73148 Federal Register / Vol. 79, No. 236 / Tuesday, December 9, 2014 / Proposed Rules 

ENVIRONMENTAL PROTECTION 

AGENCY 

40 CFR Part 98 

[EPA–HQ–OAR–2014–0831; FRL—9918–48– 

OAR] 

RIN 2060–AS37 

Greenhouse Gas Reporting Rule: 2015 

Revisions and Confidentiality 

Determinations for Petroleum and 

Natural Gas Systems 

AGENCY: Environmental Protection 

Agency. 

ACTION: Proposed rule. 

SUMMARY: The Environmental Protection 

Agency (EPA) is proposing revisions 

and confidentiality determinations for 

the petroleum and natural gas systems 

source category of the Greenhouse Gas 

Reporting Program. In particular, the 

EPA is proposing to add calculation 

methods and reporting requirements for 

greenhouse gas 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 EPA is also proposing well 

identification reporting requirements to 

improve the EPA’s ability to verify 

reported data and enhance 

transparency. This action also proposes 

confidentiality determinations for new 

data elements contained in these 

proposed amendments. 

DATES: Comments must be received on 

or before February 9, 2015. 

Public Hearing. The EPA does not 

plan to conduct a public hearing unless 

requested. To request a hearing, please 

contact the person listed in the 

following FOR FURTHER INFORMATION

CONTACT section by December 16, 2014. 

If requested, the hearing will be 

conducted on December 24, 2014, in the 

Washington, DC area. The EPA will 

provide further information about the 

hearing on the Greenhouse Gas 

Reporting Program Web site, http://

www.epa.gov/ghgreporting/index.html if 

a hearing is requested. 

ADDRESSES: Submit your comments, 

identified by Docket ID No. EPA–HQ– 

OAR–2014–0831 by any of the following 

methods: 

• Federal eRulemaking Portal: http:// 

www.regulations.gov. Follow the online 

instructions for submitting comments. 

• Email: A-and-R-Docket@epa.gov. 

Include Docket ID No. EPA–HQ–OAR– 

2014–0831 or RIN No. 2060–AS37 in the 

subject line of the message. 

• Fax: (202) 566–9744. 

• Mail: Environmental Protection 

Agency, EPA Docket Center (EPA/DC), 

Mailcode 28221T, Attention Docket ID 

No. EPA–HQ–OAR–2014–0831, 1200 

Pennsylvania Avenue NW., Washington, 

DC 20460. In addition, please mail a 

copy of your comments on the 

information collection provisions to the 

Office of Information and Regulatory 

Affairs, Office of Management and 

Budget (OMB), Attn: Desk Officer for 

EPA, 725 17th Street, NW., Washington, 

DC 20503. 

• Hand/Courier Delivery: EPA Docket 

Center, Room 3334, EPA WJC West 

Building, 1301 Constitution Avenue 

NW., Washington, DC 20004. Such 

deliveries are accepted only during the 

normal hours of operation of the Docket 

Center, and special arrangements should 

be made for deliveries of boxed 

information. 

Additional Information on Submitting 

Comments: To expedite review of your 

comments by agency staff, you are 

encouraged to send a separate copy of 

your comments, in addition to the copy 

you submit to the official docket, to 

Carole Cook, U.S. EPA, Office of 

Atmospheric Programs, Climate Change 

Division, Mail Code 6207A, 1200 

Pennsylvania Avenue NW., Washington, 

DC 20460, telephone (202) 343–9263, 

email address: GHGReportingRule@

epa.gov. 

Instructions: Direct your comments to 

Docket ID No. EPA–HQ–OAR–2014– 

0831, Greenhouse Gas Reporting Rule: 

2015 Revisions and Confidentiality 

Determinations for Petroleum and 

Natural Gas Systems; Proposed Rule. 

The EPA’s policy is that all comments 

received will be included in the public 

docket without change and may be 

made available online at http://

www.regulations.gov, including any 

personal information provided, unless 

the comment includes information 

claimed to be confidential business 

information (CBI) or other information 

whose disclosure is restricted by statute. 

Should you choose to submit 

information that you claim to be CBI, 

clearly mark the part or all of the 

information that you claim to be CBI. 

For information that you claim to be CBI 

in a disk or CD–ROM that you mail to 

the EPA, mark the outside of the disk or 

CD–ROM as CBI and then identify 

electronically within the disk or CD– 

ROM the specific information that is 

claimed as CBI. In addition to one 

complete version of the comment that 

includes information claimed as CBI, a 

copy of the comment that does not 

contain the information claimed as CBI 

must be submitted for inclusion in the 

public docket. Information marked as 

CBI will not be disclosed except in 

accordance with procedures set forth in 

40 CFR part 2. Send or deliver 

information identified as CBI to only the 

mail or hand/courier delivery address 

listed above, attention: Docket ID No. 

EPA–HQ–OAR–2014–0831. If you have 

any questions about CBI or the 

procedures for claiming CBI, please 

consult the person identified in the FOR

FURTHER INFORMATION CONTACT section. 

Do not submit information that you 

consider to be CBI or otherwise 

protected through http://

www.regulations.gov or email. The 

http://www.regulations.gov Web site is 

an ‘‘anonymous access’’ system, which 

means the EPA will not know your 

identity or contact information unless 

you provide it in the body of your 

comment. If you send an email 

comment directly to the EPA without 

going through http://

www.regulations.gov your email address 

will be automatically captured and 

included as part of the comment that is 

placed in the public docket and made 

available on the Internet. If you submit 

an electronic comment, the EPA 

recommends that you include your 

name and other contact information in 

the body of your comment and with any 

disk or CD–ROM you submit. If the EPA 

cannot read your comment due to 

technical difficulties and cannot contact 

you for clarification, the EPA may not 

be able to consider your comment. 

Electronic files should avoid the use of 

special characters, any form of 

encryption, and be free of any defects or 

viruses. 

Docket: All documents in the docket 

are listed in the http://

www.regulations.gov index. Although 

listed in the index, some information is 

not publicly available, e.g., CBI or other 

information whose disclosure is 

restricted by statute. Certain other 

material, such as copyrighted material, 

will be publicly available only in hard 

copy. Publicly available docket 

materials are available either 

electronically in http://

www.regulations.gov or in hard copy at 

the Air Docket, EPA/DC, WJC West 

Building, Room 3334, 1301 Constitution 

Ave., NW., Washington, DC. This 

Docket Facility is open from 8:30 a.m. 

to 4:30 p.m., Monday through Friday, 

excluding legal holidays. The telephone 

number for the Public Reading Room is 

(202) 566–1744, and the telephone 

number for the Air Docket is (202) 566– 

1742. 

FOR FURTHER 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: 


rljohnson on DSK3VPTVN1PROD with PROPOSALS2
Federal Register / Vol. 79, No. 236 / Tuesday, December 9, 2014 / Proposed Rules 73149 

(202) 343–2342; email address: 

GHGReportingRule@epa.gov. For 

technical information, please go to the 

Greenhouse Gas Reporting Program Web 

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

index.html. To submit a question, select 

Help Center, followed by ‘‘Contact Us.’’ 

Worldwide Web (WWW). In addition 

to being available in the docket, an 

electronic copy of today’s proposal will 

also be available through the WWW. 

Following the Administrator’s signature, 

a copy of this action will be posted on 

the EPA’s Greenhouse Gas Reporting 

Program Web site at http://

www.epa.gov/ghgreporting/index.html. 

SUPPLEMENTARY INFORMATION: 

Regulated Entities. The Administrator 

determined that this action is subject to 

the provisions of Clean Air Act (CAA) 

section 307(d). See CAA section 

307(d)(1)(V) (the provisions of section 

307(d) apply to ‘‘such other actions as 

the Administrator may determine’’). 

These are proposed amendments to 

existing regulations. If finalized, these 

amended regulations would affect 

owners or operators of petroleum and 

natural gas systems that directly emit 

greenhouse gases (GHGs). Regulated 

categories and entities include those 

listed in Table 1 of this preamble: 

TABLE 1—EXAMPLES OF AFFECTED ENTITIES BY CATEGORY

Category NAICSa Examples of affected facilities 

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

221210 Natural gas distribution. 

211111 Crude petroleum and natural gas extraction. 

211112 Natural gas liquid extraction. 

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. Other types of facilities 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. 

Acronyms and Abbreviations. The 

following acronyms and abbreviations 

are used in this document. 

API American Petroleum Institute 

BAMM best available monitoring methods 

Btu British thermal unit 

CAA Clean Air Act 

CBI confidential business information 

CFR Code of Federal Regulations 

CO2 carbon dioxide 

CO2e carbon dioxide equivalent 

EPA Environmental Protection Agency 

EIA Energy Information Administration 

FERC Federal Energy Regulatory 

Commission 

FR Federal Register 

GHG greenhouse gas 

GHGRP Greenhouse Gas Reporting Program 

GOR gas-to-oil ratio 

ICR Information Collection Request 

ISBN International Standard Book Number 

LDC local distribution company 

MMscfd million standard cubic feet per day 

NAICS North American Industry 

Classification System 

NESHAP national emission standards for 

hazardous air pollutants 

NGO non-government organization 

NGPA Natural Gas Policy Act 

NTTAA National Technology Transfer and 

Advancement Act of 1995 

OMB Office of Management and Budget 

PPDM Professional Petroleum Data 

Management 

REC reduced emission completion 

RFA Regulatory Flexibility Act 

SBA Small Business Administration 

SBREFA Small Business Regulatory 

Enforcement and Fairness Act 

U.S. United States 

UMRA Unfunded Mandates Reform Act of 

1995 

Organization of This Document. The 

following outline is provided to aid in 

locating information in this preamble. 

I. Background 

A. Organization of This Preamble 

B. Background on the Proposed Action 

C. Legal Authority 

D. How would these amendments apply to 

2015 and 2016 reports? 

II. Revisions and Other Amendments 

A. Oil Wells With Hydraulic Fracturing 

B. Onshore Petroleum and Natural Gas 

Gathering and Boosting Segment 

C. Natural Gas Transmission Lines 

Between Compressor Stations 

D. Well Identification Numbers 

E. Advanced Innovative Monitoring 

Methods 

F. Best Available Monitoring Methods 

III. Proposed Confidentiality Determinations 

A. Overview and Background 

B. Approach to Proposed CBI 

Determinations 

C. Proposed Confidentiality 

Determinations for Data Elements 

Assigned to the ‘‘Unit/Process ‘Static’ 

Characteristics That Are Not Inputs to 

Emission Equations’’ and ‘‘Unit/Process 

Operating Characteristics That Are Not 

Inputs to Emission Equations’’ Data 

Categories 

D. Other Proposed Case-by-Case 

Confidentiality Determinations for 

Subpart W 

E. Request for Comments on Proposed 

Confidentiality Determinations 

IV. Impacts of the Proposed Amendments to 

Subpart W 

A. Costs of the Proposed Amendments 

B. Impacts of the Proposed Amendments 

on Small Businesses 

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 

D. Unfunded Mandates Reform Act 

E. Executive Order 13132: Federalism 

F. Executive Order 13175: Consultation 

and Coordination With Indian Tribal 

Governments 

G. Executive Order 13045: Protection of 

Children From Environmental Health 

Risks and Safety Risks 

H. Executive Order 13211: Actions That 

Significantly Affect Energy Supply, 

Distribution, or Use 

I. National Technology Transfer and 

Advancement Act 

J. Executive Order 12898: Federal Actions 

To Address Environmental Justice in 

Minority Populations and Low-Income 

Populations 

I. Background 

A. Organization of This Preamble 

The first section of this preamble 

provides background information 

regarding the proposed amendments. 

This section also discusses the EPA’s 

legal authority under the CAA to 

promulgate and amend 40 CFR part 98 

(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 

proposed revisions to 40 CFR part 98, 

subpart W (hereafter referred to as 

‘‘subpart W’’). Section III of this 

preamble discusses proposed 

confidentiality determinations for new 

data reporting elements. Section IV of 

this preamble discusses the impacts of 

the proposed amendments to subpart W. 


rljohnson on DSK3VPTVN1PROD with PROPOSALS2
73150 Federal Register / Vol. 79, No. 236 / Tuesday, December 9, 2014 / Proposed Rules 

1U.S. Environmental Protection Agency. 

Inventory of U.S. Greenhouse Gas Emissions and 

Sinks: 1990–2012. April 15, 2014. EPA 430–R–14– 

003. This report tracks total annual U.S. emissions 

and removals by source, economic sector, and 

greenhouse gas going back to 1990. It is updated 

annually, and the latest version (cited here) covers 

emissions through 2012. 

2Climate 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. 

Finally, Section V of this preamble 

describes the statutory and executive 

order requirements applicable to this 

action. 

B. Background on the Proposed 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). 

In this current proposal, the EPA is 

proposing to amend subpart W to 

require the reporting of GHG emissions 

from several sources that have not 

previously been included in subpart W. 

These sources include oil well 

completions and workovers with 

hydraulic fracturing, petroleum and 

natural gas gathering and boosting 

systems, and transmission pipeline 

blowdowns between compressor 

stations. The proposed reporting 

requirements for oil well completions 

and workovers with hydraulic fracturing 

would be included as part of the 

existing Onshore Petroleum and Natural 

Gas Production industry segment. For 

the other sources, the EPA is proposing 

two new industry segments: the 

Onshore Petroleum and Natural Gas 

Gathering and Boosting segment for 

petroleum and natural gas gathering and 

boosting facilities, and Onshore Natural 

Gas Transmission Pipeline for 

transmission pipeline blowdowns 

between compressor stations. The EPA 

is also proposing to require the 

reporting of a well identification 

number for oil and gas wells covered in 

the Onshore Petroleum and Natural Gas 

Production segment. 

The EPA is proposing these changes 

for several reasons. First, we have been 

working to enhance the quality of data 

from petroleum and natural gas systems 

gathered through Part 98, because it has 

been an important tool for the EPA and 

the public to analyze emissions, identify 

opportunities for improving the data, 

and understand emissions trends. One 

of the strengths of the GHGRP’s 

petroleum and natural gas systems data 

is that it provides a better understanding 

of sources in the petroleum and natural 

gas industry for which the public 

previously had little information. For 

example, the data that would be 

collected through these proposed 

revisions could inform updates to the 

Inventory of U.S. Greenhouse Gas 

Emissions and Sinks 1 (hereafter referred 

to as the ‘‘U.S. GHG Inventory’’). These 

proposed revisions reflect the fact that 

this sector has been growing and 

changing rapidly since the GHGRP’s 

petroleum and natural gas systems 

requirements were originally 

promulgated in 2010. Greenhouse gas 

reporting from gathering and boosting 

systems was proposed in 2010 but was 

not finalized due to the need to conduct 

additional analysis. Emissions from the 

sources the EPA is proposing to include 

are not reported under the GHGRP with 

the exception of emissions from 

completions and workovers of oil wells 

with hydraulic fracturing that are flared 

and emissions from sources in the 

Onshore Petroleum and Natural Gas 

Gathering and Boosting segment that are 

required to report as combustion 

sources under subpart C of Part 98. 

Aside from those exceptions, which 

only include emissions associated with 

combustion and do not capture the 

majority of methane emissions from 

these sources, a nationally 

comprehensive data set of the emissions 

from the sources the EPA is proposing 

to include does not currently exist in 

the public domain. The EPA anticipates 

that these emission sources will be an 

important part of establishing a 

comprehensive data set for the 

petroleum and natural gas industry 

based on data available in the U.S. GHG 

Inventory and other sources. For more 

information, please see ‘‘Greenhouse 

Gas Reporting Rule: Technical Support 

for 2015 Revisions and Confidentiality 

Determinations for Petroleum and 

Natural Gas Systems; Proposed Rule’’ in 

Docket ID No. EPA–HQ–OAR–2014– 

0831. If finalized, this rule would 

further the EPA’s goal of improving the 

completeness, quality, accuracy, and 

transparency of data from this sector (79 

FR 74484, November 30, 2010), 

improving the ability of agencies and 

the public to use these GHG data to 

analyze emissions and understand 

emission trends. Adding well 

identification numbers to the required 

reporting for oil and gas wells covered 

by the Onshore Petroleum and Natural 

Gas Production segment would enable 

the EPA and other stakeholders to 

directly match data for reported wells 

with other local, state, and federal 

permitting and data reporting 

information, as it is the common 

identification number used for wells in 

the United States (U.S.). 

Second, a key element of the 

President’s Climate Action Plan is the 

Strategy to Reduce Methane Emissions, 

which the Administration announced 

on March 28, 2014. 2 The strategy 

summarizes the sources of methane 

emissions, commits to new steps to cut 

emissions of this potent greenhouse gas, 

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 methane emissions from 

several sectors, including the oil and 

natural gas sector. In this strategy, the 

EPA was specifically tasked with 

continuing to review regulatory 

requirements to address potential gaps 

in coverage, improve methods, and help 

ensure high quality data reporting. The 

proposed revisions to subpart W 

covered in this action would address 

data gaps, specify methods for 

measuring methane emissions, and 

provide data that could be used to 

further analyze methane emissions in 

this industry. 

Third, on March 19, 2013, the EPA 

received a petition from a group of nongovernment organizations (NGOs) 

asking 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, because 

these sources could be significant 


rljohnson on DSK3VPTVN1PROD with PROPOSALS2
Federal Register / Vol. 79, No. 236 / Tuesday, December 9, 2014 / Proposed Rules 73151 

3Petition 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. 

4U.S. EPA Office of Air Quality Planning and 

Standards (OAQPS). Oil and Natural Gas Sector 

Hydraulically Fractured Oil Well Completions and 

Associated Gas During Ongoing Production: Report 

for Oil and Natural Gas Sector, Oil Well 

Completions and Associated Gas During Ongoing 

Production Review Panel. April 2014. Available at 

http://www.epa.gov/airquality/oilandgas/pdfs/

20140415completions.pdf. 

sources of emissions that are not being 

reported. The NGOs also asked the EPA 

to require the reporting of API well 

identification numbers (currently 

known as US Well Numbers) to allow 

cross-reference to production data and 

other important information, to phase 

out the use of best available monitoring 

methods (BAMM), and to consider 

including ‘‘Advanced Innovative 

Monitoring Methods’’ to ‘‘accelerate 

development and deployment of realtime continuous methane emission 

monitoring.’’ 3 These proposed 

revisions, which address this petition, 

are consistent with the EPA’s intent to 

‘‘collect complete and accurate facilitylevel GHG emissions from the 

petroleum and natural gas industry’’ (79 

FR 74484, November 30, 2010) and to 

provide accurate and transparent data to 

inform future policy decisions. Today’s 

proposal includes the reporting of 

emissions currently not covered under 

subpart W as well as reporting of well 

identification numbers which would 

help ensure complete, accurate, and 

transparent reporting of GHG data under 

subpart W. The EPA is proposing to 

allow BAMM for a limited time only for 

sources affected by these proposed 

changes; the use of BAMM for sources 

not addressed by the proposed changes 

in this action was addressed on 

November 25, 2014 (79 FR 70352). 

Finally, the EPA is currently assessing 

the potential opportunities for applying 

innovations in measurement technology 

to identifying and estimating emissions 

from affected sources under subpart W. 

While not explicitly adding new, 

alternative monitoring methods in this 

proposal, the EPA is seeking comment 

on options for allowing use of 

alternative monitoring methods under 

the GHGRP to account for advances in 

technology. See also, ‘‘Discussion Paper 

on Potential Implementation of 

Alternative Monitoring under the 

GHGRP’’ in Docket ID No. EPA–HQ– 

OAR–2014–0831. 

C. Legal Authority 

The EPA is proposing these rule 

amendments under its existing CAA 

authority provided in CAA section 114. 

As stated in the preamble to the 2009 

final GHG reporting rule (74 FR 56260, 

October 30, 2009), CAA section 

114(a)(1) provides the EPA broad 

authority to require the information 

proposed to be gathered by this rule 

because such data would inform and are 

relevant to the EPA’s carrying out a 

wide variety of CAA provisions. See the 

preambles to the proposed (74 FR 

16448, April 10, 2009) and final GHG 

reporting rule (74 FR 56260, October 30, 

2009) for further information. 

In addition, the EPA is proposing 

confidentiality determinations for 

proposed new data elements in subpart 

W under its authorities provided in 

sections 114, 301, and 307 of the CAA. 

Section 114(c) of the CAA requires that 

the EPA make information obtained 

under section 114 available to the 

public, except where information 

qualifies for confidential treatment. The 

Administrator has determined that this 

proposed rule is subject to the 

provisions of section 307(d) of the CAA. 

D. How would these amendments apply 

to 2015 and 2016 reports? 

