Vol. 80 Thursday, 

No. 204 October 22, 2015 

Part V 

Environmental Protection Agency 

40 CFR Part 98 

Greenhouse Gas Reporting Rule: 2015 Revisions and Confidentiality 

Determinations for Petroleum and Natural Gas Systems; Final Rule 


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64262 Federal Register / Vol. 80, No. 204 / Thursday, October 22, 2015 / Rules and Regulations 

ENVIRONMENTAL PROTECTION 

AGENCY 

40 CFR Part 98 

[EPA–HQ–OAR–2014–0831; FRL–9935–50– 

OAR] 

RIN 2060–AS37 

Greenhouse Gas Reporting Rule: 2015 

Revisions and Confidentiality 

Determinations for Petroleum and 

Natural Gas Systems 

AGENCY: Environmental Protection 

Agency (EPA). 

ACTION: Final rule. 

SUMMARY: The Environmental Protection 

Agency (EPA) is finalizing revisions and 

confidentiality determinations for the 

petroleum and natural gas systems 

source category of the Greenhouse Gas 

Reporting Rule. These revisions include 

the addition of calculation methods and 

reporting requirements for greenhouse 

gas (GHG) emissions from gathering and 

boosting facilities, completions and 

workovers of oil wells with hydraulic 

fracturing, and blowdowns of natural 

gas transmission pipelines between 

compressor stations. The revisions also 

include the addition of well 

identification reporting requirements to 

improve the EPA’s ability to verify 

reported data and enhance 

transparency. This action also finalizes 

confidentiality determinations for new 

data elements contained in these 

amendments. 

DATES: This final rule is effective on 

January 1, 2016. 

ADDRESSES: The EPA has established a 

docket for this action under Docket ID 

No. EPA–HQ–OAR–2014–0831. All 

documents in the docket are listed on 

the http://www.regulations.gov Web 

site. Although listed in the index, some 

information is not publicly available, 

e.g., confidential business information 

(CBI) or other information whose 

disclosure is restricted by statute. 

Certain other material, such as 

copyrighted material, is not placed on 

the Internet and will be publicly 

available only in hard copy form. 

Publicly available docket materials are 

available electronically through http://

www.regulations.gov. 

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 

adds calculation methods, monitoring, 

and data reporting requirements and 

finalizes confidentiality determinations 

for the petroleum and natural gas 

systems source category 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 

GHGs, which include those listed in 

Table 1 of this preamble: 

TABLE 1—EXAMPLES OF AFFECTED ENTITIES BY CATEGORY

Category NAICSa 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. 

a North American Industry Classification System. 

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, 2016. 

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 December 21, 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 


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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 

e-GGRT Electronic Greenhouse Gas 

Reporting Tool 

EPA U.S. Environmental Protection Agency 

FERC Federal Energy Regulatory 

Commission 

FR Federal Register 

ft3 cubic feet 

GHG greenhouse gas 

GHGRP Greenhouse Gas Reporting Program 

GOR gas to oil ratio 

GRI Gas Research Institute 

ICR information collection request 

ID identification 

LDC local distribution company 

N2O nitrous oxide 

NAICS North American Industry 

Classification System 

NGO non-government organization 

NGPA Natural Gas Policy Act 

NTTAA National Technology Transfer and 

Advancement Act 

O&M operation and maintenance 

OMB Office of Management and Budget 

PHMSA Pipeline and Hazardous Materials 

Safety Administration 

psi/ft pounds per square inch per foot 

REC reduced emissions completion 

RFA Regulatory Flexibility Act 

scf standard cubic feet 

scf/STB standard cubic feet per stock tank 

barrel 

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 

2015 and 2016 reports? 

II. Summary of Final Revisions and Other 

Amendments to Subpart W and 

Responses to Public Comment 

A. Summary of Final Amendments for Oil 

Wells With Hydraulic Fracturing 

B. Summary of Final Amendments for the 

Onshore Petroleum and Natural Gas 

Gathering and Boosting Segment 

C. Summary of Final Amendments for the 

Onshore Natural Gas Transmission 

Pipeline Segment 

D. Summary of Final Amendments for Well 

Identification Numbers 

E. Summary of Final Amendments to Best 

Available Monitoring Methods 

III. Final Confidentiality Determinations 

A. Summary of Final Confidentiality 

Determinations for New 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 

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 

(hereafter 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 amendments to part 98, subpart W 

(Petroleum and Natural Gas Systems) 

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

including a summary of the major 

comments that the EPA considered in 

the development of this final rule. 

Section III of this preamble discusses 

the final confidentiality determinations 

for new data reporting elements. 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 

The EPA’s Greenhouse Gas Reporting 

Program (GHGRP) requires annual 

reporting of GHG data and other 

relevant information from large sources 

and suppliers in the United States. On 

October 30, 2009, the EPA published 

part 98 for collecting information 

regarding GHG emissions from a broad 

range of industry sectors (74 FR 56260). 

Although reporting requirements for 

petroleum and natural gas systems were 

originally proposed to be part of part 98 

(75 FR 16448; April 10, 2009), the final 

October 2009 rule did not include the 

petroleum and natural gas systems 

source category as one of the 29 source 

categories for which reporting 

requirements were finalized. The EPA 

re-proposed subpart W in 2010 (79 FR 

18608; April 12, 2010), and a 

subsequent final rule was published on 

November 30, 2010, with the 

requirements for the petroleum and 

natural gas systems source category at 

40 CFR part 98, subpart W (75 FR 

74458) (hereafter referred to as ‘‘the 

final subpart W rule’’). Following 

promulgation, the EPA finalized actions 

revising subpart W (76 FR 22825, April 

25, 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; 79 FR 70352, 

November 25, 2014). 

On December 9, 2014, the EPA 

proposed ‘‘2015 Revisions and 

Confidentiality Determinations for 

Petroleum and Natural Gas Systems’’ 

(79 FR 76267) to require the reporting of 

GHG emissions from several sources 

that had not previously been included 

in subpart W. These sources include 

completions and workovers of oil wells 

with hydraulic fracturing, petroleum 

and natural gas gathering and boosting 

systems, and transmission pipeline 

blowdowns between compressor 

stations. The reporting requirements for 

completions and workovers of oil wells 

with hydraulic fracturing were proposed 

to be included as part of the existing 

Onshore Petroleum and Natural Gas 

Production industry segment. For the 

other sources, the EPA proposed two 

new industry segments: The Onshore 

Petroleum and Natural Gas Gathering 

and Boosting segment for petroleum and 

natural gas gathering and boosting 

facilities, and the Onshore Natural Gas 

Transmission Pipeline segment for 

transmission pipeline blowdowns 

between compressor stations. The EPA 

also proposed to require the reporting of 

a well identification number for oil and 

gas wells covered in the Onshore 

Petroleum and Natural Gas Production 

segment. In addition, the EPA proposed 

confidentiality determinations for new 

data elements contained in the proposed 

amendments. The public comment 

period for these proposed rule 

amendments ended on February 24, 

2015, following a 2-week extension of 

the original comment period end date 

(80 FR 6495; February 5, 2015). 


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64264 Federal Register / Vol. 80, No. 204 / Thursday, October 22, 2015 / Rules and Regulations 

1Climate Action Plan—Strategy to Reduce 

Methane Emissions. The White House, Washington, 

DC, March 2014. Available at http://

www.whitehouse.gov/sites/default/files/strategy_to_

reduce_methane_emissions_2014-03-28_final.pdf. 

2Petition for Rulemaking and Interpretive 

Guidance Ensuring Comprehensive Coverage of 

Methane Sources Under Subpart W of the 

Greenhouse Gas Reporting Rule—Petroleum And 

Natural Gas Systems; Submitted by Clean Air Task 

Force, Environmental Defense Fund, Natural 

Resources Defense Council, and Sierra Club; March 

19, 2013. Docket Item No. EPA–HQ–OAR–2014– 

0831–0005. 

In this action, the EPA is finalizing 

additions and revisions to the subpart W 

calculation, monitoring, and reporting 

requirements for new sources, with 

some changes made in response to 

public comments. Responses to 

comments submitted on the proposed 

amendments can be found in sections II, 

III, and IV of this preamble as well as 

in ‘‘Response to Public Comments on 

Greenhouse Gas Reporting Rule: 2015 

Revisions and Confidentiality 

Determinations for Petroleum and 

Natural Gas Systems’’ in Docket ID No. 

EPA–HQ–OAR–2014–0831. As noted in 

the preamble to the proposed 

amendments (79 FR 73148; December 9, 

2014), these additions and revisions 

further the EPA’s goals of improving the 

completeness, quality, accuracy, and 

transparency of data from this sector, 

and improving the ability of agencies 

and the public to use these GHG data to 

analyze emissions and understand 

emission trends. 

The Strategy to Reduce Methane 

Emissions in the President’s Climate 

Action Plan summarizes the sources of 

methane (CH4) emissions, commits to 

new steps to cut emissions of this potent 

GHG, and outlines the Administration’s 

efforts to improve the measurement of 

these emissions. The strategy builds on 

progress to date and takes steps to 

further cut CH4 emissions from several 

sectors, including the oil and natural gas 

sector. In the strategy, the EPA was 

tasked to review regulatory 

requirements to address potential gaps 

in coverage, improve methods, and help 

ensure high quality data reporting.1 The 

final revisions to subpart W covered in 

this action are responsive to this task by 

addressing data gaps in subpart W, 

specifying methods for measuring CH4

emissions, and providing data that can 

be used to further analyze CH4

emissions in this industry. 

This action also addresses a petition 

the EPA received from a group of nongovernment organizations (NGOs) 

requesting that the EPA collect data 

from emissions sources not currently 

included in subpart W, including well 

completion emissions from oil wells 

that co-produce natural gas, facilities 

and pipelines in the gathering and 

boosting segment, and transmission 

pipeline blowdown events (‘‘Petition for 

Rulemaking’’).2 Table 2 of this preamble 

summarizes how the EPA has 

responded to the Petition for 

Rulemaking. These revisions, and 

previously finalized revisions where 

noted in Table 2, reflect the EPA’s 

complete response to the Petition for 

Rulemaking. It is our position that we 

have fully responded to the NGO 

petition, however, any requests 

included in the petition that have not 

been responded to in Table 2 are 

considered denied. 

TABLE 2—EPA RESPONSE TO PETITION FOR RULEMAKING

Request in petition EPA’s response Final rule citations 

(40 CFR) 

Clarify that oil wells that co-produce natural gas (‘‘coproducing wells’’), specifically wells in tight-oil formations like the Bakken and Eagle Ford, are subject to 

the completion reporting requirements as currently 

written. Expand the well completion reporting requirements to all wells, ensuring co-producing wells in any 

formation type are required to report completion emissions.

The EPA is not changing the definition of ‘‘gas well’’ or 

‘‘oil well.’’ Instead, the EPA is amending subpart W to 

require the reporting of GHG emissions from completions and workovers with hydraulic fracturing for wells 

in the Onshore Petroleum and Natural Gas Production segment, regardless of whether their primary 

product is oil or natural gas.

98.232(c)(6) 

98.232(c)(8) 

98.236(g) 

Require reporting from facilities and pipelines in the 

gathering and boosting segment of the natural gas industry.

The EPA is finalizing the proposal to amend subpart W 

to add a new industry segment, Onshore Petroleum 

and Natural Gas Gathering and Boosting, which covers emissions from equipment used by gathering 

pipeline systems that move petroleum and natural 

gas from the well to either larger gathering pipeline 

systems, natural gas processing plants, natural gas 

transmission pipelines, or natural gas distribution 

pipelines.

98.230(a)(9) 

98.232(j) 

98.233 (various) 

98.236(a)(9) 

Require reporting from transmission pipeline blowdown 

events.

The EPA is finalizing the proposal to add reporting requirements for emissions from natural gas transmission pipeline blowdowns between compressor 

stations in a new Onshore Natural Gas Transmission 

Pipeline segment.

98.230(a)(10) 

98.232(m) 

98.236(aa)(11) 

Require reporters to include API well identification numbers along with their submissions to help the public 

and policymakers understand which sources are reporting and how the threshold may be adjusted to 

most effectively provide emissions information.

The EPA is requiring the reporting of well identification 

numbers for the Onshore Petroleum and Natural Gas 

Production segment for information related specifically to wells.

98.236(f), (g), (h), (l), and 

(m) 

98.238 

Phase out the use of best available monitoring methods 

(BAMM), which will further help to ensure Subpart W 

data are rigorous, and comprehensive.

Prior to these amendments, BAMM was discontinued 

for all sources except specific sources that were affected by the amendments finalized on November 25, 

2014 (79 FR 70352); those BAMM provisions will be 

unavailable after December 31, 2015. Reporters will 

be allowed to use BAMM for the 2016 reporting year 

for only the new industry segments and emission 

sources included in this action. The EPA is not allowing the use of BAMM beyond 2016.

98.234(f) and (g) 


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TABLE 2—EPA RESPONSE TO PETITION FOR RULEMAKING—Continued 

Request in petition EPA’s response Final rule citations 

(40 CFR) 

Consider including advanced innovative monitoring 

methods as a way to accelerate development and deployment of real-time continuous CH4 emission monitoring in the oil and natural gas sector.

The agency is assessing the potential opportunities for 

application of remote sensing technologies and other 

innovations in measurement or monitoring technology 

to identifying and calculating emissions from affected 

sources under subpart W and requested comment in 

the proposal. The EPA received multiple comments 

in response to the request for comments on the feasibility, possible regulatory approaches, and provisions necessary to incorporate or allow the use of 

advanced measurement or monitoring methods in 

subpart W. All of the comments received are included in ‘‘Response to Public Comments on Greenhouse Gas Reporting Rule: 2015 Revisions and Confidentiality Determinations for Petroleum and Natural 

Gas Systems’’ in Docket ID No. EPA–HQ–OAR– 

2014–0831. The EPA is not including provisions related to advanced measurement or monitoring methods in this rule and is not responding to these comments in this rulemaking. Instead, following review of 

the data and information received in comments, the 

EPA may propose amendments related to the use of 

innovative technologies in reporting to the GHGRP in 

a future rulemaking.

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 data 

elements 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 

2015 and 2016 reports? 

These amendments are effective on 

January 1, 2016. Thus, beginning on 

January 1, 2016, facilities must follow 

the revised methods in subpart W, as 

amended, to calculate emissions 

occurring during the 2016 calendar year 

(i.e., reporting year 2016). The first 

annual reports of emissions calculated 

using the amended requirements will be 

those submitted by March 31, 2017, 

covering reporting year 2016. For 

reporting year 2015, 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 reporting year 2015 (i.e., 

the requirements in place until the 

effective date of this final rule). 

For reporting year 2016 only, we are 

allowing the use of best available 

monitoring methods (BAMM) on a 

short-term transitional basis for facilities 

new to reporting under subpart W as 

well as reporters of facilities subject to 

new monitoring requirements associated 

with these revisions. Reporters have the 

option of using BAMM for only the new 

industry segments and emission sources 

included in this action from January 1, 

2016, to December 31, 2016, without 

seeking prior EPA approval. The EPA 

will not accept requests for an extension 

for the use of BAMM beyond the time 

periods listed above. The EPA is not 

allowing the use of BAMM for the new 

well identification number provisions in 

the Onshore Petroleum and Natural Gas 

Production segment because the well 

identification number is not a parameter 

that requires monitoring equipment to 

be measured and, therefore, does not 

meet the requirements for BAMM. In 

addition, reporters should already have 

well identification numbers readily 

available for all wells and associated 

equipment to which this reporting 

requirement applies. See section II.E of 

this preamble for more information. 

II. Summary of Final Revisions and 

Other Amendments to Subpart W and 

Responses to Public Comment 

In this action, the EPA is amending 

subpart W to require the reporting of 

GHG emissions from completions and 

workovers of oil wells with hydraulic 

fracturing as part of the existing 

Onshore Petroleum and Natural Gas 

Production industry segment. The EPA 

is also adding requirements for two new 

industry segments: the Onshore 

Petroleum and Natural Gas Gathering 

and Boosting segment for petroleum and 

natural gas gathering and boosting 

systems, and the Onshore Natural Gas 

Transmission Pipeline segment for 

transmission pipeline blowdowns 

between compressor stations. Finally, 

the EPA is requiring the reporting of 

well identification numbers for oil and 

gas well-specific information (e.g., 

completions and workovers, associated 

gas venting and flaring) reported in the 

Onshore Petroleum and Natural Gas 

Production segment. The comments 

received on this rule generally did not 

dispute the merit of adding these new 

segments and sources to subpart W, but 

they did provide a number of 

suggestions regarding the technical 

details of monitoring, reporting, and 

applicability. 

Sections II.A through II.E of this 

preamble describe the requirements and 

other amendments that we are finalizing 

in this rulemaking. Section II.A 

describes the final amendments for the 


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3Within subpart W, an individual well is labeled 

an ‘‘oil well’’ or ‘‘gas well’’ depending on the 

formation type reported for that well. If wells 

produce from more than one formation type, then 

the well is classified into only one type based on 

the formation type with the most contribution to 

production as determined by the reporter’s 

engineering knowledge. See the definition of ‘‘Subbasin category, for onshore natural gas production’’ 

in 40 CFR 98.238. 

reporting of GHG emissions from 

completions and workovers of oil wells 

with hydraulic fracturing. Section II.B 

describes the final amendments for the 

reporting of GHG emissions from 

sources in the new Onshore Petroleum 

and Natural Gas Gathering and Boosting 

segment. Section II.C describes the final 

amendments for the reporting of GHG 

emissions from sources in the new 

Onshore Natural Gas Transmission 

Pipeline segment. Section II.D describes 

the requirements for reporting well 

identification numbers for the Onshore 

Petroleum and Natural Gas Production 

segment. Finally, section II.E provides a 

summary of the final amendments to the 

best available monitoring method 

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 ‘‘Response to Public 

Comments on Greenhouse Gas 

Reporting Rule: 2015 Revisions and 

Confidentiality Determinations for 

Petroleum and Natural Gas Systems’’ in 

Docket ID No. EPA–HQ–OAR–2014– 

0831 for a complete listing of all 

comments and the EPA’s responses. 

Finally, in the preamble to the 

proposed rule, the EPA stated that the 

agency is ‘‘assessing the potential 

opportunities for applying remote 

sensing technologies and other 

innovations in measurement or 

monitoring technology to identifying 

and calculating emissions from affected 

sources under subpart W’’ (79 FR 73148; 

December 9, 2014). The EPA did not 

propose, and therefore is not finalizing, 

any amendments to subpart W to this 

effect, but the EPA did request comment 

on the feasibility, possible regulatory 

approaches, provisions necessary to 

incorporate or allow the use of 

advanced measurement or monitoring 

methods in subpart W, and methods to 

ensure compliance with those 

provisions in an efficient manner. The 

EPA also requested comment on the 

memorandum ‘‘Discussion Paper on 

Potential Implementation of Alternative 

Monitoring under the GHGRP’’ in 

Docket ID No. EPA–HQ–OAR–2014– 

0831. All of the comments received are 

included in ‘‘Response to Public 

Comments on Greenhouse Gas 

Reporting Rule: 2015 Revisions and 

Confidentiality Determinations for 

Petroleum and Natural Gas Systems’’ in 

Docket ID No. EPA–HQ–OAR–2014– 

0831. The EPA will consider these 

comments in the context of any future 

action related to alternative monitoring. 

The amendments in this action will 

advance EPA’s goal of maximizing rule 

effectiveness. For example, these 

amendments provide clear monitoring, 

calculation and reporting requirements 

for new segments and sources in subpart 

W, thus enabling government, regulated 

entities, and the public to easily identify 

and understand rule requirements. In 

addition, specific changes such as 

increasing the flexibility and time 

period for transitional BAMM will make 

compliance easier than non-compliance. 

These amendments will also improve 

the EPA’s ability to assess compliance 

by adding reporting elements that allow 

the EPA to more thoroughly verify 

greenhouse gas data and understand 

trends in emissions. For example, the 

requirement for the Onshore Petroleum 

and Natural Gas Production segment to 

report well identification numbers will 

allow the EPA to link GHGRP data with 

other data sources and assess the 

completeness and representativeness of 

the data collected relative to all activity 

in the U.S. oil and gas production 

sector. Lastly, these amendments further 

advance the ability of the GHGRP to 

provide access to quality data on 

greenhouse gas emissions by adding key 

petroleum and natural gas emission 

sources to this program. One example is 

the addition of the Onshore Petroleum 

and Natural Gas Gathering and Boosting 

segment, a significant greenhouse gas 

emissions segment that had not been 

previously covered under the GHGRP. 

A. Summary of Final Amendments for 

Oil Wells With Hydraulic Fracturing 

1. Summary of Final Amendments 

The EPA is amending subpart W to 

require the reporting of GHG emissions 

from completions and workovers with 

hydraulic fracturing for wells in the 

Onshore Petroleum and Natural Gas 

Production segment, regardless of 

whether their primary product is oil or 

natural gas. In general, commenters 

supported inclusion of emissions from 

completions and workovers of oil wells 

with hydraulic fracturing in subpart W, 

and a few commenters provided 

targeted technical edits and suggestions 

for this source. Consistent with the 

requirements for completions and 

workovers of gas wells with hydraulic 

fracturing, and consistent with the 

proposed requirements, the new 

provisions include the reporting of 

activity data on the number of 

completions and workovers of oil wells 

with hydraulic fracturing and on the use 

of flaring and reduced emission 

completions (RECs). In response to 

public comments, the final monitoring 

and reporting amendments do not apply 

to completions and workovers of oil 

wells with hydraulic fracturing that 

have a gas to oil ratio (GOR) of less than 

300 standard cubic feet per stock tank 

barrel (scf/STB). 

The EPA is also amending the 

equations and definitions in 40 CFR 

98.233(g) to reflect applicability to 

completions and workovers of all gas 

and oil wells with hydraulic fracturing. 

As in the proposal, the final 

amendments require the use of either 

Equation W–10A or W–10B for 

calculating GHG emissions from 

completions and workovers of oil wells 

with hydraulic fracturing. Equation W– 

10A is used to calculate emissions from 

wells using inputs obtained from a 

representative sample of wells within a 

sub-basin and the ratio of the gas 

flowback rate to the production flow 

rate, and Equation W–10B is used to 

calculate emissions using inputs 

obtained from all wells within a subbasin and the flow rate and flow volume 

of the gas vented or flared. As proposed, 

the EPA is finalizing that emissions be 

calculated and reported separately for 

gas wells and oil wells by sub-basin and 

well type combination.3 Furthermore, as 

proposed, the final amendments require 

the use of Calculation Method 1 for 

calculating inputs to Equations W–12A 

and W–12B for oil wells. Calculation 

Method 1 relies on direct measurement 

of gas flow rate during flowback to 

develop calculation inputs; the 

requirements for the location of the flow 

meter used to measure the gas flow rate 

for oil wells are the same as the location 

requirements for gas wells. Other 

provisions that apply to completions 

and workovers of gas wells with 

hydraulic fracturing also apply to 

completions and workovers of oil wells 

with hydraulic fracturing, including the 

determination of wells that constitute a 

representative sample for use in 

Equation W–10A. 

For oil wells that do not meter gas 

production, such as some wells with a 

relatively low GOR, the EPA is adding 

a new Equation W–12C as proposed to 

calculate, rather than measure, the value 

of PRs,p (the average gas production flow 

rate during the first 30 days of 

production after the completion or 

workover), which is used as an input to 

Equation W–10A. In this Equation W– 

12C, the value of PRs,p is calculated by 

multiplying the GOR of the well by the 

measured oil production rate over the 


tkelley on DSK3SPTVN1PROD with RULES3
Federal Register / Vol. 80, No. 204 / Thursday, October 22, 2015 / Rules and Regulations 64267 

4 In this analysis, all hydrocarbon production in 

the liquid state at the wellhead was considered oil. 

