[Federal Register Volume 79, Number 236 (Tuesday, December 9, 2014)]
[Proposed Rules]
[Pages 73148-73190]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2014-28395]



[[Page 73147]]

Vol. 79

Tuesday,

No. 236

December 9, 2014

Part II





 Environmental Protection Agency





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40 CFR Part 98





Greenhouse Gas Reporting Rule: 2015 Revisions and Confidentiality 
Determinations for Petroleum and Natural Gas Systems; Proposed Rule

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

[[Page 73148]]


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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.

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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:
    <bullet> Federal eRulemaking Portal: http://www.regulations.gov. 
Follow the online instructions for submitting comments.
    <bullet> Email: <a href="/cdn-cgi/l/email-protection" class="__cf_email__" data-cfemail="6e2f430f000a433c432a010d050b1a2e0b1e0f40090118">[email protected]</a>. Include Docket ID No. EPA-
HQ-OAR-2014-0831 or RIN No. 2060-AS37 in the subject line of the 
message.
    <bullet> Fax: (202) 566-9744.
    <bullet> 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.
    <bullet> 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: <a href="/cdn-cgi/l/email-protection#cf8887889daabfa0bdbba6a1a89dbaa3aa8faabfaee1a8a0b9"><span class="__cf_email__" data-cfemail="35727d726750455a47415c5b5267405950755045541b525a43">[email protected]</span></a>.
    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:

[[Page 73149]]

(202) 343-2342; email address: <a href="/cdn-cgi/l/email-protection#55121d120730253a27213c3b3207203930153025347b323a23"><span class="__cf_email__" data-cfemail="f5b2bdb2a790859a87819c9b92a7809990b5908594db929a83">[email protected]</span></a>. 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
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                     Category                       NAICS \a\            Examples of affected facilities
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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.
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\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
CO<INF>2</INF> carbon dioxide
CO<INF>2</INF>e 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.

[[Page 73150]]

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.).
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    \1\ U.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.
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    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.
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    \2\ Climate 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.
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    Third, on March 19, 2013, the EPA received a petition from a group 
of non-government 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

[[Page 73151]]

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 real-time continuous methane emission monitoring.'' 
\3\ These proposed revisions, which address this petition, are 
consistent with the EPA's intent to ``collect complete and accurate 
facility-level 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.
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    \3\ Petition 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.
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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 first-time 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.
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    \4\ U.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.
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    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

[[Page 73152]]

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 sub-basin 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-to-oil 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 PR<INF>s,p</INF> (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 PR<INF>s,p</INF> 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

[[Page 73153]]

gathering and boosting system is a single network of pipelines, 
compressors and process equipment, including equipment to perform 
natural gas compression, dehydration, and acid gas removal, that has 
one or more well-defined connection points to gas and oil production 
and a well-defined downstream endpoint, typically a gas 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\
---------------------------------------------------------------------------

    \5\ U.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.
---------------------------------------------------------------------------

    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 (CO<INF>2</INF>e) 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

[[Page 73154]]

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

[[Page 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 CO<INF>2</INF>e 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 non-
methane 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

[[Page 73156]]

reporting because they do not, as a facility defined in 40 CFR 98.6, 
exceed the 25,000 metric tons CO<INF>2</INF>e 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 CO<INF>2</INF>e 
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

[[Page 73157]]

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 (CO<INF>2</INF>) 
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 CO<INF>2</INF>, natural gas transmission pipeline reporters 
would also report the methane and CO<INF>2</INF> emissions and location 
of each blowdown event.
    The EPA previously considered fugitive emissions that result from 
leaks in transmission pipelines in the re-proposal of subpart W in 
April 2010 (75 FR 18616, April 12, 2010), but did not include 
provisions for these emissions in either the proposed or final rules. 
The April 2010 preamble explained that the EPA did not propose 
reporting requirements for fugitive emissions from leaks in natural gas 
pipeline segments between compressor stations due to the dispersed 
nature of the fugitive emissions, and the fact that, once fugitives are 
found, the leaks causing the emissions are usually addressed quickly 
for safety reasons (75 FR 18616, April 12, 2010). The EPA also 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 
non-contiguous 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.
---------------------------------------------------------------------------

    \6\ The 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.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \7\ American 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.
    \8\ The 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.
---------------------------------------------------------------------------

    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

[[Page 73158]]

Natural Gas Production segment to report a list of well identification 
numbers associated with different emission sources for all wells in a 
sub-basin included in the reported emissions data. Reporting the well 
identification numbers associated with different emission sources for 
each sub-basin 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.<SUP>9 10</SUP>
---------------------------------------------------------------------------