The EPA is planning to address the 

comments we receive on these proposed 

changes and publish the final 

amendments before the end of 2015. If 

finalized according to this schedule, 

these amendments would become 

effective on January 1, 2016. Facilities 

would therefore be required to follow 

the revised methods in subpart W, as 

amended, to calculate, monitor, and 

report emissions beginning January 1, 

2016. The first annual reports of 

emissions calculated using the amended 

requirements would be those submitted 

by March 31, 2017, which would cover 

the 2016 emissions reporting. For the 

2015 emissions and the corresponding 

reports due by March 31, 2016, reporters 

would continue to calculate, monitor, 

and report emissions and other relevant 

data according to the requirements of 40 

CFR part 98 that are applicable during 

the 2015 calendar year. 

For 2016 emissions only, the EPA is 

proposing to allow the use of short-term 

transitional BAMM for reporters who 

would be subject to new monitoring 

requirements associated with these 

proposed revisions. The use of BAMM 

would provide flexibility for the firsttime monitoring of new emissions 

sources. These reporters would have the 

option of using BAMM from January 1, 

2016 to March 31, 2016 without seeking 

prior EPA approval. Reporters would 

also have the opportunity to request an 

extension for the use of BAMM from 

April 1, 2016 through December 31, 

2016; those owners or operators would 

be required to submit a request to the 

EPA by January 31, 2016. See Section 

II.F of this preamble for more 

information. 

II. Revisions and Other Amendments 

A. Oil Wells With Hydraulic Fracturing 

Subpart W requires the reporting of 

GHG emissions from gas well 

completions and workovers with 

hydraulic fracturing in the Onshore 

Petroleum and Natural Gas Production 

segment, but it does not require the 

reporting of GHG emissions from oil 

well completions and workovers with 

hydraulic fracturing (unless the 

emissions are routed to a flare, in which 

case the emissions would be calculated 

as part of the flare stacks emission 

source, or the well testing emissions are 

vented or flared, in which case the 

emissions would be calculated as part of 

the well testing venting and flaring 

emission source). At the time the EPA 

finalized the subpart W requirements 

(75 FR 74458, November 30, 2010), 

hydraulic fracturing of gas wells was a 

well-established and widespread 

industry practice. However, since that 

time, expansion of the use of horizontal 

drilling and hydraulic fracturing has 

allowed drilling into new formations, 

leading to increased emissions 

associated with hydraulic fracturing.4

Because hydraulic fracturing allows 

access to new geologic formations, some 

of these activities are occurring from 

completions and workovers with 

hydraulic fracturing of wells considered 

to be in oil formations according to the 

definition of ‘‘sub-basin category, for 

onshore natural gas production’’ in 40 

CFR 98.238. Since subpart W does not 

currently capture these emissions from 

oil wells with hydraulic fracturing, the 

EPA is proposing to close this data gap 

by proposing reporting requirements for 

oil well completions and workovers 

with hydraulic fracturing. 

The EPA is proposing to amend 

subpart W: (1) To clarify the 

applicability of the current provisions 

for 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, and (2) to include 

provisions for the reporting of GHG 

emissions from oil well completions 

and workovers with hydraulic 

fracturing. Consistent with the current 

requirements for gas well completions 


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73152 Federal Register / Vol. 79, No. 236 / Tuesday, December 9, 2014 / Proposed Rules 

and workovers with hydraulic 

fracturing, the proposed provisions 

include the reporting of activity data on 

the number of oil wells with hydraulic 

fracturing and on the use of flaring and 

reduced emission completions (RECs). 

The EPA is also proposing to update 

equations and definitions accordingly 

under 40 CFR 98.233(g) to reflect 

applicability to completions and 

workovers of all wells with hydraulic 

fracturing. 

The proposed monitoring methods 

and reporting requirements would 

incorporate methods that are already in 

subpart W for hydraulic fracturing of gas 

wells. The feasibility of the methods 

have been demonstrated and refined 

through several years of reporting and 

earlier amendments to subpart W. 

Specifically, the EPA is proposing to 

require the use of either Equation W– 

10A or W–10B in the current rule for 

calculating GHG emissions from oil well 

completions and workovers 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. Emissions 

would be calculated and reported 

separately for gas wells and oil wells. 

Within 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. Furthermore, 

the EPA is proposing to require 

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 EPA is 

proposing that subpart W would include 

the same requirements for the location 

of the flow meter used to measure the 

gas flow rate for an oil well as for the 

flow meter on a gas well. The EPA is 

seeking comment on whether this is the 

appropriate location for the oil well 

flow meter. The EPA is also seeking 

comment on the burden of requiring 

direct measurement of gas flow rate 

during flowback. 

The EPA is also aware that operators 

of oil wells with a relatively low gas-tooil ratio (GOR) may not meter gas during 

the completion phase or even during the 

production phase. Instead, the 

associated natural gas may be vented or 

flared without measuring the gas flow 

rate. For these oil wells that do not 

meter gas production, the EPA is 

proposing to add a new Equation W– 

12C 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 proposed 

Equation W–12C, the value of PRs,p

would be calculated by multiplying the 

GOR of the well by the measured oil 

production rate during the first 30 days 

of production after the completion or 

workover to calculate average gas 

production flow rate. 

The EPA is not proposing at this time 

to allow the use of calculated flowback 

rate for oil wells based on well 

parameters, as specified in Calculation 

Method 2 in 40 CFR 98.233(g). In the 

current subpart W, Calculation Method 

2 uses the measured gas pressure 

differential across the well choke to 

estimate gas flow rate. Based on the 

information available, the EPA 

concluded that this methodology may 

not be appropriate for estimating 

emissions from oil well completions 

because of the differences in operational 

conditions between oil and gas 

production. The EPA is seeking 

comment on how an engineering 

estimate of gas flow rate for oil wells 

might be performed as an alternative to 

the proposed monitoring methods that 

would require direct measurement of 

gas flow rate. Such an engineering 

estimate would be analogous to the 

current Calculation Method 2, but with 

alternatives to the current Equations 11– 

A and 11–B that would be applicable to 

oil wells. If an appropriate and 

technically sound approach can be 

identified, an engineering estimate 

methodology analogous to Calculation 

Method 2 for gas wells would reduce 

the burden for reporters of oil well 

completions and workovers with 

hydraulic fracturing. 

Additionally, the EPA is seeking 

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. 

The EPA is also soliciting data and other 

supporting information that could be 

used to establish a level for that 

threshold in the final rule amendments, 

if that approach were adopted. 

Supporting data should include, at a 

minimum, information sufficient to 

identify the location of any wells for 

which data are provided (e.g., US Well 

Number), the measured GOR, and 

whether the GOR for the well was 

measured during completion or 

workover. Information that would allow 

the EPA to estimate the typical 

emissions from wells with such a low 

GOR, and to estimate the total emissions 

from all wells that would be exempt if 

such a threshold were established, 

would be particularly helpful to inform 

potential inclusion of a GOR threshold 

in the final rule. The EPA particularly 

solicits specific data, rather than 

conclusory statements, to support 

commenters’ positions on whether the 

EPA should include a minimum GOR 

threshold for monitoring and reporting. 

The EPA is also seeking comment on 

whether to establish a minimum well 

pressure such that oil wells operating 

below a certain pressure would not be 

subject to the monitoring and reporting 

requirements for GHG emissions from 

completions and workovers with 

hydraulic fracturing. Similar to the 

discussion on a potential GOR threshold 

above, the EPA is also soliciting data 

and other supporting information that 

could be used to establish a level for the 

well pressure threshold in the final rule 

amendments, if that approach were 

adopted. Supporting data should 

include, at a minimum, information 

sufficient to identify the location of any 

wells for which data are provided (e.g., 

US Well Number), the measured well 

pressure, and whether the well pressure 

was measured during completion or 

workover. Information that would allow 

the EPA to estimate the typical 

emissions from wells with low well 

pressures, and to estimate the total 

emissions from all wells that would be 

exempt if such a threshold were 

established, would be particularly 

helpful to inform potential inclusion of 

a well pressure threshold in the final 

rule. The EPA particularly solicits 

specific data, rather than conclusory 

statements, to support commenters’ 

positions on whether the EPA should 

include a minimum well pressure 

threshold for monitoring and reporting. 

B. Onshore Petroleum and Natural Gas 

Gathering and Boosting Segment 

The EPA is proposing to add a new 

industry segment to subpart W, Onshore 

Petroleum and Natural Gas Gathering 

and Boosting, that would cover 

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 


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5U.S. Environmental Protection Agency Office of 

Atmosphere Programs, Climate Change Division. 

Mandatory Greenhouse Gas Reporting Rule Subpart 

W—Petroleum and Natural Gas: EPA’s Response to 

Public Comments, November 2010. Docket Item No. 

EPA–HQ–OAR–2009–0923–3608. 

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 welldefined connection points to gas and oil 

production and a well-defined 

downstream endpoint, typically a gas 

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. Acid gas removal units 

and dehydrators may also be located on 

the gathering and boosting system to 

treat the collected natural gas. There are 

two types of gathering and boosting 

systems, radial and trunk line. The 

radial type brings all the pipelines to a 

central header, while the trunk-line type 

uses several remote headers to collect 

fluid and is mainly used in large fields. 

The EPA recognized the need to 

require reporting from gathering and 

boosting systems in an earlier GHGRP 

proposed rule. Gathering lines and 

boosting stations were included in the 

original subpart W proposal (75 FR 

18608, April 12, 2010) under both the 

Onshore Petroleum and Natural Gas 

Production segment and the Onshore 

Natural Gas Processing segment. The 

EPA originally proposed to include 

reporting of emissions from intra-facility 

gathering lines and all systems engaged 

in gathering produced gas from multiple 

wells as part of the Onshore Petroleum 

and Natural Gas Production segment. 

The EPA also proposed that field 

gathering and boosting stations that 

gather and process natural gas from 

multiple wellheads and compress and 

transport natural gas as feed to natural 

gas processing facilities would be 

included in the Onshore Natural Gas 

Processing segment. 

In response to the April 2010 

proposal, the EPA received 32 comment 

letters addressing numerous aspects of 

the proposed gathering and boosting 

reporting requirements. The comments 

generally focused on the areas of 

ownership of the gathering and boosting 

system, and on determining the 

boundaries of gathering and boosting 

between the Onshore Petroleum and 

Natural Gas Production and Onshore 

Natural Gas Processing segments. The 

commenters were also concerned with 

the burden of the proposed reporting 

requirements for the gathering and 

boosting systems. These comments were 

summarized in the preamble to the final 

subpart W rule (75 FR 74458, November 

30, 2010) and can be found in the EPA’s 

Response to Public Comments 

document for the final rule.5

In response to public comments, the 

EPA recognized the need for further 

analysis of gathering and boosting 

before developing reporting 

requirements. As a result, gathering and 

boosting sources were not included in 

the final subpart W rule published in 

November 2010, and the EPA stated that 

we would continue to evaluate ‘‘the 

most appropriate mechanism for future 

actions to address the collection of 

appropriate data on gathering lines and 

boosting stations’’ (75 FR 74469, 

November 30, 2010). After further 

consideration of the comments and 

collection of additional data, the EPA is 

proposing to require reporting of 

petroleum and natural gas gathering and 

boosting equipment as part of a new 

Onshore Petroleum and Natural Gas 

Gathering and Boosting segment to 

collect the data needed to quantify the 

emissions from this segment and to 

achieve more complete coverage of the 

petroleum and natural gas systems 

sector. 

The EPA is proposing to define 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 gas to a natural gas 

processing facility, a natural gas 

transmission pipeline, or a natural gas 

distribution pipeline. Gathering and 

boosting equipment would include, but 

would not be limited to, gathering 

pipelines, separators, compressors, acid 

gas removal units, dehydrators, 

pneumatic devices/pumps, storage 

vessels, engines, boilers, heaters, and 

flares. The Onshore Petroleum and 

Natural Gas Gathering and Boosting 

segment would not include equipment 

and pipelines that are reported under 

any other industry segment defined in 

subpart W. 

The EPA is proposing to define a 

gathering and boosting system as 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. The EPA 

is proposing to define a gathering and 

boosting system owner or operator as 

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 gas 

transported. The purpose of including 

the last phrase of the definition is to 

address ownership scenarios for 

vertically integrated companies for 

which contracts are not needed to 

transfer gas from production wells to 

natural gas processing plants. The EPA 

requests comment on whether this 

phrase addresses that concern. 

The EPA is proposing to define a 

facility with respect to onshore 

petroleum and natural gas gathering and 

boosting in 40 CFR 98.238 as 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 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, would 

be 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 would only need to be reported 

if the collection of emission sources 

emits 25,000 metric tons of carbon 

dioxide equivalent (CO2e) or more per 

year. The basin-level reporting approach 

that the EPA is proposing for onshore 

petroleum and natural gas gathering and 

boosting facilities is currently being 

used for reporting in the Onshore 

Petroleum and Natural Gas Production 

sector. The proposed basin-level 

approach for the Onshore Petroleum 

and Natural Gas Gathering and Boosting 


rljohnson on DSK3VPTVN1PROD with PROPOSALS2
73154 Federal Register / Vol. 79, No. 236 / Tuesday, December 9, 2014 / Proposed Rules 

segment would achieve a balance of 

providing geographically specific 

information, while also reducing burden 

on reporters by ensuring that owners/

operators of gathering and boosting 

systems would only have to submit one 

report for all their systems within a 

basin. For more information on this 

analysis, please see ‘‘Greenhouse Gas 

Reporting Rule: Technical Support for 

2015 Revisions and Confidentiality 

Determinations for Petroleum and 

Natural Gas Systems; Proposed Rule’’ in 

Docket ID No. EPA–HQ–OAR–2014– 

0831. 

The EPA believes that the proposed 

definitions of the Onshore Petroleum 

and Natural Gas Gathering and Boosting 

segment, facility, and owner/operator 

address or avoid the major issues raised 

by the commenters in response to the 

April 2010 proposal. Defining the 

Onshore Petroleum and Natural Gas 

Gathering and Boosting segment as a 

segment separate from the Onshore 

Petroleum and Natural Gas Production 

segment and the Onshore Natural Gas 

Processing segment would avoid many 

of the boundary issues presented by the 

earlier proposal. The proposed 

definition of facility would also clarify 

how equipment located along the 

pipeline should be treated as part of the 

facility. The EPA requests comment on 

the definitions of the Onshore 

Petroleum and Natural Gas Gathering 

and Boosting segment and facility, the 

gathering and boosting system, the 

gathering and boosting system owner or 

operator, the determination of what 

emission sources are included in a 

petroleum and natural gas gathering and 

boosting facility in complex ownership 

scenarios (for example, multiple owners 

with operation handled by one of the 

owners or shared by multiple owners). 

In complex ownership scenarios, the 

EPA is proposing that the owners/

operators would assign a designated 

representative responsible for reporting 

consistent with 40 CFR 98.4, and the 

EPA requests comment on whether the 

provisions of 40 CFR 98.4 are 

appropriate for petroleum and natural 

gas gathering and boosting facilities 

with complex ownership scenarios. In 

addition, the EPA requests comment on 

whether the proposed definitions 

clearly define the boundary of the 

Onshore Petroleum and Natural Gas 

Gathering and Boosting segment as the 

pipelines and equipment between the 

Onshore Petroleum and Natural Gas 

Production segment and the Onshore 

Natural Gas Processing segment (or 

other downstream segment). 

The EPA also requests comment on 

potential concerns with overlap of these 

boundaries and whether specific 

provisions are needed to address the 

overlap. For example, the EPA 

considered whether provisions were 

needed to address the potential for some 

non-fractionating processing plants with 

an annual throughput of around 25 

million standard cubic feet per day 

(MMscfd) to be required to report as part 

of different industry segments from year 

to year (i.e., as part of Onshore 

Petroleum and Natural Gas Gathering 

and Boosting if the annual average daily 

throughput drops below 25 MMscfd one 

year and then part of the Onshore 

Natural Gas Processing segment if the 

throughput increases to above 25 

MMscfd the next year). The EPA 

considered a provision that would allow 

a non-fractionating processing facility to 

stop reporting as part of the Onshore 

Natural Gas Processing segment and 

instead report as part of the Onshore 

Petroleum and Natural Gas Gathering 

and Boosting segment if the facility 

throughput is below 25 MMscfd for 5 

consecutive years. The EPA is not 

proposing to include this provision 

because there is not sufficient 

information available on gathering and 

boosting systems for the EPA to assess 

whether such a provision is necessary, 

but the EPA is requesting comment on 

the need for a provision that addresses 

overlap of segment boundaries and what 

that provision should include. 

The EPA is proposing to use current 

methods in subpart W, when available, 

for monitoring and calculating 

emissions from the Onshore Petroleum 

and Natural Gas Gathering and Boosting 

segment. Subpart W already contains 

monitoring and calculation methods for 

all emission sources that would be 

included in the Onshore Petroleum and 

Natural Gas Gathering and Boosting 

segment, with the exception of gathering 

pipelines, in either the Onshore 

Petroleum and Natural Gas Production 

segment or the Onshore Natural Gas 

Processing segment. Since similar 

equipment and sources are included in 

multiple segments, this approach allows 

the EPA to rely on methods that have 

been proven effective for collecting GHG 

data for at least 3 years. This approach 

is expected to provide high quality data 

while reducing the burden on reporters 

that would be associated with 

determining how to implement new 

estimation methods. 

For natural gas pneumatic devices, 

pneumatic valves, pneumatic pumps, 

and atmospheric storage tanks located 

in the Onshore Petroleum and Natural 

Gas Gathering and Boosting segment, 

the EPA is proposing that gathering and 

boosting reporters use the same methods 

for calculating emissions as in the 

Onshore Petroleum and Natural Gas 

Production segment. Where these 

emission sources are located within 

gathering and boosting facilities, these 

sources are likely to be similar to the 

ones located in the Onshore Petroleum 

and Natural Gas Production segment. 

Specifically, because most processing of 

the gas and oil extracted from wells will 

be processed downstream of the 

gathering and boosting facility, the 

equipment/activities in the Onshore 

Petroleum and Natural Gas Production 

segment will be designed to handle gas 

and oil of composition similar to the gas 

and oil in the Onshore Petroleum and 

Natural Gas Gathering and Boosting 

segment, so the same methods are 

applicable and would be no more 

burdensome. 

For blowdown vent stacks, the current 

subpart W requires reporting of 

emissions for the Onshore Natural Gas 

Processing segment, but not for the 

Onshore Petroleum and Natural Gas 

Production segment. The EPA is 

proposing that the same methods that 

are used for the Onshore Natural Gas 

Processing segment be applied to 

blowdowns of equipment in the 

Onshore Petroleum and Natural Gas 

Gathering and Boosting segment. The 

same exemptions, including those for 

volumes less than 50 cubic feet and for 

desiccant dehydrator reloading, that are 

applied to the Onshore Natural Gas 

Processing segment should also be 

applied to the Onshore Petroleum and 

Natural Gas Gathering and Boosting 

segment. The EPA expects that the 

exemption for volumes less than 50 

cubic feet should alleviate any concerns 

with the burden of calculating 

emissions from small gathering 

pipelines. 

Several emission sources, including 

compressors, acid gas removal units, 

dehydrators, flares, and equipment leaks 

are found in both the Onshore 

Petroleum and Natural Gas Production 

segment and the Onshore Natural Gas 

Processing segment. For acid gas 

removal units, dehydrators, and flare 

stacks, the current subpart W specifies 

the same methods for these sources in 

both the Onshore Petroleum and Natural 

Gas Production segment and the 

Onshore Natural Gas Processing 

segment. For acid gas removal units and 

dehydrators, the current rule includes 

several alternative methods, and the 

same alternative methods are specified 

for both segments. Because these 

emission sources in the Onshore 

Petroleum and Natural Gas Gathering 

and Boosting segment are likely to be 

similar to the ones in the Onshore 

Petroleum and Natural Gas Production 

segment or the Onshore Natural Gas 


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Federal Register / Vol. 79, No. 236 / Tuesday, December 9, 2014 / Proposed Rules 73155 

Processing segment, the same methods 

would be applicable. 