J. Lieskovsky and S. Gorgen. ‘‘Drilling often results 

in both oil and natural gas production.’’ Today in 

Energy, U.S. Energy Information Administration, 

October 29, 2013. http://www.eia.gov/todayin

energy/detail.cfm?id=13571. Accessed June 9, 2015. 

5M.P. Walsh. ‘‘Oil Reservoir Primary Drive 

Mechanisms.’’ In Petroleum Engineering Handbook, 

Volume V: Reservoir Engineering and Petrophysics, 

E.D. Holstein (Ed.), L.W. Lake (Ed. in Chief), pp. V– 

895–980. Society of Petroleum Engineers, 2007. 

first 30 days of production after the 

completion or workover. 

2. Summary of Comments and 

Responses 

Comment: Several commenters 

responded to the EPA’s request for 

comment on whether to establish a 

minimum GOR threshold such that oil 

wells with a very low GOR would not 

be subject to the monitoring and 

reporting requirements for GHG 

emissions from completions and 

workovers with hydraulic fracturing. 

Most of these commenters supported 

establishment of a cutoff for wells with 

very low emissions. One commenter 

urged the EPA to require monitoring 

and reporting for all completions and 

workovers with hydraulic fracturing but 

stated that if a threshold is set, it should 

be set at a level that ensures that all 

significant emissions sources are 

included and that sources are able to 

clearly determine whether they are 

required to report. Three commenters 

supported setting a minimum GOR 

threshold. One commenter suggested a 

minimum GOR threshold of 300 and 

stated that, based on industry 

experience, oil wells with GOR values 

less than 300 do not have sufficient gas 

to operate a separator. The second 

commenter agreed that operators should 

only have to monitor and report 

emissions if the GOR is great enough to 

operate a separator and direct 

measurement is possible. The third 

commenter supporting a minimum GOR 

threshold did not provide a suggestion 

for a specific numeric threshold but 

stated that the emissions from wells 

with a low GOR are insignificant, and 

the time and resources involved in 

measuring the flowback and reporting 

emissions for wells expected to have 

minimal emissions would outweigh any 

contribution of these emissions to the 

overall source category totals. This 

commenter supported the inclusion of a 

threshold so that only significant 

sources of emissions would be included. 

Response: The EPA agrees that 

including a minimum GOR threshold 

will help minimize reporting burden 

while still capturing most of the 

emissions from this source. Energy 

Information Administration data show 

that the number of ‘‘oil only’’ wells 

drilled from 2007–2012 was less than 20 

percent of all new wells.4 These wells 

would have a GOR approaching zero 

and, therefore, would be expected to 

have low emissions. We believe that 

having no threshold may create an 

unnecessary burden for operators to 

report emissions for these wells with 

just a trace of gas. Given that the EPA 

is finalizing the proposed requirement 

that the oil well flow meter be located 

downstream of the separator, the 

separator must be operating for the 

owner or operator to be able to measure 

the flow rate and estimate emissions 

from completions and workovers of oil 

wells with hydraulic fracturing. One 

commenter, an industry trade 

association, suggested a threshold of 300 

scf/STB based on the industry trade 

association’s experience that separators 

typically do not operate at a GOR less 

than 300 scf/STB. 

The primary concern when 

determining the level for a threshold is 

volatility; the threshold must be low 

enough that the oil produced is 

considered non-volatile. Non-volatile 

‘‘black oils’’ (i.e., oil likely to not have 

gases or light hydrocarbons associated 

with it) are generally defined as having 

GOR values in the range of 200 to 900 

scf/STB.5 Oil wells with a GOR less than 

the 300 scf/STB suggested by the 

commenter are at the lower end of this 

range, and completions and workovers 

with hydraulic fracturing of these wells 

will not likely have enough gas 

associated that can be separated. 

Therefore, the final monitoring and 

reporting requirements do not apply to 

completions and workovers of oil wells 

with hydraulic fracturing that have a 

GOR of less than 300 scf/STB. 

Comment: Several commenters 

responded to the EPA’s request for 

comment on whether to establish a 

minimum well pressure threshold such 

that oil wells with a very low well 

pressure would not be subject to the 

monitoring and reporting requirements 

for GHG emissions from completions 

and workovers with hydraulic 

fracturing. Most of these commenters 

supported establishment of a cutoff for 

wells with very low well pressure. One 

commenter urged the EPA to require 

monitoring and reporting for all 

completions and workovers with 

hydraulic fracturing but stated that if a 

threshold is set, it should be set at a 

level that ensures that all significant 

emissions sources are included and that 

sources are able to clearly determine 

whether they are required to report. 

Three commenters supported setting a 

minimum well pressure threshold. One 

commenter suggested a minimum well 

pressure threshold of 0.4645 pounds per 

square inch per foot (psi/ft) because this 

is the vertical pressure gradient needed 

for a well to flow back, based on 

experience with the Natural Gas STAR 

program. The second commenter 

suggested that operators should only 

have to monitor and report emissions if 

the pressure of the reservoir during oil 

well completions and workovers is 

greater than the pressure gradient of 

0.433 psi/ft and noted that the pressure 

needed varies based on the density of 

the materials in the column and the 

depth of the well. The third commenter 

supporting a minimum well pressure 

threshold did not provide a suggestion 

for a threshold but supported the 

inclusion of a threshold so that only 

significant sources of emissions would 

be included. 

Response: The EPA evaluated the 

commenters’ suggestions and has 

decided not to include a minimum well 

pressure threshold. Both commenters 

who suggested a specific value noted in 

their comments that these pressure 

gradients are the minimum needed for 

the well to produce. In other words, 

according to the commenters’ rationale, 

wells with pressures below the 

suggested pressure thresholds would 

not have any production, regardless of 

whether a threshold is included in the 

final rule. As a result, specifying that 

reporting of emissions from completions 

and workovers of oil wells with 

hydraulic fracturing is not required 

below those pressures is redundant. 

Therefore, the final rule does not 

include a minimum well or reservoir 

pressure threshold for completions and 

workovers of oil wells with hydraulic 

fracturing. 

B. Summary of Final Amendments for 

the Onshore Petroleum and Natural Gas 

Gathering and Boosting Segment 

The EPA is amending subpart W to 

add a new industry segment, Onshore 

Petroleum and Natural Gas Gathering 

and Boosting, that covers emissions 

from equipment used by gathering 

pipeline systems that move petroleum 

and natural gas from the well to either 

larger gathering pipeline systems, 

natural gas processing plants, natural 

gas transmission pipelines, or natural 

gas distribution pipelines. A gathering 

and boosting system is a single network 

of pipelines, compressors and process 

equipment, including equipment to 

perform natural gas compression, 

dehydration, and acid gas removal, that 

has one or more well-defined 

connection points to gas and oil 

production and a well-defined 

downstream endpoint, typically a gas 


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64268 Federal Register / Vol. 80, No. 204 / Thursday, October 22, 2015 / Rules and Regulations 

processing plant or transmission 

pipeline. Gathering pipelines are 

pipelines used to transport gas from the 

furthermost downstream point in an 

onshore production facility to certain 

endpoints, generally either a gas 

processing facility or point of 

connection to a transmission pipeline. 

Compressors located along the gathering 

and boosting system are used to control 

or ‘‘boost’’ the pressure of the gas in the 

pipeline and keep the gas moving 

downstream. Commenters generally 

supported inclusion of gathering and 

boosting system emissions in subpart W, 

and many commenters suggested 

targeted revisions concerning 

definitions, what emission sources 

should be included in the segment and 

methods for individual emission 

sources. 

The remainder of this section 

describes the final reporting 

requirements for this new industry 

segment, including the segment 

description, definitions, calculation 

methods, and information to be 

reported. The amendments described in 

each section are followed by a summary 

of the major comments, if any, on those 

amendments and the EPA’s responses. 

See ‘‘Response to Public Comments on 

Greenhouse Gas Reporting Rule: 2015 

Revisions and Confidentiality 

Determinations for Petroleum and 

Natural Gas Systems’’ in Docket ID No. 

EPA–HQ–OAR–2014–0831 for a 

complete listing of all comments and 

the EPA’s responses. 

1. Segment Description for the Onshore 

Petroleum and Natural Gas Gathering 

and Boosting Segment 

a. Summary of Final Amendments 

The EPA is finalizing the definition of 

the Onshore Petroleum and Natural Gas 

Gathering and Boosting segment in 40 

CFR 98.230 as gathering pipelines and 

other equipment used to collect 

petroleum and/or natural gas from 

onshore production gas or oil wells and 

used to compress, dehydrate, sweeten, 

or transport the petroleum and/or 

natural gas to a natural gas processing 

facility, a natural gas transmission 

pipeline, or a natural gas distribution 

pipeline. Gathering and boosting 

equipment includes, but is not limited 

to, gathering pipelines, separators, 

compressors, acid gas removal (AGR) 

units, dehydrators, pneumatic devices/

pumps, storage vessels, engines, boilers, 

heaters, and flares. The Onshore 

Petroleum and Natural Gas Gathering 

and Boosting segment does not include 

equipment and pipelines that are 

reported under any other industry 

segment defined in subpart W. The 

segment definition is being finalized as 

proposed, except that the final 

amendments provide two clarifications 

regarding gathering pipelines. First, 

gathering pipelines operating on a 

vacuum are not included because they 

would not be expected to have 

emissions. Second, to address 

comments regarding the inclusion of 

liquid and multiphase streams in the 

segment, the definition clarifies that 

gathering pipelines with a GOR less 

than 300 scf/STB are not a part of the 

segment. 

b. Summary of Comments and 

Responses 

Comment: Commenters requested that 

the EPA remove ‘‘Petroleum and’’ from 

the proposed segment name, ‘‘Onshore 

Petroleum and Natural Gas Gathering 

and Boosting.’’ The commenters 

asserted that the removal would provide 

a clear demarcation between onshore 

petroleum and natural gas production 

and onshore natural gas gathering and 

boosting. They also stated that such a 

change would be more consistent with 

the segment definition, which includes 

pipelines and equipment ‘‘used to 

compress, dehydrate, sweeten, or 

transport the gas to a natural gas 

processing facility, a natural gas 

transmission pipeline or to a natural gas 

distribution pipeline.’’ The commenter 

stated that the type of equipment 

included in the gathering and boosting 

segment is ‘‘synonymous’’ with gas 

gathering and boosting systems, not 

liquid or petroleum, and they noted that 

the emission factor for equipment leaks 

from gathering pipelines is not 

applicable to gathering pipelines that 

carry mostly liquid. 

Commenters also specifically 

requested that the EPA exclude 

petroleum gathering pipelines from the 

gathering and boosting segment because 

the fugitive gas emissions from these 

gathering pipelines would be negligible. 

Both commenters stated that the 

proposed emission factor for gathering 

pipeline leaks is only applicable to gas 

gathering pipelines. Two commenters 

also requested that multi-phase flow 

lines from wells to a centralized 

production facility where initial 

separation occurs be retained in the 

Onshore Petroleum and Natural Gas 

Production segment rather than 

included in the new gathering and 

boosting segment. 

Response: The EPA is finalizing the 

segment name as proposed and not 

removing ‘‘Petroleum and’’ from the 

segment name or moving multiphase 

gathering pipelines to the Onshore 

Petroleum and Natural Gas Production 

segment. We proposed including 

‘‘Petroleum and’’ in the segment name 

to reflect the complex nature of 

upstream operations where wells can 

produce oil, natural gas, or a mixture of 

both and to signify the inclusion of GHG 

emissions from gathering and boosting 

systems moving high volatility liquids 

in this new segment. Even in wells that 

produce primarily liquids at surface 

temperature and pressure conditions, 

there is often a volatile gaseous 

component. This associated gas is 

usually considered wet due to the high 

content of natural gas liquids (volatile 

components) to go along with gaseous 

CH4. Similarly, the inclusion of all 

petroleum gathering pipelines in the 

Onshore Petroleum and Natural Gas 

Gathering and Boosting segment, 

including multiphase pipelines, is 

appropriate, because gathering lines are 

a key component to gathering and 

boosting systems. Therefore, all 

gathering pipelines that collect 

petroleum and/or natural gas from 

onshore production gas or oil wells and 

transport the petroleum and/or natural 

gas to a natural gas processing facility, 

a natural gas transmission pipeline or to 

a natural gas distribution pipeline are 

considered part of the final Onshore 

Petroleum and Natural Gas Gathering 

and Boosting segment. 

However, the EPA does agree that 

gathering pipelines carrying mostly oil 

have a low potential for GHG emissions. 

We note that the ratio of CH4 to volatile 

components increases as the GOR 

increases. Therefore, to clarify our 

intent to exclude gathering pipelines 

containing oil, the final rule clarifies 

that the Onshore Petroleum and Natural 

Gas Gathering and Boosting segment 

does not include gathering pipelines 

with a GOR of less than 300 scf/STB. 

Operators of gathering pipelines below 

that threshold are not required to 

include those pipelines in their 

gathering and boosting facility. See 

section II.B.5 of this preamble for 

additional discussion. 

Finally, as part of evaluating this 

comment, the EPA reviewed the 

proposed definitions related to the 

Onshore Petroleum and Natural Gas 

Gathering and Boosting segment and 

recognizes that two of them referred to 

‘‘the gas’’ rather than ‘‘the petroleum 

and/or natural gas.’’ One was the 

proposed description of the Onshore 

Petroleum and Natural Gas Gathering 

and Boosting segment in 40 CFR 98.230, 

as identified by the commenters, and 

the other was the definition of 

‘‘gathering and boosting system owner 

or operator’’ in 40 CFR 98.238. For 

consistency throughout the final rule 

with the intent stated in this response, 

the final description of the Onshore 


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Federal Register / Vol. 80, No. 204 / Thursday, October 22, 2015 / Rules and Regulations 64269 

Petroleum and Natural Gas Gathering 

and Boosting segment in 40 CFR 98.230 

refers to ‘‘petroleum and/or natural gas’’ 

and the final definition of ‘‘gathering 

and boosting system owner or operator’’ 

in 40 CFR 98.238 refers to ‘‘the 

petroleum or natural gas transported.’’ 

Comment: One commenter stated that 

there may be confusion regarding which 

equipment should be reported in the 

different industry segments, which 

could lead to emissions being 

mistakenly excluded or double-counted. 

For example, gathering and boosting 

equipment located on a single well pad 

or associated with a single well pad 

could be double-counted, especially if it 

is operated by one entity but owned by 

another. The commenter also noted that 

confusion over the proper segment for 

this type of equipment could make the 

difference between reporting emissions 

or not reporting emissions if a facility is 

close to the reporting threshold of 

25,000 metric tons carbon dioxide 

equivalent (CO2e). Therefore, the 

commenter requested that the EPA 

incorporate by reference the U.S. 

Department of Transportation’s Pipeline 

and Hazardous Materials Safety 

Administration (PHMSA) federally 

defined boundaries of production, 

gathering and boosting, and 

transmission segments to ensure state/

federal transparency and consistency. 

Response: The EPA is not changing 

the segment description for the Onshore 

Petroleum and Natural Gas Production 

segment in 40 CFR 98.230(a)(2) or the 

Onshore Natural Gas Processing 

segment in 40 CFR 98.230(a)(3). As 

stated at proposal, the EPA decided not 

to make any changes to the existing 

segment descriptions to provide 

consistency for reporters in that 

segment. This decision allows the EPA 

to ensure that the data gap in subpart W 

related to gathering and boosting 

systems is addressed while minimizing 

confusion over changes to other 

segments. Instead, the EPA is reiterating 

the intention for the Onshore Petroleum 

and Natural Gas Gathering and Boosting 

segment to cover equipment and 

emission sources not included in 

reporting for the existing Onshore 

Petroleum and Natural Gas Production 

or Onshore Natural Gas Processing 

segments. 

The EPA does not agree that 

emissions from the same equipment will 

be reported under more than one 

industry segment in a given reporting 

year; however, we acknowledge that 

similar equipment may exist in adjacent 

industry segments as defined in subpart 

W. The owner or operator of the 

equipment in question should first 

determine if that equipment is subject to 

reporting in another segment of subpart 

W, such as the Onshore Petroleum and 

Natural Gas Production or Onshore 

Natural Gas Processing segments. If the 

equipment is not subject to reporting in 

another segment of subpart W, then the 

owner or operator should evaluate 

whether or not the equipment is 

included in the Onshore Petroleum and 

Natural Gas Gathering and Boosting 

source category. For example, if a 

gathering and boosting owner or 

operator also owns or operates 

equipment on or associated with a 

single well pad (40 CFR 98.230(a)(2)), 

that equipment is part of the Onshore 

Petroleum and Natural Gas Production 

segment, not the Onshore Petroleum 

and Natural Gas Gathering and Boosting 

segment. Therefore, emissions from that 

equipment should not be included 

when determining if the gathering and 

boosting facility exceeds the reporting 

threshold. 

Comment: One commenter requested 

that the EPA clarify the proper segment 

for AGR units and revise the rule 

accordingly. The commenter suggested 

that the Natural Gas Processing segment 

should explicitly exclude sulfur dioxide 

and carbon dioxide (CO2) removal units, 

so that it is clear that those units do not 

report under both the Natural Gas 

Processing segment and the Onshore 

Petroleum and Natural Gas Gathering 

and Boosting segment. The commenter 

stated that this revision would be more 

consistent with the definition of gas 

processing plant in other EPA rules. If 

the EPA does not make this change, the 

commenter stated that AGR units 

should not be included in the Onshore 

Petroleum and Natural Gas Gathering 

and Boosting segment because they are 

already included in the Natural Gas 

Processing segment. The commenter 

noted that AGR units are specifically 

defined in 40 CFR 98.238 as a process 

unit that separates hydrogen sulfide 

and/or CO2 from sour natural gas using 

liquid or solid absorbents or membrane 

separators. 

Response: The EPA agrees that 

emissions from a particular acid gas 

removal unit should not be reported 

under both the Natural Gas Processing 

segment and the Onshore Petroleum and 

Natural Gas Gathering and Boosting 

segment. However, as noted previously 

in this preamble, the EPA is not 

changing the segment description for 

the Onshore Petroleum and Natural Gas 

Production segment in 40 CFR 

98.230(a)(2) or the Onshore Natural Gas 

Processing segment in 40 CFR 

98.230(a)(3). Instead, the EPA is 

reiterating the intention for the Onshore 

Petroleum and Natural Gas Gathering 

and Boosting segment to cover 

equipment and emission sources not 

included in reporting for the Onshore 

Petroleum and Natural Gas Production 

or Onshore Natural Gas Processing 

segments. The final segment description 

for the Onshore Petroleum and Natural 

Gas Gathering and Boosting segment in 

40 CFR 98.230(a)(10) specifies that 

gathering and boosting equipment does 

not include equipment reported under 

any other industry segment defined in 

40 CFR 98.230(a), which should address 

the commenter’s concern about 

reporting under multiple segments. 

Regarding the commenter’s suggestion 

to exclude AGR units from the Onshore 

Petroleum and Natural Gas Gathering 

and Boosting segment, the EPA believes 

AGR units should be reported under 

subpart W and that the current 

requirements, coupled with the 

revisions in this rulemaking, allow for a 

clear demarcation of where they should 

be included and reported. While most 

AGR units will be included in the 

Onshore Natural Gas Processing 

segment, the EPA does not agree that the 

Onshore Natural Gas Processing 

segment includes all AGR vents, 

particularly those in processes that do 

not fractionate gas liquids with an 

annual average throughput of less than 

25 million scf per day. Therefore, the 

final Onshore Petroleum and Natural 

Gas Gathering and Boosting segment 

includes AGR vents that do not meet the 

segment descriptions for the Onshore 

Petroleum and Natural Gas Production 

segment in 40 CFR 98.230(a)(2) or the 

Onshore Natural Gas Processing 

segment in 40 CFR 98.230(a)(3) but do 

meet the Onshore Petroleum and 

Natural Gas Gathering and Boosting 

segment description in 40 CFR 

98.230(a)(10). 

2. Definitions 

a. Summary of Final Amendments 

The EPA is finalizing the definition of 

‘‘gathering and boosting system’’ as 

proposed and is finalizing the definition 

of ‘‘gathering and boosting system 

owner or operator’’ as proposed with a 

clarification that the fluid being 

transported may be petroleum or natural 

gas. Specifically, a gathering and 

boosting system is a single network of 

pipelines, compressors and process 

equipment, including equipment to 

perform natural gas compression, 

dehydration, and acid gas removal, that 

has one or more connection points to 

gas and oil production and a 

downstream endpoint, typically a gas 

processing plant, transmission pipeline, 

local distribution company (LDC) 

pipeline, or other gathering and 

boosting system. A gathering and 


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boosting system owner or operator is 

any person that: (1) Holds a contract in 

which they agree to transport petroleum 

or natural gas from one or more onshore 

petroleum and natural gas production 

wells to a natural gas processing facility, 

another gathering and boosting system, 

a natural gas transmission pipeline, or a 

distribution pipeline; or (2) is 

responsible for custody of the petroleum 

or natural gas transported. In complex 

ownership scenarios, the owner/

operator assigns a designated 

representative responsible for reporting 

consistent with 40 CFR 98.4. 

The EPA is also finalizing the 

definition of ‘‘facility with respect to 

onshore petroleum and natural gas 

gathering and boosting’’ in 40 CFR 

98.238 as proposed. A facility with 

respect to onshore petroleum and 

natural gas gathering and boosting is all 

gathering pipelines and other 

equipment located along those pipelines 

that are under common ownership or 

common control by a gathering and 

boosting system owner or operator and 

that are located in a single hydrocarbon 

basin as defined in 40 CFR 98.238. 

Where a person owns or operates more 

than one gathering and boosting system 

in a basin (for example, separate 

gathering lines that are not connected), 

then all gathering and boosting systems 

and equipment that the person owns or 

operates in the basin are considered one 

facility. Any gathering and boosting 

equipment that is associated with a 

single gathering and boosting system, 

including leased, rented, or contracted 

activities, is considered to be under 

common control of the owner or 

operator of the gathering and boosting 

system. Emissions from an onshore 

petroleum and natural gas gathering and 

boosting facility only need to be 

reported if the collection of emission 

sources emits 25,000 metric tons CO2e 

or more per year. 

b. Summary of Comments and 

Responses 

Comment: Multiple commenters 

provided comments on the definition of 

‘‘facility with respect to onshore 

petroleum and natural gas gathering and 

boosting.’’ Some commenters supported 

the basin-level approach that the EPA 

proposed, although a few asked the EPA 

to clarify how to report their emissions 

if their gathering and boosting system is 

in more than one basin. Other 

commenters disagreed with the basinlevel approach and suggested that the 

EPA should use the definition of facility 

in 40 CFR 98.6. These commenters 

asserted that the basin-level approach 

would result in an expansive definition 

of facility that includes huge numbers of 

emissions sources and that this 

approach is not consistent with how a 

facility is defined elsewhere in the 

GHGRP or with traditional notions of 

aggregation under the CAA. One 

commenter asserted that defining a 

facility in a way that is not consistent 

with other CAA programs will make it 

difficult for the EPA to use the GHGRP 

data to inform future policy decisions. 

The commenter also stated that the EPA 

has not provided any explanation of 

why basin-wide aggregation is a 

reasonable data request under section 

114 of the CAA. 

Commenters opposing the basin-level 

facility definition noted that the 

Onshore Petroleum and Natural Gas 

Gathering and Boosting segment has 

very different characteristics from the 

Onshore Petroleum and Natural Gas 

Production segment, which also uses 

the basin-level approach to defining a 

facility. One commenter specifically 

noted that production sources are 

located at well-defined, discrete 

locations, owners and operators of 

production sites know where the wells 

are physically located and how many 

operate in a single production basin. In 

contrast, the commenter stated, the 

gathering and boosting operations of one 

owner or operator in a single 

hydrocarbon basin may include 

hundreds or thousands of miles of 

pipelines with multiple sites, including 

interconnects, meter stations, scrubber 

stations, pigging stations, compressor 

stations, and gas treating plants. 

