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(z) and not according to the 

reporting requirements specified in 

subpart C of this part. 

(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) * * * 


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* * * * * 

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 field gas or 

process vent gas, you may use either a 

default higher heating value of 1.235 × 

10¥3 mmBtu/scf or a site-specific higher 

heating value. For natural gas that is not 

of pipeline quality or that has a high heat 

value less than 950 Btu per standard 

cubic foot, use a site-specific higher 

heating value. 

* * * * * 

■ 6. Section 98.234 is amended by: 

■ a. Revising paragraphs (a) 

introductory text, (d)(1), and (f); 

■ b. Removing and reserving paragraph 

(g); and 

■ c. Adding paragraph (h). 

The revisions and additions read as 

follows: 

§ 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. 

* * * * * 

(f) Special reporting provisions for 

best available monitoring methods in 

reporting year 2015—(1) Best available 

monitoring methods. From January 1, 

2015 to March 31, 2015, for a facility 

subject to this subpart, you must use the 

calculation methodologies and 

equations in § 98.233 ‘‘Calculating GHG 

Emissions’’, but you may use the best 

available monitoring method for any 

parameter for which it is not reasonably 

feasible to acquire, install, and operate 

a required piece of monitoring 

equipment by January 1, 2015 as 

specified in paragraphs (f)(2) and (3) of 

this section. Starting no later than April 

1, 2015, you must discontinue using 

best available methods and begin 

following all applicable monitoring and 

QA/QC requirements of this part, except 

as provided in paragraph (f)(4) of this 

section. Best available monitoring 

methods means any of the following 

methods: 

(i) Monitoring methods currently used 

by the facility that do not meet the 

specifications of this subpart. 

(ii) Supplier data. 

(iii) Engineering calculations. 

(iv) Other company records. 

(2) Best available monitoring methods 

for well-related measurement data. You 

may use best available monitoring 

methods for well-related measurement 

data identified in paragraphs (f)(2)(i) 

and (ii) of this section that cannot 

reasonably be measured according to the 

monitoring and QA/QC requirements of 

this subpart. 

(i) If Calculation Method 1 for liquids 

unloading in § 98.233(f)(1) was used in 

calendar year 2014 and will be used 

again in calendar year 2015, the vented 

natural gas flow rate for any well in a 

unique tubing diameter group and 

pressure group combination that has not 

been previously measured. 

(ii) If using Equation W–10A of this 

subpart to determine natural gas 

emissions from completions and 

workovers for representative wells, the 

initial and average flowback rates (when 

using Calculation Method 1 in 

§ 98.233(g)(1)(i)) or pressures upstream 

and downstream of the choke (when 

using Calculation Method 2 in 

§ 98.233(g)(1)(ii)) for any well in a well 

type combination that has not been 

previously measured. 

(3) Best available monitoring methods 

for emissions measurement. You may 

use best available monitoring methods 

for sources listed in paragraphs (f)(3)(i) 

and (ii) of this section if the required 

measurement data cannot reasonably be 

obtained according to the monitoring 

and QA/QC requirements of this part. 

(i) Centrifugal compressor as found 

measurements of manifolded emissions 

from groups of centrifugal compressor 

sources according to § 98.233(o)(4) and 

(5), in onshore natural gas processing, 

onshore natural gas transmission 

compression, underground natural gas 

storage, LNG storage, and LNG import 

and export equipment as specified in 

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

(h)(2). 

(ii) Reciprocating compressor as 

found measurements of manifolded 

emissions from groups of reciprocating 

compressor sources according to 

§ 98.233(p)(4) and (5), in onshore 

natural gas processing, onshore natural 

gas transmission compression, 

underground natural gas storage, LNG 

storage, and LNG import and export 

equipment as specified in § 98.232(d)(1), 

(e)(1), (f)(1), (g)(1), and (h)(1). 

(4) Requests for extension of the use 

of best available monitoring methods 

beyond March 31, 2015. You may 

submit a request to the Administrator to 

use one or more best available 

monitoring methods for sources listed in 

paragraphs (f)(2) and (3) of this section 

beyond March 31, 2015. 

(i) Timing of request. The extension 

request must be submitted to EPA no 

later than January 31, 2015. 

(ii) Content of request. Requests must 

contain the following information: 

(A) A list of specific source types and 

parameters for which you are seeking 

use of best available monitoring 

methods. 

(B) For each specific source type for 

which you are requesting use of best 

available monitoring methods, a 

description of the reasons that the 

needed equipment could not be 

obtained and installed before April 1, 

2015. 

(C) A description of the specific 

actions you will take to obtain and 

install the equipment as soon as 

reasonably feasible and the expected 

date by which the equipment will be 

installed and operating. 

(iii) Approval criteria. To obtain 

approval to use best available 

monitoring methods after March 31, 

2015, you must submit a request 

demonstrating to the Administrator’s 

satisfaction that it is not reasonably 

feasible to acquire, install, and operate 

a required piece of monitoring 

equipment by April 1, 2015. The use of 

best available methods under paragraph 

(f) of this section will not be approved 

beyond December 31, 2015. 

* * * * * 

(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: 


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§ 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 device malfunctions during 

unit operation or activity data are not 

collected), you must follow the 

procedures specified in paragraphs (a) 

through (i) of this section, as applicable. 

(a) 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. 

(b) For each missing value of a 

parameter that should have been 

measured quarterly or more frequently 

using equipment including, but not 

limited to, 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 qualityassured 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. 

(c) For each missing value of a 

parameter that should have been 

measured annually, you must repeat the 

estimation or measurement activity for 

those sources as soon as possible, 

including in the subsequent calendar 

year if missing data are not discovered 

until after December 31 of the year in 

which data are collected, until valid 

data for reporting are obtained. Data 

developed and/or collected in a 

subsequent calendar year to substitute 

for missing data cannot be used for that 

subsequent year’s emissions estimation. 