For compressors and equipment leaks, 

subpart W contains one method in the 

Onshore Petroleum and Natural Gas 

Production segment and a different 

method for the same emission source in 

the Onshore Natural Gas Processing 

segment. We are proposing that the 

gathering and boosting reporters use the 

same method as in the Onshore 

Petroleum and Natural Gas Production 

segment. The method for the Onshore 

Petroleum and Natural Gas Production 

segment for compressors and equipment 

leaks relies on the reporter counting the 

number of compressors or components 

(e.g., population counts) and then 

applying emission factors per 

compressor or component for that 

population. Alternatively, for 

equipment leaks, the reporter may count 

the number of pieces of major 

equipment, assume the default 

component counts in Table W–1B, and 

then apply emission factors per 

component. This proposed population 

count approach is appropriate for the 

Onshore Petroleum and Natural Gas 

Gathering and Boosting segment 

because, as in the Onshore Petroleum 

and Natural Gas Production segment, 

the equipment is often geographically 

dispersed and may be visited only 

intermittently. Under the proposed 

approach, a reporter would 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. The EPA 

also seeks comment on the 

appropriateness of the methods used in 

the Onshore Natural Gas Processing 

segment for compressors and equipment 

leaks, which are outlined in 40 CFR 

98.234(a). 

For gathering pipelines, the EPA is 

proposing to use an emission factor 

approach that is essentially the same as 

the approach used for equipment leaks 

in the Onshore Petroleum and Natural 

Gas Production segment. For gathering 

lines, reporters would use the 

population count and emission factor 

approach in 40 CFR 98.233(r). The 

emission factors that are being 

proposed, which would be added to an 

amended Table W–1A, are whole gas 

emission factors based on the U.S. GHG 

Inventory. The population count would 

be the miles of gathering pipeline, 

similar to the approach used for 

calculating emissions from natural gas 

distribution pipelines in the Natural Gas 

Distribution segment. 

The EPA has determined that the 

proposed monitoring and reporting 

requirements minimize the potential 

confusion associated with calculating 

emissions from the Onshore Petroleum 

and Natural Gas Gathering and Boosting 

segment by adopting the same methods 

used for calculating emissions that are 

used in the Onshore Petroleum and 

Natural Gas Production segment and the 

Onshore Natural Gas Processing 

segment. The EPA requests comment on 

whether the proposed monitoring and 

reporting requirements for the proposed 

Onshore Petroleum and Natural Gas 

Gathering and Boosting segment are 

appropriate for these emission sources, 

and if not, what methodologies would 

be more appropriate. 

Data collected through the proposed 

reporting requirements for the Onshore 

Petroleum and Natural Gas Gathering 

and Boosting segment in subpart W 

would improve the EPA’s estimates and 

understanding of emissions from 

sources covered by the new segment 

and from the petroleum and natural gas 

sector. The improved data would 

provide a better understanding of 

sources in the petroleum and natural gas 

industry for which the public currently 

has little information. For example, the 

data that would be collected through 

these proposed revisions would inform 

updates to the U.S. GHG Inventory. 

The proposed requirements would 

require the reporting of GHG emissions 

from an entire gathering and boosting 

facility instead of the partial approach 

that currently exists under the GHGRP. 

Specifically, some gathering and 

boosting emission sources, such as 

natural gas compression stations, are 

only required to report GHG emissions 

if the facility exceeds the 25,000 metric 

tons CO2e annual emission reporting 

threshold in subpart A, 40 CFR 

98.2(a)(2), based on combustion 

emissions that are reported under 

subpart C. Subpart W does currently 

require reporting from facilities that 

perform ‘‘natural gas processing’’ in 40 

CFR 98.230(a)(3), but this requirement is 

only for those facilities that perform 

separation of natural gas liquids or nonmethane gases from produced natural 

gas or the separation of natural gas 

liquids into one or more component 

mixtures and exceed 25 MMscfd annual 

average daily gas throughput. Subpart W 

also covers sources such as 

compressors, dehydration, or acid gas 

removal that are located on a single 

well-pad or associated with a single 

well as part of the Onshore Petroleum 

and Natural Gas Production segment. 

However, if these sources are associated 

with multiple well pads and not located 

on a single well-pad, they are not part 

of the Onshore Petroleum and Natural 

Gas Production segment and are 

currently not subject to reporting under 

subpart W. 

The EPA is not proposing to alter the 

definitions for the Onshore Natural Gas 

Processing or Onshore Petroleum and 

Natural Gas Production segments within 

subpart W, found in 40 CFR 98.230, so 

if these amendments are finalized as 

proposed, then the facilities and 

emission sources that are currently in 

the Onshore Petroleum and Natural Gas 

Production segment and the Onshore 

Natural Gas Processing segment of 

subpart W would remain in those 

segments. For facilities that have 

emissions sources that are covered by 

the Onshore Petroleum and Natural Gas 

Production segment and the Onshore 

Natural Gas Processing segment of 

subpart W but do not collectively meet 

the threshold for reporting in those 

segments, those emission sources or 

equipment should only be considered in 

the proposed Onshore Petroleum and 

Natural Gas Gathering and Boosting 

segment if they meet the proposed 

definition of ‘‘gathering and boosting 

system’’ and the appropriate thresholds. 

However, the proposed Onshore 

Petroleum and Natural Gas Gathering 

and Boosting segment would increase 

the overall coverage of subpart W by 

including some facilities that are 

reporting under subpart C for 

combustion emissions but only have to 

report a subset of their emissions 

currently, or that are not reporting at all 

under the GHGRP. Under the proposed 

rule, these facilities would become part 

of the proposed Onshore Petroleum and 

Natural Gas Gathering and Boosting 

segment in subpart W. If a reporter has 

more than one facility currently 

reporting under subpart C and they are 

consolidated as part of a single 

gathering and boosting facility as 

defined in this proposal, then the 

gathering and boosting facility would 

begin reporting all their relevant facility 

emissions, including those previously 

reported under subpart C, as a single 

consolidated facility under subpart W. 

The consolidated reporting facility 

would also include the parts of the 

system, such as pipelines and smaller 

compression stations, for which 

emissions are not currently being 

reported. 

The proposed Onshore Petroleum and 

Natural Gas Gathering and Boosting 

segment would also include equipment 

and facilities that are not currently 

reporting under the GHGRP. For 

example, the EPA anticipates that the 

proposed Onshore Petroleum and 

Natural Gas Gathering and Boosting 

segment would include many 

compressor stations in gathering and 

boosting systems that are not currently 


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73156 Federal Register / Vol. 79, No. 236 / Tuesday, December 9, 2014 / Proposed Rules 

reporting because they do not, as a 

facility defined in 40 CFR 98.6, exceed 

the 25,000 metric tons CO2e per year 

reporting threshold in subpart A, 40 

CFR 98.2(a)(2). However, when 

aggregated with the gathering pipelines 

and other compressor stations that are 

under common ownership and control 

within a system, the complete system 

may exceed the reporting threshold and 

would be required to begin reporting. 

The EPA considered other reporting 

options for defining the facility and the 

level of reporting, but none of them 

would have achieved the same balance 

of geographically specific information 

and reduced industry burden as the 

proposed option. One option considered 

was using the definition of ‘‘facility’’ 

found in 40 CFR 98.6 that states, 

‘‘Facility means any physical property, 

plant, building, structure, source, or 

stationary equipment located on one or 

more contiguous or adjacent properties 

in actual physical contact or separated 

solely by a public roadway or other 

public right-of-way and under common 

ownership or common control, that 

emits or may emit any greenhouse gas. 

Operators of military installations may 

classify such installations as more than 

a single facility based on distinct and 

independent functional groupings 

within contiguous military properties.’’ 

This would mean that each piece of 

property (or adjacent properties under 

common ownership or common control) 

with gathering and boosting equipment 

that exceeded the 25,000 metric tons 

CO2e annual threshold would be 

considered its own ‘‘facility’’. This 

option provided limited data on the 

segment as a whole due to decreased 

coverage compared to other options, 

though more granular, site-specific data 

would likely be achievable for this 

option. This option would also require 

separate reports for each compressor 

station and/or gathering line, which 

would have resulted in a high reporting 

burden on owners/operators in this 

segment. Therefore, the EPA concluded 

that this option would not achieve the 

goals of having a thorough data set and 

transparent, complete information for 

this sector while minimizing burden to 

reporters. The EPA also considered an 

option that would have separated the 

gathering pipelines and gathering and 

boosting stations (e.g., facilities with 

compressors, dehydration, and acid gas 

removal) into different segments. The 

gathering and boosting stations would 

have reported at the basin level, and the 

pipelines at the national level (e.g. all 

gathering pipelines owned by a person 

or entity within the United States). 

However, the EPA is not proposing this 

option because it would have 

potentially resulted in higher burden to 

reporters by requiring reporting of 

additional facilities under their 

ownership. The EPA is seeking 

comment on whether these options 

should be considered and how they 

might achieve transparent and complete 

data for this segment without imposing 

additional burden on reporters 

compared to the proposed option. For 

more information regarding the options 

considered for defining the facility, see 

‘‘Greenhouse Gas Reporting Rule: 

Technical Support for 2015 Revisions 

and Confidentiality Determinations for 

Petroleum and Natural Gas Systems; 

Proposed Rule.’’ 

C. Natural Gas Transmission Lines 

Between Compressor Stations 

The EPA is proposing to add reporting 

requirements for emissions from natural 

gas transmission pipeline blowdowns 

between compressor stations in a new 

Onshore Natural Gas Transmission 

Pipeline segment. For purposes of the 

Onshore Natural Gas Transmission 

Pipeline segment, a blowdown is the 

release of gas from transmission 

pipelines for the purpose of reducing 

system pressure or complete 

depressurization. Transmission pipeline 

blowdowns occur when, a segment of 

pipeline is isolated from the rest of the 

line and the natural gas inside is purged 

through a blowdown vent stack. These 

blowdowns are needed to safely inspect 

and maintain the pipelines, but the 

purging of natural gas produces 

methane emissions that are currently 

not included in subpart W. In the U.S. 

GHG Inventory, the EPA estimated that 

there were over 300,000 miles of 

transmission pipelines in 2012, and the 

blowdown emissions associated with 

those pipelines were estimated to be 

85,000 metric tons of methane a year. 

Although subpart W does require 

reporting of emissions from onshore 

natural gas transmission compression 

stations, it currently does not cover 

onshore natural gas transmission 

pipelines in between compressor 

stations. This represents a gap in the 

coverage of emission sources from the 

petroleum and natural gas systems 

source category covered by subpart W. 

The EPA is proposing to define the 

onshore natural gas transmission 

pipeline owner or operator depending 

on whether the transmission pipeline is 

interstate or intrastate. For interstate 

pipelines, the onshore natural gas 

transmission pipeline owner or operator 

would be 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. For intrastate pipelines, the 

onshore natural gas transmission 

pipeline owner or operator would be 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). The Certificate of 

Public Convenience and Necessity is a 

certificate issued by the Federal Energy 

Regulatory Commission (FERC) that 

allows the pipeline company to engage 

in the transportation and/or sale for 

resale of natural gas in interstate 

commerce or to acquire and operate 

facilities needed to accomplish this. The 

certificate is issued by FERC after FERC 

has approved the construction of a 

pipeline, and it allows the holder to 

build and operate the pipeline. 

Operators of intrastate pipelines are 

required to prepare a Statement of 

Operating Conditions for compliance 

under section 311 of the NGPA. Section 

311 of the NGPA allows an interstate 

pipeline company to sell or transport 

gas on behalf of any intrastate pipeline 

or local distribution company without 

prior FERC approval. 

The EPA is proposing that the facility 

for the new Onshore Natural Gas 

Transmission Pipeline segment would 

be defined as 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 entity owned and 

operated multiple pipelines in the U.S., 

the facility would be considered the 

aggregate of those pipelines, even if they 

are not interconnected. In defining the 

facility, the EPA considered other 

options, such as the facility being the 

amount of pipeline owned and operated 

by an entity within a state or basin, or 

the facility being each separate pipeline. 

In considering these other options, the 

EPA had to take into account that many 

major pipeline systems are essentially 

linear systems to move gas from one 

part of the U.S. to another, and requiring 

reporters to file separate reports for each 

portion of the system in any one state 

or other defined geography would 

impose higher reporting burden on 

those subject to this source category 

without providing the EPA with 

additional, specific information. The 

EPA also took into account the fact that 

many entities own and operate pipeline 

segments that may not be directly 

interconnected, but are connected with 

pipelines owned and operated by other 

entities as part of the national network 

of natural gas transmission pipelines. 

The proposed approach limits the 

burden on reporters to correlate the 

pipeline ownership transfer points with 


rljohnson on DSK3VPTVN1PROD with PROPOSALS2
Federal Register / Vol. 79, No. 236 / Tuesday, December 9, 2014 / Proposed Rules 73157 

6The 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. 

7American Petroleum Institute. The API Well 

Number and Standard State And County Numeric 

Codes Including Offshore Waters. API Bulletin 

D12A, January 1979. Available at http://

wellidentification.org/dl/US_API_Bulliten_

1979.pdf. 

8The 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. 

specific geographical segments. Instead, 

the reporters can track the required 

information for their various pipelines, 

regardless of location, and submit data 

associated with all of them in one 

report. 

The EPA is proposing that reporters 

would use the methods in 40 CFR 

98.233(i) to calculate or measure 

emissions from pipeline blowdown 

events. 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. This method uses 

information that should be readily 

available to the reporter (e.g., pipeline 

length, diameter, and operating 

pressure) and so should not be overly 

burdensome. 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 would calculate 

both methane and carbon dioxide (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). In addition to the total 

annual emissions of methane and CO2, 

natural gas transmission pipeline 

reporters would also report the methane 

and CO2 emissions and location of each 

blowdown event. 

The EPA previously considered 

fugitive emissions that result from leaks 

in transmission pipelines in the reproposal 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 notes that 

larger fugitive leaks are currently 

reported to the U.S. Department of 

Transportation’s Pipeline and 

Hazardous Materials Safety 

Administration as part of 49 CFR 191.3. 

Under this provision, any pipeline 

incident that results in unintentional 

gas loss of three million cubic feet or 

more must be reported. Therefore, the 

EPA is not proposing to include 

reporting requirements for fugitive 

emissions from transmission pipeline 

leaks. 

The EPA also considered adding 

blowdowns between compressor 

stations on natural gas transmission 

pipelines to the Onshore Natural Gas 

Transmission Compression segment, 

which is already a reporting segment 

under subpart W, instead of creating a 

new segment. However, the Onshore 

Natural Gas Transmission Compression 

segment currently uses the same 

definition of facility as found in 40 CFR 

98.6 and the natural gas transmission 

pipelines that surround a compressor 

station might not be compatible with 

that definition of ‘‘facility’’ because they 

would likely not be under common 

ownership or control with the adjacent 

compressor station(s). Therefore, 

keeping the definition of facility found 

in 40 CFR 98.6 for this proposed new 

segment would result in a higher 

reporting burden on pipeline owners/

operators with a number of noncontiguous pipelines in the U.S. 

compared to the proposed option, 

because these owners/operators would 

have to submit individual reports for 

each pipeline they owned or operated. 

The proposed option simplifies 

reporting for this source by allowing 

each owner/operator to submit one 

report for all their transmission 

pipelines. 

D. Well Identification Numbers 

The EPA is proposing to amend 40 

CFR 98.236 to add reporting 

requirements for well identification 

numbers to improve data quality by 

enabling identification of wells. If 

finalized, these reporting requirements 

would be reported for the first time in 

the report covering the year in which 

the rule is made effective (e.g., if the 

final rule is effective January 1, 2016, 

then the reports covering 2016 data 

would be the first to include well 

identification numbers). Reporting of 

well identification numbers for previous 

years (e.g., 2012) is not being proposed 

by the EPA. 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).6 For any well that does 

not already have a US Well Number, the 

reporter would be required to provide 

the unique well number assigned by the 

permitting authority for drilling of oil 

and gas wells. US Well Numbers are 

required for wells in almost all states 

covered in the Onshore Petroleum and 

Natural Gas Production segment and are 

generally reported in relevant onshore 

production permitting documentation. 

This would allow the EPA to link the 

GHGRP data to other 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. Being able to match the 

GHGRP data to other data sources 

would 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 would 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. 

Since 1966, almost all U.S. oil and gas 

wells have been assigned a unique and 

permanent API Well Number in 

accordance with American Petroleum 

Institute (API)’s specification in Bulletin 

D12A.7 The API Well Number was 

established to allow regulators to track 

drilling permits, collect royalties, and 

optimize field conservation. API 

transferred ownership of the well 

numbering specification to the 

Professional Petroleum Data 

Management (PPDM) Association in 

2010. The PPDM Association issued an 

updated specification in May 2013 and 

then renamed the identifier as the US 

Well Number in June 2014.8 The PPDM 

Association is working with state 

regulatory agencies to implement the 

2013 updates, but adoption is at the 

discretion of the agency. State agencies 

that elect not to use the US Well 

Number have assigned unique well 

identification numbers to the gas and oil 

wells in that state for tracking in their 

regulatory databases. US Well Numbers 

and other well identification numbers 

are publically available, but the 

accessibility of the data varies from state 

to state. Reporters in the Onshore 

Petroleum and Natural Gas Production 

segment already track and maintain 

records by well identification number 

for other regulatory and reporting 

purposes. 

The EPA is proposing to require the 

reporting of well identification numbers 

for the Onshore Petroleum and Natural 

Gas Production segment in two general 

cases. First, the EPA proposes to require 

reporters in the Onshore Petroleum and 


rljohnson on DSK3VPTVN1PROD with PROPOSALS2
73158 Federal Register / Vol. 79, No. 236 / Tuesday, December 9, 2014 / Proposed Rules 

9Allen, D.T. et al. Measurements of methane 

emissions at natural gas production sites in the 

United States, Proceedings of the National 

Academy of Sciences of the United States of 

America, 110(44): 17768–17773, 2013. 

10EPA Handbook: Optical Remote Sensing for 

Measurement and Monitoring of Emissions Flux, 

http://www.epa.gov/ttnemc01/guidlnd/gd-052.pdf. 

Natural Gas Production segment to 

report a list of well identification 

numbers associated with different 

emission sources for all wells in a subbasin included in the reported 

emissions data. Reporting the well 

identification numbers associated with 

different emission sources for each subbasin would allow the EPA to determine 

completeness of reporting by evaluating 

the coverage of current reporting 

requirements and identifying potential 

cases of under-reporting by comparing 

lists of reported well identification 

numbers to lists of well identification 

numbers from state agencies. The EPA 

expects that this would present a low 

burden to reporters because reporters 

should already track and maintain well 

identification numbers. The EPA 

expects that most reporters track and 

maintain sub-basins for each well 

identification number. If a reporter does 

not, they can use the state code and 

county code portions of the US Well 

Number to identify the sub-basin. 

Second, 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 EPA proposes to require 

the reporter to report the well 

identification number for which those 

measurements were made, or for which 

the equipment is associated. Reporting 

the well identification numbers for 

input data based on measurements at a 

sample of wells would allow the EPA to 

compare GHGRP data to data from other 

wells in the same basin or sub-basin to 

evaluate whether the measurements 

were likely representative of all wells in 

the basin or sub-basin. The EPA expects 

that this would present a low burden to 

reporters because reporters should 

already track and maintain well 

identification numbers associated with 

measurements used for the GHGRP 

input data. 

Where emissions are reported for 

equipment that is on or associated with 

a single well pad, (e.g., dehydrators, 

acid gas removal units), providing the 

well identification number(s) for the 

associated well(s) would also allow the 

EPA to compare the data that are used 

as inputs for estimating emissions to the 

data available from the well(s) to verify 

those data. The EPA expects that this 

would also present a low burden to 

reporters because reporters already have 

to make a determination of whether the 

equipment is on or associated with a 

single well pad, and would simply need 

to note and maintain the well 

identification number(s) for that 

associated piece of equipment. 

E. Advanced Innovative Monitoring 

Methods 

As oil and gas operations seek to 

capitalize on advances in measurement 

and monitoring technology in 

optimizing process operations and 

reducing fugitive emissions from 

process equipment leaks, opportunities 

will arise for facilities to use innovative 

technologies to gather real-time, 

continuous emissions data from area 

and point sources. For example, optical 

remote sensing techniques have existed 

for many years but recent technological 

advances have allowed these devices to 

be used in the field (e.g., for fence line 

monitoring) to provide reliable 

measurements of gas concentrations, 

including methane, in the ambient air at 

the relevant detection limits.9 10

The EPA 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. The EPA’s 

objective for this assessment is to 

determine if new and innovative 

technologies could be applied to the 

GHGRP to improve the overall accuracy 

and transparency of reported data in a 

cost-effective way while still meeting 

the overall objectives of Part 98. While 

the EPA is not proposing to incorporate 

these technologies into subpart W in 

this action, the EPA is requesting 

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. 