Another commenter stated that 

gathering and boosting sites have the 

ability to boost and move gas from 

multiple basins within the same site, 

whereas production typically maintains 

operations and moves gas within one 

basin. 

Another commenter also disagreed 

with the basin-level approach, noting 

that the term ‘‘basin’’ is not common 

terminology that is used in the gathering 

and boosting industry segment. The 

commenter suggested that the EPA use 

a county- or parish-level approach with 

an equipment threshold (to determine 

which equipment should be counted 

when determining if the 25,000 metric 

tons CO2e reporting threshold has been 

exceeded). 

Response: The EPA is finalizing the 

definition of ‘‘facility with respect to 

onshore petroleum and natural gas 

gathering and boosting’’ as proposed. As 

noted in the preamble to the proposed 

amendments, the basin-level approach 

to defining a facility for the Onshore 

Petroleum and Natural Gas Gathering 

and Boosting segment is expected to 

achieve a balance of providing 

geographically specific information 

while also reducing burden on 

reporters. This approach also recognizes 

the fact that gathering and boosting 

facilities are more dispersed than 

processing facilities and are 

geographically similar to the Onshore 

Petroleum and Natural Gas Production 

segment in size and number of sources 

because, by their nature, they are 

needed to process and transport the 

petroleum and natural gas produced in 

a given basin. While some gathering and 

boosting operations may span multiple 

basins or may only be present in a 

portion of a basin, as will some onshore 

production operations, the EPA has 

concluded that a basin-level facility 

definition is the best reflection of how 

this industry is organized operationally. 

In ‘‘Greenhouse Gas Reporting Rule: 

Technical Support for 2015 Revisions 

and Confidentiality Determinations for 

Petroleum and Natural Gas Systems; 

Proposed Rule’’ (Docket Item No. EPA– 

HQ–OAR–2014–0831–0018), we 

evaluated the option of using the 

definition of ‘‘facility’’ found in 40 CFR 

98.6 for gathering and boosting 

facilities, and we found that this 

definition would provide limited data 

on the proposed Onshore Petroleum and 

Natural Gas Gathering and Boosting 

segment compared to the basin-level 

approach, due to the fact that fewer 

facilities would exceed the 25,000 

metric tons CO2e reporting threshold. It 

would also likely be more burdensome 

overall to reporters, because a larger 

number of facilities would have to be 

evaluated to determine whether they 

exceed the 25,000 metric tons CO2e 

reporting threshold, and a larger number 

of ‘‘facility’’ reports would be required 

for each owner or operator. The 

commenters did not provide any new 

information that would enable us to reevaluate this conclusion. A county- or 

parish-level approach would similarly 

result in a larger number of smaller 

facilities to be evaluated to determine 

whether they exceed the reporting 

threshold than the basin-level approach. 

This approach would result in fewer 

facilities reporting than a basin-level 

definition, especially if an equipment 

threshold were defined as requested by 

the commenter, as well as a higher 

burden for owners or operators with 

multiple facilities in a basin that exceed 

the 25,000 metric tons CO2e reporting 

threshold. Therefore, the EPA 

concluded that these options would not 

achieve the goals that were articulated 

in the preamble to the proposed rule of 

‘‘having a thorough data set and 

transparent, complete information for 

this sector while minimizing burden to 

reporters’’ (79 FR 73156; December 9, 


tkelley on DSK3SPTVN1PROD with RULES3
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6Mandatory Greenhouse Gas Reporting Rule: 

EPA’s Response to Public Comments, Subpart W: 

Petroleum and Natural Gas Systems, Docket Id. No. 

EPA–HQ–OAR–2009–0923. 

2014). For more detail on this analysis, 

see ‘‘Greenhouse Gas Reporting Rule: 

Technical Support for Final 2015 

Revisions and Confidentiality 

Determinations for Petroleum and 

Natural Gas Systems’’ in Docket ID No. 

EPA–HQ–OAR–2014–0831. We disagree 

with the comment that aggregation of 

data would not provide a data set that 

the EPA can use to inform future policy 

decisions. The purpose of this rule is to 

collect emissions and activity data for 

this industry and understand the 

relative emission sources, which we 

anticipate the aggregated data will help 

to promote. Therefore, the aggregated 

data can still inform future GHG policy. 

As we have pointed out previously, the 

EPA’s definition of ‘‘facility’’ for 

purposes of part 98 in no way impacts 

the ‘‘facility’’ definition for similar 

sources under existing CAA programs.6

Information collected under part 98 can 

inform a number of different CAA 

programs and the Agency’s authority 

under CAA section 114 as the basis for 

part 98 is independent from the EPA’s 

authority for other CAA programs. 

To address the commenters’ question 

about reporting a system in two basins, 

we are confirming in this response that 

reporters should submit one report per 

basin (i.e., per facility as it is defined in 

subpart W) and that the 25,000 metric 

tons CO2e per year reporting threshold 

applies to each basin/facility separately. 

In other words, the reporter should 

determine the emissions from the 

portion of gathering and boosting 

system associated with each basin. If the 

total emissions in each basin exceed the 

25,000 metric tons CO2e per year 

reporting threshold, then the reporter 

submits two reports. If the total 

emissions in one basin exceed the 

25,000 metric tons CO2e threshold, but 

the emissions in the other basin are 

below the threshold, then the reporter 

submits one report (for the facility that 

exceeds the threshold). 

Regarding the commenter’s question 

regarding the reasonableness of 

collecting data at the basin-level under 

the CAA, the EPA established its basis 

for collecting basin-level data in the 

final subpart W rule, when the EPA 

finalized the requirements for the 

Onshore Petroleum and Natural Gas 

Production segment. Additionally, as 

noted earlier in this section, more 

granular collection of data for this 

segment would result in higher burden 

for owners or operators with multiple 

operations in a basin that exceed the 

25,000 metric tons CO2e reporting 

threshold. See also, ‘‘Greenhouse Gas 

Emissions Reporting from the Petroleum 

and Natural Gas Industry, Background 

Technical Support Document (Docket 

Item No. EPA–HQ–OAR–2009–0923– 

3610) and ‘‘Mandatory Greenhouse Gas 

Reporting Rule Subpart W—Petroleum 

and Natural Gas: EPA’s Response to 

Public Comments’’ (Docket Item No. 

EPA–HQ–OAR–2009–0923–3608). 

3. Blowdown Vent Stacks 

a. Summary of Final Amendments 

The EPA is finalizing the 

requirements for blowdowns of 

equipment in the Onshore Petroleum 

and Natural Gas Gathering and Boosting 

segment with some clarifications from 

proposal. Emissions should be 

calculated using the same methods that 

are used for the Onshore Natural Gas 

Processing segment. The same 

exemptions, including those for 

volumes less than 50 cubic feet (ft3) and 

for desiccant dehydrator reloading, 

apply to the Onshore Petroleum and 

Natural Gas Gathering and Boosting 

segment. In response to comments that 

the segment is geographically dispersed 

and blowdowns may occur without 

personnel on-site or nearby, making it 

difficult to determine emissions from a 

blowdown event, the final amendments 

specify that for emergency blowdowns, 

reporters may use engineering estimates 

based on best available information to 

determine the temperature and pressure 

used in Equation W–14A. 

b. Summary of Comments and 

Responses 

Comment: Commenters stated that the 

EPA should not include reporting of 

blowdown vent stack emissions due to 

the large burden on the reporter. 

Instead, the commenters stated, 

blowdowns in the Onshore Petroleum 

and Natural Gas Gathering and Boosting 

segment should be treated similarly to 

blowdowns in the Onshore Petroleum 

and Natural Gas Production segment, 

where they are excluded because they 

are not located at consolidated facility 

sites and are not manned. Commenters 

also stated that blowdowns from 

gathering and boosting systems 

contribute minimally to overall GHG 

emissions. One commenter noted that 

while there is an exemption for any 

blowdown of a volume less than 50 ft3, 

there is also a burden to determine if the 

physical volume meets this reporting 

threshold. To reduce the burden, some 

commenters suggested only including 

emissions from blowdown vent stacks 

located at a facility site (e.g., compressor 

station, central tank battery). Other 

commenters stated if blowdowns remain 

in the segment, the EPA should allow 

reporters to use an emission factor 

approach to calculate emissions. 

Another commenter stated that the 

EPA’s supporting documentation 

focuses on gathering pipeline 

blowdowns, but the regulatory text 

appears to include all the blowdowns 

occurring within a basin, including 

individual equipment blowdowns. The 

commenter requested that the EPA 

clarify its intent if blowdowns remain in 

the segment. 

Response: The EPA has evaluated 

these comments and has decided to 

finalize the reporting requirements for 

blowdowns in the Onshore Petroleum 

and Natural Gas Gathering and Boosting 

segment with some revisions to address 

the commenters’ concerns. While the 

EPA does recognize that many gathering 

and boosting systems are geographically 

dispersed, as noted by the commenters, 

the nature of the Onshore Petroleum 

and Natural Gas Gathering and Boosting 

segment is such that the amount of fluid 

passing through a gathering and 

boosting system will be much greater 

than the amount of fluid at individual 

well pads. Therefore, the EPA has 

determined that the potential for 

emissions from blowdowns in the 

Onshore Petroleum and Natural Gas 

Gathering and Boosting segment is 

higher than blowdowns in the Onshore 

Petroleum and Natural Gas Production 

segment, and they should not be 

excluded. However, the EPA 

acknowledges that the geographic 

dispersion of the segment, and the fact 

that some blowdowns occur without 

facility personnel on site, may make it 

difficult to measure emissions from 

blowdowns, particularly emergency 

blowdowns. Therefore, the final 

amendments include a provision 

specifying that for emergency 

blowdowns, reporters may use 

engineering estimates based on best 

available information to determine the 

temperature at actual conditions in the 

unique physical volume and absolute 

pressure at actual conditions in the 

unique physical volume for use in 

Equation W–14A. 

To respond to the commenter’s 

request regarding whether only 

gathering pipeline blowdowns or all 

equipment blowdowns should be 

included, the EPA is clarifying that the 

intent is to include emissions from the 

‘‘blowdown vent stacks’’ source type as 

defined in subpart A of part 98. The 

focus on blowdown vent stacks located 

on gathering pipelines in the supporting 

documentation was not intended to 

imply that only gathering pipeline 

blowdowns should be reported. On the 


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64272 Federal Register / Vol. 80, No. 204 / Thursday, October 22, 2015 / Rules and Regulations 

contrary, the proposal supporting 

documentation reflects the fact that the 

EPA expected that blowdown vent 

stacks located at boosting stations 

would be similar to blowdown vent 

stacks in other industry segments and 

conducted a separate evaluation to 

determine whether the same calculation 

methods would be appropriate for 

gathering pipeline blowdown vent 

stacks. The final rule supporting 

documentation more clearly reflects this 

intent. The EPA also notes that while 

measuring equipment to determine 

whether it exceeds the 50 ft3 physical 

volume threshold for reporting may 

create an initial burden on reporters, the 

threshold will lead to a burden 

reduction as reporters become familiar 

with the identification process. 

4. Storage Tank Vented Emissions 

a. Summary of Final Amendments 

The EPA is finalizing the same 

methods for calculating emissions for 

atmospheric storage tanks located in the 

Onshore Petroleum and Natural Gas 

Gathering and Boosting segment as in 

the Onshore Petroleum and Natural Gas 

Production segment, as proposed but 

with a few clarifications. Specifically, 

the EPA is clarifying some of the 

language within 40 CFR 98.233(j) and 40 

CFR 98.236(j) that was originally written 

to apply to Onshore Petroleum and 

Natural Gas Production facilities and 

not proposed to be amended to also 

apply to storage tanks in the Onshore 

Petroleum and Natural Gas Gathering 

and Boosting segment. In particular, 

references to a ‘‘wellhead separator’’ 

have been clarified to refer simply to a 

‘‘separator,’’ which is a defined term in 

40 CFR 98.238. To accommodate 

Onshore Petroleum and Natural Gas 

Gathering and Boosting storage tanks 

that do not receive hydrocarbon liquids 

from a separator or well, Calculation 

Methods 1 and 2 have been amended to 

specify how to estimate emissions if 

liquids are received from non-separator 

equipment. In addition, certain 

instances of ‘‘sub-basin’’ have been 

amended to refer to ‘‘county’’ to clarify 

the requirements for Onshore Petroleum 

and Natural Gas Gathering and Boosting 

reporters. All other provisions in 40 

CFR 98.233(j) apply to the Onshore 

Petroleum and Natural Gas Gathering 

and Boosting segment, including the 10 

barrels per day threshold for 

determining which calculation method 

may be used for estimating emissions. 

b. Summary of Comments and 

Responses 

Comment: One commenter stated that 

combining the requirements for storage 

tanks in the Onshore Petroleum and 

Natural Gas Gathering and Boosting 

segment and the Onshore Petroleum and 

Natural Gas Production segment results 

in confusing terminology and unclear 

requirements. In particular, the 

commenter noted that the terms 

‘‘separator(s),’’ ‘‘gas-liquid separator(s),’’ 

‘‘wellhead separator(s),’’ and ‘‘wellhead 

gas-liquid separator(s),’’ appear 

throughout the storage tank 

requirements. The commenter asked 

whether the EPA intended all of these 

terms to refer to the same equipment. 

The commenter also noted that not all 

gathering and boosting system storage 

tanks receive liquids directly from 

separators, and no gathering and 

boosting storage tanks receive liquids 

directly from wellhead separators. 

Therefore, the commenter stated, the 

requirements for storage tanks in the 

Onshore Petroleum and Natural Gas 

Gathering and Boosting segment are 

unclear. 

The commenter also noted 

inconsistency between use of the terms 

‘‘oil,’’ ‘‘sales oil,’’ and ‘‘stabilized oil’’ in 

40 CFR 98.233(j) and 40 CFR 98.236(j). 

The commenter stated that Onshore 

Petroleum and Natural Gas Gathering 

and Boosting facilities may process 

condensate but not oil, and the 

commenter asked the EPA to clarify 

how those terms should be applied to 

the Onshore Petroleum and Natural Gas 

Gathering and Boosting segment. 

Finally, the commenter noted that 

Calculation Method 1 for storage tanks 

requires use of the latest available 

analysis that is representative of 

produced crude oil or condensate from 

the sub-basin category. The commenter 

stated that the term ‘‘sub-basin’’ has no 

relevance to the Onshore Petroleum and 

Natural Gas Gathering and Boosting 

segment because the composition of 

condensate processed at a compressor 

station may have little relationship to 

the oil or gas formation below the 

compressor station. 

Response: The EPA agrees that the 

language in 40 CFR 98.233(j) and 40 

CFR 98.236(j) should be clear for all 

Onshore Petroleum and Natural Gas 

Production facilities and all Onshore 

Petroleum and Natural Gas Gathering 

and Boosting facilities to which it 

applies. The existing definition of 

‘‘separator’’ in 40 CFR 98.238 is a vessel 

in which streams of multiple phases are 

gravity separated into individual 

streams of single phase. This general 

definition and the general term ‘‘gasliquid separator’’ apply to both Onshore 

Petroleum and Natural Gas Production 

facilities and all Onshore Petroleum and 

Natural Gas Gathering and Boosting 

facilities. Therefore, the EPA has 

reviewed the language and is amending 

references to a ‘‘well,’’ ‘‘well pad,’’ or 

‘‘wellhead,’’ which are terms that are 

not expected to apply to most Onshore 

Petroleum and Natural Gas Gathering 

and Boosting facilities. The final 

provisions in 40 CFR 98.233(j) and 40 

CFR 98.236(j) refer more generally to 

separators or gas-liquid separators. To 

address the comment that not all 

gathering and boosting system storage 

tanks receive liquids directly from 

separators, the EPA has amended 40 

CFR 98.233(j)(1) and (2) to specify how 

those calculation methodologies may be 

used for Onshore Petroleum and Natural 

Gas Gathering and Boosting storage 

tanks receiving hydrocarbon liquids 

from non-separator equipment (i.e., 

without a well or separator directly 

upstream of the storage tank). 

Regarding the particular material 

being stored in storage tanks, the EPA 

agrees that there is inconsistency in 

some of the terms that could cause some 

confusion. The EPA is clarifying in this 

response that for the Onshore Petroleum 

and Natural Gas Gathering and Boosting 

segment, the intent is for ‘‘oil’’ to refer 

more generally to hydrocarbon liquids, 

which is consistent with the statement 

in 40 CFR 98.233(j) that reporters are 

required to calculate emissions ‘‘from 

atmospheric pressure fixed roof storage 

tanks receiving hydrocarbon produced 

liquids.’’ The proposed separate 

reporting requirements for quantity of 

produced oil throughput and produced 

condensate throughput in 40 CFR 

98.236(aa)(10) have been revised, and 

the final rule requires reporting of the 

hydrocarbon liquids received by the 

facility and the hydrocarbon liquids 

leaving the facility. Finally, the EPA 

notes that the term ‘‘sales oil’’ is already 

defined in Subpart A to include 

‘‘produced crude oil or condensate,’’ so 

there is no further clarification needed. 

Regarding the term ‘‘sub-basin,’’ the 

EPA agrees with the commenter that the 

definition of ‘‘sub-basin category, for 

onshore natural gas production’’ in 40 

CFR 98.238 is not relevant for Onshore 

Petroleum and Natural Gas Gathering 

and Boosting facilities. The EPA also 

agrees that the operations within a 

section of a gathering and boosting 

system may not be related to the 

formation type below the surface of the 

ground at that location, especially as the 

material travels further from the wells 

supplying gas and hydrocarbon liquids 

to the system. As a result of this 

comment, the EPA reviewed the use of 

the term ‘‘sub-basin’’ as it was proposed 

to apply to Onshore Petroleum and 

Natural Gas Gathering and Boosting 

facilities. In 40 CFR 98.233(j), the 

calculation methods provide options to 


tkelley on DSK3SPTVN1PROD with RULES3
Federal Register / Vol. 80, No. 204 / Thursday, October 22, 2015 / Rules and Regulations 64273 

7U.S. Department of Transportation Pipeline and 

Hazardous Materials Safety Administration. Natural 

and Other Gas Transmission and Gathering Pipeline 

Systems: Annual Report for Calendar Year. Form 

PHMSA F 7100.2–1 (rev 10–2014). OMB No. 2137– 

0522, Expires: 10/31/2016. 

estimate unknown parameters using 

information from a previous analysis of 

the composition in the sub-basin 

category. In these cases, the intent is to 

estimate unknown parameters from a 

representative unit (e.g., well, 

separator). To reflect a similar intent for 

Onshore Petroleum and Natural Gas 

Gathering and Boosting facilities, 40 

CFR 98.233(j)(1)(vii)(B) and 40 CFR 

98.233(j)(1)(vii)(C) in Calculation 

Method 1 clarify that representative 

separators or non-separator equipment 

are located within the same county for 

Onshore Petroleum and Natural Gas 

Gathering and Boosting reporters. For 

Calculation Method 2, the term ‘‘subbasin category’’ is used to describe 

calculation of emissions for flow to 

storage tanks directly from wells. The 

final rule includes a new paragraph 40 

CFR 98.233(j)(2)(iii) to address 

calculation of emissions from flow to a 

tank from equipment other than a well 

or separator (such as a stabilizer or slug 

catcher), and this paragraph also 

clarifies that representative analyses 

should come from other non-separator 

equipment located within the same 

county. Finally, there are reporting 

requirements for a ‘‘sub-basin ID’’ in 40 

CFR 98.236. The final rule specifies that 

for Onshore Petroleum and Natural Gas 

Gathering and Boosting, the information 

to be reported is the county in which 

the equipment is located. 

5. Gathering Pipelines 

a. Summary of Final Amendments 

The EPA is finalizing the 

requirements for calculating emissions 

from gathering pipelines defined to be 

included in the Onshore Petroleum and 

Natural Gas Gathering and Boosting 

segment as proposed. The methodology 

is similar to the approach used for 

equipment leaks in the Onshore 

Petroleum and Natural Gas Production 

segment. For gathering lines, reporters 

use the population count and emission 

factor approach in 40 CFR 98.233(r). 

The emission factors in Table W–1A for 

gathering pipelines are whole gas 

emission factors based on the U.S. GHG 

Inventory. The population count is the 

miles of gathering pipeline, similar to 

the approach used for calculating 

emissions from natural gas distribution 

pipelines in the Natural Gas 

Distribution segment. As noted in 

section II.B.1.a of this preamble, 

gathering pipelines with a GOR less 

than 300 scf/STB are not included in 

this segment. 

b. Summary of Comments and 

Responses 

Comment: One commenter asserted 

that the EPA should revise the proposed 

emission factor of 2.81 standard cubic 

feet (scf)/hour/mile for leaks from 

gathering pipelines to be based on 

characteristics of currently operating 

gathering pipelines rather than 

distribution pipelines or older data on 

gathering pipelines. The commenter 

also noted that this emission factor is 

not applicable to gathering pipelines 

that carry primarily liquids, as there is 

no gas stream until after separation. The 

commenter identified gathering 

pipeline-specific data from PHMSA and 

used the data to calculate a suggested 

emission factor of 2.23 scf/hour/mile. 

Response: We reviewed the 

underlying data used to develop the 

proposed emission factor, and we agree 

with the commenter that the proposed 

emission factor could better account for 

differences between pipeline types and 

for currently operating gathering 

pipelines. In the 1996 Gas Research 

Institute (GRI)/EPA report that is the 

basis of the emission factor, materialspecific emissions factors for gathering 

lines were developed using data from 

direct measurement of distribution 

pipelines conducted in the 1990s, not 

gathering pipelines. These materialspecific emission factors are the same 

emission factors used by the commenter 

as the starting point for their revised 

emission factor. 

We agree with the commenter that the 

emission factors should better represent 

currently operating gathering pipelines; 

however, there is significant variability 

in gathering pipelines and gathering 

system configurations. Owners and 

operators currently report the mileage of 

pipeline by gathering pipeline type to 

PHMSA.7 Therefore, rather than 

calculate a single emission factor for 

gathering pipelines based on a 

distribution of gathering pipeline 

materials, as was done at proposal, the 

EPA determined that the most 

appropriate approach is to develop 

gathering pipeline emission factors for 

four pipeline material types: Protected 

steel, unprotected steel, plastic, and cast 

iron. (For more information about the 

development of these emission factors, 

see ‘‘Greenhouse Gas Reporting Rule: 

Technical Support for Final 2015 

Revisions and Confidentiality 

Determinations for Petroleum and 

Natural Gas Systems’’ in Docket ID No. 

EPA–HQ–OAR–2014–0831.) The final 

amendments require reporters to 

estimate emissions using materialspecific emission factors provided in the 

rule and to report gathering pipeline 

mileage by material type. 

The EPA also notes that reporters will 

not need to calculate emissions from 

gathering pipelines that carry 

hydrocarbon liquids if they are below 

the minimum GOR threshold for the 

Onshore Petroleum and Natural Gas 

Gathering and Boosting segment. 

6. Other Emission Sources 

a. Summary of Final Amendments 

The EPA is finalizing the 

requirements for natural gas pneumatic 

devices and pneumatic pumps located 

in the Onshore Petroleum and Natural 

Gas Gathering and Boosting segment as 

proposed. Gathering and boosting 

reporters will use the same methods for 

calculating emissions as in the Onshore 

Petroleum and Natural Gas Production 

segment. The EPA is also finalizing the 

requirements for acid gas removal units, 

dehydrators, and flare stacks as 

proposed. The methods are the same as 

the methods for these sources in both 

the Onshore Petroleum and Natural Gas 

Production segment and the Onshore 

Natural Gas Processing segment. The 

EPA is also finalizing the requirements 

for compressors and equipment leaks as 

proposed, with one clarification 

regarding how to count ‘‘meters/piping’’ 

for equipment leaks. Gathering and 

boosting reporters use the same method 

as in the Onshore Petroleum and 

Natural Gas Production segment. 