Where missing data procedures are used 

for the previous year, at least 30 days 

must separate emissions estimation or 

measurements for the previous year and 

emissions estimation or measurements 

for the current year of data collection. 

(d) For each missing value of a 

parameter that should have been 

measured biannually (every two years), 

you must conduct the estimation or 

measurement activity for those sources 

as soon as possible in the subsequent 

calendar year if the estimation or 

measurement was not made in the 

appropriate year (first year of data 

collection and every two years 

thereafter), until valid data for reporting 

are obtained. Data developed and/or 

collected in a subsequent calendar year 

to substitute for missing data cannot be 

used to alternate or postpone 

subsequent biannual emissions 

estimations or measurements. 

(e) For the first 6 months of required 

data collection, facilities that become 

newly subject to this subpart W may use 

best engineering estimates for any data 

that cannot reasonably be measured or 

obtained according to the requirements 

of this subpart. 

(f) For the first 6 months of required 

data collection, facilities that are 

currently subject to this subpart W and 

that acquire new sources from another 

facility that were not previously subject 

to this subpart W may use best 

engineering estimates for any data 

related to those newly acquired sources 

that cannot reasonably be measured or 

obtained according to the requirements 

of this subpart. 

(g) Unless addressed in another 

paragraph of this section, for each 

missing value of any activity data, you 

must substitute data value(s) using the 

best available estimate(s) of the 

parameter(s), based on all applicable 

and available process or other 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). 

(i) You must follow recordkeeping 

requirements listed in § 98.237(f). 

■ 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. Reporters that use a flow or 

volume measurement system that 

corrects to standard conditions as 

provided in the introductory text in 

§ 98.233 for data elements that are 

otherwise required to be determined at 

actual conditions, report gas volumes at 

standard conditions rather the gas 

volumes at actual conditions and report 

the standard temperature and pressure 

used by the measurement system rather 

than the actual temperature and 

pressure. 

(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 each 

GHG, for each applicable industry 

segment listed in paragraphs (a)(1) 

through (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 (xvii) 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) 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. 

(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 


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in paragraphs (a)(3)(i) through (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. 

(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 (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 (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. 

(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 (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. 

(7) LNG import and export equipment. 

For the equipment/activities specified 

in paragraphs (a)(7)(i) through (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 (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. 

(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 (ii) of this 

section. 

(i) The total number of devices of each 

type, determined according to 

§ 98.233(a)(1) and (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 (C) of this section. 

(A) The number of devices of each 

type reported in paragraph (b)(1)(i) of 

this section that are counted. 

(B) The number of devices of each 

type 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) For each type of pneumatic device, 

the 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. 

(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 (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). 


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(3) Annual CO2 emissions, in metric 

tons CO2, for all natural gas driven 

pneumatic pumps combined, calculated 

according to § 98.233(c)(1) and (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 (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 (2) of this section. 

(1) You must report the information 

specified in paragraphs (d)(1)(i) through 

(vi) of this section for each acid gas 

removal unit. 

(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 under 

subpart PP of this part. 

(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 that best represents 

the wells supplying gas to the unit (for 

the onshore petroleum and natural gas 

production industry segment only). 

(2) You must report information 

specified in paragraphs (d)(2)(i) through 

(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 (B) of this 

section. 

(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) of this section. 

(A) Indicate 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 (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. 

(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: Glycol 

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 (3). 

(1) For each glycol 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 (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. 

(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 


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regenerator firebox/fire tubes, report the 

information specified in paragraphs 

(e)(1)(xvi)(A) through (C) of this section 

for these emissions from the dehydrator. 

(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 (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, if applicable, (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, if applicable, (e)(5). 

(xviii) Sub-basin ID that best 

represents the wells supplying gas to the 

dehydrator (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 (v) of this section for 

the entire facility. 

(i) The total number of dehydrators at 

the facility. 

(ii) Whether any dehydrator emissions 

were vented to a vapor recovery device. 

If any dehydrator emissions were 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 dehydrator 

emissions were vented to a control 

device other than a vapor recovery 

device or a flare or regenerator firebox/ 

fire tubes. If any dehydrator emissions 

were vented to a control device(s) other 

than a vapor recovery device or a flare 

or regenerator firebox/fire tubes, then 

you must specify the type of control 

device(s) and the total number of 

dehydrators at the facility that were 

vented to each type of control device. 

(iv) Whether any dehydrator 

emissions were vented to a flare or 

regenerator firebox/fire tubes. If any 

dehydrator emissions were vented to a 

flare or regenerator firebox/fire tubes, 

then you must report the information 

specified in paragraphs (e)(2)(iv)(A) 

through (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 dehydrator emissions that 

were not vented to a flare or regenerator 

firebox/fire tubes, report the information 

specified in paragraphs (e)(2)(v)(A) and 

(B) of this section. 

(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, if applicable, 

(e)(5), where emissions are added 

together for all such dehydrators. 

(B) Annual CH4 emissions, in metric 

tons CH4, 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, if applicable, 

(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 (iii) of this 

section for the entire facility. 

(i) The same information specified in 

paragraphs (e)(2)(i) through (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, if 

applicable, (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, if 

applicable, (e)(5), and summing for all 

such dehydrators. 

(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 group 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 (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 group. 

(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 group. 

(viii) Annual natural gas emissions, in 

standard cubic feet, from well venting 

for liquids unloading, calculated 

according to § 98.233(f)(1). 

(ix) Annual CO2 emissions, in metric 

tons CO2, from well venting for liquids 

unloading, calculated according to 

§ 98.233(f)(1) and (4). 

(x) Annual CH4 emissions, in metric 

tons CH4, from well venting for liquids 

unloading, calculated according to 

§ 98.233(f)(1) and (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 (E) of this section for each 

individual well not using a plunger lift 

that was tested during the year. 

(A) API Well Number of tested well. 


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(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 (E) of this section for each 

individual well using a plunger lift that 

was tested during the year. 