In particular, the EPA is soliciting data 

and case studies that could provide 

information regarding the benefits, 

costs, and potential problem areas, 

including consistency among reporters 

and the feasibility of verifying 

emissions, associated with using 

advanced innovative monitoring 

methods for providing emissions 

measurements in the oil and natural gas 

sector, including the provision of realtime or continuous measurements. 

Additionally, we are seeking 

comment on the EPA’s memorandum on 

alternative and innovative measurement 

or monitoring technologies (see 

‘‘Discussion Paper on Potential 

Implementation of Alternative 

Monitoring under the GHGRP’’ in 

Docket ID No. EPA–HQ–OAR–2014– 

0831). 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. 

F. Best Available Monitoring Methods 

The EPA is proposing that facilities 

will be allowed to use BAMM for the 

proposed amendments for the 2016 

reporting year for only the new industry 

segments and emission sources 

included in this proposal. 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. This proposal would allow 

reporters to use best available methods 

to estimate inputs to emission equations 

for the newly proposed emission 

sources using their best engineering 

judgment for cases where the 

monitoring of these inputs would not be 

possible beginning on January 1, 2016. 

The EPA is not proposing to allow the 

use of BAMM for the proposed reporting 

of well identification numbers because 

reporters should already have well 

identification numbers readily available 

for all wells and associated equipment 

to which this proposed reporting 

requirement would apply. 

These reporters have the option of 

using BAMM from January 1, 2016, to 

March 31, 2016, without seeking prior 

EPA approval for certain parameters 

that cannot reasonably be measured 

according to the monitoring and QA/QC 

requirements of 40 CFR 98.234. 

Reporters would also have the 

opportunity to request an extension for 

the use of BAMM beyond March 31, 

2016; those owners or operators would 

submit a request to the Administrator by 

January 31, 2016. This additional time 

for reporters to comply with the 

monitoring methods for new emission 

sources in subpart W would allow 

facilities to install the necessary 

monitoring equipment during other 

planned (or unplanned) process unit 

downtime, thus avoiding process 

interruptions. 

The EPA is not proposing to allow the 

use of BAMM beyond 2016 and does not 

anticipate that BAMM would be needed 

beyond 2016 for the new segments and 


rljohnson on DSK3VPTVN1PROD with PROPOSALS2
Federal Register / Vol. 79, No. 236 / Tuesday, December 9, 2014 / Proposed Rules 73159 

11 Direct emitter data categories that meet the 

definition of ‘‘emission data’’ in 40 CFR 2.301(a) are 

‘‘Facility and Unit Identifier Information,’’ 

‘‘Emissions,’’ ‘‘Calculation Methodology and 

Methodological Tier,’’ and ‘‘Data Elements Reported 

for Periods of Missing Data that are not Inputs to 

Emission Equations.’’ 12Revisions to Reporting and Recordkeeping 

Requirements, and Confidentiality Determinations 

Under the Greenhouse Gas Reporting Program; 

Final Rule. (79 FR 63750, October 24, 2014). 

emissions sources being proposed in 

this rule. 

III. Proposed Confidentiality 

Determinations 

A. Overview and Background 

In this proposed rule, we are 

proposing confidentiality 

determinations for 171 data elements 

proposed to be reported by the 

following segments: Onshore Petroleum 

and Natural Gas Production, Onshore 

Petroleum and Natural Gas Gathering 

and Boosting, and Onshore Natural Gas 

Transmission Pipeline. These data 

elements include new reporting 

requirements for existing sources 

already reporting under subpart W as 

well as new reporting requirements that 

would be reported by additional 

industry segments or sources under 

these proposed amendments. 

The final confidentiality 

determinations the EPA has previously 

made for the remainder of the subpart 

W data elements are unaffected by the 

proposed amendments and continue to 

apply. For information on 

confidentiality determinations for the 

GHGRP and subpart W data elements, 

see: 75 FR 39094, July 7, 2010; 76 FR 

30782, May 26, 2011; 77 FR 48072, 

August 13, 2012; 79 FR 63750, October 

24, 2014. These proposed 

confidentiality determinations would be 

finalized after considering public 

comment. The EPA plans to finalize 

these determinations at the same time 

the proposed rule amendments 

described in this action are finalized. 

B. Approach to Proposed CBI 

Determinations 

With the exception of the specific 

data elements addressed in Section III.D 

of this preamble, we are applying the 

same approach as previously used for 

making confidentiality determinations 

for data elements reported under the 

GHGRP. In the ‘‘Confidentiality 

Determinations for Data Required Under 

the Mandatory Greenhouse Gas 

Reporting Rule and Amendments to 

Special Rules Governing Certain 

Information Obtained Under the Clean 

Air Act’’ (hereafter referred to as ‘‘2011 

Final CBI Rule’’) (76 FR 30782, May 26, 

2011), the EPA grouped Part 98 data 

elements into 22 data categories (11 

direct emitter data categories and 11 

supplier data categories) with each of 

the 22 data categories containing data 

elements that are similar in type or 

characteristics. The EPA then made 

categorical confidentiality 

determinations for eight direct emitter 

data categories and eight supplier data 

categories and applied the categorical 

confidentiality determination to all data 

elements assigned to the category. Of 

these data categories with categorical 

determinations, the EPA determined 

that four direct emitter data categories 

are comprised of those data elements 

that meet the definition of ‘‘emissions 

data,’’ as defined at 40 CFR 2.301(a), 

and that, therefore, are not entitled to 

confidential treatment under section 

114(c) of the CAA.11 The EPA 

determined that the other four direct 

emitter data categories and the eight 

supplier data categories do not meet the 

definition of ‘‘emission data.’’ For these 

data categories that are determined not 

to be emission data, the EPA determined 

categorically that data in three direct 

emitter data categories and five supplier 

data categories are eligible for 

confidential treatment as CBI, and that 

the data in one direct emitter data 

category and three supplier data 

categories are ineligible for confidential 

treatment as CBI. For two direct emitter 

data categories, ‘‘Unit/Process ‘Static’ 

Characteristics that Are Not Inputs to 

Emission Equations’’ and ‘‘Unit/Process 

Operating Characteristics that Are Not 

Inputs to Emission Equations,’’ and 

three supplier data categories, ‘‘GHGs 

Reported,’’ ‘‘Production/Throughput 

Quantities and Composition,’’ and 

‘‘Unit/Process Operating 

Characteristics,’’ the EPA determined in 

the 2011 Final CBI Rule that the data 

elements assigned to those categories 

are not emission data, but the EPA did 

not make categorical CBI determinations 

for them. Rather, the EPA made CBI 

determinations for each individual data 

element included in those categories on 

a case-by-case basis taking into 

consideration the criteria in 40 CFR 

2.208. No final confidentiality 

determination was made for the inputs 

to emission equation data category (a 

direct emitter data category) in the 2011 

Final CBI Rule. However, the EPA has 

since proposed and finalized an 

approach for addressing disclosure 

concerns associated with inputs to 

emissions equations.12

For this rulemaking, we are proposing 

to assign 165 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. 

Note that subpart W is a direct emitter 

source category, thus, no data are 

assigned to any supplier data categories. 

For data elements the EPA has 

assigned in this proposed action to a 

direct emitter category with a 

categorical determination, the EPA is 

proposing that the categorical 

determination for the category be 

applied to the proposed new data 

element. For the proposed categorical 

assignment of the data elements in these 

eight categories with categorical 

determinations, see the memorandum 

‘‘Data Category Assignments and 

Confidentiality Determinations for All 

Data Elements (excluding inputs to 

emission equations) in the Proposed 

‘2015 Revisions and Confidentiality 

Determinations for Petroleum and 

Natural Gas Systems’ ’’ in Docket ID No. 

EPA–HQ–OAR–2014–0831. 

For data elements assigned to the 

‘‘Unit/Process ‘Static’ Characteristics 

that Are Not Inputs to Emission 

Equations’’ and ‘‘Unit/Process Operating 

Characteristics that Are Not Inputs to 

Emission Equations,’’ we are proposing 

confidentiality determinations on a 

case-by-case basis taking into 

consideration the criteria in 40 CFR 

2.208, consistent with the approach 

used for data elements previously 

assigned to these two data categories. 

For the proposed categorical assignment 

of these data elements, see the 

memorandum ‘‘Data Category 

Assignments and Confidentiality 

Determinations for All Data Elements 

(excluding inputs to emission 

equations) in the Proposed ‘2015 

Revisions and Confidentiality 

Determinations for Petroleum and 

Natural Gas Systems’ ’’ in Docket ID No. 

EPA–HQ–OAR–2014–0831. For the 

results of our case-by-case evaluation of 

these data elements, see Sections III.C 

and III.D of this preamble. 

In addition to the individual data 

element determinations described above 

and for the reasons stated below, we are 

proposing individual confidentiality 

determinations for six new data 

elements without making a data 

category assignment. In the 2011 Final 

CBI rule, although the EPA grouped 

similar data into categories and made 

categorical confidentiality 

determinations for a number of data 

categories, the EPA also recognized that 

similar data elements may not always 

have the same confidentiality status, in 

which case the EPA made individual 

instead of categorical determinations for 

the data elements within such data 


rljohnson on DSK3VPTVN1PROD with PROPOSALS2
73160 Federal Register / Vol. 79, No. 236 / Tuesday, December 9, 2014 / Proposed Rules 

13 In the 2011 Final CBI rule, several data 

categories include both CBI and non-CBI data 

elements. See 76 FR 30786. 

14See the ‘‘Change to the Reporting Date for 

Certain Data Elements Required Under the 

Mandatory Reporting of Greenhouse Gases Rule’’ 

(hereinafter referred to as the ‘‘Final Deferral 

Notice’’) (76 FR 53057, August 25, 2011) and the 

accompanying memorandum entitled ‘‘Process for 

Evaluating and Potentially Amending Part 98 Inputs 

to Emission Equations’’ (Docket ID EPA–HQ–OAR– 

2010–0929). 

15See the memoranda titled ‘‘Summary of Data 

Collected to Support Determination of Public 

Availability of Inputs to Emission Equations for 

which Reporting was Deferred to March 31, 2015’’ 

and ‘‘Evaluation of Competitive Harm from 

Disclosure of Inputs to Equations Data Elements 

Deferred to March 31, 2015.’’ (Docket ID EPA–HQ– 

OAR–2010–0929). 

categories.13 Similarly, while the six 

proposed new data elements are similar 

in type or certain characteristics to data 

elements previously assigned to the 

‘‘Production/Throughput Data Not Used 

as Input’’ and ‘‘Raw Materials 

Consumed that are Not Inputs to 

Emission Equations’’ data categories, we 

do not believe that they share the same 

confidentiality status as the non-subpart 

W data elements already assigned to 

those two data categories, which the 

EPA has determined categorically to be 

CBI based on the data elements assigned 

to those categories at the time of the 

2011 Final CBI Rule. As discussed in 

more detail below, our review showed 

that these six subpart W production and 

throughput-related data elements fail to 

qualify for confidential treatment. 

Therefore, we do not believe that the 

categorical determinations for the 

‘‘Production/Throughput Data Not Used 

as Input’’ and ‘‘Raw Materials 

Consumed that are Not Inputs to 

Emission Equations’’ data categories are 

appropriate for these six data elements; 

accordingly, these data elements should 

not be assigned to these data categories. 

Not assigning these six data elements to 

these two data categories would also 

leave unaffected the existing categorical 

determinations for these data categories, 

which remain valid and applicable to 

the data elements assigned to those data 

categories. For the reasons stated above, 

we are proposing individual 

confidentiality determinations for these 

six data elements without making 

categorical assignment. 

Our proposed individual 

determinations follow the same two step 

evaluation process as set forth in the 

2011 Final CBI Rule and subsequent 

confidentiality determinations for Part 

98 data. Specifically, we first 

determined whether the data element 

meets the definition of emission data in 

40 CFR 2.301(a). Data elements that 

meet the definition of emission data are 

required to be released under section 

114 of the CAA. For data elements 

found to not meet the definition of 

emission data, we evaluated whether a 

data element meets the criteria in 40 

CFR 2.208 for confidential treatment. In 

particular, we focus on: (1) Whether the 

data are already public; and (2) whether 

‘‘. . . disclosure of the information is 

likely to cause substantial harm to the 

business’s competitive position.’’ For 

the results of our case-by-case 

evaluation of these six proposed subpart 

W data elements, see Section III.D of 

this preamble. 

We are also proposing to assign 65 

additional data elements used to 

calculate GHG emissions in subpart W 

for the Onshore Petroleum and Natural 

Gas Gathering and Boosting segment, 

Onshore Natural Gas Transmission 

Pipeline segment, and for emissions 

from oil wells with hydraulic fracturing 

to the ‘‘Input to Emission Equation’’ 

data category. We are not proposing a 

confidentiality determination for this 

data category. The majority of these data 

elements are existing data elements in 

subpart W that would be applied to the 

new Onshore Petroleum and Natural 

Gas Gathering and Boosting segment 

and Onshore Natural Gas Transmission 

Pipeline segment. Some of the data 

elements are new data elements that are 

used as inputs to proposed Equation W– 

12C. Due to concerns expressed by 

reporters with the potential release of 

inputs to emission equations, we 

previously established a process for 

evaluating ‘‘inputs to emission 

equation’’ data elements to identify 

potential disclosure concerns and 

actions to address such concerns if 

appropriate.14 The EPA has used this 

process to evaluate inputs to emission 

equations, including the subpart W data 

elements that are already assigned to the 

inputs to emission equations data 

category.15 We performed a similar 

evaluation for the 67 subpart W inputs 

to emission equations when they are 

applied to the Onshore Petroleum and 

Natural Gas Gathering and Boosting 

segment, Onshore Natural Gas 

Transmission Pipeline segment, and for 

calculating emissions from oil wells 

with hydraulic fracturing. 

For the Onshore Natural Gas 

Transmission Pipeline segment, the EPA 

did not identify any potential disclosure 

concerns with the data elements that are 

inputs to emissions equations. 

Accordingly, the proposal would 

require reporting of these data elements 

by March 31, 2017, which is the 

reporting deadline for the 2016 

reporting year. 

For calculating emissions from oil 

wells with hydraulic fracturing, the EPA 

did not identify any disclosure 

concerns, except when the oil wells to 

which those inputs to emission 

equations apply meet the definition of 

either ‘‘wildcat well’’ or ‘‘delineation 

well.’’ ‘‘Delineation well’’ is defined as 

‘‘a well drilled in order to determine the 

boundary of a field or producing 

reservoir.’’ ‘‘Wildcat well’’ is defined as 

‘‘a well outside known fields or the first 

well drilled in an oil or gas field where 

no other oil and gas production exists.’’ 

As noted in a previous rulemaking (79 

FR 63750, October 24, 2014), the early 

public disclosure of certain data 

elements that are inputs for these two 

specific well definitions could reveal 

data on well productivity that could 

give competitors an advantage by giving 

them information on new fields or new 

areas of existing fields without having to 

drill their own wildcat or delineation 

wells. This could result in the loss of 

investment value for certain reporters. 

For wildcat and delineation wells, the 

EPA is proposing to allow reporters to 

delay reporting of these data elements 

for 2 years, as currently allowed for gas 

wells with hydraulic fracturing that 

meet the definition of either ‘‘wildcat 

well’’ or ‘‘delineation well’’, because a 

2-year delay of reporting is sufficient to 

prevent early public disclosure of these 

data and will provide sufficient time for 

a reporter to thoroughly conduct an 

assessment of the well. The specific 

proposed data elements impacted are: 

(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 (§ 98.236(g)(5)(i)); (2) the 

cumulative flowback time, in hours, for 

each sub-basin, after sufficient 

quantities of gas are present to enable 

separation (§ 98.236(g)(5)(i)); (3) the 

measured flowback rate, in standard 

cubic feet per hour, for each sub-basin 

(§ 98.236(g)(5)(ii)); and (4) the total 

annual gas-liquid separator oil volume 

that is sent to applicable onshore storage 

tanks, in barrels (§ 98.236(j)(1)(v)). 

In addition to the data elements that 

are inputs to emission equations for 

wildcat and delineation wells, the EPA 

has further determined that one other 

proposed data element related to these 

two specific types of wells may have 

early disclosure concerns due to the 

reasons stated above. Therefore, in order 

to treat all early disclosure concerns 

related to exploratory wells consistently 

throughout subpart W, the EPA is 

proposing to allow reporters to delay 

reporting for this data element for 2 

years as well. The EPA is also proposing 

a confidentiality determination for this 

data element, found in Table 3 of this 


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Federal Register / Vol. 79, No. 236 / Tuesday, December 9, 2014 / Proposed Rules 73161 

preamble, which would apply once the 

data element is reported to the EPA 

following the 2-year delay. The specific 

proposed data element impacted is: The 

total annual oil throughput that is sent 

to all atmospheric tanks, in barrels 

(§ 98.236(j)(2)(i)(A)). Other data 

elements related to delineation or 

wildcat wells that are not proposed to 

be amended in this action have been 

addressed in a previous rulemaking (79 

FR 70352, November 25, 2014). 

For calculating emissions from 

sources in the Onshore Petroleum and 

Natural Gas Gathering and Boosting 

segment, the EPA did not identify any 

disclosure concerns. The Onshore 

Petroleum and Natural Gas Gathering 

and Boosting segment would be a 

regionally concentrated segment, with 

gathering lines and other services 

located in fixed geological basins. 

Because of the amount of fixed assets 

required to operate in this segment (e.g., 

gathering lines and boosting stations), 

companies operating in this segment 

enter into long term agreements with 

natural gas producers to gather natural 

gas and transport it to natural gas 

processing facilities or, in some cases, 

transmission pipelines. These 

agreements are for long periods, lasting 

from several years to the life of the lease 

for the producing wells, and establish 

the prices for gathering services for the 

life of the agreement. Once these 

agreements are established, information 

that would be revealed from the ‘‘inputs 

to emissions equations’’ is not likely to 

affect the competitive position of the 

company operating the gathering and 

boosting system because it will not 

reveal information about the cost or 

profitability of providing that gathering 

service, or about the company’s ability 

to enter into new agreements and 

expand operations. As a result, the 

‘‘inputs to equations’’ data elements in 

this segment would not be likely to 

reveal any proprietary information 

about the facility or cost to do business. 

For the list of new subpart W inputs 

to emission equations and the results of 

our evaluation, see the memorandum, 

‘‘Review for Potential Disclosure 

Concerns for Inputs to Emission 

Equations Affected by the Proposed 

‘2015 Revisions and Confidentiality 

Determinations for Petroleum and 

Natural Gas Systems’ ’’ in Docket ID No. 

EPA–HQ–OAR–2014–0831. 

C. Proposed Confidentiality 

Determinations for Data Elements 

Assigned to the ‘‘Unit/Process ‘Static’ 

Characteristics That Are Not Inputs to 

Emission Equations’’ and ‘‘Unit/Process 

Operating Characteristics That Are Not 

Inputs to Emission Equations’’ Data 

Categories 

The EPA is proposing that 36 data 

elements for subpart W that have been 

assigned to the ‘‘Unit/Process Operating 

Characteristics That Are Not Inputs to 

Emission Equations’’ data category or 

the ‘‘Unit/Process ‘Static’ Characteristics 

That Are Not Inputs to Emission 

Equations’’ data category would be 

reported for sources in the proposed 

Onshore Petroleum and Natural Gas 

Gathering and Boosting segment, the 

Onshore Natural Gas Transmission 

Pipeline segment, or for onshore natural 

petroleum and natural gas production 

facilities that report emissions from oil 

wells with hydraulic fracturing. The 

data elements were assigned to these 

two categories in earlier EPA actions (77 

FR 48072, August 13, 2012; and 79 FR 

70352, November 25, 2014). We are 

proposing confidentiality 

determinations for these data elements 

when applied to these new emission 

sources based on the approach set forth 

in the 2011 Final CBI Rule for data 

elements assigned to these two data 

categories. In that rule, the EPA 

determined categorically that data 

elements assigned to these two data 

categories do not meet the definition of 

emission data in 40 CFR 2.301(a); the 

EPA then made individual, instead of 

categorical, confidentiality 

determinations for these data elements. 

As with all other data elements 

assigned to these two categories, the 

EPA concluded that the proposed new 

data elements do not meet the definition 

of emissions data in 40 CFR 2.301(a). 