    \9\ Allen, 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.
    \10\ EPA Handbook: Optical Remote Sensing for Measurement and 
Monitoring of Emissions Flux, http://www.epa.gov/ttnemc01/guidlnd/gd-052.pdf.
---------------------------------------------------------------------------

    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 real-time 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

[[Page 73159]]

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\
---------------------------------------------------------------------------

    \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.''
    \12\ Revisions to Reporting and Recordkeeping Requirements, and 
Confidentiality Determinations Under the Greenhouse Gas Reporting 
Program; Final Rule. (79 FR 63750, October 24, 2014).
---------------------------------------------------------------------------

    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

[[Page 73160]]

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.
---------------------------------------------------------------------------

    \13\ In the 2011 Final CBI rule, several data categories include 
both CBI and non-CBI data elements. See 76 FR 30786.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \14\ See the ``Change to the Reporting Date for Certain Data 
Elements Required Under the Mandatory Reporting of Greenhouse Gases 
Rule'' (hereinafter referred to as the ``Final Deferral Notice'') 
(76 FR 53057, August 25, 2011) and the accompanying memorandum 
entitled ``Process for Evaluating and Potentially Amending Part 98 
Inputs to Emission Equations'' (Docket ID EPA-HQ-OAR-2010-0929).
    \15\ See the memoranda titled ``Summary of Data Collected to 
Support Determination of Public Availability of Inputs to Emission 
Equations for which Reporting was Deferred to March 31, 2015'' and 
``Evaluation of Competitive Harm from Disclosure of Inputs to 
Equations Data Elements Deferred to March 31, 2015.'' (Docket ID 
EPA-HQ-OAR-2010-0929).
---------------------------------------------------------------------------

    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 (Sec.  
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 (Sec.  98.236(g)(5)(i)); (3) the measured flowback rate, in 
standard cubic feet per hour, for each sub-basin (Sec.  
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 
(Sec.  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

[[Page 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 (Sec.  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-by-case 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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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

[[Page 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.
---------------------------------------------------------------------------

    \16\ See 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).

---------------------------------------------------------------------------

[[Page 73170]]

[GRAPHIC] [TIFF OMITTED] TP09DE14.007


[[Page 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-by-case confidentiality 
determinations made in response to individual claims for confidential 
treatment not made through rulemaking. It provides an opportunity to 
rebut the agency's proposed determinations prior to finalization. We 
will evaluate the comments on our proposed determinations, including 
claims of confidentiality and information substantiating such claims, 
before finalizing the confidentiality determinations. Please note that 
this will be a reporter's only opportunity to substantiate a 
confidentiality claim for 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

[[Page 73172]]

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.
---------------------------------------------------------------------------

    \17\ The EPA's RFA guidance for rule writers suggests the 
``sales'' test continues to be the preferred quantitative metric for 
economic impact screening analysis.

                                                Table 4--Estimated Cost-To-Sales Ratios for First Year Costs by Industry and Enterprise Size \a\
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                                                                                   Owned by enterprises with:
                                                                                                          Average              -----------------------------------------------------------------
                                                                                  SBA size standard      cost per      All         <20                  100 to                500 to
            Industry segment              NAICS        NAICS description        (effective January 22,    entity   enterprises  employees   20 to 99     499        <500       999      1,000 to
                                                                                        2014)            ($1,000/   (percent)      \b\     employees  employees  employees  employees    2,499
                                                                                                          entity)               (percent)  (percent)  (percent)  (percent)  (percent)  employees
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Onshore Petroleum and Natural Gas            211  Oil and Gas Extraction....  500 employees............    $29.36       0.07        0.43       0.03       0.01       0.09       0.00    0.00
 Production.
                                          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  $35.5 million............     29.36       0.45        1.24       0.39       0.08       0.33       0.02      NA
                                                   and Gas Operations.
                                             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             211  Oil and Gas Extraction....  500 employees............      3.19       0.01        0.05       0.00       0.00       0.01       0.00    0.00
 Pipeline.
                                          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  $35.5 million............      3.19       0.05        0.13       0.04       0.01       0.04       0.00      NA
                                                   and Gas Operations.
                                             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            211  Oil and Gas Extraction....  500 employees............     24.70       0.06        0.36       0.03       0.01       0.08       0.00    0.00
 Gathering and Boosting.
                                          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  $35.5 million............     24.70       0.38        1.04       0.32       0.07       0.27       0.02      NA
                                                   and Gas Operations.
                                             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
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
\a\ The 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.
\b\ The 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.