(A) 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. 

(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 (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 (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 (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 (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 

(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 combination. 

(3) Number of completions or 

workovers in the sub-basin and well 

type combination 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 (ii) of this section. 

(i) Cumulative gas flowback time, in 

hours, from when gas is first detected 

until sufficient quantities are present to 

enable separation, and the cumulative 

flowback time, in hours, after sufficient 

quantities of gas are present to enable 

separation (sum of ‘‘Tp,i’’ and sum of 

‘‘Tp,s’’ values used in Equation W–10A). 

You may delay the reporting of this data 

element if you indicate in the annual 

report that wildcat wells and/or 

delineation wells are the only wells 

included in this number. If you elect to 

delay reporting of this data element, you 

must report by the date specified in 

§ 98.236(cc) the total number of hours of 

flowback from all wells during 

completions or workovers and the API 

Well Number(s) for the well(s) included 

in the number. 

(ii) For the measured well(s), the 

flowback rate, in standard cubic feet per 

hour (average of ‘‘FRs,p’’ values used in 

Equation W–12A). You may delay the 

reporting of this data element if you 

indicate in the annual report that 

wildcat wells and/or delineation wells 

are the only wells that can be used for 

the measurement. If you elect to delay 

reporting of this data element, you must 

report by the date specified in 

§ 98.236(cc) the measured flowback rate 

during well completion or workover and 

the API Well Number(s) for the well(s) 

included in the measurement. 

(6) If you used Equation W–10B to 

calculate annual volumetric total gas 

emissions, then you must report the 

information specified in paragraphs 

(g)(6)(i) and (ii) of this section. 

(i) Vented natural gas volume, in 

standard cubic feet, for each well in the 

sub-basin (‘‘FVs,p’’ in Equation W–10B). 

(ii) Flow rate at the beginning of the 

period of time when sufficient 

quantities of gas are present to enable 

separation, in standard cubic feet per 

hour, for each well in the sub-basin 

(‘‘FRp,i’’ 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 had gas well 

completions or workovers without 

hydraulic fracturing, then you must 

report the information specified in 

paragraphs (h)(1) through (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 (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 venting 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). You may delay reporting of 

this data element if you indicate in the 

annual report that wildcat wells and/or 

delineation wells are the only wells that 

can be used for the measurement. If you 

elect to delay reporting of this data 

element, you must report by the date 

specified in § 98.236(cc) the measured 

average daily gas production rate for all 

wells during completions and the API 

Well Number(s) for the well(s) included 

in the measurement. 

(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– 


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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 (vii) of this section. 

(i) Sub-basin ID. 

(ii) Number of well completions that 

flared gas. 

(iii) Total number of hours that gas 

vented to a flare during venting 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). You may delay reporting of this 

data element if you indicate in the 

annual report that wildcat wells and/or 

delineation wells are the only wells that 

can be used for the measurement. If you 

elect to delay reporting of this data 

element, you must report by the date 

specified in § 98.236(cc) the measured 

average daily gas production rate for all 

wells during completions and the API 

Well Number(s) for the well(s) included 

in the measurement. 

(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 (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)). 

(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 

(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 or event type 

or by using flow meters or a 

combination of both. If you calculated 

emissions by equipment or event type 

for any blowdown vent stacks, then you 

must report the information specified in 

paragraph (i)(1) of this section 

considering, in aggregate, all blowdown 

vent stacks for which emissions were 

calculated by equipment or event type. 

If you calculated emissions using flow 

meters for any blowdown vent stacks, 

then you must report the information 

specified in paragraph (i)(2) of this 

section considering, in aggregate, all 

blowdown vent stacks for which 

emissions were calculated using flow 

meters. 

(1) Report by equipment or event type. 

If you calculated emissions from 

blowdown vent stacks by the seven 

categories listed in § 98.233(i)(2), then 

you must report the equipment or event 

types and the information specified in 

paragraphs (i)(1)(i) through (iii) of this 

section for each equipment or event 

type. If a blowdown event resulted in 

emissions from multiple equipment 

types, and the emissions cannot be 

apportioned to the different equipment 

types, then you may report the 

information in paragraphs (i)(1)(i) 

through (iii) of this section for the 

equipment type that represented the 

largest portion of the emissions for the 

blowdown event. 

(i) Total number of blowdowns in the 

calendar year for the equipment or event 

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 or 

event type). 

(ii) Annual CO2 emissions for the 

equipment or event type, in metric tons 

CO2, calculated according to 

§ 98.233(i)(2)(iii). 

(iii) Annual CH4 emissions for the 

equipment or event 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 (ii) of this 

section for the facility. 

(i) Annual CO2 emissions from all 

blowdown vent stacks at the facility for 

which emissions were calculated using 

flow meters, 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 for 

which emissions were calculated using 

flow meters, 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 (2) of 

this section as applicable. If you used 

Calculation Method 1 or Calculation 

Method 2, and 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. 

(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 (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 oil volume from 

gas-liquid separators and direct from 

wells that is sent to applicable onshore 

production storage tanks, in barrels. You 

may delay reporting of this data element 

if you indicate in the annual report that 

wildcat wells and delineation wells are 

the only wells in the sub-basin with oil 

production greater than or equal to 10 

barrels per day and flowing to gas-liquid 

separators or direct to storage tanks. If 

you elect to delay reporting of this data 

element, you must report by the date 


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Federal Register / Vol. 79, No. 227 / Tuesday, November 25, 2014 / Rules and Regulations 70417 

specified in § 98.236(cc) the total 

volume of oil from all wells and the API 

Well Number(s) for the well(s) included 

in this volume. 

(iv) The average gas-liquid separator 

temperature, in degrees Fahrenheit. 

(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 (E) of this section. 

(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 (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 (D) of 

this section. 

(A) The number of atmospheric tanks 

that controlled emissions with flares. 

(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 

paragraphs (j)(2)(i) through (iii) of this 

section. 