The EPA then considered the 

confidentiality criteria at 40 CFR 2.208 

in making our proposed confidentiality 

determinations. Specifically, we focused 

on whether the data are already publicly 

available from other sources and, if not, 

whether disclosure of the data is likely 

to cause substantial harm to the 

business’ competitive position. Table 2 

of this preamble lists the data elements 

assigned to the ‘‘Unit/Process Operating 

Characteristics That Are Not Inputs to 

Emission Equations’’ and ‘‘Unit/Process 

‘Static’ Characteristics That Are Not 

Inputs to Emission Equations’’ data 

categories, the proposed confidentiality 

determination for each data element, 

and our rationale for each determination 

as they would apply to the Onshore 

Petroleum and Natural Gas Gathering 

and Boosting segment or for oil wells 

with hydraulic fracturing in the 

Onshore Petroleum and Natural Gas 

Production segment. 

For the existing data elements 

previously 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’’ that would be reported by 

the newly proposed Onshore Petroleum 

and Natural Gas Gathering and Boosting 

segment, the Onshore Natural Gas 

Transmission Pipeline segment, or for 

oil wells with hydraulic fracturing, we 

are proposing confidentiality 

determinations based on a new case-bycase evaluation of the data elements, 

taking into consideration the 

characteristics of the new reporters that 

would be required to report these data 

elements by the proposed amendments. 

Because these data elements do not 

meet the definition of emissions data in 

40 CFR 2.301(a), the EPA used the 

criteria at 40 CFR 2.208 in making our 

proposed confidentiality 

determinations. Specifically, we focused 

on whether the data are already publicly 

available from other sources and, if not, 

whether disclosure of the data is likely 

to cause substantial harm to the 

business’ competitive position. Table 2 

of this preamble lists the data elements 

by data category, the proposed 

confidentiality determination for each 

data element, and our rationale for each 

determination. 


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Table 2. Proposed Confidentiality for Data Elements Assigned to the "Unit/Process Operating Characteristics That 

Are Not Inputs to Emission Equations" and "Unit/Process 'Static' Characteristics That Are Not Inputs to Emission 

Equations" Data Categories 

Proposed Confidentiality Determination 

Citation Data Element and Rationale 

"Unit/Process Ouerating Characteristics That Are Not Inuuts to Emission Eguations" Data Category 

98.236( d)(l )(v) Whether any C02 emissions This proposed data element would be 

from the acid gas removal unit reported by onshore petroleum and natural 

are recovered and transferred gas gathering and boosting facilities. This 

outside the facility. data element indicates that a facility is 

operating an acid gas removal unit and 

indicates how the facility handles the C02 

emissions it generates. Acid gas removal units 

are used to remove C02 and hydrogen sulfide 

from raw natural gas streams and are 

commonly found at compressor stations in 

gathering and boosting systems, and at natural 

gas processing facilities. These units are listed 

in a facility's construction and operating 

permits, which are publicly available. 

Because this information is routinely 

available through required pennits, we 

propose these data elements be designated as 

"not CBI." 

98.236( e )(1 )(xvi) Whether any dehydrator These proposed data elements would be 

emissions are vented to a vapor reported by onshore petroleum and natural 

recovery device. gas gathering and boosting facilities. These 

98.236( e )(1 )(xvii) Whether any dehydrator data elements indicate that a facility is 

emissions are vented to a flare or equipped with dehydration units, the number 

regenerator firebox/fire tubes. of dehydrators used, the design of dehydrator 

98.236( e )(1 )(xviii) For each glycol dehydrator with used (glycol or desiccant), and how emissions 

from dehydration units are handled by the 

an annual average daily natural facility. Dehydration units are used to remove 

gas throughput greater than or water from natural gas streams and are equal to 0.4 MMscfd, whether commonly found at compressor stations in 

any dehydrator emissions are gathering and boosting systems, and at natural vented to the atmosphere gas processing facilities. Because they are a without being routed to a flare or 

source of hazardous air pollutants, these units 

regenerator firebox/fire tubes. 

are subject to rigorous emissions control 

98.236( e )(2)(iii) For glycol dehydrators with an requirements(~, 40 CFR part 63, subpart 

annual average daily natural gas HH). Dehydration units and their associated 

throughput less than 0.4 control devices are listed in a facility's 

MMscfd, whether any the total construction and operating permits, which are 

number of dehydrators were publicly available. For this reason, we 

venting to a vapor recovery propose these data elements be designated as 

device. "not CBI" for onshore petroleum and natural 

98.236( e )(2)(iv) For glycol dehydrators with an gas gathering and boosting facilities. 

annual average daily natural gas 

throughput less than 0.4 

MMscfd, the number of 

dehydrators venting to a control 

device other than a vapor 
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Proposed Confidentiality Determination 

Citation Data Element and Rationale 

recovery device or a flare or 

regenerator firebox/fire tubes. 

98.236(c)(2)(v) For glycol dehydrators with an 

annual average daily natural gas 

throughput less than 0.4 

MMscfd, whether any 

dehydrator emissions were 

vented to a flare or regenerator 

firebox/fire tubes. 

98.236( e)(2)(v)(A) For glycol dehydrators with an 

annual average daily natural gas 

throughput less than 0.4 MMscfd 

and vented to a flare or 

regenerator firebox, the total 

number of dehydrators 

98.236( e )(3)(i) For dehydrators that use 

desiccant, the total number of 

dehydrators at the facility. 

98.236(e)(3)(i) For dehydrators that use 

desiccant, the total number of 

dehydrators venting to a vapor 

recovery device. 

98.236( e )(3)(i) For dehydrators that use 

desiccant, the number of 

dehydrators venting to a control 

device other than a vapor 

recovery device or a flare or 

regenerator firebox/fire tubes. 

98.236( e )(3)(i) For dehydrators that use 

desiccant and vent to a flare or 

regenerator firebox, the total 

number of dehydrators. 

98.236(e)(3)(i) For dehydrators that use 

desiccant and vent to a flare or 

regenerator firebox, the total 

number of dehydrators. 

98.236(g) Whether the facility had any oil These proposed data elements would be 

well completions or workovers reported by onshore petroleum and natural 

with hydraulic fracturing in the gas production facilities and provide 

calendar year. infotmation on whether the facility conducted 

98.236(g)(3) For each oil well completion or any oil well completions or workovers during 

workovcr and well type the reporting year, and for those facilities that 

combination, the total number of had well completions and/or workovers, the 

completions or workovers with number of completions and work overs that 

hydraulic fracturing. were completed and the cumulative flowback 

98.236(g)(5)(i) If you used Equation W-lOA to 

time. Infom1ation on the number of 

completions and workovers perfom1ed by an calculate annual volumetric total oil and gas operator in a given year and the 

gas emissions for multiple wells, 
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Proposed Confidentiality Determination 

Citation Data Element and Rationale 

the cumulative gas flowback age and production rates for wells can be 

time, in hours, for each sub- derived from or is available publicly on state 

basin, from when gas is first oil and gas commission Web sites. 

detected until sufficient Infonnation on the flowback time would be 

quantities are present to enable aggregated across multiple oil wells in a subseparation ("Tr/' in Equation W- basin. Because disclosure of these data 

lOA). elements would not be likely to cause 

98.236(g)(5)(i) If you used Equation W-lOA to substantial competitive harm, we propose 

calculate annual volumetric total these data elements be designated as "not 

gas emissions for multiple wells, CBI." 

the cumulative flowback time, in 

hours, for each sub-basin, after 

sufficient quantities of gas are 

present to enable separation 

("Tr.s" in Equation W-1 OA). 

98.236(i)(l)(i) If you calculated emissions from This proposed data element would be 

blowdown vent stacks by reported by onshore petroleum and natural 

equipment or event type, the gas gathering and boosting facilities and 

total number ofblowdowns in natural gas transmission pipeline facilities. 

the calendar year for the Blowdowns occur when equipment is taken 

equipment or event type (the out of service, either to be placed on standby 

sum of equation variable "N" or for maintenance purposes, and the natural 

from Equation W-14A or gas in the equipment is typically released to 

Equation W-14B of this subpart, the atmosphere. This practice may occur as 

for all unique physical volumes part of a routine scheduled maintenance or as 

for the equipment or event type). the result of an un-planned event (~, 

equipment breakdown). Although blowdown 

events may be associated with periods of 

reduced production or throughput, onshore 

petroleum and natural gas gathering and 

boosting facilities and natural gas 

transmission pipeline facilities typically have 

backup units that can be used to avoid 

production shutdowns. Hence, the number of 

blowdown events that occur during a 

reporting year does not indicate a plant was 

shut down and would not provide any 

potentially sensitive infonnation on the 

impact of such events on a facility's 

production or throughput. Hence, the 

disclosure of the number ofblowdowns 

occurring during a reporting year is not likely 

to cause substantial competitive harm. For 

this reason, we propose that this data element 

be designated "not CBI." 

98.236G) If any of the atmospheric tanks These proposed data elements would be 

are observed to have reported by onshore petroleum and natural 

malfunctioning dump valves, gas gathering and boosting facilities and 

indicate that dump valves were provide information on malfunctioning of 

malfunctioning. dump valves on gas-liquid separators. 
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Proposed Confidentiality Determination 

Citation Data Element and Rationale 

98.236(j)(3)(i) If any of the gas-liquid separator Separators are used to separate hydrocarbons 

liquid dump valves did not close into liquid and gas phases and are typically 

properly during the reporting connected to atmospheric storage tanks where 

year, the total number of gas- the hydrocarbon liquids are stored. Dump 

liquid separators whose liquid valves on separators periodically release 

dump valves did not close I iquids from the separator. The time period 

properly during the calendar during which a dump valve is malfunctioning 

year. provides little insight into maintenance 

98.236(j)(3 )(ii) If dump valves on multiple gas- practices or the nature or cost of repairs that 

liquid separators in a sub-basin are needed. Therefore, release of this 

did not close properly, the total information would not be likely to cause 

time the dump valves on gassubstantial competitive harm to reporters. For 

liquid separators did not close this reason, we are proposing these data 

properly in the calendar year, in elements be designated as "not CBL" 

hours (sum of"Tn" in Equation 

W-16). 

98.236(z)(2)(iii) Type of fuel combusted. This data element would be reported by 

onshore petroleum and natural gas gathering 

and boosting facilities. This data element 

would provide information on the types of 

fuel burned. However, facilities in this 

segment generally burn fuels that are readily 

available to them as part of their operations. 

Information on the types of fuels burned by a 

facility is typically available in a facility's 

construction and operating permits. For these 

reasons, we consider that release of 

information on the types of fuels burned by 

onshore petroleum and natural gas gathering 

and boosting facilities would not be likely to 

cause substantive competitive harm and 

propose this data element be designated as 

"not CBI" for this industry segment. 

98.236(aa)(ll)(i) The quantity of natural gas These proposed data elements would be 

received at all custody transfer reported by natural gas transmission pipeline 

stations in the calendar year, in companies, which are regionally concentrated 

thousand standard cubic feet. and have control over particular segments of 

This value may include meter the pipeline infrastructure. Existing pipeline 

corrections, but only for the construction and natural gas transmission 

calendar year covered by the technology and operations development 

annual report. information is generally well-known and 

98.236(aa)(ll )(ii) The quantity of natural gas understood. It is possible that the limited 

withdrawn from in-system number of firms and the regional 

storage in the calendar year, in concentration could pose potential data 

thousand standard cubic feet. sensitivity issues. Firms in the natural gas 

98.236(aa)(ll )(iii) The quantity of natural gas 

transmission pipeline segment compete with 

others in their region for shipments of natural added to in-system storage in the 

gas. Even though there may be only one calendar year, in thousand pipeline transmitting natural gas from one standard cubic feet. 
73166 Federal Register / Vol. 79, No. 236 / Tuesday, December 9, 2014 / Proposed Rules 


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Proposed Confidentiality Determination 

Citation Data Element and Rationale 

98.236(aa)(ll)(iv) The quantity of natural gas location to another, competition exists 

transferred to third parties such between firms that wish to accept shipments 

as LDCs or other transmission of natural gas within a given region, for 

pipelines, in thousand standard potential transmission to different endpoints. 

cubic feet. Such firms could make use of information 

98.236(aa)(ll)(v) The quantity of natural gas 

about their competitors' throughput quantity 

consumed by the transmission and/or cost structure to strategically set their 

pipeline facility for operational prices or other contract tenns. Even though 

purposes, in thousand standard the market is regulated by FERC, actual 

cubic feet. contract prices may be set at levels below the 

FERC-mandated maximum tariff. However, 

the infonnation proposed to be collected is 

aggregated to the nationwide level, and small 

pipeline operations are unlikely to report as 

they are not expected to exceed the reporting 

threshold. In addition, these data elements are 

also reported to the Energy Information 

Administration (EfA) (~,natural gas 

withdrawn from storage, natural gas stored, 

gas received at city gate), and the ETA 

publishes the data on their Web site on an 

annual basis. Because disclosure of these 

proposed new data elements would not be 

likely to cause substantive competitive harm, 

we propose these data elements be designated 

as "not CBI." 

"Unit/Process 'Static' Characteristics That Are Not Inputs to Emission Eguations" Data Category 

98.236(j)( 1 )(xi) If using Calculation Method 1 or These data clements would he reported by 

2, the number of wells sending onshore petroleum and natural gas gathering 

oil to gas-liquid separators or and boosting facilities. Separators are used to 

directly to atmospheric tanks. separate hydrocarbons into liquid and gas 

98.236(j)(l )(xii) If using Calculation Method 1 or phases. Separators are typically connected to 

2, the number of atmospheric atmospheric storage tanks (hydrocarbon 

tanks. tanks) where hydrocarbon liquids arc stored. 

98.236(j)(l )(xiv)(A) If using Calculation Method 1 or 

The number of well-head separators sending 

oil to atmospheric tanks can vary widely 2, if any emissions from the depending on numerous conditions, including atmospheric tanks at your the sizing of the tank and throughput of the facility were controlled with separators, and the number of parties involved 

vapor recovery systems, the with handling or processing the separated number of atmospheric tanks constituents. Information on the count of that control emissions with atmospheric storage tanks with a throughput vapor recovery systems. above 500 barrels of oil per day is already 

98.236(j)(l )(xvi)(A) If using Calculation Method 1 or publicly available in title V permits under the 

2, if you controlled emissions EPA's National Emission Standards for 

from any atmospheric tanks at Hazardous Air Pollutants (NESIIAP) for Oil 

your facility with one or more and Gas Production ( 40 CFR part 63, subpart 

flares, the number of HB} Any additional information required 

atmospheric tanks that controlled under subpart W regarding the number of 

emissions with flares. 
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Proposed Confidentiality Determination 

Citation Data Element and Rationale 

98.236(j)(2)(i)(D) If using Calculation Method 3, wellhead separators is the same type of 

the number of atmospheric tanks information already made publicly available 

in the basin. through the NESHAP and thus is a reasonable 

98.236(j)(2)(ii)(B) If using Calculation Method 3, expansion of that infonnation. Further, 

the number of atmospheric tanks information about the number of well-head 

in the sub-basin that did not separators sending oil to atmospheric tanks 

control emissions with flares, does not provide insight into the pertormance 

including those that have vapor (ability to separate hydrocarbon into different 

recovery. phases) or the overall operational efficiency 

98.23 6(j)(2 )(iii)(B) If using Calculation Method 3, 

for the facility that could cause substantial 

competitive harm if disclosed. We propose the number of atmospheric tanks that these data elements be designated as "not 

in the sub-basin that controlled CBI." 

emissions with flares. 

98.236(z)(1 )(ii) For each combustion unit type This data element would be reported by 

listed in §§ 98.236(z)(l ), the onshore petroleum and natural gas gathering 

total number of combustion and boosting facilities. This data element 

units. provides information on the number of 

internal and external combustion units located 

at these facilities. However, this information 

would not be likely to cause substantial 

competitive harm if released to the public, 

because internal and external combustion 

units are typical parts of an onshore 

petroleum and natural gas gathering and 

boosting facility and the total number of such 

units is not considered to be competitively 

sensitive information by this industry 

segment. Because disclosure of the number of 

combustion units would not be likely to cause 

substantive competitive harm to this segment, 

we propose this data element be designated as 

''not CBI" when reported by onshore 

petroleum and natural gas gathering and 

boosting facilities. 

98.236(aa)(ll)(vi) The miles of transmission This proposed data element would be 

pipeline in the facility. reported by natural gas transmission pipeline 

companies, which are regionally concentrated 

and have control over particular segments of 

the pipeline infrastructure. Existing pipeline 

construction and natural gas transmission 

technology and operations development 

information is generally well-known and 

understood. It is possible that the limited 

number of firms and the regional 

concentration could pose potential data 

sensitivity issues. Firms in the natural gas 

transmission pipeline segment compete with 

others in their region for shipments of natural 
73168 Federal Register / Vol. 79, No. 236 / Tuesday, December 9, 2014 / Proposed Rules 

16See the rationale for determining that similar 

data elements are not CBI for the onshore petroleum 

and natural gas production segment and the natural 

gas processing segment in the November 25, 2014 

preamble (79 FR 70352). 

D. Other Proposed Case-by-Case 

Confidentiality Determinations for 

Subpart W 

The proposed revision includes six 

data elements that are production and/ 

or throughput data from subpart W 

facilities that would be newly reported 

for the Onshore Petroleum and Natural 

Gas Gathering and Boosting segment. 

Although these data elements are 

similar in certain types or 

characteristics to the data elements in 

‘‘Production/Throughput Data that are 

Not Inputs to Emissions Equations’’ or 

‘‘Raw Materials Consumed that are Not 

Inputs to Emissions Equations’’ data 

categories, for the reasons provided in 

Section III.B of this preamble, we are 

not proposing to assign these data 

elements to a data category. Instead, we 

are proceeding to make individual 

confidentiality determinations for these 

data elements. The proposed results of 

these individual determinations are 

presented in Table 3 of this preamble. 

As described in Section III.B of this 

preamble, our proposed determinations 

for these data elements were based on 

a two-step process in which we first 

evaluated whether the data element met 

the definition of emission data. This 

first step in the evaluation is important 

because emission data are not eligible 

for confidential treatment pursuant to 

section 114(c) of the CAA, which 

precludes emissions data from being 

considered confidential and requires 

that such data be made available to the 

public. The term ‘‘emission data’’ is 

defined in 40 CFR 2.301(a). 

We propose to determine that none of 

these six data elements are emission 

data under 40 CFR 2.301(a)(2)(i), 

because they do not provide any 

information characterizing actual GHG 

emissions or descriptive information 

about the location or nature of the 

emissions source. However, we note 

that this determination is made strictly 

in the context of the GHGRP and may 

not apply to other regulatory programs. 

In the second step, we evaluate 

whether the data element is entitled to 

confidentiality treatment, based on the 

criteria for confidential treatment 

specified in 40 CFR 2.208. In particular, 

the EPA focused on the following two 

factors: (1) Whether the data were 

already publicly available; and (2) 

whether ‘‘. . . disclosure of the 

information is likely to cause significant 

harm to the business’ competitive 

position.’’ See 40 CFR 2.208(e)(1). For 

each of these six data elements, we 

determined whether the information is 

already available in the public domain. 

For those data elements for which no 

published data could be found, we 

evaluated whether their publication 

would be likely to cause competitive 

harm. 

For the proposed Onshore Petroleum 

and Natural Gas Gathering and Boosting 

segment, the EPA is proposing that five 

data elements related to the throughput 

of each gathering and boosting facility 

be reported and one data element 

related to the amount of produced gas 

consumed by the facility be reported. 

These data elements are not publicly 

available for all facilities operating in 

the Onshore Petroleum and Natural Gas 

Gathering and Boosting segment, 

although they are publicly available for 

facilities in the Onshore Petroleum and 

Natural Gas Production segment and the 

Onshore Natural Gas Processing 

segment.16 However, information for 


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Federal Register / Vol. 79, No. 236 / Tuesday, December 9, 2014 / Proposed Rules 73169 

some gathering and boosting systems is 

available on the company Web site or in 

annual reports. In addition, even if the 

data are not available, companies 

operating in this segment enter into long 

term agreements with natural gas 

producers to gather natural gas. Once 

these agreements are established, 

information that would be revealed from 

the data elements in Table 3 is not likely 

to affect the competitive position of the 

company operating the gathering and 

boosting system because it will not 

reveal information about the cost or 

profitability of providing that gathering 

service, or about the company’s ability 

to enter into new agreements and 

expand operations. In addition, the 

information will be aggregated to the 

basin or sub-basin level rather than 

being reported for individual gathering 

and boosting systems. Therefore, we 

propose that these data, when reported 

by the newly proposed onshore 

petroleum and natural gas gathering and 

boosting reporters, be designated as not 

CBI because their disclosure would not 

be likely to cause competitive harm to 

reporters in that industry segment. This 

proposed determination does not affect 

earlier determinations made for 

reporters of the same data elements in 

other industry segments. 