[[Page 73173]]

    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 CO<INF>2</INF>e 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-for-profit 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

[[Page 73174]]

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

[[Page 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

0
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

0
2. Section 98.230 is amended by adding paragraphs (a)(9) and (10) to 
read as follows:


Sec. Sec.  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 Sec.  98.238.
* * * * *
0
3. Section 98.231 is amended by revising paragraph (a) to read as 
follows:


Sec.  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 Sec.  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 Sec.  98.232(c) emit 25,000 metric tons of 
CO<INF>2</INF> equivalent or more per year.
    (2) Facilities must report emissions from the natural gas 
distribution industry segment only if emission sources specified in 
paragraph Sec.  98.232(i) emit 25,000 metric tons of CO<INF>2</INF> 
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 Sec.  98.232(j) emit 25,000 metric tons 
of CO<INF>2</INF> 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 Sec.  98.232(m) emit 25,000 metric tons of CO<INF>2</INF> 
equivalent or more per year.
* * * * *
0
4. Section 98.232 is amended by:
0
a. Revising paragraphs (a) and (c)(6) and (8);
0
b. Adding paragraph (j);
0
c. Revising paragraph (k); and
0
d. Adding paragraph (m).
    The revisions and additions read as follows:


Sec.  98.232  GHGs to report.

    (a) You must report CO<INF>2</INF>, CH<INF>4</INF>, and 
N<INF>2</INF>O emissions from each industry segment specified in 
paragraphs (b) through (j) and (m) of this section, CO<INF>2</INF>, 
CH<INF>4</INF>, and N<INF>2</INF>O 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.
* * * * *

[[Page 73176]]

    (j) For an onshore petroleum and natural gas gathering and boosting 
facility, report CO<INF>2</INF>, CH<INF>4</INF>, and N<INF>2</INF>O 
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 Sec.  98.233(z) and report under 
this subpart the emissions of CO<INF>2</INF>, CH<INF>4</INF>, and 
N<INF>2</INF>O 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 Sec.  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 CO<INF>2</INF>, CH<INF>4</INF>, 
and N<INF>2</INF>O 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 
CO<INF>2</INF> and CH<INF>4</INF> emissions from blowdown vent stacks.
0
5. Section 98.233 is amended by:
0
a. Revising the parameters ``EF<INF>t</INF>'' and ``GHG<INF>i</INF>'' 
of Equation W-1 in paragraph (a);
0
b. Revising paragraph (a)(2);
0
c. Revising the parameter ``EF'' of Equation W-2 in paragraph (c);
0
d. Revising paragraph (d)(8)(iii);
0
e. Revising paragraphs (g) introductory text, (g)(1) introductory text, 
(g)(1)(i) and the paragraph (g)(1)(ii) heading;
0
f. Revising the parameters ``FRM<INF>s</INF>,'' ``FR<INF>s,p</INF>'' 
and ``PR<INF>s,p</INF>'' of Equation W-12A in paragraph (g)(1)(iii);
0
g. Revising the parameters ``FRM<INF>i,</INF>'' and 
``PR<INF>s,p</INF>'' of Equation W-12B in paragraph (g)(1)(iv);
0
h. Revising paragraphs (g)(1)(v) and (vi);
0
i. Adding paragraph (g)(1)(vii);
0
j. Revising paragraph (g)(2) introductory text;
0
k. Adding paragraph (g)(2)(iv);
0
l. Revising paragraph (g)(4) introductory text;
0
m. Revising paragraphs (j) introductory text, (j)(1) introductory text, 
and (j)(6);
0
n. Revising paragraph (n)(2)(i);
0
o. Revising paragraphs (o) introductory text and (o)(10);
0
p. Revising paragraphs (p) introductory text and (p)(10);
0
q. Revising paragraphs (r) introductory text and (r)(2);
0
r. Revising paragraphs (u)(2)(i) and (iii); and
0
x. Revising paragraphs (z) introductory text and (z)(1)(ii).
    The revisions and additions read as follows:


Sec.  98.233  Calculating GHG emissions.