(i) Report the information specified in 

paragraphs (j)(2)(i)(A) through (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. You may delay 

reporting of this data element if you 

indicate in the annual report that 

wildcat wells and delineation wells are 

the only wells in the sub-basin with oil 

production less than 10 barrels per day 

and that send oil to atmospheric tanks. 

If you elect to delay reporting of this 

data element, you must report by the 

date specified in § 98.236(cc) the total 

annual oil throughput from all wells 

and the API Well Number(s) for the 

well(s) included in this volume. 

(B) An estimate of the fraction of oil 

throughput reported in paragraph 

(j)(2)(i)(A) of this section 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) of this section 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 gasliquid separators (‘‘Count’’ from 

Equation W–15 of this subpart) in the 

basin. 

(F) The number of wells without gasliquid separators (‘‘Count’’ from 

Equation W–15 of this subpart) in the 

basin. 

(ii) Report the information specified 

in paragraphs (j)(2)(ii)(A) through (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 and adjusted for 

vapor recovery, if applicable. 

(D) Annual CH4 emissions, in metric 

tons CH4, from atmospheric tanks in the 

sub-basin that did not control emissions 

with flares, calculated using Equation 

W–15 of this subpart and adjusted for 

vapor recovery, if applicable. 

(iii) Report the information specified 

in paragraphs (j)(2)(iii)(A) through (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. 

(3) If you used Calculation Method 1 

or Calculation Method 2, and any gasliquid 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 (iv) of this section for 

each sub-basin. 

(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 

(sum of the ‘‘Tn’’ values used in 

Equation W–16 of this subpart). 

(iii) Annual CO2 emissions, in metric 

tons CO2, that resulted from dump 

valves on gas-liquid 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 W–16 of 

this subpart. 

(k) Transmission storage tanks. You 

must indicate whether your facility 


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70418 Federal Register / Vol. 79, No. 227 / Tuesday, November 25, 2014 / Rules and Regulations 

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 (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 (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) Indicate whether scrubber dump 

valve leakage occurred for the 

transmission storage tank vent 

according to § 98.233(k)(2). 

(iv) Indicate 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) of this section, 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 (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 the leak is 

counted as having occurred, in hours, as 

determined in § 98.233(k)(3) (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 (4). 

(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 (4). 

(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 

(vi) of this section. 

(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, as defined in 

§ 98.233(k)(3) (may use best available 

data if a continuous flow measurement 

device was used). 

(iv) Annual CO2 emissions, in metric 

tons CO2, that resulted from flaring gas, 

calculated according to § 98.233(k)(5). 

(v) Annual CH4 emissions, in metric 

tons CH4, that resulted from flaring gas, 

calculated according to § 98.233(k)(5). 

(vi) Annual N2O emissions, in metric 

tons N2O, that resulted from flaring gas, 

calculated according to § 98.233(k)(5). 

(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 (4) of this 

section, 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 (vi) of this section. 

(i) Number of wells tested in the 

calendar year. 

(ii) Average number of well testing 

days per well for well(s) tested 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. You may 

delay reporting of this data element if 

you indicate in the annual report that 

wildcat wells and/or delineation wells 

are the only wells that are tested. If you 

elect to delay reporting of this data 

element, you must report by the date 

specified in § 98.236(cc) the measured 

average flow rate for well(s) tested and 

the API Well Number(s) for the well(s) 

included in the measurement. 

(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 (vii) of this section. 

(i) Number of wells tested in the 

calendar year. 

(ii) Average number of well testing 

days per well for well(s) tested 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. You may 

delay reporting of this data element if 

you indicate in the annual report that 

wildcat wells and/or delineation wells 

are the only wells that are tested. If you 

elect to delay reporting of this data 

element, you must report by the date 

specified in § 98.236(cc) the measured 

average flow rate for well(s) tested and 

the API Well Number(s) for the well(s) 

included in the measurement. 

(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 (v) of this section. 

(i) Number of wells tested in the 

calendar year. 

(ii) Average number of well testing 

days per well for well(s) tested in the 

calendar year. 

(iii) Average annual production rate 

for well(s) tested, in actual cubic feet 

per day. You may delay reporting of this 

data element if you indicate in the 

annual report that wildcat wells and/or 

delineation wells are the only wells that 

are tested. If you elect to delay reporting 

of this data element, you must report by 

the date specified in § 98.236(cc) the 

measured average annual production 

rate for well(s) tested and the API Well 

Number(s) for the well(s) included in 

the measurement. 

(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 (vi) of this section. 

(i) Number of wells tested in calendar 

year. 

(ii) Average number of well testing 

days per well for well(s) tested in the 

calendar year. 

(iii) Average annual production rate 

for well(s) tested, in actual cubic feet 


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Federal Register / Vol. 79, No. 227 / Tuesday, November 25, 2014 / Rules and Regulations 70419 

per day. You may delay reporting of this 

data element if you indicate in the 

annual report that wildcat wells and/or 

delineation wells are the only wells that 

are tested. If you elect to delay reporting 

of this data element, you must report by 

the date specified in § 98.236(cc) the 

measured average annual production 

rate for well(s) tested and the API Well 

Number(s) for the well(s) included in 

the measurement. 

(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). 

(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 

(8) of this section for each sub-basin. 

(1) Sub-basin ID. 

(2) Indicate whether any associated 

gas was vented directly to the 

atmosphere without flaring. 

(3) Indicate 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). You 

may delay reporting of this data element 

if you indicate in the annual report that 

wildcat wells and/or delineation wells 

are the only wells from which 

associated gas was vented or flared. If 

you elect to delay reporting of this data 

element, you must report by the date 

specified in § 98.236(cc) the volume of 

oil produced for well(s) with associated 

gas venting and flaring and the API Well 

Number(s) for the well(s) included in 

the measurement. 