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Table 3. Proposed Individual Confidentiality Determination for New Data Elements 

Proposed Confidentiality Determination and 

Citation Data Element Rationale 

Onshore Petrolewn and Natural Gas Gathering and Boosting 

98.236(j)(2)(i)(A) If using Calculation Method We propose that each of these data elements be 

3, the total annual designated as "not CBI." The Onshore 

oil/condensate throughput Petroleum and Natural Gas Gathering and 

that is sent to all atmospheric Boosting segment is a regionally concentrated 

tanks in the gathering and segment, with gathering lines and other 

boosting facility, in barrels. services located in fixed geological basins. 

98.236( aa)(l O)(i) The quantity of produced gas Because of the amount of fixed assets required 

throughput in the calendar to operate in this segment (~, gathering lines 

year, in thousand standard and boosting stations), companies operating in 

cubic feet. this segment enter into long term agreements 

98.236(aa)(1 O)(ii) The quantity of produced gas 

with natural gas producers to gather natural gas 

and transport it to natural gas processing consumed by the facility in facilities or, in some cases, transmission the calendar year, in pipelines. These agreements are for long thousand standard cubic feet. periods, lasting from several years to the life of 

98.236(aa)( lO)(iii) The quantity ofproduced the lease for the producing wells, and establish 

condensate throughput in the the prices for gathering services for the life of 

calendar year, in barrels. the agreement. Once these agreements are 

98.236(aa)(l O)(iv) The quantity of produced oil established, information on the actual 

throughput in the calendar throughput of the gathering and boosting 

year, in barrels. system is not likely to affect the competitive 

98.236(aa)(l O)(v) The quantity of gas flared, position of the company operating the 

vented and/or unaccounted gathering and boosting system because it will 

for in the calendar year, in not reveal information about the cost or 

thousand standard cubic feet. profitability of providing that gathering 

service, or about the company's ability to enter 

into new agreements and expand operations. 

Data on the length, diameter, and pressure of 

gathering lines, and on the size (~, 

horsepower) of gathering compression stations 

is typically publicly available through 

construction and operating permits for these 

sources. These data can be used to determine 

the capacity of these systems, if it is not 

already reported elsewhere. Actual throughput 

of gathering and boosting systems, in terms of 

annual average daily throughput, is frequently 

included in the quarterly or annual reports for 

publicly traded companies and these are 

readily available on company Web sites. 

Annual throughput capacity and actual 

throughput is often also listed on gathering 

company Web sites. Based on the general 

availability of the actual throughput 

information, and the absence of an adverse 

competitive effect from revealing this 

information, the EPA is proposing that these 

data elements be considered "not CBI." 
Federal Register / Vol. 79, No. 236 / Tuesday, December 9, 2014 / Proposed Rules 73171 

E. Request for Comments on Proposed 

Confidentiality Determinations 

For the CBI component of this 

rulemaking, we are specifically 

soliciting comment on the following 

issues. First, we specifically seek 

comment on the proposed data category 

assignments, and application of the 

established categorical confidentiality 

determinations to new data elements 

assigned to categories with such 

determinations. If a commenter believes 

that the EPA has improperly assigned 

certain new data elements to any of the 

data categories established in the 2011 

Final CBI Rule, please provide specific 

comments identifying which of these 

data elements may be mis-assigned 

along with a detailed explanation of 

why you believe them to be incorrectly 

assigned and in which data category you 

believe they belong. In addition, if you 

believe that a data element should be 

assigned to one of the two direct emitter 

data categories that do not have a 

categorical confidentiality 

determination, please also provide 

specific comment along with detailed 

rationale and supporting information on 

whether such data element does or does 

not qualify as CBI. 

We also seek comment on the 

proposed individual confidentiality 

determinations for the following data 

elements: 26 data elements assigned to 

the ‘‘Unit/Process Operating 

Characteristics That Are Not Inputs to 

Emission Equations’’ data category; 10 

data elements assigned to the ‘‘Unit/ 

Process ‘Static’ Characteristics That Are 

Not Inputs to Emission Equations’’ 

category; and six data elements for 

which no data category assignment was 

proposed. 

By proposing confidentiality 

determinations prior to data reporting 

through this proposal and rulemaking 

process, we provide reporters an 

opportunity to submit comments, in 

particular comments identifying data 

they consider sensitive and their 

rationales and supporting 

documentation; this opportunity is the 

same opportunity that is afforded to 

submitters of information in case-bycase confidentiality determinations 

made in response to individual claims 

for confidential treatment not made 

through rulemaking. It provides an 

opportunity to rebut the agency’s 

proposed determinations prior to 

finalization. We will evaluate the 

comments on our proposed 

determinations, including claims of 

confidentiality and information 

substantiating such claims, before 

finalizing the confidentiality 

determinations. Please note that this 

will be a reporter’s only opportunity to 

substantiate a confidentiality claim for 

the data elements identified in this 

rulemaking. Upon finalizing the 

confidentiality determinations of the 

data elements identified in this rule, the 

EPA will release or withhold these data 

in accordance with 40 CFR 2.301, which 

contains special provisions governing 

the treatment of Part 98 data for which 

confidentiality determinations have 

been made through rulemaking. 

When submitting comments regarding 

the confidentiality determinations we 

are proposing in this action, please 

identify each individual data element 

you do or do not consider to be CBI or 

emission data in your comments. Please 

explain specifically how the public 

release of that particular data element 

would or would not cause a competitive 

disadvantage to a facility. Discuss how 

this data element may be different from 

or similar to data that are already 

publicly available. Please submit 

information identifying any publicly 

available sources of information 

containing the specific data elements in 

question. Data that are already available 

through other sources would likely be 

found not to qualify for CBI protection. 

In your comments, please identify the 

manner and location in which each 

specific data element you identify is 

publicly available, including a citation. 

If the data are physically published, 

such as in a book, industry trade 

publication, or federal agency 

publication, provide the title, volume 

number (if applicable), author(s), 

publisher, publication date, and 

International Standard Book Number 

(ISBN) or other identifier. For data 

published on a Web site, provide the 

address of the Web site and the date you 

last visited the Web site and identify the 

Web site publisher and content author. 

If your concern is that competitors 

could use a particular data element to 

discern sensitive information, 

specifically describe the pathway by 

which this could occur and explain how 

the discerned information would 

negatively affect your competitive 

position. Describe any unique process or 

aspect of your facility that would be 

revealed if the particular data element 

you consider sensitive were made 

publicly available. If the data element 

you identify would cause harm only 

when used in combination with other 

publicly available data, then describe 

the other data, identify the public 

source(s) of these data, and explain how 

the combination of data could be used 

to cause competitive harm. Describe the 

measures currently taken to keep the 

data confidential. Avoid conclusory and 

unsubstantiated statements, or general 

assertions regarding potential harm. 

Please be as specific as possible in your 

comments and include all information 

necessary for the EPA to evaluate your 

comments. 

IV. Impacts of the Proposed 

Amendments to Subpart W 

A. Costs of the Proposed Amendments 

As discussed in Section II of this 

preamble, the EPA is proposing 

amendments to subpart W that would 

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. 

Reporters in the Onshore Petroleum 

and Natural Gas Production segment 

would have to monitor and report 

emissions and data elements associated 

with oil well completions and 

workovers with hydraulic fracturing. 

Reporters in this segment would also 

have to report the well identification 

numbers associated with individual oil 

and gas wells, and when reporting 

emissions for certain pieces of 

equipment, such as acid gas removal 

units, dehydrators, tanks, and flares, 

that are 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 would count 

towards determining applicability with 

subpart W. The proposed 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. 

Reporters in the Onshore Petroleum 

and Natural Gas Gathering and Boosting 

segment would need to estimate and 

report emissions data and related data 

elements associated with several 

different emission sources within this 

newly proposed industry segment. 

Approximately 200 new reporters are 

expected to be subject to subpart W due 

to the proposed amendments for the 

Onshore Petroleum and Natural Gas 

Gathering and Boosting segment in this 

rulemaking. 

Reporters in the Onshore Natural Gas 

Transmission Pipeline segment would 

need to estimate and report emissions 

data and related data elements 

associated with transmission pipeline 

blowdown activities. Approximately 

150 new reporters are expected to be 


rljohnson on DSK3VPTVN1PROD with PROPOSALS2
73172 Federal Register / Vol. 79, No. 236 / Tuesday, December 9, 2014 / Proposed Rules 

17The EPA’s RFA guidance for rule writers 

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

preferred quantitative metric for economic impact 

screening analysis. 

subject to subpart W due to the 

proposed amendments in this 

rulemaking. 

The proposed amendments to subpart 

W are not expected to significantly 

increase burden. See the memorandum, 

‘‘Assessment of Impacts of the 2015 

Proposed Revisions to Subpart W’’ in 

Docket ID No. EPA–HQ–OAR–2014– 

0831 for additional information. 

B. Impacts of the Proposed 

Amendments on Small Businesses 

As required by the Regulatory 

Flexibility Act (RFA) and Small 

Business Regulatory Enforcement and 

Fairness Act (SBREFA), the EPA 

assessed the potential impacts of these 

amendments on small entities (small 

businesses, governments, and non-profit 

organizations). (See Section V.C of this 

preamble for definitions of small 

entities.) 

The EPA conducted a screening 

assessment comparing compliance costs 

to onshore petroleum and natural gas 

production specific receipts data for 

establishments owned by small 

businesses. This ratio constitutes a 

‘‘sales’’ test that computes the 

annualized compliance costs of this rule 

as a percentage of sales and determines 

whether the ratio exceeds 1 percent.17

The cost-to-sales ratios were constructed 

at the establishment level (average 

reporting program costs per 

establishment/average establishment 

receipts) for several business size 

ranges. This allowed the EPA to account 

for receipt differences between 

establishments owned by large and 

small businesses and differences in 

small business definitions across 

affected industries. The results of the 

screening assessment are shown in 

Table 4 of this preamble. 

TABLE 4—ESTIMATED COST-TO-SALES RATIOS FOR FIRST YEAR COSTS BY INDUSTRY AND ENTERPRISE SIZE A

Industry segment NAICS NAICS description 

SBA size standard 

(effective January 

22, 2014) 

Average 

cost per 

entity 

($1,000/ 

entity) 

All enterprises 

(percent) 

Owned by enterprises with: 

<20 

employees b

(percent) 

20 to 

99 employees 

(percent) 

100 to 

499 

employees 

(percent) 

<500 

employees 

(percent) 

500 to 

999 

employees 

(percent) 

1,000 

to 

2,499 

employees 

Onshore Petroleum 

and Natural Gas 

Production.

211 Oil and Gas Extraction.500 employees ....... $29.36 0.07 0.43 0.03 0.01 0.09 0.00 0.00 

213111 Drilling Oil and Gas 

Wells.

500 employees ....... 29.36 0.28 1.00 0.32 0.06 0.19 0.02 0.01 

213112 Support Activities for 

Oil and Gas Operations.

$35.5 million ........... 29.36 0.45 1.24 0.39 0.08 0.33 0.02 NA 

221 Utilities ..................... 500 employees ....... 29.36 0.08 0.84 0.14 0.06 0.19 0.04 NA 

486 Pipeline Transportation.$25.5 million ........... 29.36 0.29 0.44 0.18 0.26 0.26 0.33 NA 

Onshore Natural 

Gas Transmission 

Pipeline.

211 Oil and Gas Extraction.500 employees ....... 3.19 0.01 0.05 0.00 0.00 0.01 0.00 0.00 

213111 Drilling Oil and Gas 

Wells.

500 employees ....... 3.19 0.03 0.11 0.03 0.01 0.02 0.00 0.00 

213112 Support Activities for 

Oil and Gas Operations.

$35.5 million ........... 3.19 0.05 0.13 0.04 0.01 0.04 0.00 NA 

221 Utilities ..................... 500 employees ....... 3.19 0.01 0.09 0.01 0.01 0.02 0.00 NA 

486 Pipeline Transportation.$25.5 million ........... 3.19 0.03 0.05 0.02 0.03 0.03 0.04 NA 

Onshore Petroleum 

and Natural Gas 

Gathering and 

Boosting.

211 Oil and Gas Extraction.500 employees ....... 24.70 0.06 0.36 0.03 0.01 0.08 0.00 0.00 

213111 Drilling Oil and Gas 

Wells.

500 employees ....... 24.70 0.23 0.84 0.27 0.05 0.16 0.02 0.01 

213112 Support Activities for 

Oil and Gas Operations.

$35.5 million ........... 24.70 0.38 1.04 0.32 0.07 0.27 0.02 NA 

221 Utilities ..................... 500 employees ....... 24.70 0.07 0.70 0.12 0.05 0.16 0.04 NA 

486 Pipeline Transportation.$25.5 million ........... 24.70 0.24 0.37 0.15 0.22 0.22 0.28 NA 

aThe Census Bureau defines an enterprise as a business organization consisting of one or more domestic establishments that were specified 

under common ownership or control. The enterprise and the establishment are the same for single-establishment firms. Each multi-establishment 

company forms one enterprise—the enterprise employment and annual payroll are summed from the associated establishments. Enterprise size 

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

Since the Small Business Administration (SBA)’s business size definitions (http://www.sba.gov/size) apply to an establishment’s ultimate parent 

company, we assume in this analysis that the enterprise definition above is consistent with the concept of ultimate parent company that is typically used for SBREFA screening analyses. bThe Census Bureau has missing data ranges for this employee range. Hence the receipts are an underestimate of the true value. Therefore, 

the cost-to-sales ratio is a conservative estimate. 


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As shown, the cost-to-sales ratios are 

less than 1 percent for all 

establishments, except the ratio for the 

1–20 employee range for facilities in the 

Onshore Petroleum and Natural Gas 

Production segment with NAICS code 

213111, which is 1 percent, and the 

ratios for the 1–20 employee range for 

facilities in the Onshore Petroleum and 

Natural Gas Production and Onshore 

Petroleum and Natural Gas Gathering 

and Boosting segments with NAICS 

code 213112, which are greater than 1 

percent but less than 2 percent. The 

petroleum and natural gas industry has 

a large number of enterprises, the 

majority of them in the 1–20 employee 

range. However, a large fraction of 

production comes from large 

corporations and not those with less 

than 20 employee enterprises. The 

smaller enterprises in most cases deal 

with very small operations (such as a 

single family owning a few production 

wells) that are unlikely to cross the 

25,000 metric tons CO2e threshold 

considered for the rule. An exception to 

such a scenario is a small (less than 20 

employee) enterprise owning large 

operations but conducting nearly all of 

its operations through contractors. This 

is not an uncommon practice in the 

Onshore Petroleum and Natural Gas 

Production segment. Such enterprises, 

however, are a very small group among 

the almost 16,000 enterprises in the less 

than 20 employee category, and the EPA 

proposes to cover them in the rule. 

The EPA took a conservative 

approach with the model entity 

analysis. Although the appropriate SBA 

size definition should be applied at the 

parent company (enterprise) level, data 

limitations allowed us only to compute 

and compare ratios for a model 

establishment within several enterprise 

size ranges. 

Although this rule will not have a 

significant economic impact on a 

substantial number of small entities, the 

agency nonetheless tried to reduce the 

impact of this rule on small entities. See 

Section V.C of this preamble for more 

detail on the measures taken by the EPA 

to ensure that the burdens imposed on 

small entities would be minimal. 

V. Statutory and Executive Order 

Reviews 

A. Executive Order 12866: Regulatory 

Planning and Review and Executive 

Order 13563: Improving Regulation and 

Regulatory Review 

This action is not a ‘‘significant 

regulatory action’’ under the terms of 

Executive Order 12866 (58 FR 51735, 

October 4, 1993) and is therefore not 

subject to review under Executive 

Orders 12866 and 13563 (76 FR 3821, 

January 21, 2011). 

B. Paperwork Reduction Act 

The information collection 

requirements in this proposed rule have 

been submitted for approval to OMB 

under the Paperwork Reduction Act, 44 

U.S.C. 3501 et seq. The Information 

Collection Request (ICR) document 

prepared by the EPA has been assigned 

EPA ICR number 2300.16. OMB has 

previously approved the information 

collection requirements for 40 CFR part 

98 under the provisions of the 

Paperwork Reduction Act, 44 U.S.C. 

3501 et seq., and has assigned OMB 

control number 2060–0629. 

This action proposes to 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. Impacts associated with the 

proposed changes to the monitoring and 

reporting requirements are detailed in 

the memorandum ‘‘Assessment of 

Impacts of the 2015 Proposed Revisions 

to Subpart W’’ (see Docket ID No. EPA– 

HQ–OAR–2014–0831). Burden is 

defined at 5 CFR 1320.3(b). 

The estimated projected cost and hour 

burden associated with reporting for the 

proposed amendments to subpart W 

affecting the three industry segments are 

$7.2 million and 73,000 hours, 

respectively. For the hour burden, the 

estimated average burden hours per new 

response is 113 hours, the proposed 

frequency of response is once annually, 

and the estimated number of likely new 

respondents that would result from 

these proposed amendments is 

approximately 400. 

The estimated total projected cost and 

hour burden associated with all ten 

subpart W industry segments are 

317,400 hours and $29.2 million per 

year for a 3-year period, where identical 

annual costs are anticipated for all 3 

years. The average annual burden to the 

EPA for this period is estimated to be 

10,400 hours for oversight activities. 

The annual reporting and recordkeeping 

burden for this collection of information 

is estimated to average 63.4 hours per 

response. 

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. 

To comment on the agency’s need for 

this information, the accuracy of the 

provided burden estimates, and any 

suggested methods for minimizing 

respondent burden, the EPA has 

established a public docket for this rule, 

which includes this ICR, under Docket 

ID number EPA–HQ–OAR–2014–0831. 

Submit any comments related to the ICR 

to the EPA and OMB. See ADDRESSES

section at the beginning of this proposed 

rule for where to submit comments to 

the EPA. Send comments to OMB at the 

Office of Information and Regulatory 

Affairs, Office of Management and 

Budget, 725 17th Street NW., 

Washington, DC 20503, Attention: Desk 

Office for the EPA. Since OMB is 

required to make a decision concerning 

the ICR between 30 and 60 days after 

December 9, 2014, a comment to OMB 

is best assured of having its full effect 

if OMB receives it by January 8, 2015. 

The final rule will respond to any OMB 

or public comments on the information 

collection requirements contained in 

this proposal. We continue to be 

interested in the potential impacts of 

this proposed action on the burden 

associated with the proposed 

amendments and welcome comments 

on issues related to such impacts. 

C. Regulatory Flexibility Act 

The Regulatory Flexibility Act (RFA) 

generally requires an agency to prepare 

a regulatory flexibility analysis of any 

rule subject to notice and comment 

rulemaking requirements under the 

Administrative Procedure Act or any 

other statute unless the agency certifies 

that the rule will not have a significant 

economic impact on a substantial 

number of small entities. Small entities 

include small businesses, small 

organizations, and small governmental 

jurisdictions. 

For purposes of assessing the impacts 

of today’s proposed rule on small 

entities, small entity is defined as: (1) A 

small business as defined by the Small 

Business Administration’s regulations at 

13 CFR 121.201; (2) a small 

governmental jurisdiction that is a 

government of a city, county, town, 

school district or special district with a 

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

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

owned and operated and is not 

dominant in its field. 

After considering the economic 

impacts of these proposed rule 

amendments on small entities, I certify 

that this action would not have a 

significant economic impact on a 

substantial number of small entities. 

The small entities directly regulated by 

this proposed rule include small 

businesses in the petroleum and gas 

industry. The EPA has determined that 

some small businesses would be 


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73174 Federal Register / Vol. 79, No. 236 / Tuesday, December 9, 2014 / Proposed Rules 

affected because their production 

processes emit GHGs exceeding the 

reporting threshold. This action 

includes proposed amendments that 

may result in a burden increase on 

subpart W reporters, but the EPA has 

determined that it is not a significant 

increase. See Section IV.B of this 

preamble for more details on the 

analysis of the potential impact of this 

proposal on small business entities. 

Although this proposed rule will not 

have a significant economic impact on 

a substantial number of small entities, 

the EPA nonetheless has tried to reduce 

the impact of this rule on small entities. 

As part of the process of finalization of 

the final subpart W rule, the EPA took 

several steps to evaluate the effect of the 

rule on small entities. For example, the 

EPA determined appropriate thresholds 

that reduced the number of small 

businesses reporting. In addition, the 

EPA supports a ‘‘help desk’’ for the 

GHGRP, which would be available to 

answer questions on the provisions in 

this rulemaking. 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. We continue to be interested 

in the potential impacts of the proposed 

rule amendments on small entities and 

welcome comments on issues related to 

such impacts. 