Specifically, a reporter will need to 

establish an inventory of the 

components or equipment subject to the 

population counts, apply the emission 

factors, and then update the inventory 

each year to account for new or retired 

components or equipment. 

b. Summary of Comments and 

Responses 

Comment: Two commenters stated 

that the major equipment categories for 

calculating equipment leaks by 

population count are not clear for the 

Onshore Petroleum and Natural Gas 

Gathering and Boosting segment. Both 

commenters requested that the EPA 

clarify how to count ‘‘meters/piping’’ for 

the Onshore Petroleum and Natural Gas 

Gathering and Boosting segment. One 

commenter also requested clarification 

regarding separators, compressors, and 

in-line heaters (specifically, whether 

small heating systems used to ensure a 

temperate environment for a meter are 

considered in-line heaters). The 


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8See the memorandum ‘‘Equipment-Level 

Population Emission Factors for Onshore 

Production,’’ Docket Item No. EPA–HQ–OAR– 

2009–0923–3582, for more information regarding 

the derivation of this table. 

commenter also noted that there was 

limited time to evaluate the 

appropriateness of the emission factors 

in Table W–1A and the component 

counts in Table W–1B for gathering and 

boosting systems. 

Response: The categories in Table W– 

1B represent the types of equipment that 

are generally expected to be found in 

the field for Onshore Petroleum and 

Natural Gas Production and Onshore 

Petroleum and Natural Gas Gathering 

and Boosting facilities.8 For the Onshore 

Petroleum and Natural Gas Gathering 

and Boosting segment, the EPA realizes 

that reporters will only use those 

categories that apply (e.g., reporters will 

not include wellheads, as that 

equipment type is specific to Onshore 

Petroleum and Natural Gas Production 

facilities). 

Most of the major equipment 

categories are described by function in 

the rule. For the example of a separator, 

40 CFR 98.238 defines a separator as ‘‘a 

vessel in which streams of multiple 

phases are gravity separated into 

individual streams of single phase.’’ 

Any device meeting this functional 

definition will fall into this major 

equipment category. Other major 

categories are described in the rule by 

their functional role, including 

dehydrators and compressors. For the 

in-line heater example for which the 

commenter requested clarification, the 

equipment described is not located in 

line with the fluid flow and therefore 

would not be considered in this 

equipment category. 

The EPA agrees with both 

commenters that the measurement of 

meters/piping in the Onshore Petroleum 

and Natural Gas Gathering and Boosting 

segment was not clear as proposed. The 

final rule specifies that reporters in the 

Onshore Petroleum and Natural Gas 

Gathering and Boosting segment should 

count the number of meters in the 

facility and use that as the count for 

‘‘meters/piping.’’ 

Comment: Two commenters 

supported the use of calculation 

methods that include emission factors 

for the Onshore Petroleum and Natural 

Gas Gathering and Boosting segment 

because they are less burdensome to the 

industry. However, the commenters also 

requested that the EPA allow reporters 

the option to use any available data/

information that provides the best 

representation of emissions from their 

specific sources, including 

manufacturer data, test data, 

measurement and/or monitoring data. 

The commenters compared this option 

to the approach in state-level emissions 

inventories that require an emissions 

reporting hierarchy. The commenters 

noted that this approach will provide 

the EPA with more accurate emissions 

data that could be used to update the 

emission factors for the Onshore 

Petroleum and Natural Gas Gathering 

and Boosting segment. 

Response: The calculation methods 

provided in subpart W were selected to 

minimize burden on industry while 

maintaining the necessary quality and 

consistency of data to inform policy. 

Therefore, outside of the BAMM 

provisions being finalized in this 

rulemaking, the EPA does not agree to 

allow reporters to use customized, 

individual information for their 

emission sources at this time. The EPA 

is currently investigating additional 

calculation methods for subpart W 

sources and may propose additional 

calculation methods in the future. 

C. Summary of Final Amendments for 

the Onshore Natural Gas Transmission 

Pipeline Segment 

1. Summary of Final Amendments 

The EPA is finalizing the proposal to 

add reporting requirements for 

emissions from natural gas transmission 

pipeline blowdowns between 

compressor stations in a new Onshore 

Natural Gas Transmission Pipeline 

segment. Commenters generally had no 

objections to the merit of including this 

segment in subpart W but did suggest 

technical edits and clarifications for 

targeted provisions. As noted in the 

preamble to the proposed amendments, 

a blowdown is the release of gas from 

transmission pipelines that causes a 

reduction in system pressure or a 

complete depressurization. The EPA is 

clarifying that for the purposes of the 

Onshore Natural Gas Transmission 

Pipeline segment, the blowdowns that 

must be reported are blowdowns of a 

pipeline or section of pipeline. 

The EPA is finalizing clarifications to 

the proposed definition of onshore 

natural gas transmission pipeline owner 

or operator. For interstate pipelines, the 

onshore natural gas transmission 

pipeline owner or operator is the person 

identified as the transmission pipeline 

owner or operator on the Certificate of 

Public Convenience and Necessity 

issued under 15 U.S.C. 717f, as 

proposed. For intrastate pipelines, the 

onshore natural gas transmission 

pipeline owner or operator is the person 

identified as the owner or operator on 

the transmission pipeline’s Statement of 

Operating Conditions under section 311 

of the Natural Gas Policy Act (NGPA). 

If the intrastate pipeline is not subject 

to section 311 of the NGPA, the onshore 

natural gas transmission pipeline owner 

or operator is the person identified as 

the owner or operator on reports to the 

state regulatory body regulating rates 

and charges for the sale of natural gas 

to consumers. Finally, the owner or 

operator of a pipeline that falls under 

the ‘‘Hinshaw Exemption’’ is the person 

identified as the owner or operator on 

blanket certificates issued under 18 CFR 

284.224. 

The EPA is finalizing the definition of 

facility for the new Onshore Natural Gas 

Transmission Pipeline segment as 

proposed; the facility is the total U.S. 

mileage of natural gas transmission 

pipelines owned or operated by an 

onshore natural gas transmission 

pipeline owner or operator. If an owner 

or operator has multiple pipelines in the 

United States, the facility is considered 

the aggregate of those pipelines, even if 

they are not interconnected. 

The EPA is finalizing the requirement 

that reporters use the methods in 40 

CFR 98.233(i) to calculate or measure 

emissions from pipeline blowdown 

events as proposed. One method allows 

a reporter to calculate emissions based 

on the volume of the pipeline segment 

between isolation valves that is blown 

down and the pressure and temperature 

of the gas within the pipeline. The 

second method allows the reporter to 

measure the emissions from the 

blowdown using a flow meter on the 

blowdown vent stack. In both methods, 

the reporter calculates both CH4 and 

CO2 emissions from the volume of 

natural gas vented using either default 

gas composition or engineering 

estimates of composition as specified in 

40 CFR 98.233(u)(2)(iii). 

The EPA is not finalizing the 

proposed requirement to report the 

emissions and location (latitude and 

longitude) of each blowdown event. 

Instead, the EPA is requiring that 

Onshore Natural Gas Transmission 

Pipeline reporters report the total CH4

and CO2 emissions in each state, the 

number of blowdowns in each state, and 

the miles of pipeline in each state. In 

addition, instead of requiring Onshore 

Natural Gas Transmission Pipeline 

reporters to use the same equipment and 

event type categories as other industry 

segments reporting blowdown 

emissions, the EPA is including 

reporting categories specific to the 

Onshore Natural Gas Transmission 

Pipeline segment. 


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Federal Register / Vol. 80, No. 204 / Thursday, October 22, 2015 / Rules and Regulations 64275 

2. Summary of Comments and 

Responses 

Comment: Several commenters noted 

that not all intrastate pipelines are 

subject to section 311 of the NGPA and 

asked the EPA to clarify which 

intrastate pipelines are subject to 

reporting. One commenter requested 

that the EPA clarify that intrastate 

pipelines not subject to the NGPA are 

not required to report under subpart W. 

Another commenter suggested revising 

the definition of owner or operator to 

state that if section 311 of the NGPA 

does not apply, the intrastate 

transmission pipeline owner or operator 

is the owner or operator identified on 

required reports with the appropriate 

state agency. 

Response: It was our intent to include 

transmission pipelines (including 

intrastate pipelines) that meet the 

already existing subpart W definition of 

‘‘transmission pipeline’’ in the Onshore 

Natural Gas Transmission Pipeline 

segment. A transmission pipeline in 

subpart W is defined in 40 CFR 98.238 

as a Federal Energy Regulatory 

Commission (FERC) rate-regulated 

Interstate pipeline, a state rate-regulated 

Intrastate pipeline, or a pipeline that 

falls under the ‘‘Hinshaw Exemption’’ as 

referenced in section 1(c) of the Natural 

Gas Act, 15 U.S.C. 717–717 (w)(1994). 

After reviewing the comments on the 

proposed rule, we re-reviewed section 

311 of the NGPA and found that only 

operators of some intrastate pipelines, 

including those that transport natural 

gas on behalf of an interstate pipeline or 

sell natural gas to an interstate pipeline, 

are required to prepare a Statement of 

Operating Conditions for compliance 

under section 311 of the NGPA. 

Therefore, to clarify how to determine 

the owner and operator of intrastate 

transmission pipelines, the finalized 

definition of ‘‘onshore natural gas 

transmission pipeline owner or 

operator’’ specifies that for intrastate 

transmission pipelines not subject to 

section 311 of the NGPA, the owner or 

operator is the person identified as the 

owner or operator on reports to the state 

regulatory body regulating rates and 

charges for the sale of natural gas to 

consumers. The EPA also found that the 

proposed definition of ‘‘onshore natural 

gas transmission pipeline owner or 

operator’’ did not specify how to 

determine the owner or operator of 

pipelines that fall under the ‘‘Hinshaw 

Exemption.’’ The EPA notes that similar 

to intrastate pipelines, pipelines that fall 

under the ‘‘Hinshaw Exemption’’ must 

apply for a ‘‘blanket certificate’’ under 

18 CFR 284.224 in order to transport 

petroleum or natural gas on behalf of 

interstate pipelines. Therefore, the 

finalized definition of ‘‘onshore natural 

gas transmission pipeline owner or 

operator’’ also specifies that for a 

pipeline that falls under the ‘‘Hinshaw 

Exemption,’’ the owner or operator is 

the person identified as the owner or 

operator on blanket certificates issued 

under 18 CFR 284.224. 

Comment: Commenters appreciated 

that the EPA provided a threshold of 50 

ft3 of physical volume for blowdown 

emissions reporting but requested 

several changes. Commenters requested 

that the EPA include a list of ancillary 

equipment, such as metering and/or 

regulating stations, pipeline 

interconnects, and pig launchers and 

receivers, that would be excluded from 

reporting of blowdown emissions. One 

commenter suggested that, alternatively, 

the physical volume threshold could be 

increased to 3,000 thousand cubic feet 

to clearly exclude blowdowns of 

ancillary facilities along the pipeline. 

Another commenter stated that it is not 

feasible to establish a specific de 

minimis volume threshold to exclude all 

ancillary equipment. 

Response: The EPA is finalizing the 

reporting threshold of 50 ft3 of physical 

volume for blowdowns in the Onshore 

Natural Gas Transmission Pipeline 

segment as proposed. This threshold 

excludes smaller blowdown sources that 

have little contribution to emissions, 

consistent with other industry segments 

within subpart W that must report 

blowdown stack vent emissions. The 

EPA is not increasing the physical 

volume reporting threshold to account 

for blowdowns from ancillary 

equipment, as this would be 

inconsistent with the EPA’s previous 

analysis in ‘‘Equipment Threshold for 

Blowdowns’’ (see Docket Item No. EPA– 

HQ–OAR–2009–0923–3581), and 

commenters were divided on whether 

increasing the threshold would even 

address their primary concern. 

The EPA agrees that the emphasis for 

the Onshore Natural Gas Transmission 

Pipeline segment is on calculating and 

reporting blowdown emissions from 

pipeline segments, not ancillary 

equipment. However, any list of 

ancillary equipment that would be 

excluded from blowdown reporting 

could be incomplete, resulting in 

reporting of emissions from other 

equipment that is ancillary but not on 

the list in the rule. In addition, some of 

the equipment identified as ‘‘ancillary’’ 

in this segment is not considered 

ancillary in other industry segments, 

which could lead to confusion among 

reporters. Instead, the final rule clarifies 

that facilities in the Onshore Natural 

Gas Transmission Pipeline segment 

report pipeline blowdown emissions 

from blowdown vent stacks. If the 

blowdown does not include a pipeline 

segment or has a physical volume of less 

than 50 ft3, then that blowdown is not 

required to be reported. 

Comment: Several commenters stated 

that the blowdown equipment and event 

type categories in 40 CFR 98.233(i)(2) 

were developed for compressor station 

blowdowns and would not provide 

meaningful information regarding 

pipeline blowdowns in the Onshore 

Natural Gas Transmission Pipeline 

segment. The commenters provided 

suggestions for categories that would be 

more applicable to Onshore Natural Gas 

Transmission Pipeline blowdowns and 

would provide more valuable 

information than relying on the 

categories in the existing rule. 

Response: The EPA agrees with the 

commenters that the rule should 

include blowdown categories specific to 

blowdowns in the Onshore Natural Gas 

Transmission Pipeline segment. The 

final rule specifies that blowdowns 

must be grouped into one of the 

following categories: Pipeline integrity 

work (e.g., the preparation work of 

modifying facilities, ongoing 

assessments, maintenance or 

mitigation), traditional operations or 

pipeline maintenance, equipment 

replacement or repair (e.g., valves), pipe 

abandonment, new construction or 

modification of pipelines including 

commissioning and change of service, 

operational precaution during activities 

(e.g. excavation near pipelines), 

emergency shutdowns including 

pipeline incidents as defined by 

PHMSA, and all other pipeline 

segments with a physical volume greater 

than or equal to 50 ft3. 

Comment: Commenters requested that 

the EPA not finalize the requirement to 

report latitude and longitude for each 

blowdown event. The commenters 

indicated this requirement would be 

burdensome, such data are not currently 

collected, the requirement is 

inconsistent with the Paperwork 

Reduction Act, and the data would not 

be useful in determining the inventory. 

Some commenters also suggested 

aggregating emissions at the state level 

or only at the national/facility level. 

Response: The requirement to report 

latitude and longitude of each 

blowdown was included in the 

proposed rule to help characterize the 

emissions from the new Onshore 

Natural Gas Transmission Pipeline 

segment on a more granular level than 

the nationwide facility. The EPA 

evaluated this comment and has noted 

the commenters’ assertion that the 

latitude and longitude of each 


tkelley on DSK3SPTVN1PROD with RULES3
64276 Federal Register / Vol. 80, No. 204 / Thursday, October 22, 2015 / Rules and Regulations 

9The Professional Petroleum Data Management 

Association. The US Well Number Standard: An 

Identifier for Petroleum Industry Wells in the USA. 

Version 2013 rev 1, published June 19, 2014. 

Available at http://dl.ppdm.org/dl/1147. 

blowdown is not information currently 

reported elsewhere and may result in 

additional burden. Therefore, the EPA is 

not finalizing the requirement to report 

the emissions or latitude and longitude 

for each individual blowdown. Instead, 

the EPA is finalizing requirements for 

reporters to aggregate blowdown 

emissions by state and report the 

number of blowdowns and mileage of 

pipeline per state. 

Comment: Two commenters 

questioned the requirement to report the 

data elements in proposed 40 CFR 

98.236(aa)(11). Two commenters noted 

that the quantities of natural gas in this 

section are duplicative of information 

reported to FERC annually in FERC 

Form 2, although the units of measure 

are dekatherms rather than thousand 

standard cubic feet. One commenter 

noted that for the GHGRP reporting, 

they would assume 1 dekatherm is 

equivalent to 1,000 scf of natural gas, 

based on the approximate heat value of 

natural gas. The other commenter 

opposed these reporting requirements 

because they are duplicative and 

inconsistent with the requirements of 

the PRA, which is intended to reduce 

the information burden imposed by the 

federal government by requiring that 

agencies ensure that reported 

information is not duplicative of other 

available data and has a practical utility. 

This commenter stated that the EPA has 

not followed the PRA. The commenter 

also stated that the requested 

information is irrelevant to assisting 

EPA in verifying pipeline blowdown 

emissions; in particular, the information 

cannot be used to calculate pipeline 

blowdown volumes. 

Response: As the EPA has noted 

elsewhere, the data collected in the 

GHGRP will be used to inform future 

policy decisions. As such, information 

regarding emissions and the inputs 

needed to verify those emissions is only 

part of the information that is needed. 

It is important to understand that, to 

inform future policy, activity data is 

often as useful as emissions estimates. 

The EPA has determined that data 

elements in 40 CFR 98.236(aa)(11) are 

activity data that will be used to 

determine how to use the emissions 

data to inform future policy decisions. 

It is essential that reporters provide and 

certify the data they gather under this 

rule so that EPA has a complete 

inventory from all sources under this 

rule and can directly relate the activity 

data to the emissions data reported, 

which will provide for appropriate 

verification of the emissions data 

reported. 

The EPA agrees with the first 

commenter that for purposes of 

reporting the data elements in 40 CFR 

98.236(aa)(11), reporters may consider 1 

dekatherm equal to 1,000 scf. 

Comment: Several commenters 

asserted that the EPA has not been 

consistent in its decisions on whether to 

include pipeline leaks across the 

subpart W industry segments. Some 

commenters supported the EPA’s 

proposal not to include leaks from 

transmission pipelines and noted the 

decision was consistent with the 

Onshore Petroleum and Natural Gas 

Production segment. Conversely, one 

commenter stated that transmission 

pipeline leaks should be reported, 

consistent with the new Onshore 

Petroleum and Natural Gas Gathering 

and Boosting segment. This commenter 

noted that accidental leaks at these 

facilities can be a significant source of 

CH4 emissions, as evidenced by the 

magnitude of emissions from pipeline 

incidents reported to PHMSA, and leaks 

at remote locations may not be noticed 

or repaired immediately. 

Response: The EPA previously 

considered fugitive emissions that result 

from leaks in transmission pipelines in 

the re-proposal of subpart W in April 

2010 (75 FR 18616; April 12, 2010) but 

did not include provisions for these 

emissions in either the proposed or final 

rules. The April 2010 preamble 

explained that the EPA did not propose 

reporting requirements for fugitive 

emissions from leaks in natural gas 

pipeline segments between compressor 

stations due to the dispersed nature of 

the fugitive emissions and the fact that, 

once fugitives are found, the leaks 

causing the emissions are usually 

addressed quickly for safety reasons (75 

FR 18616; April 12, 2010). The EPA also 

noted in the proposal preamble for these 

amendments (79 FR 76267; December 9, 

2014) that larger fugitive leaks are 

currently reported to PHMSA as part of 

49 CFR 191.3. Under this provision, any 

pipeline incident that results in 

unintentional gas loss of 3 million ft3 or 

more must be reported. The commenter 

that noted that emissions can be 

significant cited the emissions reported 

to PHMSA under this provision, and the 

EPA does not find it necessary to 

require owners and operators to report 

this same information under the 

GHGRP. The focus of the PHMSA 

reporting requirements is to identify 

major safety-related incidents that are 

not a part of typical operations. 

Therefore, the EPA is not finalizing a 

requirement to report fugitive emissions 

from transmission pipeline leaks but 

will continue to review this source as 

part of the EPA’s ongoing effort to 

ensure comprehensive, high quality data 

in subpart W. 

D. Summary of Final Amendments for 

Well Identification Numbers 

1. Summary of Final Amendments 

The EPA is finalizing some of the 

proposed amendments to 40 CFR 98.236 

to add reporting requirements for well 

identification numbers to improve data 

quality by enabling identification of 

wells. These well identification 

numbers will be reported for the first 

time in the report covering 2016 

emissions; reporters will not be required 

to report well identification numbers for 

previous years. For the majority of 

wells, the well identification number 

reported will be the US Well Number 

(formerly referred to as the API Well 

Number, or API Number).9 For any well 

that does not already have a US Well 

Number, the reporter will be required to 

provide the unique well number 

assigned by the permitting authority for 

drilling of oil and gas wells. 

Commenters varied in their level of 

support for the proposed provisions 

regarding well identification numbers. 

The EPA is adjusting the final 

provisions in response to concerns 

about these reporting provisions raised 

in comments. 

The EPA is requiring the reporting of 

well identification numbers for the 

Onshore Petroleum and Natural Gas 

Production segment only for 

information related specifically to wells. 

For reporters in the Onshore Petroleum 

and Natural Gas Production segment 

that report emissions using input data 

that are calculated from measurements 

at individual wells or equipment 

associated with individual wells (e.g., if 

Equation W–10A was used to calculate 

emissions from oil well completions 

and workovers with hydraulic 

fracturing, well testing emissions), the 

report must include the well 

identification number for which those 

measurements were made and the well 

identification number(s) of other wells 

to which the measurements will be 

applied. This includes a list of the well 

identification numbers by sub-basin for 

the producing wells at the end of the 

calendar year as well as lists of the well 

identification numbers for the wells 

acquired, divested, completed, and 

permanently taken out of production 

during the calendar year. The EPA is not 

finalizing the proposed requirement that 

reporters in the Onshore Petroleum and 

Natural Gas Production segment report 

a list of well identification numbers 

associated with different emission 


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Federal Register / Vol. 80, No. 204 / Thursday, October 22, 2015 / Rules and Regulations 64277 

sources for all wells in a sub-basin 

included in the reported emissions data. 

The EPA is finalizing the proposed 

change to update references to the ‘‘API 

well number’’ in subpart W to ‘‘well 

identification number.’’ The EPA is not 

otherwise changing the well 

identification reporting requirements 

finalized in 2014 (79 FR 70352; 

November 25, 2014). Reporters will still 

need to report well identification 

numbers for liquids unloading and for 

any exploratory wells for which 

reporting has been delayed for 2 years. 

2. Summary of Comments and 

Responses 

Comment: While one commenter 

supported the addition of well 

identification number reporting, most 

commenters opposed the proposal to 

require reporting of well identification 

numbers. These commenters asserted 

that requiring reporting of well 

identification numbers is an overreach 

of the EPA’s authority for the reporting 

program under CAA section 114 and 

that the EPA has not provided a 

reasoned basis for the departure from 

the previous EPA approach that wellspecific data was not necessary under 

Subpart W. Commenters also noted that 

well identification numbers are not 

needed to validate reported emissions. 

One commenter noted that the EPA has 

not questioned the data collected from 

wells thus far; nor has the EPA stated 

that the data already collected are 

insufficient to inform policy without 

addition of well identification numbers, 

so with this proposal, the EPA is no 

longer balancing data collection with 

reporting burdens. Commenters stated 

that mapping and maintaining a 

database of well identification numbers 

is more burdensome than the EPA 

estimated, and one commenter stated 

that it would be arbitrary and capricious 

to require companies to expend the 

resources necessary to report these data. 

Commenters also noted that it is not 

clear how to interpret the term 

‘‘associated with’’ in all cases. One 

commenter stated that matching specific 

wells with emissions in the GHGRP 

could cause security concerns. 

Response: The EPA disagrees that 

requiring reporting of well identification 

numbers is an overreach of our 

authority. The EPA has determined that 

these data elements are useful and 

necessary for the verification of existing 

data and for characterizing the 

emissions from the industry segment. 

This final revision will allow the EPA 

to link the GHGRP data to other 

databases (i.e. state permitting 

databases) to more easily match the data 

reported under the GHGRP with other 

data sources and will improve the 

accuracy and transparency of subpart 

W. Additionally, being able to match the 

GHGRP data to other data sources will 

provide the EPA with more options for 

analysis of the GHGRP data to better 

inform future policy decisions related to 

GHG emissions from the oil and natural 

gas production sector. The reporting of 

the well identification numbers will 

also allow the EPA to assess the 

completeness and representativeness of 

the data collected under the GHGRP as 

a portion of all activity in the oil and 

natural gas production sector. The EPA 

reiterates that CAA section 114 provides 

the EPA with the authority to collect 

emissions data, which includes 

information about the location of the 

source of emissions. Section 114 

generally authorizes the EPA to gather 

information from any person who owns 

or operates an emissions source, who is 

subject to a requirement of the CAA, 

who manufactures control or process 

equipment, or who the Administrator 

believes has information necessary for 

the purposes of section 114(a). The EPA 

may gather information for purposes of 

establishing implementation plans or 

emissions standards, determining 

compliance, or ‘‘carrying out any 

provision’’ of the CAA. For these 

reasons, the Administrator may request 

that a person, on a one-time, periodic or 

continuous basis, establish and 

maintain records, make reports, install 

and operate monitoring equipment and, 

among other things, provide such 

information the Administrator may 

reasonably require. This language has 

been interpreted to grant the EPA broad 

authority. See, e.g., Dow Chemical Co. v. 