(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 § 98.233(m)). You 

may delay reporting of this data element 

if you indicate in the annual report that 

wildcat wells and/or delineation wells 

from which associated gas was vented 

or flared. If you elect to delay reporting 

of this data element, you must report by 

the date specified in § 98.236(cc) the 

measured total volume of associated gas 

sent to sales for well(s) with associated 

gas venting and flaring and the API Well 

Number(s) for the well(s) included in 

the measurement. 

(7) If you had associated gas 

emissions vented directly to the 

atmosphere without flaring, then you 

must report the information specified in 

paragraphs (m)(7)(i) through (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 (4). 

(iii) Annual CH4 emissions, in metric 

tons CH4, calculated according to 

§ 98.233(m)(3) and (4). 

(8) If you had associated gas 

emissions that were flared, then you 

must report the information specified in 

paragraphs (m)(8)(i) through (iv) of this 

section for each sub-basin. 

(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 

(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. 

(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 (‘‘Vs’’ in Equations 

W–19 and W–20 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 (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 (4), you must report the 

information specified in paragraph 

(o)(3) of this section. For each 

compressor source or manifolded group 

of compressor sources that you conduct 

continuous monitoring as specified in 

§ 98.233(o)(3) or (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 (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 (xiv) of this section for 

each centrifugal compressor located at 

your facility. 

(i) Unique name or ID for the 

centrifugal compressor. 

(ii) Hours in operating-mode. 

(iii) Hours in not-operatingdepressurized-mode. 

(iv) Indicate whether the compressor 

was measured in operating-mode. 

(v) Indicate whether the compressor 

was measured in not-operatingdepressurized-mode. 

(vi) Indicate which, if any, 

compressor sources are part of a 

manifolded group of compressor 

sources. 

(vii) Indicate which, if any, 

compressor sources are routed to a flare. 

(viii) Indicate which, if any, 

compressor sources have vapor 

recovery. 

(ix) Indicate which, if any, 

compressor source emissions are 

captured for fuel use or are routed to a 

thermal oxidizer. 


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70420 Federal Register / Vol. 79, No. 227 / Tuesday, November 25, 2014 / Rules and Regulations 

(x) Indicate whether the compressor 

has blind flanges installed and 

associated dates. 

(xi) Indicate whether the compressor 

has wet or dry seals. 

(xii) If the compressor has wet seals, 

the number of wet seals. 

(xiii) Power output of the compressor 

driver (hp). 

(xiv) Indicate whether the compressor 

had a scheduled depressurized 

shutdown during the reporting year. 

(2) Compressor source. (i) For each 

compressor source at each compressor, 

report the information specified in 

paragraphs (o)(2)(i)(A) through (C) of 

this section. 

(A) Centrifugal compressor name or 

ID. Use the same ID as in paragraph 

(o)(1)(i) of this section. 

(B) Centrifugal compressor source 

(wet seal, isolation valve, or blowdown 

valve). 

(C) Unique name or ID for the leak or 

vent. If the leak or vent is connected to 

a manifolded group of compressor 

sources, use the same leak or vent ID for 

each compressor source in the 

manifolded group. If multiple 

compressor sources are released through 

a single vent for which continuous 

measurements are used, use the same 

leak or vent ID for each compressor 

source released via the measured vent. 

For a single compressor using as found 

measurements, you must provide a 

different leak or vent ID for each 

compressor source. 

(ii) For each leak or vent, report the 

information specified in paragraphs 

(o)(2)(ii)(A) through (E) of this section. 

(A) Indicate whether the leak or vent 

is for a single compressor source or 

manifolded group of compressor sources 

and whether the emissions from the leak 

or vent are released to the atmosphere, 

routed to a flare, combustion (fuel or 

thermal oxidizer), or vapor recovery. 

(B) Indicate whether an as found 

measurement(s) as identified in 

§ 98.233(o)(2) or (4) was conducted on 

the leak or vent. 

(C) Indicate whether continuous 

measurements as identified in 

§ 98.233(o)(3) or (5) were conducted on 

the leak or vent. 

(D) Report emissions as specified in 

paragraphs (o)(2)(ii)(D)(1) and (2) of this 

section for the leak or vent. If the leak 

or vent is routed to a flare, combustion, 

or vapor recovery, you are not required 

to report emissions under this 

paragraph. 

(1) Annual CO2 emissions, in metric 

tons CO2.

(2) Annual CH4 emissions, in metric 

tons CH4.

(E) If the leak or vent is routed to 

flare, combustion, or vapor recovery, 

report the percentage of time that the 

respective device was operational when 

the compressor source emissions were 

routed to the device. 

(3) As found measurement sample 

data. If the measurement methods 

specified in § 98.233(o)(2) or (4) are 

conducted, report the information 

specified in paragraph (o)(3)(i) of this 

section. If the calculation specified in 

§ 98.233(o)(6)(ii) is performed, report 

the information specified in paragraph 

(o)(3)(ii) of this section. 

(i) For each as found measurement 

performed on a leak or vent, report the 

information specified in paragraphs 

(o)(3)(i)(A) through (F) of this section. 

(A) Name or ID of leak or vent. Use 

same leak or vent ID as in paragraph 

(o)(2)(i)(C) of this section. 

(B) Measurement date. 

(C) Measurement method. If emissions 

were not detected when using a 

screening method, report the screening 

method. If emissions were detected 

using a screening method, report only 

the method subsequently used to 

measure the volumetric emissions. 

(D) Measured flow rate, in standard 

cubic feet per hour. 

(E) For each compressor attached to 

the leak or vent, report the compressor 

mode during which the measurement 

was taken. 

(F) If the measurement is for a 

manifolded group of compressor 

sources, indicate whether the 

measurement location is prior to or after 

comingling with non-compressor 

emission sources. 

(ii) For each compressor mode-source 

combination where a reporter emission 

factor as calculated in Equation W–23 

was used to calculate emissions in 

Equation W–22, report the information 

specified in paragraphs (o)(3)(ii)(A) 

through (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 (EFs,m in 

Equation W–23). 