D. Unfunded Mandates Reform Act 

The proposed amendments and 

confidentiality determinations do not 

contain a federal mandate that may 

result in expenditures of $100 million or 

more for State, local, and tribal 

governments, in the aggregate, or the 

private sector in any one year. This 

action proposes to 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. This 

action also proposes confidentiality 

determinations for reported data 

elements. As discussed in Section V.B 

of this preamble, for the first year, the 

estimated total projected cost and hour 

burden associated with reporting for the 

proposed amendments to subpart W 

affecting the three industry segments are 

$7.2 million and 73,000 hours, 

respectively. Thus, this proposed rule is 

not subject to the requirements of 

section 202 and 205 of the Unfunded 

Mandates Reform Act of 1995 (UMRA). 

This rule is also not subject to the 

requirements of section 203 of UMRA 

because it contains no regulatory 

requirements that might significantly or 

uniquely affect small governments. As 

discussed in Section V.B of this 

preamble, the total collective impact on 

regulated entities is $7.2 million 

annually. Because this impact on each 

individual facility is estimated to be 

approximately $9,000 annually, the EPA 

has determined that the provisions in 

this action would not significantly 

impact small governments. In addition, 

because none of the provisions apply 

specifically to small governments, the 

EPA has determined that the provisions 

in this action would not uniquely 

impact small governments. Therefore, 

this action is not subject to the 

requirements of section 203 of the 

UMRA. 

E. Executive Order 13132: Federalism 

This action does not have federalism 

implications. It will not have substantial 

direct effects on the states, on the 

relationship between the national 

government and the states, or on the 

distribution of power and 

responsibilities among the various 

levels of government, as specified in 

Executive Order 13132. For a more 

detailed discussion about how Part 98 

relates to existing state programs, please 

see Section II of the preamble to the 

final Part 98 rule (74 FR 56266, October 

30, 2009). 

This action proposes to 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. This action also proposes 

confidentiality determinations for 

reported data elements. Few, if any, 

state or local government facilities 

would be affected by the provisions in 

this proposed rule. This regulation also 

does not limit the power of States or 

localities to collect GHG data and/or 

regulate GHG emissions. Thus, 

Executive Order 13132 does not apply 

to this action. 

In the spirit of Executive Order 13132, 

and consistent with the EPA policy to 

promote communications between the 

EPA and state and local governments, 

the EPA specifically solicits comment 

on this proposed action from state and 

local officials. 

F. Executive Order 13175: Consultation 

and Coordination With Indian Tribal 

Governments 

Subject to the Executive Order 13175 

(65 FR 67249, November 9, 2000) the 

EPA may not issue a regulation that has 

tribal implications, that imposes 

substantial direct compliance costs, and 

that is not required by statute, unless 

the federal government provides the 

funds necessary to pay the direct 

compliance costs incurred by tribal 

governments, or the EPA consults with 

tribal officials early in the process of 

developing the proposed regulation and 

develops a tribal summary impact 

statement. 

The EPA has concluded that this 

action may have tribal implications. 

However, it will neither impose 

substantial direct compliance costs on 

tribal governments, nor preempt tribal 

law. This action proposes to 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. This action also proposes 

confidentiality determinations for 

reported data elements. This regulation 

would apply directly to petroleum and 

natural gas facilities that emit 

greenhouses gases. Although few 

facilities that would be subject to the 

rule are likely to be owned by tribal 

governments, it is possible that there 

may be some facilities owned by tribal 

governments. 

The EPA consulted with tribal 

officials early in the process of 

developing subpart W to permit them to 

have meaningful and timely input into 

its development. In particular, the EPA 

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). For additional 

information about the EPA’s 

interactions with tribal governments, 

see Section IV.F of the preamble to the 

re-proposal of subpart W published on 

April 12, 2010 (75 FR 18608), and 

Section IV.F of the preamble to the final 

subpart W published on November 30, 

2010 (75 FR 74458). 

The EPA specifically solicits 

additional comment on this proposed 

action from tribal officials. 

G. Executive Order 13045: Protection of 

Children From Environmental Health 

Risks and Safety Risks 

The EPA interprets Executive Order 

13045 (62 FR 19885, April 23, 1997) as 

applying only to those regulatory 

actions that concern health or safety 

risks, such that the analysis required 

under section 5–501 of the Executive 

Order has the potential to influence the 

regulation. This proposed action is not 

subject to Executive Order 13045 

because it does not establish an 


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Federal Register / Vol. 79, No. 236 / Tuesday, December 9, 2014 / Proposed Rules 73175 

environmental standard intended to 

mitigate health or safety risks. 

H. Executive Order 13211: Actions That 

Significantly Affect Energy Supply, 

Distribution, or Use 

This proposed action is not a 

‘‘significant energy action’’ as defined in 

Executive Order 13211 (66 FR 28355, 

May 22, 2001), because it is not likely 

to have a significant adverse effect on 

the supply, distribution, or use of 

energy. Part 98 relates to monitoring, 

reporting, and recordkeeping and does 

not impact energy supply, distribution, 

or use. This action proposes to 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. This action also proposes 

confidentiality determinations for 

reported data elements. 

I. National Technology Transfer and 

Advancement Act 

Section 12(d) of the National 

Technology Transfer and Advancement 

Act of 1995 (NTTAA), Public Law 104– 

113, 12(d) (15 U.S.C. 272 note) directs 

the EPA to use voluntary consensus 

standards in its regulatory activities 

unless to do so would be inconsistent 

with applicable law or otherwise 

impractical. Voluntary consensus 

standards are technical standards (e.g., 

materials specifications, test methods, 

sampling procedures, and business 

practices) that are developed or adopted 

by voluntary consensus standards 

bodies. NTTAA directs the EPA to 

provide Congress, through OMB, 

explanations when the agency decides 

not to use available and applicable 

voluntary consensus standards. 

This proposed rulemaking does not 

involve any new technical standards. 

Therefore, the EPA is not considering 

the use of any voluntary consensus 

standards. 

J. Executive Order 12898: Federal 

Actions To Address Environmental 

Justice in Minority Populations and 

Low-Income Populations 

Executive Order 12898 (59 FR 7629, 

February 16, 1994) establishes federal 

executive policy on environmental 

justice. Its main provision directs 

federal agencies, to the greatest extent 

practicable and permitted by law, to 

make environmental justice part of their 

mission by identifying and addressing, 

as appropriate, disproportionately high 

and adverse human health or 

environmental effects of their programs, 

policies, and activities on minority 

populations and low-income 

populations in the United States. 

The EPA has determined that these 

proposed rule amendments will not 

have disproportionately high and 

adverse human health or environmental 

effects on minority or low-income 

populations because the amendments 

do not affect the level of protection 

provided to human health or the 

environment. This is because the 

proposed amendments address 

information collection and reporting 

and verification procedures. 

List of Subjects in 40 CFR Part 98 

Environmental protection, 

Administrative practice and procedure, 

Greenhouse gases, Reporting and 

recordkeeping requirements. 

Dated: November 13, 2014. 

Gina McCarthy, 

Administrator. 

For the reasons stated in the 

preamble, title 40, chapter I, of the Code 

of Federal Regulations as amended 

November 25, 2014 at 79 FR 70351, and 

effective January 1, 2015, is proposed to 

be further 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 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. 

(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 paragraph 

§ 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 paragraph 

§ 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 paragraph § 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 paragraph (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. 

* * * * * 

(8) Well venting during well 

workovers with hydraulic fracturing. 

* * * * * 


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(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 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 the 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 paragraphs (j) 

introductory text, (j)(1) introductory 

text, and (j)(6); 

■ n. Revising paragraph (n)(2)(i); 

■ o. Revising paragraphs (o) 

introductory text and (o)(10); 

■ p. Revising paragraphs (p) 

introductory text and (p)(10); 

■ q. Revising paragraphs (r) 

introductory text and (r)(2); 

■ r. 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, 

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. 

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 subpart for each type of natural gas 

pneumatic device (continuous high 

bleed, continuous low bleed, and 

intermittent bleed) using engineering 

estimates based on best available data. 

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 of 

this subpart for each type of natural gas 

pneumatic device (continuous high 

bleed, continuous low bleed, and 

intermittent bleed) using engineering 

estimates based on best available data. 

* * * * * 

(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 of this section, you 

must follow the procedures specified in 

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


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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. 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. 

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 gas 

production rate for the sub-basin and 

well type combination, calculated using 

procedures specified in paragraph 

(g)(1)(iii) of this section, expressed in 

standard cubic feet per hour. 

FRMi = Ratio of initial 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, expressed in 

standard cubic feet per hour, 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, 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 for each well, p, as 

determined by using an appropriate 

meter according to methods described in 

§ 98.234(b), or by using receipts of gas 

purchases that are used for the energized 

fracture job. Convert to standard 

conditions using paragraph (t) of this 

section. If the fracture process did not 

inject gas into the reservoir or if the 

injected gas is CO2 then EnFs,p is 0. 

FVs,p = Flow volume of vented or flared gas 

for each well, p, in standard cubic feet 

per hour 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) of this 

section 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 as specified in 

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

determine the value of FRMs. You must 

use Equation W–12B as specified in 

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

determine the value of FRMi. The 

procedures specified in paragraphs 

(g)(1)(v) and (vi) 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 


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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 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. 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. 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 Equation 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 paragraphs (g)(1)(vii)(A) or 

(g)(1)(vii)(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. 

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. 

* * * * * 

(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 

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 hydrocarbon liquids 

flowing directly to atmospheric storage 

tanks without passing through a 

wellhead separator with throughput 

greater than or equal to 10 barrels per 

day, calculate annual CH4 and CO2

emissions using Calculation Method 2 

as specified in paragraph (j)(2) of this 

section. For hydrocarbon liquids 

flowing to gas-liquid separators or 

directly to atmospheric storage tanks 

with throughput less than 10 barrels per 

day, use Calculation Method 3 as 

specified in paragraph (j)(3) of this 

section. If you use Calculation Method 

1 or Calculation Method 2, you must 

also calculate emissions that may have 

occurred due to dump valves not 

closing properly using the method 

specified in paragraph (j)(4) 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)(5) 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)(6) 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 


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wellhead gas-liquid separator before 

liquid transfer to storage tanks. 

Calculate flashing emissions with a 

software program, such as AspenTech 

HYSYS® or API 4697 E&P Tank, that 

uses the Peng-Robinson equation of 

state, models flashing emissions, and 

speciates CH4 and CO2 emissions that 

will result when the oil from the 

separator enters an atmospheric 

pressure storage tank. The following 

parameters must be determined for 

typical operating conditions over the 

year by engineering estimate and 

process knowledge based on best 

available data, and must be used at a 

minimum to characterize emissions 

from liquid transferred to tanks: 

* * * * * 

(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. 

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 

Calculation Methods 1 or 2 in paragraphs 

(j)(1) and (2) of this section (with 

separators) in standard cubic feet per 

year. 

Tn = Total time a dump valve is not closing 

properly in the calendar year in hours. 

Estimate Tn based on maintenance, 

operations, or routine 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) of this section do not apply 

and instead you must calculate CH4, 

CO2, and N2O emissions as specified in 

paragraph (o)(12) of this section. If 

emissions from a compressor source are 

captured for fuel use or are routed to a 

thermal oxidizer, paragraphs (o)(1) 

through (12) of this section do not apply 

and instead you must calculate and 

report emissions as specified in subpart 

C of this part. If emissions from a 

compressor source are routed to vapor 

recovery, paragraphs (o)(1) through (12) 

of this section do not apply. If you are 

required to report emissions from 

centrifugal compressor venting at an 

onshore petroleum and natural gas 

production facility as specified in 

§ 98.232(c)(19) 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) of this 

section; and calculate CH4 and CO2

mass emissions as specified in 

paragraph (o)(11) of this section. 

* * * * * 

(10) Method for calculating 

volumetric GHG emissions from wet seal 

oil degassing vents at an onshore 

petroleum and natural gas production 

facility 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) of this section do not apply 

and instead you must calculate CH4, 

CO2, and N2O emissions as specified in 

paragraph (p)(12) of this section. If 

emissions from a compressor source are 

captured for fuel use or are routed to a 

thermal oxidizer, paragraphs (p)(1) 

through (12) of this section do not apply 

and instead you must calculate and 

report emissions as specified in subpart 

C of this part. If emissions from a 

compressor source are routed to vapor 

recovery, paragraphs (p)(1) through (12) 

of this section do not apply. If you are 

required to report emissions from 

reciprocating compressor venting at an 

onshore petroleum and natural gas 

production facility as specified in 

§ 98.232(c)(11) or an onshore petroleum 


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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) of this 

section; and calculate CH4 and CO2

mass emissions as specified in 

paragraph (p)(11) of this section. 

* * * * * 

(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. 

* * * * * 

(r) Equipment leaks by population 

count. This paragraph applies to 

emissions sources listed in 

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

(i)(3), (i)(4), (i)(5), (i)(6), (j)(9), and (j)(10) 

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 this paragraph (r) and 

do not need to be reported. You must 

calculate emissions from all emission 

sources listed in this paragraph using 

Equation W–32A of this section, except 

for natural gas distribution facility 

emission sources listed in § 98.232(i)(3). 

Natural gas distribution facility 

emission sources listed in § 98.232(i)(3) 

must calculate emissions using Equation 

W–32B and according to paragraph 

(r)(6)(ii) of this section. 

Where: 

Es,e,i = Annual volumetric emissions of GHGi

from the emission source type in 

standard cubic feet. The emission source 

type may be a component (e.g., 

connector, open-ended line, etc.), below 

grade metering-regulating station, below 

grade transmission-distribution transfer 

station, distribution main, 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. Underground 

natural gas storage facilities must count 

each component listed in Table W–4 of 

this subpart. LNG storage facilities must 

count the number of vapor recovery 

compressors. LNG import and export 

facilities must count the number of vapor 

recovery compressors. Natural gas 

distribution facilities must count: (1) The 

number of distribution services by 

material type; (2) miles of distribution 

mains by material type; and (3) number 

of below grade metering-regulating 

stations, by pressure type; as listed in 

Table W–7 of this subpart. 

CountMR = Total number of meter/regulator 

runs at above grade metering-regulating 

stations that are not above grade 

transmission-distribution transfer 

stations or, when used to calculate 

emissions according to paragraph (q)(9) 

of this section, the total number of 

meter/regulator runs at above grade 

transmission-distribution transfer 

stations. 

EFs,e = Population emission factor for the 

specific emission source type, as listed 

in Tables W–1A and W–4 through W–7 

of this subpart. Use appropriate 

population emission factor for operations 

in Eastern and Western U.S., according 

to Table W–1D of this subpart. 

EFs,MR,i = Meter/regulator run population 

emission factor for GHGi based on all 

surveyed above grade transmissiondistribution transfer stations over ‘‘n’’ 

years, in standard cubic feet of GHGi per 

operational hour of all meter/regulator 

runs, as determined in Equation W–31. 

GHGi = For onshore petroleum and natural 

gas production facilities 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 


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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, 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. 

(B) Multiply major equipment counts 

by the average component counts listed 

in Table W–1B 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 in Table W–1A of this subpart for 

operations in Eastern and Western U.S. 

according to the mapping in Table 

W–1D of this subpart. 

(ii) Component Count Method 2. 

Count each component individually for 

the facility. Use the appropriate factor in 

Table W–1A of this subpart for 

operations in Eastern and Western U.S. 

according to the mapping in Table 

W–1D of this subpart. 

* * * * * 

(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 paragraph (z)(3) and (4) 

of this section, as follows: 

(1) * * * 

(ii) Emissions from fuel combusted in 

stationary or portable equipment at 

onshore natural gas and petroleum 

production facilities, 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 

March 31, 2016, you must use the 

calculation methodologies and 

equations in § 98.233 but you may use 

the best available monitoring method for 

any parameter for which it is not 

reasonably feasible to acquire, install, 

and operate a required piece of 

monitoring equipment by January 1, 

2016 as specified in paragraphs (g)(2) 

through (5) of this section. Starting no 

later than April 1, 2016, you must 

discontinue using best available 

methods and begin following all 

applicable monitoring and QA/QC 

requirements of this part, except as 

provided in paragraph (g)(6) of this 

section. Best available monitoring 

methods means any of the following 

methods: 

(i) Monitoring methods currently used 

by the facility that do not meet the 

specifications of this subpart. 

(ii) Supplier data. 

(iii) Engineering calculations. 

(iv) Other company records. 

(2) Best available monitoring methods 

for well-related measurement data 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. 

(3) Best available monitoring methods 

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). 

(4) Best available monitoring methods 

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. 

(5) Best available monitoring methods 

for specified activity data. You may use 

best available monitoring methods for 

activity data as listed in paragraphs 

(g)(5)(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). 

(6) Requests for extension of the use 

of best available monitoring methods 

beyond March 31, 2016. You may 

submit a request to the Administrator to 

use one or more best available 

monitoring methods for sources listed in 

paragraphs (g)(2) through (5), of this 

section beyond March 31, 2016. 


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(i) Timing of request. The extension 

request must be submitted to EPA no 

later than January 31, 2016. 

(ii) Content of request. Requests must 

contain the following information: 

(A) A list of specific source types and 

parameters for which you are seeking 

use of best available monitoring 

methods. 

(B) For each specific source type for 

which you are requesting use of best 

available monitoring methods, a 

description of the reasons that the 

needed equipment could not be 

obtained and installed before April 1, 

2016. 

(C) A description of the specific 

actions you will take to obtain and 

install the equipment as soon as 

reasonably feasible and the expected 

date by which the equipment will be 

installed and operating. 

(iii) Approval criteria. To obtain 

approval to use best available 

monitoring methods after March 31, 

2016, you must submit a request 

demonstrating to the Administrator’s 

satisfaction that it is not reasonably 

feasible to acquire, install, and operate 

a required piece of monitoring 

equipment by April 1, 2016. The use of 

best available methods under this 

paragraph (g) will not be approved 

beyond December 31, 2016. 