U.S., 467 U.S. 227, 233 (1986) 

(‘‘Regulatory and enforcement authority 

generally carries with it all modes of 

inquiring and investigation traditionally 

employed or useful to execute the 

authority granted.’’). See, generally 

Mandatory Greenhouse Gas Reporting 

Rule: EPA’s Response to Public 

Comments, Volume No.: 9, Legal Issues 

(Docket Item No. EPA–HQ–OAR–2008– 

0508–2264). The requirement to report 

well identification numbers for wellspecific data clearly fits within EPA’s 

statutory authority. We also believe, for 

the reasons stated above, that we are 

exercising this authority reasonably in 

furtherance of the purposes of the Clean 

Air Act. Further, the EPA disagrees that 

this is a deviation from our previous 

approach to collecting data. As 

discussed in section II.B of this 

preamble, the EPA is finalizing the 

requirement to report Onshore 

Petroleum and Natural Gas Gathering 

and Boosting facilities at the basin-level, 

which is consistent with our previous 

approach to the Onshore Petroleum and 

Natural Gas Production segment. 

Therefore, the EPA is finalizing the 

requirements to report the well 

identification number for well-specific 

data as proposed. Specifically, for 

reporters in the Onshore Petroleum and 

Natural Gas Production segment that 

report emissions using input data that 

are calculated from measurements at 

individual wells or equipment or 

operations associated with individual 

wells (e.g., if Equation W–10A is used 

to calculate emissions from oil well 

completions and workovers with 

hydraulic fracturing, well testing 

emissions, liquids unloading), the report 

must include the well identification 

number for which those measurements 

were made, or for which the equipment 

or operations are associated. In addition, 

the EPA is finalizing the requirements 

in 40 CFR 98.236(aa)(1)(ii)(D) through 

(H) to include a list of the well 

identification numbers by sub-basin for 

the producing wells at the end of the 

calendar year and lists of the well 

identification numbers for the wells 

acquired, divested, completed, and 

permanently taken out of production 

during the calendar year. The EPA 

continues to expect that this is a low 

burden to reporters because reporters 

already track and maintain well 

identification numbers associated with 

measurements used for the GHGRP 

input data. 

To respond to the comment that well 

identification numbers may not be 

available for or assigned to equipment 

other than wells, the EPA reviewed the 

permits and requirements in seven 

different states. Although most of the 

states assign unique identifiers to each 

emission source, the EPA found that 

only two of the seven states have a 

tracking system that links individual 

emission sources to specific wells and 

well identification numbers, and these 

two states are not consistent in their 

approach. (See ‘‘Greenhouse Gas 

Reporting Rule: Technical Support for 

2015 Revisions and Confidentiality 

Determinations for Petroleum and 

Natural Gas Systems; Final Rule’’ in 

Docket ID No. EPA–HQ–OAR–2014– 

0831 for more information on this 

analysis.) While it may be 

straightforward to assign some emission 

sources directly to one well, particularly 

if there is only one well on the single 

well pad and the reporter does not 

operate any other wells nearby, the 

EPA’s review of state requirements 

shows that there may be multiple 

scenarios in which a reporter does not 

know which well or wells are associated 

with a particular emission source. For 


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64278 Federal Register / Vol. 80, No. 204 / Thursday, October 22, 2015 / Rules and Regulations 

10 ‘‘Confidentiality Determinations for Data 

Required Under the Mandatory Greenhouse Gas 

Reporting Rule and Amendments to Special Rules 

Governing Certain Information Obtained Under the 

Clean Air Act’’ (76 FR 30782, May 26, 2011). 

example, there may be multiple wells 

on a single well pad and multiple 

storage tanks associated with that well 

pad, and the tanks may have the ability 

to receive hydrocarbon liquids from 

several of those wells. Therefore, in 

light of the potential burden of requiring 

facilities to develop new tracking 

systems that would assign and track 

emissions to well identification 

numbers for the purposes of part 98, the 

EPA is not requiring facilities in this 

rulemaking to report well identification 

numbers for every emission source in a 

facility in the Onshore Petroleum and 

Natural Gas Production segment. 

E. Summary of Final Amendments to 

Best Available Monitoring Methods 

1. Summary of Final Amendments 

As proposed, reporters will be 

allowed to use BAMM for the 2016 

reporting year for the new industry 

segments and emission sources 

included in this action. These include 

calculating and reporting emissions 

from oil well completions and 

workovers with hydraulic fracturing, 

from onshore petroleum and natural gas 

gathering and boosting systems, and for 

transmission pipeline blowdown 

emissions. Reporters are allowed to use 

BAMM to estimate inputs to emission 

equations for the newly finalized 

emission sources for cases where the 

monitoring of these inputs would not be 

possible beginning on January 1, 2016. 

The use of BAMM is not allowed for the 

reporting of well identification numbers 

because reporters should already have 

well identification numbers readily 

available for all wells and associated 

equipment to which this reporting 

requirement applies and because the 

well identification number is not a 

parameter that requires monitoring 

equipment to be measured and, 

therefore, does not meet the 

requirements for BAMM. 

For these sources, the EPA is 

finalizing a longer timeline for BAMM 

than was proposed. Reporters have the 

option of using BAMM for the new 

industry segments and emission sources 

included in this action from January 1, 

2016, to December 31, 2016, without 

seeking prior EPA approval. The 

provision providing a set amount of 

automatic transitional BAMM will allow 

reporters to prepare for data collection 

while automatically being able to use 

BAMM, which is consistent with the 

approach of 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, and is responsive to 

comments received on the proposed 

rule provisions. 

The EPA is not finalizing the 

proposed provision to allow reporters 

the opportunity to request an extension 

for the use of BAMM. The EPA will not 

accept requests for an extension for the 

use of BAMM beyond the time periods 

listed above. As proposed, the EPA also 

is not providing transitional BAMM for 

these new requirements beyond 

December 31, 2016. 

The EPA is not allowing the use of 

BAMM beyond 2016 and does not 

anticipate that BAMM will be needed 

beyond 2016 for the new segments and 

emissions sources being finalized in this 

rule. 

2. Summary of Comments and 

Responses 

Comment: Several commenters stated 

that only 3 months of automatic BAMM 

and 1 year of transitional BAMM is not 

enough time to implement the 

monitoring and measurement 

requirements for facilities newly subject 

to subpart W and newly added emission 

sources. The commenter stated that 

adding a new segment is a significant 

amendment and the EPA has set the 

precedent of providing at least 1 year of 

automatic BAMM when adding a new 

segment to subpart W. The commenters 

noted that not all gathering and boosting 

reporters are already reporting as 

Onshore Petroleum and Natural Gas 

Production facilities, so they will not 

necessarily all be familiar with the 

monitoring and calculation 

methodologies. The commenters also 

noted that nearly all reporters will be 

spending the first month working on 

BAMM requests for the rest of 2016. 

The commenters had a variety of 

suggestions for how long the EPA 

should provide BAMM for these new 

emission sources. Several commenters 

suggested 1 year (through the end of 

2016) for automatic BAMM. Another 

commenter suggested March 31, 2017 

(i.e., 1 year in addition to the EPA’s 

proposed 3 months), and another stated 

that 3 years would be consistent with 

the length of time provided when the 

Onshore Petroleum and Natural Gas 

Production segment was added to 

subpart W. Some commenters addressed 

the length of transitional BAMM with 

the EPA’s approval. One commenter 

noted that a new reporter/facility could 

become subject to one of the new 

segments beyond the end of 2016, so 

there should be no deadline for 

submitting a request for BAMM to the 

EPA. Another requested transitional 

BAMM through the end of 2018. 

Response: The EPA recognizes that 

most of the amendments being finalized 

in this rulemaking are new requirements 

rather than clarifications of existing 

reporting requirements for facilities 

already subject to subpart W and may 

require the development and 

implementation of new systems of data 

collection and monitoring. Therefore, 

the EPA is finalizing 1 year of automatic 

transitional BAMM in place of the 

proposed 3 months of automatic 

transitional BAMM. This additional 

time for reporters to comply with the 

revised monitoring methods in subpart 

W will allow facilities to install the 

necessary monitoring equipment and 

implement any new systems of data 

collection that may be required. Because 

the amount of time for which automatic 

BAMM is available should be sufficient 

time to comply with the requirements of 

subpart W for the new segments and 

emission sources, the EPA will not 

provide additional BAMM beyond the 

automatic BAMM provisions in 40 CFR 

98.234(g). 

We note that 40 CFR 98.235(e) and(f) 

provides 6 months of reporting 

flexibility for facilities that become 

subject to subpart W or acquire new 

sources after reporting year 2016. 

Reporters may also refer to the 

provisions of 40 CFR 98.235 after 

reporting year 2016 for guidance on 

reporting emissions if certain required 

data are not collected. 

III. Confidentiality Determinations 

A. Summary of Final Confidentiality 

Determinations for New Subpart W Data 

Elements 

In the proposed rule, we assigned new 

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.10 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 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 


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Federal Register / Vol. 80, No. 204 / Thursday, October 22, 2015 / Rules and Regulations 64279 

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 six 

new data elements without making a 

data category assignment. Refer to the 

preamble to the proposed rule (79 FR 

76267; December 9, 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. 

Specifically, the EPA is finalizing the 

proposed decision to require each of the 

new data elements to be designated as 

‘‘not CBI.’’ 

The EPA proposed to provide 

reporters with the option to delay 

reporting of five data elements for 2 

reporting years in situations where 

exploratory wells are the only wells in 

a sub-basin. We received comment 

requesting that the EPA provide the 

same 2-year delay for additional data 

elements associated with exploratory 

wells. The comment and the EPA’s 

response are included in section III.B of 

this preamble. Based on consideration 

of the comment and consistent with the 

EPA’s previous decisions related to 

exploratory wells under part 98 (79 FR 

63750, October 24, 2014; 79 FR 70352, 

November 25, 2014), the EPA is 

finalizing provisions to provide 

reporters with the option to delay 

reporting of five data elements as 

proposed and, based on comments 

received, an additional two data 

elements for 2 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 seven data 

elements associated with the 

delineation or wildcat well may be 

delayed for 2 reporting years: (1) The 

cumulative gas flowback time, in hours, 

for each sub-basin, from when gas is 

first detected until sufficient quantities 

are present to enable separation (40 CFR 

98.236(g)(5)(i)); (2) the cumulative 

flowback time, in hours, for each subbasin, after sufficient quantities of gas 

are present to enable separation (40 CFR 

98.236(g)(5)(i)); (3) the measured 

flowback rate, in standard cubic feet per 

hour, for each sub-basin (40 CFR 

98.236(g)(5)(ii)); (4) the gas to oil ratio 

for the well (40 CFR 98.236(g)(5)(iii)(A)); 

(5) the volume of oil produced during 

the first 30 days of production after 

completions of each newly drilled well 

or well workover using hydraulic 

fracturing (40 CFR 98.236(g)(5)(iii)(B)); 

(6) the total annual gas-liquid separator 

oil volume that is sent to applicable 

onshore storage tanks, in barrels (40 

CFR 98.236(j)(1)(iii)); and (7) the total 

annual oil throughput that is sent to all 

atmospheric tanks, in barrels (40 CFR 

98.236(j)(2)(i)(A). 

Four of the seven 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). Two of the 

seven data elements are inputs only 

when the applicable data are related to 

a single well (the two data elements in 

40 CFR 98.236(g)(5)(i)), and one data 

element is never an input (40 CFR 

98.236(j)(2)(i)(A)). Where the EPA agrees 

that there are early disclosure concerns 

related to exploratory wells, the EPA 

decided to treat those early disclosure 

concerns consistently throughout 

subpart W by providing the option to 

delay reporting by 2 years to all seven 

data elements listed above. 

At proposal, in cases where the two 

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

are not inputs to equations, they were 

assigned to the ‘‘Unit/Process Operating 

Characteristics that are Not Inputs to 

Emission Equations’’ category and were 

proposed to be ‘‘not CBI.’’ The EPA is 

finalizing this determination as 

proposed. Specifically, the ‘‘not CBI’’ 

determination applies to all situations 

except for when the data elements are 

inputs to equations. 

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. The EPA evaluated and 

summarized any potential disclosure 

concerns with the reporting of the data 

elements assigned to the ‘‘Inputs to 

Emission Equations’’ data category in 

the memo titled ‘‘Review for Potential 

Disclosure Concerns for Inputs to 

Emission Equations Affected by the 

2015 Revisions and Confidentiality 

Determinations for Petroleum and 

Natural Gas Systems’’ available in 

Docket ID No. EPA–HQ–OAR–2014– 

0831. Other than the exception of the 

early disclosure concerns for certain 

data elements related to exploratory 

wells discussed earlier in this section, 

the EPA has concluded that there are no 

disclosure concerns with the reporting 

of these data elements. 

The data element collected under 40 

CFR 98.236(j)(2)(i)(A) was proposed as 

‘‘not CBI’’ and was not assigned to a 

data category. The EPA is finalizing this 

determination as proposed as well. For 

the data elements reported under 40 

CFR 98.236(g)(5)(i)) (in cases where they 

are not inputs to equations) and 40 CFR 

98.236(j)(2)(i)(A), the ‘‘not CBI’’ 

determinations will apply once the data 

are reported to the EPA following the 2- 

year delay. 

B. Summary of Comments and 

Responses 

This section summarizes the major 

comments and responses related to the 

proposed categorical assignments and 

confidentiality determinations. See 

‘‘Response to Public Comments on 

Greenhouse Gas Reporting Rule: 2015 

Revisions and Confidentiality 

Determinations for Petroleum and 

Natural Gas Systems’’ in Docket ID No. 

EPA–HQ–OAR–2014–0831 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: 2015 Revisions and 

Confidentiality Determinations for 

Petroleum and Natural Gas Systems; 

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

OAR–2014–0831 for a complete listing 

of final data category assignments and 

confidentiality determinations, and a 

discussion of changes since proposal. 

Comment: One commenter requested 

that the EPA reconsider the 

determination that the quantity of 

produced gas throughput in the 

calendar year and the quantity of 

produced gas consumed by the facility 

in the calendar year are ‘‘not CBI.’’ The 

commenter noted that the quantity of 

natural gas received and the quantity of 

processed gas leaving processing plants 

was maintained as CBI in the 2014 

amendments (79 FR 70352; November 

25, 2014). The commenter also stated 

that information on fuel consumed at 

gathering and boosting facilities is not 

typically publically available, and when 

this information is combined with the 

quantity of produced gas throughput, it 

directly indicates the fuel efficiency of 

a station. The commenter noted that 

while the EPA is correct that the 

agreements are long-term for a given 

well, revealing information about one 

facility’s fuel efficiency could cause 

competitive harm by affecting contracts 

for other facilities owned by that 

company, especially if there are smaller 

gathering and boosting facilities in the 

area that do not have to report this 

information to the GHGRP. 

The commenter also requested that 

the EPA clarify a number of the 

reporting elements in 40 CFR 


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98.236(aa)(10). Specifically, the 

commenter requested clarification of the 

terms ‘‘produced gas,’’ ‘‘produced 

condensate,’’ ‘‘produced oil,’’ 

‘‘throughput,’’ and ‘‘consumed’’ as they 

are used in proposed 40 CFR 

98.236(aa)(10). The commenter also 

asserted that the data element in 40 CFR 

98.236(aa)(10)(ii) (‘‘quantity of produced 

gas consumed’’) would be redundant 

with subpart C and should not be 

finalized. Finally, the commenter stated 

that the requirement to report the 

‘‘quantity of gas flared, vented and/or 

unaccounted for in the calendar year’’ in 

40 CFR 98.236(10)(aa)(v) would 

undermine over 5 years of rule 

development, public comment, 

reconsiderations, and petitioner 

negotiations because it would require 

reporting of emissions that are 

otherwise exempted (e.g., blowdowns 

below 50 ft3). 

Response: The EPA reviewed these 

comments and has clarified the 

reporting elements in 40 CFR 

98.236(aa)(10) for the final rule. The 

final reporting requirements include: (1) 

The quantity of gas received by the 

gathering and boosting facility in the 

calendar year, in thousand standard 

cubic feet; (2) the quantity of gas 

transported to a natural gas processing 

facility, a natural gas transmission 

pipeline, a natural gas distribution 

pipeline, or another gathering and 

boosting facility in the calendar year, in 

thousand standard cubic feet; (3) the 

quantity of all hydrocarbon liquids 

received by the gathering and boosting 

facility in the calendar year, in barrels; 

and (4) the quantity of all hydrocarbon 

liquids transported to a natural gas 

processing facility, a natural gas 

transmission pipeline, a natural gas 

distribution pipeline, or another 

gathering and boosting facility in the 

calendar year, in barrels. The EPA has 

determined that these quantities will be 

easily accessible for all reporters and are 

more consistent with the reporting 

requirements for the Onshore Natural 

Gas Processing segment. The EPA is 

finalizing the CBI determinations for 

these quantities as ‘‘not CBI,’’ as 

proposed. 

The final reporting requirements do 

not include the terms ‘‘produced gas,’’ 

‘‘produced condensate,’’ ‘‘produced 

oil,’’ ‘‘throughput,’’ or ‘‘consumed,’’ so 

no clarification regarding the use of 

those terms is needed. In particular, the 

final rule does not include a 

requirement to report the quantity of 

produced gas consumed by the facility. 

The difference between the quantities 

received by a gathering and boosting 

facility and the quantities exiting the 

gathering and boosting facility is 

expected to include the quantity of gas 

consumed by the facility as well as the 

quantity of gas flared or vented in one 

lump sum. Therefore, the reporting 

requirements do not directly indicate 

the fuel efficiency of the stations in a 

gathering and boosting facility. 

Comment: One commenter reiterated 

previously stated concerns over the 

disclosure of information for 

exploratory wells, especially when they 

are located in stepout areas where no 

prior reporting exists for a given subbasin. The commenter supported the 

EPA’s proposal to defer reporting of data 

elements related to oil well completions 

and workovers with hydraulic fracturing 

for exploratory wells, but expressed 

concern that EPA has not provided such 

a delay in reporting for all emissions 

data and data elements that are 

associated with exploratory wells. 

Specifically, the commenter stated that 

the EPA failed to provide a necessary 2- 

year deferral in reporting for the 

following data elements, which are as 

business sensitive and confidential as 

the other information for which the EPA 

proposed to defer reporting for 2 years: 

• 40 CFR 98.236(g)(5)(iii)(A)—If you used 

Equation W–12C to calculate the average gas 

production rate for an oil well, the gas to oil 

ratio for the well in standard cubic feet of gas 

per barrel of oil. 

• 40 CFR 98.236(g)(5)(iii)(B)—If you used 

Equation W–12C to calculate the average gas 

production rate for an oil well, the volume 

of oil produced during the first 30 days of 

production after completions of each newly 

drilled well or well workover using hydraulic 

fracturing, in barrels. 

• 40 CFR 98.236(g)(6)(i)—If you used 

Equation W–10B to calculate annual 

volumetric total gas emissions for 

completions that vent gas to the atmosphere, 

the vented natural gas volume, in standard 

cubic feet, for each well in the sub-basin. 

• 40 CFR 98.236(g)(6)(ii)—If you used 

Equation W–10B to calculate annual 

volumetric total gas emissions for 

completions that vent gas to the atmosphere, 

the 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 subbasin. 

• 40 CFR 98.236(g)(7)—For each oil well 

completion or workover and well type 

combination, annual gas emissions. 

• 40 CFR 98.236(g)(8)—For each oil well 

completion or workover and well type 

combination, annual CO2 emissions. 

• 40 CFR 98.236(g)(9)—For each oil well 

completion or workover and well type 

combination, annual CH4 emissions. 

• 40 CFR 98.236(g)(10)—For each oil well 

completion or workover and well type 

combination, the total N2O emissions, if the 

well emissions were vented to a flare. 

Response: The EPA reviewed the data 

elements identified by the commenter as 

having disclosure concerns for 

exploratory wells (delineation wells and 

wildcat wells). Consistent with the 

EPA’s previous decisions related to 

exploratory wells under part 98 (79 FR 

63750, October 24, 2014; 79 FR 70352, 

November 25, 2014), the EPA has 

determined that, for gas well 

completions or workovers with 

hydraulic fracturing of wildcat wells 

and/or delineation wells, early public 

disclosure of some of the additional data 

elements identified by the commenter 

could reveal the well productivity of 

wildcat wells and/or delineation wells, 

thereby resulting in the loss of 

investment value. 

The additional data elements that 

could reveal well productivity for 

wildcat and/or delineation wells are as 

follows: 

• The gas to oil ratio for the well (40 CFR 

98.236(g)(5)(iii)(A)) 

• The volume of oil produced during the 

first 30 days of production after completions 

of each newly drilled well or well workover 

using hydraulic fracturing (40 CFR 

98.236(g)(5)(iii)(B)) 

As the EPA has previously noted (79 

FR 70352, November 25, 2014), 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 seven 

total 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 2-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 data elements, in those cases 

where delineation wells or wildcat 

wells are the only wells in a sub-basin, 

reporters should be provided an option 

to delay reporting of the given data 

element for 2 reporting years starting in 

2015. In such cases, if the 2-year delay 

in reporting is used, the reporter must 

indicate for each delayed reporting 

element that wildcat wells and/or 

delineation wells are the only wells in 

a sub-basin that can be used for the 

measurement in the current reporting 

year. In addition, when reporters report 

the delayed data elements after the 2- 

year delay, they must also report the 

well identification 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 


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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 

seven data elements in their 2016 

annual report submitted by March 31, 

2017, or (2) elect to delay reporting of 

these data elements for up to 2 years. If 

the reporter elects to delay reporting, 

then the well identification numbers for 

the wildcat and delineation wells in the 

sub-basin for which reporting has been 

delayed and the data elements delayed 

from reporting must be reported no later 

than March 31, 2019. 

The following inputs meet the 

definition of emission data in 40 CFR 

2.301(a)(2)(i) because they indicate the 

amount or frequency of gas emitted by 

the facility: Volume of natural gas 

vented (reported under 40 CFR 

98.236(g)(6)(i)) and flow rate at the 

beginning of the period of time when 

sufficient quantities of gas are present to 

enable separation (reported under 40 

CFR 98.236(g)(6)(ii)). Without 

corresponding activity data, such as a 

count of the exploratory wells in a subbasin or production or flow rate data for 

a sub-basin containing only exploratory 

wells, there is no potential to disclose 

business sensitive information based on 

these data elements. Therefore, the EPA 

is not providing an option to delay 

reporting of these data elements for 2 

reporting years. 

Similarly, the data element annual gas 

emissions (reported under 40 CFR 

98.236(g)(7)) meets the definition of 

emission data in 40 CFR 2.301(a)(2)(i) 

and is assigned to the ‘‘Emissions’’ data 

category because it indicates the amount 

of gas emitted by the facility. In 

addition, the following data elements 

meet the definition of emission data in 

40 CFR 2.301(a)(2)(i) and are assigned to 

the ‘‘Emissions’’ data category because 

they are emissions of pollutants emitted 

by the source: annual CO2 emissions 

(reported under 40 CFR 98.236(g)(8)), 

annual CH4 emissions (reported under 

40 CFR 98.236(g)(9)), and annual nitrous 

oxide (N2O) emissions if the well 

emissions were vented to a flare 

(reported under 40 CFR 98.236(g)(10)). 