(C) The total number of compressors 

measured in the compressor modesource combination in the current 

reporting year and the preceding two 

reporting years (Countm in Equation W– 

23). 

(D) Indicate whether the compressor 

mode-source combination reporter 

emission factor is facility-specific or 

based on all of the reporter’s applicable 

facilities. 

(4) Continuous measurement data. If 

the measurement methods specified in 

§ 98.233(o)(3) or (5) are conducted, 

report the information specified in 

paragraphs (o)(4)(i) through (iv) of this 

section for each continuous 

measurement conducted on each leak or 

vent associated with each compressor 

source or manifolded group of 

compressor sources. 

(i) Name or ID of leak or vent. Use 

same leak or vent ID as in paragraph 

(o)(2)(i)(C) of this section. 

(ii) Measured volume of flow during 

the reporting year, in million standard 

cubic feet. 

(iii) Indicate whether the measured 

volume of flow during the reporting 

year includes compressor blowdown 

emissions as allowed for in 

§ 98.233(o)(3)(ii) and (o)(5)(iii). 

(iv) If the measurement is for a 

manifolded group of compressor 

sources, indicate whether the 

measurement location is prior to or after 

comingling with non-compressor 

emission sources. 

(5) Onshore petroleum and natural 

gas production. 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 

(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 (2) of this 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 (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 (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 (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 (xiv) of this section for 

each reciprocating compressor located 

at your facility. 


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(i) Unique name or ID for the 

reciprocating compressor. 

(ii) Hours in operating-mode. 

(iii) Hours in standby-pressurizedmode. 

(iv) Hours in not-operatingdepressurized-mode. 

(v) Indicate whether the compressor 

was measured in operating-mode. 

(vi) Indicate whether the compressor 

was measured in standby-pressurizedmode. 

(vii) Indicate whether the compressor 

was measured in not-operatingdepressurized-mode. 

(viii) Indicate which, if any, 

compressor sources are part of a 

manifolded group of compressor 

sources. 

(ix) Indicate which, if any, 

compressor sources are routed to a flare. 

(x) Indicate which, if any, compressor 

sources have vapor recovery. 

(xi) Indicate which, if any, 

compressor source emissions are 

captured for fuel use or are routed to a 

thermal oxidizer. 

(xii) Indicate whether the compressor 

has blind flanges installed and 

associated dates. 

(xiii) Power output of the compressor 

driver (hp). 

(xiv) Indicate whether the compressor 

had a scheduled depressurized 

shutdown during the reporting year. 

(2) Compressor source. (i) For each 

compressor source at each compressor, 

report the information specified in 

paragraphs (p)(2)(i)(A) through (C) of 

this section. 

(A) Reciprocating compressor name or 

ID. Use the same ID as in paragraph 

(p)(1)(i) of this section. 

(B) Reciprocating compressor source 

(isolation valve, blowdown valve, or rod 

packing). 

(C) Unique name or ID for the leak or 

vent. If the leak or vent is connected to 

a manifolded group of compressor 

sources, use the same leak or vent ID for 

each compressor source in the 

manifolded group. If multiple 

compressor sources are released through 

a single vent for which continuous 

measurements are used, use the same 

leak or vent ID for each compressor 

source released via the measured vent. 

For a single compressor using as found 

measurements, you must provide a 

different leak or vent ID for each 

compressor source. 

(ii) For each leak or vent, report the 

information specified in paragraphs 

(p)(2)(ii)(A) through (E) of this section. 

(A) Indicate whether the leak or vent 

is for a single compressor source or 

manifolded group of compressor sources 

and whether the emissions from the leak 

or vent are released to the atmosphere, 

routed to a flare, combustion (fuel or 

thermal oxidizer), or vapor recovery. 

(B) Indicate whether an as found 

measurement(s) as identified in 

§ 98.233(p)(2) or (4) was conducted on 

the leak or vent. 

(C) Indicate whether continuous 

measurements as identified in 

§ 98.233(p)(3) or (5) were conducted on 

the leak or vent. 

(D) Report emissions as specified in 

paragraphs (p)(2)(ii)(D)(1) and (2) of this 

section for the leak or vent. If the leak 

or vent is routed to flare, combustion, or 

vapor recovery, you are not required to 

report emissions under this paragraph. 

(1) Annual CO2 emissions, in metric 

tons CO2.

(2) Annual CH4 emissions, in metric 

tons CH4.

(E) If the leak or vent is routed to 

flare, combustion, or vapor recovery, 

report the percentage of time that the 

respective device was operational when 

the compressor source emissions were 

routed to the device. 

(3) As found measurement sample 

data. If the measurement methods 

specified in § 98.233(p)(2) or (4) are 

conducted, report the information 

specified in paragraph (p)(3)(i) of this 

section. If the calculation specified in 

§ 98.233(p)(6)(ii) is performed, report 

the information specified in paragraph 

(p)(3)(ii) of this section. 

(i) For each as found measurement 

performed on a leak or vent, report the 

information specified in paragraphs 

(p)(3)(i)(A) through (F) of this section. 

(A) Name or ID of leak or vent. Use 

same leak or vent ID as in paragraph 

(p)(2)(i)(C) of this section. 

(B) Measurement date. 

(C) Measurement method. If emissions 

were not detected when using a 

screening method, report the screening 

method. If emissions were detected 

using a screening method, report only 

the method subsequently used to 

measure the volumetric emissions. 

(D) Measured flow rate, in standard 

cubic feet per hour. 

(E) For each compressor attached to 

the leak or vent, report the compressor 

mode during which the measurement 

was taken. 

(F) If the measurement is for a 

manifolded group of compressor 

sources, indicate whether the 

measurement location is prior to or after 

comingling with non-compressor 

emission sources. 

(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 (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 (EFs,m in 

Equation W–28). 

(C) The total number of compressors 

measured in the compressor modesource 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 

based on all of the reporter’s applicable 

facilities. 