* * * * * 

■ 7. Section 98.236 is amended by: 

■ a. Revising paragraph (a) introductory 

text; 

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

■ c. Revising paragraphs (b)(1)(ii)(A) 

and (B) and (c) introductory text; 

■ d. Redesignating paragraphs (c)(2) 

through (4) as paragraphs (c)(3) through 

(5), respectively; 

■ e. Adding new paragraph (c)(2); 

■ f. Revising paragraphs (d)(1) 

introductory text and (d)(1)(i); 

■ g. Redesignating paragraphs (d)(1)(ii) 

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

through (vii), respectively; 

■ h. Adding new paragraph (d)(1)(ii); 

■ i. Revising newly redesignated 

paragraph (d)(1)(vii); 

■ j. Revising paragraphs (e)(1) 

introductory text and (e)(1)(i); 

■ k. Redesignating paragraphs (e)(1)(ii) 

through (xviii) as paragraphs (e)(1)(iii) 

through (xix), respectively; 

■ l. Adding new paragraph (e)(1)(ii); 

■ m. Revising newly redesignated 

paragraphs (e)(1)(xvii) introductory text, 

(e)(1)(xviii) introductory text, and 

(e)(1)(xix); 

■ n. Revising paragraph (e)(2) 

introductory text; 

■ o. Redesignating paragraphs (e)(2)(ii) 

through (v) as paragraphs (e)(2)(iii) 

through (vi), respectively; 

■ q. Adding new paragraph (e)(2)(ii); 

■ p. Revising newly redesignated 

paragraphs (e)(2)(iii), (e)(1)(iv), (e)(2)(v) 

introductory text, and (e)(2)(vi) 

introductory text; 

■ q. Revising paragraphs (e)(3)(i) 

introductory text, (f)(1)(ii), (f)(1)(xi)(A), 

(f)(1)(xii)(A), (f)(2)(i), (g) introductory 

text, (g)(1), (g)(2), (g)(5)(i), and (g)(5)(ii); 

■ r. Adding paragraph (g)(5)(iii); 

■ s. Revising paragraph (g)(6); 

■ t. Revising paragraphs (h)(1)(i), 

(h)(1)(iv), (h)(2)(i), (h)(2)(iv), (h)(3)(i), 

(h)(4)(i) and (i) introductory text; 

■ u. Adding paragraph (i)(3); 

■ v. Revising paragraphs (j) introductory 

text and (j)(1) introductory text; 

■ w. Redesignating paragraphs (j)(1)(ii) 

through (xiv) as paragraphs (j)(1)(iv) 

through (xvi), respectively; 

■ x. Adding new paragraphs (j)(1)(ii) 

and (j)(1)(iii); 

■ y. Revising newly redesignated 

paragraphs (j)(1)(v), (j)(1)(ix), (j)(1)(x), 

(j)(1)(xiv) introductory text, (j)(1)(xv) 

introductory text, and (j)(1)(xvi) 

introductory text; 

■ z. Revising paragraphs (j)(2)(i) 

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

(j)(2)(i)(C), (j)(2)(ii)(B), (j)(2)(iii)(B), and 

(l)(1) introductory text; 

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

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

through (vii), respectively; 

■ bb. Adding new paragraph (l)(1)(ii); 

■ cc. Revising newly designated 

paragraph (l)(1)(v); 

■ dd. Revising paragraph (l)(2) 

introductory text; 

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

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

through (viii), respectively; 

■ ff. Adding new paragraph (l)(2)(ii); 

■ gg. Revising newly designated 

paragraph (l)(2)(v); 

■ hh. Revising paragraph (l)(3) 

introductory text; 

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

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

through (vi), respectively; 

■ jj. Adding new paragraph (l)(3)(ii); 

■ kk. Revising newly designated 

paragraph (l)(3)(iv); 

■ ll. Revising paragraph (l)(4) 

introductory text; 

■ mm. Redesignating paragraphs 

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

(l)(4)(iii) through (vii), respectively; 

■ nn. Adding new paragraph (l)(4)(ii); 

■ oo. Revising newly designated 

paragraph (l)(4)(iv); 

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

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

introductory text and (n)(1); 

■ qq. Adding paragraph (n)(13); 

■ rr. Revising paragraphs (o) 

introductory text and (o)(5) introductory 

text; 

■ ss. Redesignating paragraphs (o)(5)(ii) 

and (iii) as paragraphs (o)(5)(iii) and 

(iv), respectively; 

■ tt. Adding new paragraph (o)(5)(ii); 

■ uu. Revising paragraphs (p) 

introductory text and (p)(5) introductory 

text; 

■ vv. Redesignating paragraphs (p)(5)(ii) 

and (iii) as paragraphs (p)(5)(iii) and 

(iv), respectively; 

■ ww. Adding new paragraph (p)(5)(ii); 

■ xx. Revising paragraphs (r)(1) 

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

introductory text, (r)(3)(ii), (w)(2), and 

(x) introductory text; 

■ yy. Redesignating paragraphs (x)(2) 

through (4) as paragraphs (x)(3) through 

(5), respectively; 

■ zz. Adding new paragraph (x)(2); 

■ aaa. Revising paragraphs (z) 

introductory text and (z)(1) introductory 

text; 

■ bbb. Adding new paragraph (z)(1)(iii); 

■ ccc. Revising paragraph (z)(2) 

introductory text; 

■ ddd. Redesignating paragraphs 

(z)(2)(ii) through (vi) as paragraphs 

(z)(2)(iii) through (vii), respectively; 

■ eee. Adding new paragraph (z)(2)(ii); 

■ fff. Revising paragraphs (aa) 

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

through (H); 

■ ggg. Adding paragraphs (aa)(10) and 

(11); and 

■ hhh. 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) of this section, 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. 


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(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. 

(b) * * * 

(1) * * * 

(ii) * * * 

(A) The number of devices of each 

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

this section that are counted. A list of 

the well ID numbers associated with the 

devices that are counted (for the 

onshore petroleum and natural gas 

production industry segment only). 

(B) The number of devices of each 

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

this section that are estimated (not 

counted). A list of the well ID numbers 

associated with the devices that are 

estimated (not counted) (for the onshore 

petroleum and natural gas production 

industry segment only). 

* * * * * 

(c) Natural gas driven pneumatic 

pumps. You must indicate whether the 

facility has any natural gas driven 

pneumatic pumps. If the facility 

contains any natural gas driven 

pneumatic pumps, then you must report 

the information specified in paragraphs 

(c)(1) through (5) of this section. 

* * * * * 

(2) A list of the well ID numbers 

associated with the natural gas driven 

pneumatic pumps (for the onshore 

petroleum and natural gas production 

industry segment only). 

* * * * * 

(d) * * * 

(1) You must report the information 

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

(vii) of this section for each acid gas 

removal unit. 

(i) A unique name or ID number for 

the acid gas removal unit. For the 

onshore petroleum and natural gas 

production 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. 

(ii) A list of the well ID number(s) 

associated with the acid gas removal 

units (for the onshore petroleum and 

natural gas production industry segment 

only). 

* * * * * 

(vii) Sub-basin ID that best represents 

the wells and/or equipment supplying 

gas to the unit (for the onshore 

petroleum and natural gas production 

and the onshore petroleum and natural 

gas gathering and boosting industry 

segments only). 

* * * * * 

(e) * * * 

(1) For each glycol dehydrator that 

has an annual average daily natural gas 

throughput greater than or equal to 0.4 

million standard cubic feet per day (as 

specified in § 98.233(e)(1)), you must 

report the information specified in 

paragraphs (e)(1)(i) through (xix) of this 

section for the dehydrator. 

(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. 

(ii) A list of well ID number(s) 

associated with the dehydrators (for the 

onshore petroleum and natural gas 

production industry segment only). 

* * * * * 

(xvii) Whether any dehydrator 

emissions are vented to a flare or 

regenerator firebox/fire tubes. If any 

emissions are vented to a flare or 

regenerator firebox/fire tubes, report the 

information specified in paragraphs 

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

for these emissions from the dehydrator. 

(xviii) Whether any dehydrator 

emissions are vented to the atmosphere 

without being routed to a flare or 

regenerator firebox/fire tubes. If any 

emissions are not routed to a flare or 

regenerator firebox/fire tubes, then you 

must report the information specified in 

paragraphs (e)(1)(xviii)(A) and (B) of 

this section for those emissions from the 

dehydrator. 

(xix) Sub-basin ID that best represents 

the wells and/or equipment supplying 

gas to the dehydrator (for the onshore 

petroleum and natural gas production 

and the onshore petroleum and natural 

gas gathering and boosting industry 

segments only). 

(2) For glycol dehydrators with an 

annual average daily natural gas 

throughput less than 0.4 million 

standard cubic feet per day (as specified 

in § 98.233(e)(2)), you must report the 

information specified in paragraphs 

(e)(2)(i) through (vi) of this section for 

the entire facility. 

* * * * * 

(ii) A list of the well ID numbers 

associated with the dehydrators at the 

facility (for the onshore petroleum and 

natural gas production industry segment 

only). 

(iii) Whether any dehydrator 

emissions were vented to a vapor 

recovery device. If any dehydrator 

emissions were vented to a vapor 

recovery device, then you must report 

the total number of dehydrators at the 

facility that vented to a vapor recovery 

device. For the onshore petroleum and 

natural gas production industry segment 

only, also report a list of the associated 

well ID numbers. 

(iv) Whether any dehydrator 

emissions were vented to a control 

device other than a vapor recovery 

device or a flare or regenerator firebox/ 

fire tubes. If any dehydrator emissions 

were vented to a control device(s) other 

than a vapor recovery device or a flare 

or regenerator firebox/fire tubes, then 

you must specify the type of control 

device(s) and the total number of 

dehydrators at the facility that were 

vented to each type of control device. 

For the onshore petroleum and natural 

gas production industry segment only, 

also report a list of the associated well 

ID numbers for each type of control 

device. 

(v) Whether any dehydrator emissions 

were vented to a flare or regenerator 

firebox/fire tubes. If any dehydrator 

emissions were vented to a flare or 

regenerator firebox/fire tubes, then you 

must report the information specified in 

paragraphs (e)(2)(v)(A) through (D) of 

this section. 

* * * * * 

(vi) For dehydrators reported in 

paragraph (e)(2)(i) of this section that 

were not vented to a flare or regenerator 

firebox/fire tubes, report the information 

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

(B) of this section. 

* * * * * 

(3) * * * 

(i) The same information specified in 

paragraphs (e)(2)(i) through (v) of this 

section for glycol dehydrators, and 

report the information under this 

paragraph for dehydrators that use 

desiccant. 

* * * * * 

(f) * * * 

(1) * * * 

(ii) Well tubing diameter and pressure 

group ID and a list of the well ID 


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numbers associated with each sub-basin 

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) * * * 

(i) Cumulative gas flowback time, in 

hours, from when gas is first detected 

until sufficient quantities are present to 

enable separation, and the cumulative 

flowback time, in hours, after sufficient 

quantities of gas are present to enable 

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

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

You may delay the reporting of this data 

element if you indicate in the annual 

report that wildcat wells and/or 

delineation wells are the only wells 

included in this number. If you elect to 

delay reporting of this data element, you 

must report by the date specified in 

§ 98.236(cc) the total number of hours of 

flowback from all wells during 

completions or workovers and the 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 

hour, for each sub-basin (average of 

‘‘FRs,p’’ values in Equation W–12A), 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 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). 

(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). 

(6) If you used Equation W–10B to 

calculate annual volumetric total gas 

emissions for completions that vent gas 

to the atmosphere, then you must report 

the 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). 

(ii) Flow rate, in standard cubic feet 

per hour, at the beginning of the period 

of time when sufficient quantities of gas 

are present to enable separation (‘‘FRp,i’’ 

in Equation W–10B). 

(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 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). 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 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). 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 without hydraulic fracturing and 

without flaring. 

* * * * * 

(4) * * * 

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

numbers associated with each sub-basin 

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. 

* * * * * 

(3) Onshore natural gas transmission 

pipeline segment. Report the 

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

(i)(3)(iii) for each separate transmission 

pipeline blowdown event. 

(i) Annual CO2 emissions in metric 

tons CO2. 


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(ii) Annual CH4 emissions in metric 

tons CH4. 

(iii) The location of the blowdown, in 

latitude and longitude in decimal degree 

format provided as a comma-delimited 

‘‘latitude, longitude’’ coordinate pair 

reported in decimal degrees to at least 

four digits to the right of the decimal 

point. 

(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, and any atmospheric tanks 

were observed to have malfunctioning 

dump valves during the calendar year, 

then you must indicate that dump 

valves were malfunctioning and you 

must report the information specified in 

paragraph (j)(3) of this section. 

(1) If you used Calculation Method 1 

or Calculation Method 2 to calculate 

GHG emissions, then you must report 

the information specified in paragraphs 

(j)(1)(i) through (xv) of this section for 

each sub-basin and by calculation 

method. Onshore petroleum and natural 

gas gathering and boosting facilities do 

not report the information specified in 

paragraph (j)(1)(xiii) of this section. 

* * * * * 

(ii) A list of the well ID number(s) 

associated with the tanks that controlled 

emissions with flares (for the onshore 

petroleum and natural gas production 

industry segment only). 

(iii) A list of the well ID number(s) 

associated with the tanks that did not 

control emissions with flares (for the 

onshore petroleum and natural gas 

production industry segment only). 

* * * * * 

(v) The total annual oil volume from 

gas-liquid separators and direct from 

wells 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 if you 

indicate in the annual report that 

wildcat wells and/or delineation wells 

are the only wells in the sub-basin 

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. 

* * * * * 

(ix) The minimum and maximum 

concentration (mole fraction) of CO2 in 

flash gas from onshore production and 

onshore natural gas gathering and 

boosting storage tanks. 

(x) The minimum and maximum 

concentration (mole fraction) of CH4 in 

flash gas from onshore production and 

onshore petroleum and natural gas 

gathering and boosting storage tanks. 

* * * * * 

(xiv) If any emissions from the 

atmospheric tanks at your facility were 

controlled with vapor recovery systems, 

then you must report the information 

specified in paragraphs (j)(1)(xiv)(A) 

through (E) of this section. 

* * * * * 

(xv) If any atmospheric tanks at your 

facility vented gas directly to the 

atmosphere without using a vapor 

recovery system or without flaring, then 

you must report the information 

specified in paragraphs (j)(1)(xv)(A) 

through (C) of this section. 

* * * * * 

(xvi) If you controlled emissions from 

any atmospheric tanks at your facility 

with one or more flares, then you must 

report the information specified in 

paragraphs (j)(1)(xvi)(A) through (D) of 

this section. 

* * * * * 

(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. 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 if you indicate in the 

annual report that wildcat wells and/or 

delineation wells are the only wells in 

the sub-basin with oil production less 

than 10 barrels per day and that send oil 

to atmospheric tanks. If you elect to 

delay reporting of this data element, you 

must report by the date specified in 

§ 98.236(cc) the total annual oil 

throughput from all wells and the well 

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

the measurement. 

(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) * * * 

(B) The number of atmospheric tanks 

in the sub-basin that did not control 

emissions with flares, including those 

that have vapor recovery, and for the 

onshore petroleum and natural gas 

production industry segment only, a list 

of the well ID numbers of the associated 

wells. 

* * * * * 

(iii) * * * 

(B) The number of atmospheric tanks 

in the sub-basin that controlled 

emissions with flares, and for the 

onshore petroleum and natural gas 

production industry segment only, a list 

of the well ID numbers of the associated 

wells. 

* * * * * 

(l) * * * 

(1) If you used Equation W–17A to 

calculate annual volumetric natural gas 

emissions at actual conditions from oil 

wells and the emissions are not vented 

to a flare, then you must report the 

information specified in paragraphs 

(l)(1)(i) through (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 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 


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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 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 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 in each sub-basin 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 this subpart). You 

may delay reporting of this data element 

if you indicate in the annual report that 

wildcat wells and/or delineation wells 

are the only wells from which 

associated gas was vented or flared. If 

you elect to delay reporting of this data 

element, you must report by the date 

specified in § 98.236(cc) the volume of 

oil produced for well(s) with associated 

gas venting and flaring and the 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) Flare stacks. You must indicate if 

your facility contains any flare stacks. 

You must report the information 

specified in paragraphs (n)(1) through 

(13) of this section for each flare stack 

at your facility, and for each industry 

segment applicable to your facility. 

(1) Unique name or ID for the flare 

stack. For the onshore petroleum and 

natural gas production 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. 

* * * * * 

(13) For the onshore petroleum and 

natural gas production industry 

segment, a list of the well ID numbers 

associated with flare stacks in each subbasin. 

(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 

(iv) of this section. 

* * * * * 

(ii) A list of the well ID numbers for 

the wells at which these compressors 

are located (for the onshore petroleum 

and natural gas production industry 

segment only). 

* * * * * 

(p) Reciprocating compressors. You 

must indicate whether your facility has 

reciprocating compressors. You must 

report the information specified in 

paragraphs (p)(1) and (2) of this section 

for all reciprocating compressors at your 

facility. For each compressor source or 

manifolded group of compressor sources 

that you conduct as found leak 

measurements as specified in 

§ 98.233(p)(2) or (4), you must report the 

information specified in paragraph 

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

compressor source or manifolded group 

of compressor sources that you conduct 

continuous monitoring as specified in 

§ 98.233(p)(3) or (5), you must report the 

information specified in paragraph 

(p)(4) of this section. Reciprocating 

compressors in onshore petroleum and 

natural gas production 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 


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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 (iv) of this section. 

* * * * * 

(ii) A list of the well ID numbers for 

the wells at which these compressors 

are located (for the onshore petroleum 

and natural gas production industry 

segment only). 

* * * * * 

(r) * * * 

(1) You must indicate whether your 

facility contains any of the emission 

source types required to use Equation 

W–32A of this subpart. You must report 

the information specified in paragraphs 

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

separately for each emission source type 

required to use Equation W–32A of this 

subpart that is located at your facility. 

Onshore petroleum and natural gas 

production facilities and onshore 

petroleum and natural gas gathering and 

boosting facilities must report the 

information specified in paragraphs 

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

separately by component type, service 

type, and geographic location (i.e., 

Eastern U.S. or Western U.S.). 

(i) Emission source type. Onshore 

petroleum and natural gas production 

facilities and onshore petroleum and 

natural gas gathering and boosting 

facilities must report the component 

type, service type, and geographic 

location. For the onshore petroleum and 

natural gas production facilities only, 

also report a list of well ID numbers for 

the associated wells. 

* * * * * 

(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. 

* * * * * 

(w) * * * 

(2) EOR injection pump system 

identifier and a list of the well ID 

number(s) associated with each EOR 

injection pump. 

* * * * * 

(x) EOR hydrocarbon liquids. You 

must indicate whether hydrocarbon 

liquids were produced through EOR 

operations. If hydrocarbon liquids were 

produced through EOR operations, you 

must report the information specified in 

paragraphs (x)(1) through (5) of this 

section for each sub-basin category with 

EOR operations. 

* * * * * 

(2) A list of the well ID numbers 

associated with the EOR operations in 

each sub-basin. 

* * * * * 

(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 

paragraphs (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 paragraphs 

(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. 

(1) Indicate whether the combustion 

units include: External fuel combustion 

units with a rated heat capacity less 

than or equal to 5 million Btu per hour; 

or, internal fuel combustion units that 

are not compressor-drivers, with a rated 

heat capacity less than or equal to 1 

mmBtu/hr (or the equivalent of 130 

horsepower). If the facility contains 

external fuel combustion units with a 

rated heat capacity less than or equal to 

5 million Btu per hour or internal fuel 

combustion units that are not 

compressor-drivers, with a rated heat 

capacity less than or equal to 1 million 

Btu per hour (or the equivalent of 130 

horsepower), then you must report the 

information specified in paragraphs 

(z)(1)(i) through (iii) of this section for 

each unit type. 

* * * * * 

(iii) A list of the well ID numbers 

associated with the combustion units 

(for the onshore petroleum and natural 

gas production industry segment only). 

(2) Indicate whether the combustion 

units include: External fuel combustion 

units with a rated heat capacity greater 

than 5 million Btu per hour; internal 

fuel combustion units that are not 

compressor-drivers, with a rated heat 

capacity greater than 1 million Btu per 

hour (or the equivalent of 130 

horsepower); or, internal fuel 

combustion units of any heat capacity 

that are compressor-drivers. If your 

facility contains: External fuel 

combustion units with a rated heat 

capacity greater than 5 mmBtu/hr; 

internal fuel combustion units that are 

not compressor-drivers, with a rated 

heat capacity greater than 1 million Btu 

per hour (or the equivalent of 130 

horsepower); or internal fuel 

combustion units of any heat capacity 

that are compressor-drivers, then you 

must report the information specified in 

paragraphs (z)(2)(i) through (vii) for 

each combustion unit type and fuel type 

combination. 

* * * * * 

(ii) A list of the well ID numbers 

associated with the combustion units 

(for the onshore petroleum and natural 

gas production industry segment only). 

* * * * * 

(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 

and a list of the well ID numbers at the 

end of the calendar year (exclude only 

those wells permanently taken out of 

production, i.e., plugged and 

abandoned). 

(E) The number of producing wells 

and a list of the well ID numbers 

acquired during the calendar year. 

(F) The number of producing wells 

and a list of the well ID numbers 

divested during the calendar year. 

(G) The number of wells and a list of 

the well ID numbers completed during 

the calendar year. 

(H) The number of wells permanently 

taken out of production (i.e., plugged 

and abandoned) and a list of the well ID 

numbers during the calendar year. 

* * * * * 

(10) For onshore petroleum and 

natural gas gathering and boosting 

facilities, report the quantities specified 

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

this section. 

(i) The quantity of produced gas 

throughput in the calendar year, in 

thousand standard cubic feet. 

(ii) The quantity of produced gas 

consumed by the facility in the calendar 

year, in thousand standard cubic feet. 


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(iii) The quantity of produced 

condensate throughput in the calendar 

year, in barrels. 

(iv) The quantity of produced oil 

throughput in the calendar year, in 

barrels. 

(v) The quantity of gas flared, vented 

and/or unaccounted for in the calendar 

year, in thousand standard cubic feet. 

(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 in the facility. 

* * * * * 

(cc) If you elect to delay reporting the 

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

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

(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 of ‘‘Facility with 

respect to 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 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 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. 

* * * * * 

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 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. 

* * * * * 

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 OF 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 


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Federal Register / Vol. 79, No. 236 / Tuesday, December 9, 2014 / Proposed Rules 73189 

TABLE W–1A OF 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) 

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 

Open-ended Line ................................................................................................................................................................. 0 .006 

Other 5 .................................................................................................................................................................................. 0 .003 

Population Emission Factors—Gathering Pipelines 

Gathering Pipeline 7 ............................................................................................................................................................. 2 .81 

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 

Gathering Pipeline 7 ............................................................................................................................................................. 2 .81 

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 factor is in units of ‘‘scf/hour/mile of pipeline.’’ 


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73190 Federal Register / Vol. 79, No. 236 / Tuesday, December 9, 2014 / Proposed Rules 

■ 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. 2014–28395 Filed 12–8–14; 8:45 am] 

BILLING CODE 6560–50–P 


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