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. Without 

corresponding activity data, such as a 

count of the exploratory wells in a subbasin or production or flow rate data for 

a sub-basin containing only exploratory 

wells, there is no potential to disclose 

business sensitive information based on 

these data elements. Therefore, the EPA 

is not providing an option to delay 

reporting of these data elements for 2 

reporting years. 

IV. Impacts of the Final Amendments to 

Subpart W 

A. Impacts of the Final Amendments 

The final amendments to subpart W 

add monitoring and reporting 

requirements for reporters in three 

industry segments: Onshore Petroleum 

and Natural Gas Production, Onshore 

Petroleum and Natural Gas Gathering 

and Boosting, and Onshore Natural Gas 

Transmission Pipeline. The EPA is 

adding 213 new data elements to the 

reporting requirements. The new data 

elements impose additional burden and 

costs because, for each of the new data 

elements that are required to be 

reported, reporters are required to 

calculate the data element using readily 

available data and report the value to 

the EPA via e-GGRT as part of the 

annual report currently required under 

part 98. 

The EPA calculated the increase in 

reporting and recordkeeping burden 

associated with the new data elements 

by adjusting labor hours upwards per 

reporter for all affected industry 

segments. For all three segments, an 

estimate of 10 hours per year per 

reporter was allotted for reporting via eGGRT and 10 hours per year per 

reporter was allotted for recordkeeping. 

Costs to reporters associated with this 

rulemaking are expressed as labor costs 

(i.e., the cost of labor by facility staff to 

comply with the amendments), capital 

costs for equipment and travel, and 

operation and maintenance (O&M) 

costs. 

Reporters in the Onshore Petroleum 

and Natural Gas Production segment 

have to monitor and report emissions 

and data elements associated with oil 

well completions and workovers with 

hydraulic fracturing. Reporters in this 

segment also have to report the well 

identification numbers associated with 

individual oil and gas wells. The 

addition of the requirement to report 

emissions associated with oil well 

completions and workovers with 

hydraulic fracturing is expected to cause 

an increase in the amount of emissions 

that count towards determining 

applicability under subpart W. The 

addition of reporting requirements for 

oil wells with hydraulic fracturing is 

expected to affect 246 existing reporters 

and to cause approximately 50 new 

reporters to exceed the reporting 

threshold for the onshore petroleum and 

natural gas production facility. These 

numbers have not changed from 

proposal. 

The 50 new reporters will be required 

to estimate and report emissions data 

and related data elements associated 

with several different emission sources 

within this new industry segment, 

including acid gas removal units, 

associated natural gas venting and 

flaring, storage tanks, dehydrators, 

equipment leaks, liquids unloading, and 

pneumatic devices. 

Reporters in the Onshore Petroleum 

and Natural Gas Gathering and Boosting 

segment must estimate and report 

emissions data and related data 

elements associated with several 

different emission sources within this 

new industry segment, including acid 

gas removal units, storage tanks, 

blowdown vents, dehydrators, 

equipment leaks, flare stacks, and 

pneumatic devices. Approximately 200 

new reporters are expected to be subject 

to subpart W due to the amendments for 

the Onshore Petroleum and Natural Gas 

Gathering and Boosting segment in this 

rulemaking. This number has not 

changed from proposal. 

Reporters in the Onshore Natural Gas 

Transmission Pipeline segment will 

need to estimate and report emissions 

data and related data elements 

associated with transmission pipeline 

blowdown activities. Approximately 

183 new reporters in this segment are 

expected to be subject to subpart W. 

This number increased from 150 to 183 

since proposal due to public comment. 

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 slightly from 

proposal. The final amendments to 

subpart W are not expected to 

significantly change the burden 

calculated at proposal. 

The EPA has determined that the cost 

associated with this final action will be 

$7,190,235 each year and has worked to 

minimize burden to reporters where 

practicable. See the memorandum, 

‘‘Assessment of Impacts of the 2015 

Final Revisions to Subpart W’’ in Docket 

ID No. EPA–HQ–OAR–2014–0831 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. We note that 

numerous commenters asserted that the 

burden was underestimated, and some 

provided suggestions for improvement, 

but most of those comments did not 

include the detailed information the 

EPA needed to assess the comment 


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11U.S. Department of Transportation. Pipeline 

and Hazardous Materials Safety Administration. 

Draft Regulatory Evaluation, Regulated Natural Gas 

Gathering Lines, Regulatory Analysis, Docket 

RSPA–1998–4868. Available at www.viadata.com/

pipeliner/library_docs/Gatheringanalysis.pdf. 

fully, such as a suggestion for a revised 

burden estimate, support for the 

suggestion, and an explanation of why 

the suggested value is representative of 

all sources subject to the same 

requirements. See ‘‘Response to Public 

Comments on Greenhouse Gas 

Reporting Rule: 2015 Revisions and 

Confidentiality Determinations for 

Petroleum and Natural Gas Systems’’ in 

Docket ID No. EPA–HQ–OAR–2014– 

0831 for a complete listing of all 

comments and responses. 

Comment: One commenter asked for 

an explanation for the estimate of 200 

respondents in the Onshore Petroleum 

and Natural Gas Gathering and Boosting 

segment. The commenter noted that the 

EPA estimated the number of reporters 

in the Onshore Natural Gas Processing 

industry segment as 291 reporters. The 

commenter stated by the nature of the 

industry, any company with a 

processing plant will most likely also 

have an associated gathering system 

subject to reporting and suggested that 

the number of reporters in the Onshore 

Petroleum and Natural Gas Gathering 

and Boosting industry segment should 

total 291, at minimum, but potentially 

more. 

Response: Due to differences in the 

definitions of the two industry 

segments, the EPA disagrees that the 

number of reporters in the Onshore 

Petroleum and Natural Gas Gathering 

and Boosting segment should match the 

number of reporters in the Onshore 

Natural Gas Processing segment. The 

EPA estimate of 200 respondents was 

based on the regulatory analysis for 

Office of Pipeline Safety (OPS) safety 

regulations. In the analysis, it was 

estimated that 50 percent of the 400 

natural gas gathering pipeline operators 

under regulation are small entities 

operating small diameter, low pressure 

(Type B) gathering lines and fifty 

percent are large diameter, high 

pressure lines (Type A) potentially 

subject to the safety regulation 

(depending upon proximity to 

population centers).11

Comment: One commenter noted that 

the EPA estimated that there are 150 

reporters for Onshore Natural Gas 

Transmission Pipeline facilities at 

proposal. However, the commenter 

stated that the EPA should expect 183 

reporters in the segment based on the 

number of operators that are required to 

complete a PHMSA annual report 

(PHMSA F–7100–2) or are regulated by 

FERC under section 311 of the NGPA. 

Response: The EPA agrees with the 

suggested change. The preamble to the 

final amendments, the final Supporting 

Statement, and the memorandum 

‘‘Assessment of Impacts of the 2015 

Final Revisions to Subpart W’’ (see 

Docket ID No. EPA–HQ–OAR–2014– 

0831) have been updated to reflect the 

change from 150 reporters to 183 

reporters in the Onshore Natural Gas 

Transmission Pipeline segment. 

Comment: Two commenters objected 

to the collection of well identification 

numbers. One commenter noted that 

collection would require significant 

resources and would be unduly 

burdensome on operators. The other 

commenter stated that the burdens 

associated with collecting and reporting 

this data far outweigh any minimal 

benefits in data quality. 

Response: The EPA is finalizing the 

well identification number reporting 

requirements for well-specific data as 

proposed, but the EPA is not requiring 

well identification numbers to be 

reported in this rulemaking for 

equipment other than wells. See section 

II.D of this preamble for additional 

discussion responding to this comment. 

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 and was therefore not 

submitted to the Office of Management 

and Budget (OMB) for review. 

In addition, the EPA prepared an 

analysis of the potential costs associated 

with the final amendments to subpart 

W. This analysis is contained in the 

memorandum ‘‘Assessment of Impacts 

of the 2015 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–2014–0831) and 

the analysis is briefly summarized in 

section IV of this preamble. 

B. Paperwork Reduction Act (PRA) 

The information collection activities 

in this rule have been submitted for 

approval to the OMB under the PRA. 

The Information Collection Request 

(ICR) document that the EPA prepared 

has been assigned EPA ICR number 

2300.16. You can find a copy of the ICR 

in the docket for this rule, and it is 

briefly summarized here. The 

information collection requirements are 

not enforceable until OMB approves 

them. 

This action adds monitoring and 

reporting requirements for reporters in 

three industry segments: Onshore 

Petroleum and Natural Gas Production, 

Onshore Petroleum and Natural Gas 

Gathering and Boosting, and Onshore 

Natural Gas Transmission Pipeline. Data 

collection complements the Inventory of 

U.S. Greenhouse Gas Emissions and 

Sinks (Inventory) and provides a critical 

tool for communities to identify nearby 

sources of GHGs and provide 

information to state and local 

governments. The data can be used to 

complement atmospheric GHG studies 

and inform updates to emission 

inventories. Various activity data are 

collected that can be used to improve 

understanding of the occurrence of 

emissions from a variety of sources. 

Data collected must be made available 

to the public unless the data qualify for 

CBI treatment under the CAA and EPA 

regulations. All data determined by the 

EPA to be CBI are safeguarded in 

accordance with regulations in 40 CFR 

chapter 1, part 2, subpart B. 

Respondents/Affected Entities: The 

respondents in this information 

collection include owners and operators 

of petroleum and natural gas systems 

facilities that must report their GHG 

emissions to the EPA to comply with 

subpart W of part 98. 

Respondent’s Obligation To Respond: 

The respondent’s obligation to respond 

is mandatory under the authority 

provided in CAA section 114. 

Estimated Number of Respondents: 

Approximately 3,300 respondents per 

year. 

Frequency of Response: Annual. 

Total Estimated Burden: 317,100 

hours (per year). Burden is defined at 5 

CFR 1320.3(b). 

Total Estimated Cost: $29.2 million 

(per year), includes $1.1 million 

annualized capital and 2.8 million 

operation & maintenance costs. 

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. When 

OMB approves this ICR, the Agency will 

announce that approval in the Federal 

Register and publish a technical 

amendment to 40 CFR part 9 to display 

the OMB control number for the 

approved information collection 

activities contained in this final rule. 

C. Regulatory Flexibility Act (RFA) 

I certify that this action will not have 

a significant economic impact on a 

substantial number of small entities 

under the RFA. The small entities 


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subject to the requirements of this 

action are: (1) A small business as 

defined by the Small Business 

Administration’s regulations at 13 CFR 

121.201; (2) a small governmental 

jurisdiction that is a government of a 

city, county, town, school district or 

special district with a population of less 

than 50,000; and (3) a small 

organization that is any not-for-profit 

enterprise which is independently 

owned and operated and is not 

dominant in its field. 

The Agency has determined that a few 

small businesses may experience an 

insignificant impact. Details of this 

analysis are presented in section IV.B of 

the preamble to the proposed 

amendments (79 FR 76267; December 9, 

2014). 

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 action does not contain an 

unfunded mandate of $100 million or 

more as described in UMRA, 2 U.S.C. 

1531–1538, and does not significantly or 

uniquely affect small governments. This 

action imposes no enforceable duty on 

any state, local, or tribal governments or 

the private sector. 

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. 

F. Executive Order 13175: Consultation 

and Coordination With Indian Tribal 

Governments 

This action has tribal implications. 

However, it will neither impose 

substantial direct compliance costs on 

federally recognized tribal governments, 

nor preempt tribal law. This regulation 

will apply directly to petroleum and 

natural gas facilities that emit GHGs. 

Although few facilities that will 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 under the EPA Policy on 

Consultation and Coordination with 

Indian Tribes early in the process of 

developing this regulation to permit 

them to have meaningful and timely 

input into its development. A summary 

of that consultation is provided in 

section IV.F of the preamble to the reproposal 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 as applying only to those 

regulatory actions that concern 

environmental health or safety risks, 

that the EPA has reason to believe may 

disproportionately affect children, per 

the definition of ‘‘covered regulatory 

action’’ in section 2–202 of the 

Executive Order. This action is not 

subject to Executive Order 13045 

because it does not concern an 

environmental health risk 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, because it is not a 

significant regulatory action under 

Executive Order 12866. 

I. National Technology Transfer and 

Advancement Act (NTTAA) 

This rulemaking does not involve 

technical standards. 

J. Executive Order 12898: Federal 

Actions To Address Environmental 

Justice in Minority Populations and 

Low-Income Populations 

The EPA believes the human health or 

environmental risk addressed by this 

action will not have potential 

disproportionately high and adverse 

human health or environmental effects 

on minority, low-income or indigenous 

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 (CRA) 

This action is subject to the CRA, and 

the EPA will submit a rule report to 

each House of the Congress and to the 

Comptroller General of the United 

States. This action is not a ‘‘major rule’’ 

as defined by 5 U.S.C. 804(2). 

List of Subjects in 40 CFR Part 98 

Environmental protection, 

Administrative practice and procedure, 

Greenhouse gases, Reporting and 

recordkeeping requirements. 

Dated: October 1, 2015. 

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, et seq. 

Subpart W—Petroleum and Natural 

Gas Systems 

■ 2. Section 98.230 is amended by 

adding paragraphs (a)(9) and (10) to read 

as follows: 

§ 98.230 Definition of the source category. 

(a) * * * 

(9) Onshore petroleum and natural 

gas gathering and boosting. Onshore 

petroleum and natural gas gathering and 

boosting means gathering pipelines and 

other equipment used to collect 

petroleum and/or natural gas from 

onshore production gas or oil wells and 

used to compress, dehydrate, sweeten, 

or transport the petroleum and/or 

natural gas to a natural gas processing 

facility, a natural gas transmission 

pipeline or to a natural gas distribution 

pipeline. Gathering and boosting 

equipment includes, but is not limited 

to gathering pipelines, separators, 

compressors, acid gas removal units, 

dehydrators, pneumatic devices/pumps, 

storage vessels, engines, boilers, heaters, 

and flares. Gathering and boosting 

equipment does not include equipment 

reported under any other industry 

segment defined in this section. 

Gathering pipelines operating on a 

vacuum and gathering pipelines with a 

GOR) less than 300 standard cubic feet 

per stock tank barrel (scf/STB) are not 

included in this industry segment (oil 


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here refers to hydrocarbon liquids of all 

API gravities). 

(10) Onshore natural gas transmission 

pipeline. Onshore natural gas 

transmission pipeline means all natural 

gas transmission pipelines as defined in 

§ 98.238. 

* * * * * 

■ 3. Section 98.231 is amended by 

revising paragraph (a) to read as follows: 

§ 98.231 Reporting threshold. 

(a) You must report GHG emissions 

under this subpart if your facility 

contains petroleum and natural gas 

systems and the facility meets the 

requirements of § 98.2(a)(2), except for 

the industry segments in paragraphs 

(a)(1) through (4) of this section. 

(1) Facilities must report emissions 

from the onshore petroleum and natural 

gas production industry segment only if 

emission sources specified in 

§ 98.232(c) emit 25,000 metric tons of 

CO2 equivalent or more per year. 

(2) Facilities must report emissions 

from the natural gas distribution 

industry segment only if emission 

sources specified in § 98.232(i) emit 

25,000 metric tons of CO2 equivalent or 

more per year. 

(3) Facilities must report emissions 

from the onshore petroleum and natural 

gas gathering and boosting industry 

segment only if emission sources 

specified in § 98.232(j) emit 25,000 

metric tons of CO2 equivalent or more 

per year. 

(4) Facilities must report emissions 

from the onshore natural gas 

transmission pipeline industry segment 

only if emission sources specified in 

§ 98.232(m) emit 25,000 metric tons of 

CO2 equivalent or more per year. 

* * * * * 

■ 4. Section 98.232 is amended by: 

■ a. Revising paragraphs (a) and (c)(6) 

and (8); 

■ b. Adding paragraph (j); 

■ c. Revising paragraph (k); and 

■ d. Adding paragraph (m). 

The revisions and additions read as 

follows: 

§ 98.232 GHGs to report. 

(a) You must report CO2, CH4, and 

N2O emissions from each industry 

segment specified in paragraphs (b) 

through (j) and (m) of this section, CO2, 

CH4, and N2O emissions from each flare 

as specified in paragraphs (b) through (j) 

of this section, and stationary and 

portable combustion emissions as 

applicable as specified in paragraph (k) 

of this section. 

* * * * * 

(c) * * * 

(6) Well venting during well 

completions with hydraulic fracturing 

that have a GOR of 300 scf/STB or 

greater (oil here refers to hydrocarbon 

liquids produced of all API gravities). 

* * * * * 

(8) Well venting during well 

workovers with hydraulic fracturing 

that have a GOR of 300 scf/STB or 

greater (oil here refers to hydrocarbon 

liquids produced of all API gravities). 

* * * * * 

(j) For an onshore petroleum and 

natural gas gathering and boosting 

facility, report CO2, CH4, and N2O 

emissions from the following source 

types: 

(1) Natural gas pneumatic device 

venting. 

(2) Natural gas driven pneumatic 

pump venting. 

(3) Acid gas removal vents. 

(4) Dehydrator vents. 

(5) Blowdown vent stacks. 

(6) Storage tank vented emissions. 

(7) Flare stack emissions. 

(8) Centrifugal compressor venting. 

(9) Reciprocating compressor venting. 

(10) Equipment leaks from valves, 

connectors, open ended lines, pressure 

relief valves, pumps, flanges, and other 

equipment leak sources (such as 

instruments, loading arms, stuffing 

boxes, compressor seals, dump lever 

arms, and breather caps). 

(11) Gathering pipeline equipment 

leaks. 

(12) You must use the methods in 

§ 98.233(z) and report under this 

subpart the emissions of CO2, CH4, and 

N2O from stationary or portable fuel 

combustion equipment that cannot 

move on roadways under its own power 

and drive train, and that is located at an 

onshore petroleum and natural gas 

gathering and boosting facility as 

defined in § 98.238. Stationary or 

portable equipment includes the 

following equipment, which are integral 

to the movement of natural gas: Natural 

gas dehydrators, natural gas 

compressors, electrical generators, 

steam boilers, and process heaters. 

(k) Report under subpart C of this part 

(General Stationary Fuel Combustion 

Sources) the emissions of CO2, CH4, and 

N2O from each stationary fuel 

combustion unit by following the 

requirements of subpart C except for 

facilities under onshore petroleum and 

natural gas production, onshore 

petroleum and natural gas gathering and 

boosting, and natural gas distribution. 

Onshore petroleum and natural gas 

production facilities must report 

stationary and portable combustion 

emissions as specified in paragraph (c) 

of this section. Natural gas distribution 

facilities must report stationary 

combustion emissions as specified in 

paragraph (i) of this section. Onshore 

petroleum and natural gas gathering and 

boosting facilities must report stationary 

and portable combustion emissions as 

specified in paragraph (j) of this section. 

* * * * * 

(m) For onshore natural gas 

transmission pipeline, report pipeline 

blowdown CO2 and CH4 emissions from 

blowdown vent stacks. 

■ 5. Section 98.233 is amended by: 

■ a. Revising the parameters ‘‘EFt’’ and 

‘‘GHGi’’ of Equation W–1 in paragraph 

(a); 

■ b. Revising paragraph (a)(2); 

■ c. Revising the parameter ‘‘EF’’ of 

Equation W–2 in paragraph (c); 

■ d. Revising paragraph (d)(8)(iii); 

■ e. Revising paragraphs (g) 

introductory text, (g)(1) introductory 

text, (g)(1)(i), and paragraph (g)(1)(ii) 

heading; 

■ f. Revising the parameters ‘‘FRMs,’’ 

‘‘FRs,p’’ and ‘‘PRs,p’’ of Equation W–12A 

in paragraph (g)(1)(iii); 

■ g. Revising the parameters ‘‘FRMi,’’ 

and ‘‘PRs,p’’ of Equation W–12B in 

paragraph (g)(1)(iv); 

■ h. Revising paragraphs (g)(1)(v) and 

(vi); 

■ i. Adding paragraph (g)(1)(vii); 

■ j. Revising paragraph (g)(2) 

introductory text; 

■ k. Adding paragraph (g)(2)(iv); 

■ l. Revising paragraph (g)(4) 

introductory text; 

■ m. Revising paragraph (i)(2) 

introductory text; 

■ n. Revising the parameters ‘‘Ta’’ and 

‘‘Pa’’ of Equation W–14A in paragraph 

(i)(2)(i); 

■ o. Revising paragraphs (j) introductory 

text, (j)(1) through (3), and (j)(6); 

■ p. Revising paragraph (n)(2)(i); 

■ q. Revising paragraphs (o) 

introductory text and (o)(10); 

■ r. Revising paragraphs (p) 

introductory text and (p)(10); 

■ s. Revising paragraphs (r) introductory 

text, (r)(2) introductory text, and 

(r)(2)(i); 

■ t. Revising paragraphs (u)(2)(i) and 

(iii); and 

■ x. Revising paragraphs (z) 

introductory text and (z)(1)(ii). 

The revisions and additions read as 

follows: 

§ 98.233 Calculating GHG emissions. 

* * * * * 

(a) * * * 

* * * * * 

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, 


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onshore natural gas transmission 

compression, and underground natural 

gas storage facilities, respectively. 

Onshore petroleum and natural gas 

gathering and boosting facilities must 

use the population emission factors 

listed in Table W–1A of this subpart. 

GHGi = For onshore petroleum and natural 

gas production facilities, onshore 

petroleum and natural gas gathering and 

boosting 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. 

* * * * * 

(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 section 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. 

For the onshore petroleum and natural 

gas gathering and boosting industry 

segment, you have the option in the first 

two consecutive calendar years to 

determine ‘‘Countt’’ for Equation W–1 

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. 

* * * * * 

(c) * * * 

* * * * * 

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 and onshore petroleum and 

natural gas gathering and boosting 

facilities. 

* * * * * 

(d) * * * 

(8) * * * 

(iii) If a continuous gas analyzer is not 

available or installed, you may use the 

outlet pipeline quality specification for 

CO2 in natural gas. 

* * * * * 

(g) Well venting during completions 

and workovers with hydraulic 

fracturing. Calculate annual volumetric 

natural gas emissions from gas well and 

oil 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 gas flowback rate is measured 

from a specified number of example 

completions or workovers and Equation 

W–10B applies when the gas 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, you must follow the 

procedures specified in paragraph (g)(1). 

If you elect to use Equation W–10B, you 

must use a recording flow meter 

installed on the vent line, downstream 

of a separator and ahead of a flare or 

vent, to measure the gas flowback. For 

either equation, 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 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 

venting during well 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. 

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 but 

does not include periods when the oil 

well ceases to produce fluids to the 

surface. 

FRMs = Ratio of average gas 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. 

FRMi = Ratio of initial gas flowback rate 

during well completions and workovers 

from hydraulic fracturing to 30-day gas 

production rate for the sub-basin and 

well type combination, calculated using 

procedures specified in paragraph 

(g)(1)(iv) of this section, for the period of 

flow to open tanks/pits. 

PRs,p = Average gas production flow rate 

during the first 30 days of production 

after completions of newly drilled wells 

or 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. If 

applicable, PRs,p may be calculated for 

oil wells using procedures specified in 

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

EnFs,p = Volume of N2 injected gas in cubic 

feet at standard conditions that was 

injected into the reservoir during an 

energized fracture job or during flowback 

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 or 

injection during flowback. Convert to 

standard conditions using paragraph (t) 

of this section. If the fracture process did 


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not inject gas into the reservoir or if the 

injected gas is CO2 then EnFs,p is 0. 

FVs,p = Flow volume of vented or flared gas 

for each well, p, in standard cubic feet 

measured using a recording flow meter 

(digital or analog) on the vent line to 

measure gas 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 on gas wells, 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. If you elect to use Equation 

W–10A of this section on oil wells, you 

must use Calculation Method 1 as 

specified in paragraph (g)(1)(i) to 

determine the value of FRMs and FRMi. 