(4) Continuous measurement data. If 

the measurement methods specified in 

§ 98.233(p)(3) or (5) are conducted, 

report the information specified in 

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

section for each continuous 

measurement conducted on each leak or 

vent associated with each compressor 

source or manifolded group of 

compressor sources. 

(i) Name or ID of leak or vent. Use 

same leak or vent ID as in paragraph 

(p)(2)(i)(C) of this section. 

(ii) Measured volume of flow during 

the reporting year, in million standard 

cubic feet. 

(iii) Indicate whether the measured 

volume of flow during the reporting 

year includes compressor blowdown 

emissions as allowed for in 

§ 98.233(p)(3)(ii) and (p)(5)(iii). 

(iv) If the measurement is for a 

manifolded group of compressor 

sources, indicate whether the 

measurement location is prior to or after 

comingling with non-compressor 

emission sources. 

(5) Onshore petroleum and natural 

gas production. Reciprocating 

compressors in onshore petroleum and 

natural gas production must report the 

information specified in paragraphs 

(p)(5)(i) through (iii) of this section. 

(i) Number of reciprocating 

compressors. 

(ii) Annual CO2 emissions, in metric 

tons CO2, from reciprocating 

compressors. 

(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 (2) of this section. Natural gas 

distribution facilities with emission 

sources listed in § 98.232(i)(1) must also 

report the information specified in 

paragraph (q)(3) of this section. 


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(1) You must report the information 

specified in paragraphs (q)(1)(i) and (ii) 

of this section. 

(i) Except as specified in paragraph 

(q)(1)(ii) of this section, 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 

(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 (v) of this 

section but report a zero (‘‘0’’) for the 

information required according to 

paragraphs (q)(2)(iii), (iv), and (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 are assumed to be 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 as 

calculated using Equation W–30 (for 

surveyed components only). 

(v) Annual CH4 emissions, in metric 

tons CH4, for the component type as 

calculated using Equation W–30 (for 

surveyed components only). 

(3) Natural gas distribution facilities 

with emission sources listed in 

§ 98.232(i)(1) must also report the 

information specified in paragraphs 

(q)(3)(i) through (viii) and, if applicable, 

(q)(3)(ix) of this section. 

(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 

transmission-distribution transfer 

stations in the current leak survey cycle, 

in standard cubic feet of CO2 per 

operational hour of all meter/regulator 

runs (‘‘EFs,MR,i’’ for CO2 calculated using 

Equation W–31 of this subpart). 

(viii) Meter/regulator run CH4

emission factor based on all surveyed 

transmission-distribution transfer 

stations in the current leak survey cycle, 

in standard cubic feet of CH4 per 

operational hour of all meter/regulator 

runs (‘‘EFs,MR,i’’ for CH4 calculated using 

Equation W–31 of this subpart). 

(ix) If your natural gas distribution 

facility performs equipment leak 

surveys across a multiple year leak 

survey cycle, you must also report: 

(A) The total number of meter/

regulator runs at above grade 

transmission-distribution transfer 

stations at your facility (‘‘CountMR’’ in 

Equation W–32B of this subpart). 

(B) Average estimated time that each 

meter/regulator run at above grade 

transmission-distribution transfer 

stations was operational in the calendar 

year, in hours per meter/regulator run 

(‘‘Tw,avg’’ in Equation W–32B of this 

subpart). 

(C) Annual CO2 emissions, in metric 

tons CO2, for all above grade 

transmission-distribution transfer 

stations at your facility. 

(D) Annual CH4 emissions, in metric 

tons CH4, for all above grade 

transmission-distribution transfer 

stations at your facility. 

(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 

paragraphs (r)(1) through (3) of this 

section, as applicable. 

(1) You must indicate whether your 

facility contains any of the emission 

source types required to use Equation 

W–32A of this subpart. You must report 

the information specified in paragraphs 

(r)(1)(i) through (v) of this section 

separately for each emission source type 

required to use Equation W–32A of this 

subpart that is located at your facility. 

Onshore petroleum and natural gas 

production facilities must report the 

information specified in paragraphs 

(r)(1)(i) through (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. 

(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 (r)(2)(i) through 

(v) of this section. 

(i) Number of above grade 

transmission-distribution transfer 

stations at the facility. 

(ii) Number of above grade meteringregulating stations that are not 

transmission-distribution transfer 

stations at the facility. 

(iii) 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). 

(iv) Average estimated time that each 

meter/regulator run at above grade 

metering-regulating stations that are not 

above grade transmission-distribution 

transfer stations was operational in the 

calendar year, in hours per meter/

regulator run (‘‘Tw,avg’’ in Equation W– 

32B of this subpart). 

(v) If your facility has above grade 

metering-regulating stations that are not 

above grade transmission-distribution 

transfer stations and your facility also 

has above grade transmissiondistribution transfer stations, you must 

also report: 

(A) Annual CO2 emissions, in metric 

tons CO2, from above grade meteringregulating stations that are not above 

grade transmission-distribution transfer 

stations. 

(B) Annual CH4 emissions, in metric 

tons CH4, from above grade metering 

regulating stations that are not above 

grade transmission-distribution transfer 

stations. 


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(3) Onshore petroleum and natural gas 

production facilities must also report 

the information specified in paragraphs 

(r)(3)(i) and (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 (B) of this section, for 

each major equipment 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 (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 

(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. 

(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 W–37 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 (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] 

(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 (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 (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, 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 (vi) of this 

section 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 (2). 

(v) Annual CH4 emissions, in metric 

tons CH4, calculated according to 

§ 98.233(z)(1) and (2). 

(vi) Annual N2O emissions, in metric 

tons N2O, calculated according to 

§ 98.233(z)(1) and (2). 

(aa) Each facility must report the 

information specified in paragraphs 

(aa)(1) through (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 (ii) of this 

section. 

(i) Report the information specified in 

paragraphs (aa)(1)(i)(A) through (C) 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 

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 and 

condensate produced in the calendar 

year for sales, in barrels. 

(ii) Report the information specified 

in paragraphs (aa)(1)(ii)(A) through (M) 

of this section for each unique sub-basin 

category. 

(A) State. 

(B) County. 

(C) Formation type. 


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70424 Federal Register / Vol. 79, No. 227 / Tuesday, November 25, 2014 / Rules and Regulations 

(D) The number of producing wells at 

the end of the calendar year (exclude 

only those wells permanently taken out 

of production, i.e., plugged and 

abandoned) . 

(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 permanently 

taken out of production (i.e., plugged 

and abandoned) 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. 

(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) and (ii) of this section. 

(i) The total quantity of gas handled 

at the offshore platform in the calendar 

year, in thousand standard cubic feet, 

including production volumes and 

volumes transferred via pipeline from 

another location. 

(ii) The total quantity of oil and 

condensate handled at the offshore 

platform in the calendar year, in barrels, 

including production volumes and 

volumes transferred via pipeline from 

another location. 

(3) For natural gas processing, report 

the information specified in paragraphs 

(aa)(3)(i) through (vii) of this section. 

(i) The quantity of natural 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 cumulative quantity of all 

NGLs (bulk and fractionated) received at 

the gas processing plant in the calendar 

year, in barrels. 

(iv) The cumulative quantity of all 

NGLs (bulk and fractionated) leaving the 

gas processing plant in the calendar 

year, in barrels. 

(v) Average mole fraction of CH4 in 

natural gas received. 

(vi) Average mole fraction of CO2 in 

natural gas received. 

(vii) Indicate whether the facility 

fractionates NGLs. 

(4) For natural gas transmission 

compression, report the quantity 

specified in paragraphs (aa)(4)(i) 

through (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 (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 (iii) of this section. 

(i) The quantity of LNG added into 

storage in the calendar year, in thousand 

standard cubic feet. 

(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 (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 

§ 98.3(c)(8) except as provided in 

paragraphs (bb)(1) and (2) of this 

section. 

(1) For quarterly measurements, 

report the total number of quarters that 

a missing data procedure was used for 

each data element rather than the total 

number of hours. 

(2) For annual or biannual (once every 

two years) measurements, you do not 

need to report the number of hours that 

a missing data procedure was used for 

each data element. 

(cc) If you elect to delay reporting the 

information in paragraph (g)(5)(i), 

(g)(5)(ii), (h)(1)(iv), (h)(2)(iv), (j)(1)(iii), 

(j)(2)(i)(A), (l)(1)(iv), (l)(2)(iv), (l)(3)(iii), 

(l)(4)(iii), (m)(5), or (m)(6) of this 

section, you must report the information 

required in that paragraph no later than 

the date 2 years following the date 

specified in § 98.3(b) introductory text. 

■ 9. Section 98.237 is amended by 

adding paragraph (f) to read as follows: 

§ 98.237 Records that must be retained. 

* * * * * 

(f) For each time a missing data 

procedure was used, keep a record 

listing the emission source type, a 

description of the circumstance that 

resulted in the need to use missing data 

procedures, the missing data provisions 

in § 98.235 that apply, the calculation or 

analysis used to develop the substitute 

value, and the substitute value. 

■ 10. Section 98.238 is amended by: 

■ a. Adding a definition for ‘‘Associated 

gas venting or flaring’’ in alphabetical 

order; 

■ b. Removing the definition for 

‘‘Component’’; 

■ c. Adding definitions for ‘‘Compressor 

mode’’ and ‘‘Compressor source’’ in 

alphabetical order; 

■ d. Removing the definitions for 

‘‘Equipment leak’’ and ‘‘Equipment leak 

detection’’; 

■ e. Adding definitions for ‘‘Manifolded 

compressor source’’ and ‘‘Manifolded 

group of compressor sources’’ in 

alphabetical order; 

■ f. Revising the definition for ‘‘Meter/ 

regulator run’’; 


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Federal Register / Vol. 79, No. 227 / Tuesday, November 25, 2014 / Rules and Regulations 70425 

■ g. Adding definitions for ‘‘Reduced 

emissions completion’’ and ‘‘Reduced 

emissions workover’’ in alphabetical 

order; and 

■ h. Revising the definition for ‘‘Subbasin 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-operatingdepressurized-mode. For a reciprocating 

compressor, ‘‘mode’’ refers to either: 

Operating-mode, standby-pressurizedmode, or not-operating-depressurizedmode. 

Compressor source means the source 

of certain venting or leaking emissions 

from a centrifugal or reciprocating 

compressor. For centrifugal 

compressors, ‘‘source’’ refers to 

blowdown valve leakage through the 

blowdown vent, unit isolation valve 

leakage through an open blowdown vent 

without blind flanges, and wet seal oil 

degassing vents. For reciprocating 

compressors, ‘‘source’’ refers to 

blowdown valve leakage through the 

blowdown vent, unit isolation valve 

leakage through an open blowdown vent 

without blind flanges, and rod packing 

emissions. 

* * * * * 

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. 

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, in 

the natural gas distribution industry 

segment. At least one meter, at least one 

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 emissions 

from the gas outlet of the separator that 

are otherwise vented are 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 de minimis 

direct venting to the atmosphere. Short 

periods of flaring during a reduced 

emissions completion may occur. 

Reduced emissions workover means a 

well workover with hydraulic fracturing 

(i.e., refracturing) where gas flowback 

emissions from the gas outlet of the 

separator that are otherwise vented are 

captured, cleaned, and routed to the 

flow line or collection system, reinjected 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 de minimis direct venting to 

the atmosphere. Short periods of flaring 

during a reduced emissions workover 

may occur. 

* * * * * 

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 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. 

* * * * * 

[FR Doc. 2014–27681 Filed 11–24–14; 8:45 am] 

BILLING CODE 6560–50–P 


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