These values must be based on the flow 

rate for flowback gases, 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 of this section as 

specified in paragraph (g)(1)(iii) of this 

section to determine the value of FRMs. 

You must use Equation W–12B of this 

section 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) of this 

section also apply. When making gas 

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, downstream of a separator 

and ahead of a flare or vent, to measure 

the gas flowback rates in units of 

standard cubic feet per hour according 

to methods set forth in § 98.234(b). 

(ii) Calculation Method 2 (for gas 

wells). * * * 

(iii) * * * 

* * * * * 

FRMs = Ratio of average gas 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 gas production rate for each subbasin and well type combination. 

FRs,p = Measured average gas 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 of this section 

converted to a flow rate for this 

parameter. 

PRs,p = Average gas production flow rate 

during the first 30 days of production 

after completions of newly drilled wells 

or 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. For oil wells for which 

production is not measured continuously 

during the first 30 days of production, 

the average flow rate may be based on 

individual well production tests 

conducted within the first 30 days of 

production. Alternatively, if applicable, 

PRs,p may be calculated for oil wells 

using procedures specified in paragraph 

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

* * * * * 

(iv) * * * 

* * * * * 

FRMi = Ratio of initial gas flowback rate 

during well completions and workovers 

from hydraulic fracturing to 30-day gas 

production rate for the sub-basin and 

well type combination, for the period of 

flow to open tanks/pits. 

* * * * * 

PRs,p = Average gas production flow rate 

during the first 30-days of production 

after completions of newly drilled wells 

or 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. For oil wells for which 

production is not measured continuously 

during the first 30 days of production, 

the average flow rate may be based on 

individual well production tests 

conducted within the first 30 days of 

production. Alternatively, if applicable, 

PRs,p may be calculated for oil wells 

using procedures specified in paragraph 

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

* * * * * 

(v) For Equation W–10A of this 

section, the ratio of gas flowback rate 

during well completions and workovers 

from hydraulic fracturing to 30-day gas 

production rate are applied to all well 

completions and well workovers, 

respectively, in the sub-basin and well 

type combination for the total number of 

hours of flowback and for the first 30 

day average gas production rate for each 

of these wells. 

(vi) For Equations W–12A and W–12B 

of this section, calculate new flowback 

rates for well completions and well 

workovers in each sub-basin and well 

type combination once every two years 

starting in the first calendar year of data 

collection. 

(vii) For oil wells where the gas 

production rate is not metered and you 

elect to use Equation W–10A of this 

section, calculate the average gas 

production rate (PRs,p) using Equation 

W–12C of this section. If GOR cannot be 

determined from your available data, 

then you must use one of the procedures 

specified in paragraph (g)(1)(vii)(A) or 

(B) of this section to determine GOR. If 

GOR from each well is not available, use 

the GOR from a cluster of wells in the 

same sub-basin category. 


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Where: 

PRs,p = Average gas production flow rate 

during the first 30 days of production 

after completions of newly drilled wells 

or well workovers using hydraulic 

fracturing in standard cubic feet per hour 

of well p, in the sub-basin and well type 

combination. 

GORp = Average gas to oil ratio during the 

first 30 days of production after 

completions of newly drilled wells or 

workovers using hydraulic fracturing in 

standard cubic feet of gas per barrel of 

oil for each well p, that was measured in 

the sub-basin and well type combination; 

oil here refers to hydrocarbon liquids 

produced of all API gravities. 

Vp = Volume of oil produced during the first 

30 days of production after completions 

of newly drilled wells or well workovers 

using hydraulic fracturing in barrels of 

each well p, that was measured in the 

sub-basin and well type combination. 

720 = Conversion from 30 days of production 

to hourly production rate. 

(A) You may use an appropriate 

standard method published by a 

consensus-based standards organization 

if such a method exists. 

(B) You may use an industry standard 

practice as described in § 98.234(b). 

(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 (iv) of this section. 

* * * * * 

(iv) Oil well or gas well. 

* * * * * 

(4) Calculate annual emissions from 

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) * * * 

(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. For industry segments other than 

onshore natural gas transmission 

pipeline, 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. For the onshore 

natural gas transmission pipeline 

segment, pipeline segments or event 

types must be grouped into the 

following eight categories: Pipeline 

integrity work (e.g., the preparation 

work of modifying facilities, ongoing 

assessments, maintenance or 

mitigation), traditional operations or 

pipeline maintenance, equipment 

replacement or repair (e.g., valves), pipe 

abandonment, new construction or 

modification of pipelines including 

commissioning and change of service, 

operational precaution during activities 

(e.g. excavation near pipelines), 

emergency shutdowns including 

pipeline incidents as defined in 49 CFR 

191.3, and all other pipeline segments 

with a physical volume greater than or 

equal to 50 cubic feet. If a blowdown 

event resulted in emissions from 

multiple categories and the emissions 

cannot be apportioned to the different 

categories, then categorize the 

blowdown event in the category that 

represented the largest portion of the 

emissions for the blowdown event. 

(i) * * * 

* * * * * 

Ta = Temperature at actual conditions in the 

unique physical volume (°F). For 

emergency blowdowns at onshore 

petroleum and natural gas gathering and 

boosting facilities, engineering estimates 

based on best available information may 

be used to determine the temperature. 

* * * * * 

Pa = Absolute pressure at actual conditions 

in the unique physical volume (psia). For 

emergency blowdowns at onshore 

petroleum and natural gas gathering and 

boosting facilities, engineering estimates 

based on best available information may 

be used to determine the pressure. 

* * * * * 

(j) Onshore production and onshore 

petroleum and natural gas gathering 

and boosting 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 and onshore 

petroleum and natural gas gathering and 

boosting facilities (including stationary 

liquid storage not owned or operated by 

the reporter), as specified in this 

paragraph (j). For gas-liquid separators 

or onshore petroleum and natural gas 

gathering and boosting non-separator 

equipment (e.g., stabilizers, slug 

catchers) 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 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 hydrocarbon liquids 

flowing to gas-liquid separators or nonseparator equipment 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 for separators, 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 and 

onshore petroleum and natural gas 

gathering and boosting storage tanks 

using operating conditions in the last 

gas-liquid separator or non-separator 

equipment 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 PengRobinson equation of state, models 

flashing emissions, and speciates CH4

and CO2 emissions that will result when 

the oil from the separator or nonseparator equipment enters an 

atmospheric pressure storage tank. The 

following parameters must be 

determined for typical operating 


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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: 

(i) Separator or non-separator 

equipment temperature. 

(ii) Separator or non-separator 

equipment pressure. 

(iii) Sales oil or stabilized oil API 

gravity. 

(iv) Sales oil or stabilized oil 

production rate. 

(v) Ambient air temperature. 

(vi) Ambient air pressure. 

(vii) Separator or non-separator 

equipment oil composition and Reid 

vapor pressure. If this data is not 

available, determine these parameters 

by using one of the methods described 

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

of this section. 

(A) If separator or non-separator 

equipment oil composition and Reid 

vapor pressure default data are provided 

with the software program, select the 

default values that most closely match 

your separator or non-separator 

equipment pressure first, and API 

gravity secondarily. 

(B) If separator or non-separator 

equipment oil composition and Reid 

vapor pressure data are available 

through your previous analysis, select 

the latest available analysis that is 

representative of produced crude oil or 

condensate from the sub-basin category 

for onshore petroleum and natural gas 

production or from the county for 

onshore petroleum and natural gas 

gathering and boosting. 

(C) Analyze a representative sample of 

separator or non-separator equipment 

oil in each sub-basin category for 

onshore petroleum and natural gas 

production or each county for onshore 

petroleum and natural gas gathering and 

boosting for oil composition and Reid 

vapor pressure using an appropriate 

standard method published by a 

consensus-based standards organization. 

(2) Calculation Method 2. Calculate 

annual CH4 and CO2 emissions using 

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

section for 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 in onshore 

petroleum and natural gas production 

and onshore petroleum and natural gas 

gathering and boosting (if applicable). 

Calculate annual CH4 and CO2

emissions using the methods in 

paragraph (j)(2)(iii) of this section for 

non-separator equipment with annual 

average daily hydrocarbon liquids 

throughput greater than or equal to 10 

barrels per day that flow directly to 

atmospheric storage tanks in onshore 

petroleum and natural gas gathering and 

boosting. 

(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 a 

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 the 

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. 

(iii) Flow to storage tank direct from 

non-separator equipment. Calculate CH4

and CO2 emissions using either of the 

methods in paragraph (j)(2)(iii)(A) or (B) 

of this section. 

(A) If other non-separator equipment 

liquid and gas compositions are 

available through a previous analysis, 

select the latest available analysis that is 

representative of liquid and gas from 

non-separator equipment in the same 

county and assume all of the CH4 and 

CO2 in both hydrocarbon liquids and 

gas are emitted from the tank. 

(B) If non-separator equipment liquid 

and gas compositions are not available, 

use default liquid and gas compositions 

in software programs, such as API 4697 

E&P Tank, that most closely match the 

non-separator equipment gas/liquid 

ratio and API gravity and assume all of 

the CH4 and CO2 in both hydrocarbon 

liquids 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, wells, or non-separator 

equipment in thousand standard cubic 

feet per separator, well, or non-separator 

equipment 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, wells, or 

non-separator equipment with annual 

average daily throughput less than 10 

barrels per day. Count only separators, 

wells, or non-separator equipment that 

feed oil directly to the storage tank. 

1,000 = Conversion from thousand standard 

cubic feet to standard cubic feet. 

* * * * * 

(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 gas-liquid separator 

liquid dump valves not closing during 

the calendar year by using Equation W– 

16 of this section. 


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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 separator 

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. 

* * * * * 

(n) * * * 

(2) * * * 

(i) For onshore natural gas production 

and onshore petroleum and natural gas 

gathering and boosting, determine the 

GHG mole fraction using paragraph 

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

* * * * * 

(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) 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) 

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) 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) or an onshore petroleum 

and natural gas gathering and boosting 

facility as specified in § 98.232(j)(8), you 

must calculate volumetric emissions as 

specified in paragraph (o)(10); and 

calculate CH4 and CO2 mass emissions 

as specified in paragraph (o)(11). 

* * * * * 

(10) Method for calculating 

volumetric GHG emissions from wet seal 

oil degassing vents at an onshore 

petroleum and natural gas production 

facility or an onshore petroleum and 

natural gas gathering and boosting 

facility. You must calculate emissions 

from centrifugal compressor wet seal oil 

degassing vents at an onshore petroleum 

and natural gas production facility or an 

onshore petroleum and natural gas 

gathering and boosting 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 GHGi. Use 1.2 × 

107 standard cubic feet per year per 

compressor for CH4 and 5.30 × 105

standard cubic feet per year per 

compressor for CO2 at 60 °F and 14.7 

psia. 

* * * * * 

(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) 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) 

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) 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) or an onshore petroleum 

and natural gas gathering and boosting 

facility as specified in § 98.232(j)(5), you 

must calculate volumetric emissions as 

specified in paragraph (p)(10); and 

calculate CH4 and CO2 mass emissions 

as specified in paragraph (p)(11). 

* * * * * 

(10) Method for calculating 

volumetric GHG emissions from 

reciprocating compressor venting at an 

onshore petroleum and natural gas 

production facility or an onshore 

petroleum and natural gas gathering 

and boosting facility. You must 

calculate emissions from reciprocating 

compressor venting at an onshore 

petroleum and natural gas production 

facility or an onshore petroleum and 

natural gas gathering and boosting 

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. 

* * * * * 


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(r) Equipment leaks by population 

count. This paragraph (r) applies to 

emissions sources listed in § 98.232 

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

(i)(4), (i)(5), (i)(6), (j)(10), and (j)(11) 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 of this 

section 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, distribution 

service, or gathering pipeline. 

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 and onshore petroleum and 

natural gas gathering and boosting 

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. Onshore petroleum 

and natural gas gathering and boosting 

facilities must also count the miles of 

gathering pipelines by material type 

(protected steel, unprotected steel, 

plastic, or cast iron). 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 of 

this section. 

GHGi = For onshore petroleum and natural 

gas production facilities and onshore 

petroleum and natural gas gathering and 

boosting 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¥2 CO2. 

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. 

* * * * * 

(2) Onshore petroleum and natural gas 

production facilities and onshore 

petroleum and natural gas gathering and 

boosting 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 and onshore petroleum 

and natural gas gathering and boosting 

systems 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), except for miles of 

gathering pipelines by material type, 

which must be determined using 

Component Count Method 2 in 

paragraph (r)(2)(ii) of this section. 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 and onshore 

petroleum and natural gas gathering and 

boosting 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 for onshore 

petroleum and natural gas production 

operations and the number of meters in 

the facility for onshore petroleum and 

natural gas gathering and boosting 

operations. 

(B) Multiply major equipment counts 

by the average component counts listed 

in Table W–1B of this subpart for 

onshore natural gas production and 

onshore petroleum and natural gas 

gathering and boosting; and Table W–1C 

of this subpart for onshore oil 

production. Use the appropriate factor 


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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. 

* * * * * 

(u) * * * 

(2) * * * 

(i) GHG mole fraction in produced 

natural gas for onshore petroleum and 

natural gas production facilities and 

onshore petroleum and natural gas 

gathering and boosting facilities. If you 

have a continuous gas composition 

analyzer for produced natural gas, you 

must use an annual average of these 

values for determining the mole 

fraction. If you do not have a continuous 

gas composition analyzer, then you 

must use an annual average gas 

composition based on your most recent 

available analysis of the sub-basin 

category or facility, as applicable to the 

emission source. 

* * * * * 

(iii) GHG mole fraction in 

transmission pipeline natural gas that 

passes through the facility for the 

onshore natural gas transmission 

compression industry segment and the 

onshore natural gas transmission 

pipeline 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. 

* * * * * 

(z) Onshore petroleum and natural 

gas production, onshore petroleum and 

natural gas gathering and boosting, and 

natural gas distribution combustion 

emissions. Calculate CO2, CH4, and N2O 

combustion-related emissions from 

stationary or portable equipment, except 

as specified in paragraphs (z)(3) and (4) 

of this section, as follows: 

(1) * * * 

(ii) Emissions from fuel combusted in 

stationary or portable equipment at 

onshore petroleum and natural gas 

production facilities, at onshore 

petroleum and natural gas gathering and 

boosting 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. 

* * * * * 

■ 6. Section 98.234 is amended by 

adding paragraph (g) to read as follows: 

§ 98.234 Monitoring and QA/QC 

requirements. 

* * * * * 

(g) Special reporting provisions for 

best available monitoring methods in 

reporting year 2016—(1) Best available 

monitoring methods. From January 1, 

2016, to December 31, 2016, you must 

use the calculation methodologies and 

equations in § 98.233 but you may use 

the best available monitoring method as 

described in paragraph (g)(2) of this 

section for any parameter specified in 

paragraphs (g)(3) through (6) of this 

section for which it is not reasonably 

feasible to acquire, install, and operate 

a required piece of monitoring 

equipment by January 1, 2016. Starting 

no later than January 1, 2017, you must 

discontinue using best available 

methods and begin following all 

applicable monitoring and QA/QC 

requirements of this part. For onshore 

petroleum and natural gas production, 

this paragraph (g)(1) only applies if 

emissions from well completions and 

workovers of oil wells with hydraulic 

fracturing cause your facility to exceed 

the reporting threshold in § 98.231(a)(1). 

(2) 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. 

(3) Best available monitoring methods 

for well-related measurement data for 

oil wells with hydraulic fracturing. You 

may use best available monitoring 

methods for any well-related 

measurement data that cannot 

reasonably be measured according to the 

monitoring and QA/QC requirements of 

this subpart for venting during well 

completions and workovers of oil wells 

with hydraulic fracturing. 

(4) Best available monitoring methods 

for measurement data for onshore 

petroleum and natural gas gathering 

and boosting facilities. You may use 

best available monitoring methods for 

any leak detection and/or measurement 

data that cannot reasonably be measured 

according to the monitoring and QA/QC 

requirements of this subpart for acid gas 

removal vents as specified in 

§ 98.233(d). 

(5) Best available monitoring methods 

for measurement data for natural gas 

transmission pipelines. You may use 

best available monitoring methods for 

any measurement data for natural gas 

transmission pipelines that cannot 

reasonably be obtained according to the 

monitoring and QA/QC requirements of 

this subpart for blowdown vent stacks. 

(6) Best available monitoring methods 

for specified activity data. You may use 

best available monitoring methods for 

activity data as listed in paragraphs 

(g)(6)(i) through (iii) of this section that 

cannot reasonably be obtained 

according to the monitoring and QA/QC 

requirements of this subpart for well 

completions and workovers of oil wells 

with hydraulic fracturing, onshore 

petroleum and natural gas gathering and 

boosting facilities, or natural gas 

transmission pipelines. 

(i) Cumulative hours of venting, days, 

or times of operation in § 98.233(e), (g), 

(o), (p), and (r). 

(ii) Number of blowdowns, 

completions, workovers, or other events 

in § 98.233(g) and (i). 

(iii) Cumulative volume produced, 

volume input or output, or volume of 

fuel used in paragraphs § 98.233(d), (e), 

(j), (n), and (z). 

* * * * * 

■ 7. Section 98.236 is amended by: 

■ a. Revising paragraph (a) introductory 

text; 

■ b. Adding paragraphs (a)(9) and (10); 

■ c. Revising paragraphs (d)(1)(i) and 

(vi); 

■ d. Revising paragraphs (e)(1)(i) and 

(xviii); 

■ e. Revising paragraphs (f)(1)(ii), 

(f)(1)(xi)(A), (f)(1)(xii)(A), and (f)(2)(i); 

■ f. Revising paragraphs (g) introductory 

text, (g)(1), (g)(2), (g)(5), and (g)(6); 

■ g. Revising paragraphs (h)(1)(i) and 

(iv), (h)(2)(i) and (iv), (h)(3)(i), and 

(h)(4)(i); 

■ h. Revising paragraphs (i) 

introductory text and (i)(1) introductory 

text; 

■ i. Adding paragraph (i)(3); 

■ j. Revising paragraphs (j) introductory 

text and (j)(1) introductory text; 

■ k. Revising paragraphs (j)(1)(i), (iii), 

(iv) (v), (vii), and (viii); 

■ l. Revising paragraphs (j)(2)(i) 

introductory text, (j)(2)(i)(A) through 

(C), (j)(2)(ii), (j)(2)(iii) introductory text, 

(j)(2)(iii)(A) and (B), and (j)(3) 

introductory text; 

■ m. Revising paragraph (l)(1) 

introductory text; 

■ n. Redesignating paragraphs (l)(1)(ii) 

through (vi) as paragraphs (l)(1)(iii) 

through (vii), respectively; 

■ o. Adding paragraph (l)(1)(ii); 

■ p. Revising newly designated 

paragraph (l)(1)(v); 

■ q. Revising paragraph (l)(2) 

introductory text; 

■ r. Redesignating paragraphs (l)(2)(ii) 

through (vii) as paragraphs (l)(2)(iii) 

through (viii), respectively; 

■ s. Adding paragraph (l)(2)(ii); 

■ t. Revising newly designated 

paragraph (l)(2)(v); 

■ u. Revising paragraph (l)(3) 

introductory text; 

■ v. Redesignating paragraphs (l)(3)(ii) 

through (v) as paragraphs (l)(3)(iii) 

through (vi), respectively; 

■ w. Adding paragraph (l)(3)(ii); 

■ x. Revising newly designated 

paragraph (l)(3)(iv); 


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■ y. Revising paragraph (l)(4) 

introductory text; 

■ a. Redesignating paragraphs (l)(4)(ii) 

through (vi) as paragraphs (l)(4)(iii) 

through (vii), respectively; 

■ aa. Adding paragraph (l)(4)(ii); 

■ bb. Revising newly designated 

paragraph (l)(4)(iv); 

■ cc. Revising paragraphs (m)(1), (m)(5), 

(m)(6), (m)(7)(i), (m)(8)(i); 

■ dd. Revising paragraph (n)(1); 

■ ee. Revising paragraphs (o) 

introductory text and (o)(5) introductory 

text; 

■ ff. Revising paragraphs (p) 

introductory text and (p)(5) introductory 

text; 

■ gg. Revising paragraphs (r)(1) 

introductory text, (r)(1)(i), (r)(3) 

introductory text, and (r)(3)(ii) 

introductory text; 

■ hh. Revising paragraph (z) 

introductory text; 

■ ii. Revising paragraphs (aa) 

introductory text and (aa)(1)(ii)(D) 

through (H); 

■ jj. Adding paragraphs (aa)(10) and 

(11); and 

■ kk. Revising paragraph (cc). 

The revisions and additions read as 

follows: 

§ 98.236 Data reporting requirements. 

* * * * * 

(a) The annual report must include 

the information specified in paragraphs 

(a)(1) through (10) 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 (10), and each applicable 

emission source listed in paragraphs (b) 

through (z) of this section. 

* * * * * 

(9) Onshore petroleum and natural 

gas gathering and boosting. For the 

equipment/activities specified in 

paragraphs (a)(9)(i) through (xi) 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) Blowdown vent stacks. Report the 

information specified in paragraph (i) of 

this section. 

(vi) Storage tanks. Report the 

information specified in paragraph (j) of 

this section. 

(vii) Flare stacks. Report the 

information specified in paragraph (n) 

of this section. 

(viii) Centrifugal compressors. Report 

the information specified in paragraph 

(o) of this section. 

(ix) Reciprocating compressors. 

Report the information specified in 

paragraph (p) of this section. 

(x) Equipment leaks by population 

count. Report the information specified 

in paragraph (r) of this section. 

(xi) Combustion equipment. Report 

the information specified in paragraph 

(z) of this section. 

(10) Onshore natural gas transmission 

pipeline. For blowdown vent stacks, 

report the information specified in 

paragraph (i) of this section. 

* * * * * 

(d) * * * 

(1) * * * 

(i) A unique name or ID number for 

the acid gas removal unit. For the 

onshore petroleum and natural gas 

production and the onshore petroleum 

and natural gas gathering and boosting 

industry segments, 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. 

* * * * * 

(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) or 

name of the county that best represents 

the equipment supplying gas to the unit 

(for the onshore petroleum and natural 

gas gathering and boosting industry 

segment only). 

* * * * * 

(e) * * * 

(1) * * * 

(i) A unique name or ID number for 

the dehydrator. For the onshore 

petroleum and natural gas production 

and the onshore petroleum and natural 

gas gathering and boosting industry 

segments, a different name or ID may be 

used for a single dehydrator for each 

location it operates at in a given year. 

* * * * * 

(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) or name of the county 

that best represents the equipment 

supplying gas to the dehydrator (for the 

onshore petroleum and natural gas 

gathering and boosting industry segment 

only). 

* * * * * 

(f) * * * 

(1) * * * 

(ii) Well tubing diameter and pressure 

group ID and a list of the well ID 

numbers associated with each sub-basin 

and well tubing diameter and pressure 

group ID. 

* * * * * 

(xi) * * * 

(A) Well ID number of tested well. 

* * * * * 

(xii) * * * 

(A) Well ID number. 

* * * * * 

(2) * * * 

(i) Sub-basin ID and a list of the well 

ID numbers associated with each subbasin. 

* * * * * 

(g) Completions and workovers with 

hydraulic fracturing. You must indicate 

whether your facility had any well 

completions or workovers with 

hydraulic fracturing during the calendar 

year. If your facility had 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 and a list of the well 

ID numbers associated with each subbasin that had completions or 

workovers with hydraulic fracturing 

during the calendar year. 

(2) Well type combination (horizontal 

or vertical, gas well or oil well). 

* * * * * 

(5) If you used Equation W–10A of 

§ 98.233 to calculate annual volumetric 

total gas emissions, then you must 

report the information specified in 

paragraphs (g)(5)(i) through (iii) 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 

of § 98.233). 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 well ID number(s) for 

the well(s) included in the number. 

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

flowback rate, in standard cubic feet per 


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

Equation W–12A of § 98.233), and the 

well ID numbers of the wells for which 

it is measured. 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 well ID number(s) for the well(s) 

included in the measurement. 

(iii) If you used Equation W–12C of 

§ 98.233 to calculate the average gas 

production rate for an oil well, then you 

must report the information specified in 

paragraphs (g)(5)(iii)(A) and (B) of this 

section. 

(A) Gas to oil ratio for the well in 

standard cubic feet of gas per barrel of 

oil (‘‘GORp’’ in Equation W–12C of 

§ 98.233). 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 gas to oil ratio for the 

well and the well ID number for the 

well. 

(B) Volume of oil produced during the 

first 30 days of production after 

completions of each newly drilled well 

or well workover using hydraulic 

fracturing, in barrels (‘‘Vp’’ in Equation 

W–12C of § 98.233). 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 volume of oil produced 

during the first 30 days of production 

after well completion or workover and 

the well ID number for the well. 

(6) If you used Equation W–10B of 

§ 98.233 to calculate annual volumetric 

total gas emissions, then you must 

report the information specified in 

paragraphs (g)(6)(i) through (iii) 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 

of § 98.233). 

(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 of § 98.233). 

(iii) The well ID number for which 

vented natural gas volume was 

measured. 

* * * * * 

(h) * * * 

(1) * * * 

(i) Sub-basin ID and a list of the well 

ID numbers associated with each subbasin for gas well completions without 

hydraulic fracturing and without flaring. 

* * * * * 

(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 of § 98.233). 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 well ID number(s) 

for the well(s) included in the 

measurement. 

* * * * * 

(2) * * * 

(i) Sub-basin ID and a list of the well 

ID numbers associated with each subbasin for gas well completions without 

hydraulic fracturing and with flaring. 

* * * * * 

(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 of § 98.233). 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 well ID number(s) 

for the well(s) included in the 

measurement. 

* * * * * 

(3) * * * 

(i) Sub-basin ID and a list of the well 

ID numbers associated with each subbasin for gas well workovers without 

hydraulic fracturing and without flaring. 

* * * * * 

(4) * * * 

(i) Sub-basin ID and a list of well ID 

numbers associated with each sub-basin 

for gas well workovers without 

hydraulic fracturing and with flaring. 

* * * * * 

(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. For the onshore natural gas 

transmission pipeline segment, you 

must also report the information in 

paragraph (i)(3) of this section. 

(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) for 

industry segments other than the 

onshore natural gas transmission 

pipeline segment, 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. If 

you calculated emissions from 

blowdown vent stacks by the eight 

categories listed in § 98.233(i)(2) for the 

onshore natural gas transmission 

pipeline segment, then you must report 

the pipeline segments or event types 

and the information specified in 

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

section for each ‘‘equipment or event 

type’’ (i.e., category). If a blowdown 

event resulted in emissions from 

multiple categories, and the emissions 

cannot be apportioned to the different 

categories, then you may report the 

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

through (iii) of this section for the 

‘‘equipment or event type’’ (i.e., 

category) that represented the largest 

portion of the emissions for the 

blowdown event. 

* * * * * 


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(3) Onshore natural gas transmission 

pipeline segment. Report the 

information in paragraphs (i)(3)(i) 

through (iii) of this section for each 

state. 

(i) Annual CO2 emissions in metric 

tons CO2. 

(ii) Annual CH4 emissions in metric 

tons CH4. 

(iii) Annual number of blowdown 

events. 

(j) Onshore production and onshore 

petroleum and natural gas gathering 

and boosting 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 of § 98.233(j), 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 of § 98.233(j) to 

calculate GHG emissions, then you must 

report the information specified in 

paragraphs (j)(1)(i) through (xvi) of this 

section for each sub-basin (for onshore 

production) or county (for onshore 

petroleum and natural gas gathering and 

boosting) and by calculation method. 

Onshore petroleum and natural gas 

gathering and boosting facilities do not 

report the information specified in 

paragraphs (j)(1)(ix) and (xi) of this 

section. 

(i) Sub-basin ID (for onshore 

production) or county name (for 

onshore petroleum and natural gas 

gathering and boosting). 

* * * * * 

(iii) The total annual oil volume from 

gas-liquid separators and direct from 

wells or non-separator equipment that is 

sent to applicable onshore production 

and onshore petroleum and natural gas 

gathering and boosting storage tanks, in 

barrels. You may delay reporting of this 

data element for onshore production 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 

specified in § 98.236(cc) the total 

volume of oil from all wells and the 

well ID number(s) for the well(s) 

included in this volume. 

(iv) The average gas-liquid separator 

or non-separator equipment 

temperature, in degrees Fahrenheit. 

(v) The average gas-liquid separator or 

non-separator equipment pressure, in 

pounds per square inch gauge. 

* * * * * 

(vii) The minimum and maximum 

concentration (mole fraction) of CO2 in 

flash gas from onshore production and 

onshore natural gas gathering and 

boosting storage tanks. 

(viii) The minimum and maximum 

concentration (mole fraction) of CH4 in 

flash gas from onshore production and 

onshore natural gas gathering and 

boosting storage tanks. 

* * * * * 

(2) * * * 

(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 of § 98.233(j). Onshore 

gathering and boosting facilities do not 

report the information specified in 

paragraphs (j)(2)(i)(E) and (F) of this 

section. 

(A) The total annual oil/condensate 

throughput that is sent to all 

atmospheric tanks in the basin, in 

barrels. You may delay reporting of this 

data element for onshore production if 

you indicate in the annual report that 

wildcat wells and delineation wells are 

the only wells in the sub-basin with oil/ 

condensate production less than 10 

barrels per day and that send oil/

condensate 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/condensate throughput from all 

wells and the well ID number(s) for the 

well(s) included in this volume. 

(B) An estimate of the fraction of oil/ 

condensate 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/ 

condensate 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. 

* * * * * 

(ii) Report the information specified 

in paragraphs (j)(2)(ii)(A) through (D) of 

this section for each sub-basin (for 

onshore production) or county (for 

onshore petroleum and natural gas 

gathering and boosting) with 

atmospheric tanks whose emissions 

were calculated using Calculation 

Method 3 of § 98.233(j) and that did not 

control emissions with flares. 

(A) Sub-basin ID (for onshore 

production) or county name (for 

onshore petroleum and natural gas 

gathering and boosting). 

(B) The number of atmospheric tanks 

in the sub-basin (for onshore 

production) or county (for onshore 

petroleum and natural gas gathering and 

boosting) that did not control emissions 

with flares. 

(C) Annual CO2 emissions, in metric 

tons CO2, from atmospheric tanks in the 

sub-basin (for onshore production) or 

county (for onshore petroleum and 

natural gas gathering and boosting) that 

did not control emissions with flares, 

calculated using Equation W–15 of 

§ 98.233(j) and adjusted for vapor 

recovery, if applicable. 

(D) Annual CH4 emissions, in metric 

tons CH4, from atmospheric tanks in the 

sub-basin (for onshore production) or 

county (for onshore petroleum and 

natural gas gathering and boosting) that 

did not control emissions with flares, 

calculated using Equation W–15 of 

§ 98.233(j) 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 (for 

onshore production) or county (for 

onshore petroleum and natural gas 

gathering and boosting) with 

atmospheric tanks whose emissions 

were calculated using Calculation 

Method 3 of § 98.233(j) and that 

controlled emissions with flares. 

(A) Sub-basin ID (for onshore 

production) or county name (for 

onshore petroleum and natural gas 

gathering and boosting). 

(B) The number of atmospheric tanks 

in the sub-basin (for onshore 

production) or county (for onshore 

petroleum and natural gas gathering and 

boosting) that controlled emissions with 

flares. 

* * * * * 

(3) If you used Calculation Method 1 

or Calculation Method 2 of § 98.233(j), 

and any gas-liquid separator liquid 

dump values did not close properly 

during the calendar year, then you must 

report the information specified in 

paragraphs (j)(3)(i) through (iv) of this 

section for each sub-basin (for onshore 

production) or county (for onshore 

petroleum and natural gas gathering and 

boosting). 

* * * * * 

(l) * * * 

(1) If you used Equation W–17A of 

§ 98.233 to calculate annual volumetric 

natural gas emissions at actual 


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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 

(vii) of this section. 

* * * * * 

(ii) Well ID numbers for the wells 

tested in the calendar year. 

* * * * * 

(v) 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 well ID number(s) for the well(s) 

included in the measurement. 

* * * * * 

(2) If you used Equation W–17A of 

§ 98.233 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 (viii) of this 

section. 

* * * * * 

(ii) Well ID numbers for the wells 

tested in the calendar year. 

* * * * * 

(v) 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 well ID number(s) for the well(s) 

included in the measurement. 

* * * * * 

(3) If you used Equation W–17B of 

§ 98.233 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 

(vi) of this section. 

* * * * * 

(ii) Well ID numbers for the wells 

tested in the calendar year. 

* * * * * 

(iv) 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 well ID 

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

measurement. 

* * * * * 

(4) If you used Equation W–17B of 

§ 98.233 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 

(vii) of this section. 

* * * * * 

(ii) Well ID numbers for the wells 

tested in the calendar year. 

* * * * * 

(iv) 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 well ID 

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

measurement. 

* * * * * 

(m) * * * 

(1) Sub-basin ID and a list of well ID 

numbers for wells for which associated 

gas was vented or flared. 

* * * * * 

(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 § 98.233). 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 well ID 

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 well ID 

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

measurement. 

(7) * * * 

(i) Total number of wells for which 

associated gas was vented directly to the 

atmosphere without flaring and a list of 

their well ID numbers. 

* * * * * 

(8) * * * 

(i) Total number of wells for which 

associated gas was flared and a list of 

their well ID numbers. 

* * * * * 

(n) * * * 

(1) Unique name or ID for the flare 

stack. For the onshore petroleum and 

natural gas production and onshore 

petroleum and natural gas gathering and 

boosting industry segments, 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. 

* * * * * 

(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 and onshore 

petroleum and natural gas gathering and 

boosting 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. 

* * * * * 

(5) Onshore petroleum and natural 

gas production and onshore petroleum 

and natural gas gathering and boosting. 

Centrifugal compressors with wet seal 

degassing vents in onshore petroleum 

and natural gas production and onshore 

petroleum and natural gas gathering and 

boosting must report the information 

specified in paragraphs (o)(5)(i) through 

(iii) of this section. 

* * * * * 

(p) Reciprocating compressors. You 

must indicate whether your facility has 

reciprocating compressors. You must 

report the information specified in 


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64296 Federal Register / Vol. 80, No. 204 / Thursday, October 22, 2015 / Rules and Regulations 

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 and onshore 

petroleum and natural gas gathering and 

boosting 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. 

* * * * * 

(5) Onshore petroleum and natural 

gas production and onshore petroleum 

and natural gas gathering and boosting. 

Reciprocating compressors in onshore 

petroleum and natural gas production 

and onshore petroleum and natural gas 

gathering and boosting must report the 

information specified in paragraphs 

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

* * * * * 

(r) * * * 

(1) You must indicate whether your 

facility contains any of the emission 

source types required to use Equation 

W–32A of § 98.233. 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 that is 

located at your facility. Onshore 

petroleum and natural gas production 

facilities and onshore petroleum and 

natural gas gathering and boosting 

facilities must report the information 

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

(v) 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 and onshore petroleum and 

natural gas gathering and boosting 

facilities must report the component 

type, service type and geographic 

location. 

* * * * * 

(3) Onshore petroleum and natural gas 

production facilities and onshore 

petroleum and natural gas gathering and 

boosting facilities must also report the 

information specified in paragraphs 

(r)(3)(i) and (ii) of this section. 

* * * * * 

(ii) Onshore petroleum and natural 

gas production facilities and onshore 

petroleum and natural gas gathering and 

boosting 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. 

* * * * * 

(z) Combustion equipment at onshore 

petroleum and natural gas production 

facilities, onshore petroleum and 

natural gas gathering and boosting 

facilities, and natural gas distribution 

facilities. If your facility is required by 

§ 98.232(c)(22), (i)(7), or (j)(12) to report 

emissions from combustion equipment, 

then you must indicate whether your 

facility has any combustion units 

subject to reporting according to 

paragraph (a)(1)(xvii), (a)(8)(i), or 

(a)(9)(xi) of this section. If your facility 

contains any combustion units subject 

to reporting according to paragraph 

(a)(1)(xvii), (a)(8)(i), or (a)(9)(xi) of this 

section, then you must report the 

information specified in paragraphs 

(z)(1) and (2) of this section, as 

applicable. 

* * * * * 

(aa) Each facility must report the 

information specified in paragraphs 

(aa)(1) through (11) 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) * * * 

(ii) * * * 

(D) The number of producing wells at 

the end of the calendar year and a list 

of the well ID numbers (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 and a 

list of the well ID numbers. 

(F) The number of producing wells 

divested during the calendar year and a 

list of the well ID numbers. 

(G) The number of wells completed 

during the calendar year and a list of the 

well ID numbers. 

(H) The number of wells permanently 

taken out of production (i.e., plugged 

and abandoned) during the calendar 

year and a list of the well ID numbers. 

* * * * * 

(10) For onshore petroleum and 

natural gas gathering and boosting 

facilities, report the quantities specified 

in paragraphs (aa)(10)(i) through (iv) of 

this section. 

(i) The quantity of gas received by the 

gathering and boosting facility in the 

calendar year, in thousand standard 

cubic feet. 

(ii) The quantity of gas transported to 

a natural gas processing facility, a 

natural gas transmission pipeline, a 

natural gas distribution pipeline, or 

another gathering and boosting facility 

in the calendar year, in thousand 

standard cubic feet. 

(iii) The quantity of all hydrocarbon 

liquids received by the gathering and 

boosting facility in the calendar year, in 

barrels. 

(iv) The quantity of all hydrocarbon 

liquids transported to a natural gas 

processing facility, a natural gas 

transmission pipeline, a natural gas 

distribution pipeline, or another 

gathering and boosting facility in the 

calendar year, in barrels. 

(11) For onshore natural gas 

transmission pipeline facilities, report 

the quantities specified in paragraphs 

(aa)(11)(i) through (vi) 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 

transferred to third parties such as LDCs 

or other transmission pipelines, in 

thousand standard cubic feet. 

(v) The quantity of natural gas 

consumed by the transmission pipeline 

facility for operational purposes, in 

thousand standard cubic feet. 

(vi) The miles of transmission 

pipeline for each state in the facility. 

* * * * * 

(cc) If you elect to delay reporting the 

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

(g)(5)(ii), (g)(5)(iii)(A), (g)(5)(iii)(B), 

(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. 

■ 8. Section 98.238 is amended by 

adding definitions for ‘‘Facility with 

respect to onshore petroleum and 

natural gas gathering and boosting for 

purposes of reporting under this subpart 

and for the corresponding subpart A 

requirements,’’ ‘‘Facility with respect to 

the onshore natural gas transmission 

pipeline segment,’’ ‘‘Gathering and 


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Federal Register / Vol. 80, No. 204 / Thursday, October 22, 2015 / Rules and Regulations 64297 

boosting system,’’ ‘‘Gathering and 

boosting system owner or operator,’’ 

‘‘Onshore natural gas transmission 

pipeline owner or operator,’’ and ‘‘Well 

identification (ID) number’’ in 

alphabetical order to read as follows: 

§ 98.238 Definitions. 

* * * * * 

Facility with respect to onshore 

petroleum and natural gas gathering 

and boosting for purposes of reporting 

under this subpart and for the 

corresponding subpart A requirements 

means all gathering pipelines and other 

equipment located along those pipelines 

that are under common ownership or 

common control by a gathering and 

boosting system owner or operator and 

that are located in a single hydrocarbon 

basin as defined in this section. Where 

a person owns or operates more than 

one gathering and boosting system in a 

basin (for example, separate gathering 

lines that are not connected), then all 

gathering and boosting equipment that 

the person owns or operates in the basin 

would be considered one facility. Any 

gathering and boosting equipment that 

is associated with a single gathering and 

boosting system, including leased, 

rented, or contracted activities, is 

considered to be under common control 

of the owner or operator of the gathering 

and boosting system that contains the 

pipeline. The facility does not include 

equipment and pipelines that are part of 

any other industry segment defined in 

this subpart. 

* * * * * 

Facility with respect to the onshore 

natural gas transmission pipeline 

segment means the total U.S. mileage of 

natural gas transmission pipelines, as 

defined in this section, owned and 

operated by an onshore natural gas 

transmission pipeline owner or operator 

as defined in this section. The facility 

does not include pipelines that are part 

of any other industry segment defined 

in this subpart. 

* * * * * 

Gathering and boosting system means 

a single network of pipelines, 

compressors and process equipment, 

including equipment to perform natural 

gas compression, dehydration, and acid 

gas removal, that has one or more 

connection points to gas and oil 

production and a downstream endpoint, 

typically a gas processing plant, 

transmission pipeline, LDC pipeline, or 

other gathering and boosting system. 

Gathering and boosting system owner 

or operator means any person that holds 

a contract in which they agree to 

transport petroleum or natural gas from 

one or more onshore petroleum and 

natural gas production wells to a natural 

gas processing facility, another 

gathering and boosting system, a natural 

gas transmission pipeline, or a 

distribution pipeline, or any person 

responsible for custody of the petroleum 

or natural gas transported. 

* * * * * 

Onshore natural gas transmission 

pipeline owner or operator means, for 

interstate pipelines, the person 

identified as the transmission pipeline 

owner or operator on the Certificate of 

Public Convenience and Necessity 

issued under 15 U.S.C. 717f, or, for 

intrastate pipelines, the person 

identified as the owner or operator on 

the transmission pipeline’s Statement of 

Operating Conditions under section 311 

of the Natural Gas Policy Act, or for 

pipelines that fall under the ‘‘Hinshaw 

Exemption’’ as referenced in section 1(c) 

of the Natural Gas Act, 15 U.S.C. 717– 

717 (w)(1994), the person identified as 

the owner or operator on blanket 

certificates issued under 18 CFR 

284.224. If an intrastate pipeline is not 

subject to section 311 of the Natural Gas 

Policy Act (NGPA), the onshore natural 

gas transmission pipeline owner or 

operator is the person identified as the 

owner or operator on reports to the state 

regulatory body regulating rates and 

charges for the sale of natural gas to 

consumers. 

* * * * * 

Well identification (ID) number means 

the unique and permanent identification 

number assigned to a petroleum or 

natural gas well. If the well has been 

assigned a US Well Number, the well ID 

number required in this subpart is the 

US Well Number. If a US Well Number 

has not been assigned to the well, the 

well ID number is the identifier 

established by the well’s permitting 

authority. 

* * * * * 

■ 9. Revise Table W–1A of subpart W of 

part 98 to read as follows: 

TABLE W–1A TO SUBPART W OF PART 98—DEFAULT WHOLE GAS EMISSION FACTORS FOR ONSHORE PETROLEUM AND

NATURAL GAS PRODUCTION FACILITIES AND ONSHORE PETROLEUM AND NATURAL GAS GATHERING AND BOOSTING

FACILITIES

Onshore petroleum and natural gas production and Onshore petroleum and natural gas gathering and boosting Emission factor 

(scf/hour/component) 

Eastern U.S. 

Population Emission Factors—All Components, Gas Service 1

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

Connector ............................................................................................................................................................................ 0.003 

Open-ended Line ................................................................................................................................................................. 0.061 

Pressure Relief Valve .......................................................................................................................................................... 0.040 

Low Continuous Bleed Pneumatic Device Vents 2 .............................................................................................................. 1.39 

High Continuous Bleed Pneumatic Device Vents 2 ............................................................................................................. 37.3 

Intermittent Bleed Pneumatic Device Vents 2 ...................................................................................................................... 13.5 

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

Population Emission Factors—All Components, Light Crude Service 4

Valve .................................................................................................................................................................................... 0.05 

Flange .................................................................................................................................................................................. 0.003 

Connector ............................................................................................................................................................................ 0.007 

Open-ended Line ................................................................................................................................................................. 0.05 

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

Other 5 .................................................................................................................................................................................. 0.30 

Population Emission Factors—All Components, Heavy Crude Service 6

Valve .................................................................................................................................................................................... 0.0005 

Flange .................................................................................................................................................................................. 0.0009 

Connector (other) ................................................................................................................................................................. 0.0003 


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64298 Federal Register / Vol. 80, No. 204 / Thursday, October 22, 2015 / Rules and Regulations 

TABLE W–1A TO SUBPART W OF PART 98—DEFAULT WHOLE GAS EMISSION FACTORS FOR ONSHORE PETROLEUM AND

NATURAL GAS PRODUCTION FACILITIES AND ONSHORE PETROLEUM AND NATURAL GAS GATHERING AND BOOSTING

FACILITIES—Continued 

Onshore petroleum and natural gas production and Onshore petroleum and natural gas gathering and boosting Emission factor 

(scf/hour/component) 

Open-ended Line ................................................................................................................................................................. 0.006 

Other 5 .................................................................................................................................................................................. 0.003 

Population Emission Factors—Gathering Pipelines, by Material Type 7

Protected Steel .................................................................................................................................................................... 0.47 

Unprotected Steel ................................................................................................................................................................ 16.59 

Plastic/Composite ................................................................................................................................................................ 2.50 

Cast Iron .............................................................................................................................................................................. 27.60 

Western U.S. 

Population Emission Factors—All Components, Gas Service 1

Valve .................................................................................................................................................................................... 0.121 

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

Open-ended Line ................................................................................................................................................................. 0.031 

Pressure Relief Valve .......................................................................................................................................................... 0.193 

Low Continuous Bleed Pneumatic Device Vents 2 .............................................................................................................. 1.39 

High Continuous Bleed Pneumatic Device Vents 2 ............................................................................................................. 37.3 

Intermittent Bleed Pneumatic Device Vents 2 ...................................................................................................................... 13.5 

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

Population Emission Factors—All Components, Light Crude Service 4

Valve .................................................................................................................................................................................... 0.05 

Flange .................................................................................................................................................................................. 0.003 

Connector (other) ................................................................................................................................................................. 0.007 

Open-ended Line ................................................................................................................................................................. 0.05 

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

Other 5 .................................................................................................................................................................................. 0.30 

Population Emission Factors—All Components, Heavy Crude Service 6

Valve .................................................................................................................................................................................... 0.0005 

Flange .................................................................................................................................................................................. 0.0009 

Connector (other) ................................................................................................................................................................. 0.0003 

Open-ended Line ................................................................................................................................................................. 0.006 

Other 5 .................................................................................................................................................................................. 0.003 

Population Emission Factors—Gathering Pipelines by Material Type 7

Protected Steel .................................................................................................................................................................... 0.47 

Unprotected Steel ................................................................................................................................................................ 16.59 

Plastic/Composite ................................................................................................................................................................ 2.50 

Cast Iron .............................................................................................................................................................................. 27.60 

1For multi-phase flow that includes gas, use the gas service emissions factors. 

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

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

4 Hydrocarbon liquids greater than or equal to 20°API are considered ‘‘light crude.’’ 5 ‘‘Others’’ category includes instruments, loading arms, pressure relief valves, stuffing boxes, compressor seals, dump lever arms, and vents. 

6 Hydrocarbon liquids less than 20°API are considered ‘‘heavy crude.’’ 7Emission factors are in units of ‘‘scf/hour/mile of pipeline.’’ 

■ 10. Amend Table W–1B of subpart W 

of part 98 by revising the table heading 

to read as follows: 

TABLE W–1B TO SUBPART W OF PART

98—DEFAULT AVERAGE COMPONENT COUNTS FOR MAJOR ONSHORE NATURAL GAS PRODUCTION

EQUIPMENT AND ONSHORE PETROLEUM AND NATURAL GAS GATHERING AND BOOSTING EQUIPMENT

* * * * * 

[FR Doc. 2015–25840 Filed 10–21–15; 08:45 am] 

BILLING CODE 6560–50–P 


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