* * * * *
    (a) * * *
* * * * *

EF<INF>t</INF> = 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.
GHG<INF>i</INF> = 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 
GHG<INF>i</INF>, CH<INF>4</INF> or CO<INF>2</INF>, 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 ``Count<INF>t</INF>'' 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 
``Count<INF>t</INF>'' 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 
CO<INF>2</INF> 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

[[Page 73177]]

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 CH<INF>4</INF> and 
CO<INF>2</INF> 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 CH<INF>4</INF>, CO<INF>2</INF>, and 
N<INF>2</INF>O annual emissions as specified in paragraph (g)(4) of 
this section.
[GRAPHIC] [TIFF OMITTED] TP09DE14.008


Where:

E<INF>s,n</INF> = 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.
T<INF>p,s</INF> = 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.
T<INF>p,i</INF> = 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.
FRM<INF>s</INF> = 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.
FRM<INF>i</INF> = 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.
PR<INF>s,p</INF> = 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, PR<INF>s,p</INF> may be calculated for oil wells using 
procedures specified in paragraph (g)(1)(vii) of this section.
EnF<INF>s,p</INF> = Volume of N<INF>2</INF> 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 Sec.  
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 
CO<INF>2</INF> then EnF<INF>s,p</INF> is 0.
FV<INF>s,p</INF> = 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 Sec.  98.234(b).
FR<INF>p,i</INF> = 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 Sec.  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 
FRM<INF>s</INF> and FRM<INF>i</INF>. 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 FRM<INF>s</INF> and FRM<INF>i</INF>. 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 FRM<INF>s</INF> and FRM<INF>i</INF> must be determined 
individually for completions and workovers per sub-basin 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 sub-basin 
and well type combination; and complete measurements or calculations 
for at least five completions or workovers for greater than 250 
completions or workovers for each sub-basin and well type combination.
    (i) Calculation Method 1. You must use Equation W-12A as specified 
in paragraph (g)(1)(iii) of this section to determine the value of 
FRM<INF>s</INF>. You must use Equation W-12B as specified in paragraph 
(g)(1)(iv) of this section to determine the value of FRM<INF>i</INF>. 
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 Sec.  98.234(b).
    (ii) Calculation Method 2 (for gas wells). * * *
    (iii) * * *
* * * * *

FRM<INF>s</INF> = Ratio of average gas flowback rate, during the 
period of time when sufficient quantities of gas are present to 
enable

[[Page 73178]]

separation, of well completions and workovers from hydraulic 
fracturing to 30-day gas production rate for each sub-basin and well 
type combination.
FR<INF>s,p</INF> = 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 sub-basin and well type combination. Convert measured and 
calculated FR<INF>a</INF> values from actual conditions upstream of 
the restriction orifice (FR<INF>a</INF>) to standard conditions 
(FR<INF>s,p</INF>) 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.
PR<INF>s,p</INF> = 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, PR<INF>s,p</INF> may be 
calculated for oil wells using procedures specified in paragraph 
(g)(1)(vii) of this section.

* * * * *
    (iv) * * *
* * * * *

FRM<INF>i</INF> = 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.
* * * * *
PR<INF>s,p</INF> = 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, PR<INF>s,p</INF> 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 (PR<INF>s,p</INF>) 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.
[GRAPHIC] [TIFF OMITTED] TP09DE14.009


Where:

PR<INF>s,p</INF> = 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.
GOR<INF>p</INF> = 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.
V<INF>p</INF> = 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 Sec.  
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 CH<INF>4</INF>, 
CO<INF>2</INF>, and N<INF>2</INF>O (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 CH<INF>4</INF> and 
CO<INF>2</INF> 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 CH<INF>4</INF> and CO<INF>2</INF> 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 
CH<INF>4</INF>, CO<INF>2</INF>, and N<INF>2</INF>O annual emissions as 
specified in paragraph (j)(6) of this section.
    (1) Calculation Method 1. Calculate annual CH<INF>4</INF> and 
CO<INF>2</INF> emissions from onshore production storage tanks and 
onshore petroleum and natural gas gathering and boosting storage tanks 
using operating conditions in the last

[[Page 73179]]

wellhead gas-liquid separator before liquid transfer to storage tanks. 
Calculate flashing emissions with a software program, such as AspenTech 
HYSYS[supreg] or API 4697 E&P Tank, that uses the Peng-Robinson 
equation of state, models flashing emissions, and speciates 
CH<INF>4</INF> and CO<INF>2</INF> 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.
[GRAPHIC] [TIFF OMITTED] TP09DE14.010


Where:

E<INF>s,i,o</INF> = 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.
E<INF>n</INF> = 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.
T<INF>n</INF> = Total time a dump valve is not closing properly in 
the calendar year in hours. Estimate T<INF>n</INF> 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.
CF<INF>n</INF> = Correction factor for tank emissions for time 
period T<INF>n</INF> is 2.87 for crude oil production. Correction 
factor for tank emissions for time period T<INF>n</INF> 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 Sec.  
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 CH<INF>4</INF> and 
CO<INF>2</INF> 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 CH<INF>4</INF>, CO<INF>2</INF>, and N<INF>2</INF>O 
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 Sec.  
98.232(c)(19) or an onshore petroleum and natural gas gathering and 
boosting facility as specified in Sec.  98.232(j)(8), you must 
calculate volumetric emissions as specified in paragraph (o)(10) of 
this section; and calculate CH<INF>4</INF> and CO<INF>2</INF> 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.
[GRAPHIC] [TIFF OMITTED] TP09DE14.011


Where:

E<INF>s,i</INF> = Annual volumetric GHG<INF>i</INF> (either 
CH<INF>4</INF> or CO<INF>2</INF>) 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.
EF<INF>i,s</INF> = Emission factor for GHG<INF>i</INF>. Use 1.2 x 
10\7\ standard cubic feet per year per compressor for CH<INF>4</INF> 
and 5.30 x 10\5\ standard cubic feet per year per compressor for 
CO<INF>2</INF> at 60 [deg]F and 14.7 psia.
* * * * *
    (p) Reciprocating compressor venting. If you are required to report 
emissions from reciprocating compressor venting as specified in Sec.  
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 CH<INF>4</INF> and 
CO<INF>2</INF> 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 CH<INF>4</INF>, CO<INF>2</INF>, and N<INF>2</INF>O 
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 Sec.  
98.232(c)(11) or an onshore petroleum

[[Page 73180]]

and natural gas gathering and boosting facility as specified in Sec.  
98.232(j)(5), you must calculate volumetric emissions as specified in 
paragraph (p)(10) of this section; and calculate CH<INF>4</INF> and 
CO<INF>2</INF> 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.
[GRAPHIC] [TIFF OMITTED] TP09DE14.012


Where:

E<INF>s,i</INF> = Annual volumetric GHG<INF>i</INF> (either 
CH<INF>4</INF> or CO<INF>2</INF>) emissions from reciprocating 
compressors, at standard conditions, in cubic feet.
Count = Total number of reciprocating compressors.
EF<INF>i,s</INF> = Emission factor for GHG<INF>i</INF>. Use 9.48 x 
10\3\ standard cubic feet per year per compressor for CH<INF>4</INF> 
and 5.27 x 10\2\ standard cubic feet per year per compressor for 
CO<INF>2</INF> at 60 [deg]F and 14.7 psia.
* * * * *
    (r) Equipment leaks by population count. This paragraph applies to 
emissions sources listed in Sec.  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 CH<INF>4</INF> plus 
CO<INF>2</INF> by weight. Emissions sources in streams with gas content 
less than or equal to 10 percent CH<INF>4</INF> plus CO<INF>2</INF> 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 Sec.  98.232(i)(3). Natural gas distribution facility 
emission sources listed in Sec.  98.232(i)(3) must calculate emissions 
using Equation W-32B and according to paragraph (r)(6)(ii) of this 
section.
[GRAPHIC] [TIFF OMITTED] TP09DE14.013

[GRAPHIC] [TIFF OMITTED] TP09DE14.014


Where:

E<INF>s,e,i</INF> = Annual volumetric emissions of GHG<INF>i</INF> 
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.
E<INF>s,MR,i</INF> = Annual volumetric emissions of GHG<INF>i</INF> 
from all 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 annual volumetric emissions of 
GHG<INF>i</INF> from all meter/regulator runs at above grade 
transmission-distribution transfer stations, in standard cubic feet.
Count<INF>e</INF> = 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.
Count<INF>MR</INF> = 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.
EF<INF>s,e</INF> = 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.
EF<INF>s,MR,i</INF> = Meter/regulator run population emission factor 
for GHG<INF>i</INF> based on all surveyed above grade transmission-
distribution transfer stations over ``n'' years, in standard cubic 
feet of GHG<INF>i</INF> per operational hour of all meter/regulator 
runs, as determined in Equation W-31.
GHG<INF>i</INF> = For onshore petroleum and natural gas production 
facilities and onshore petroleum and natural gas gathering and 
boosting facilities, concentration of GHG<INF>i</INF>, 
CH<INF>4</INF>, or CO<INF>2</INF>, in produced natural gas as 
defined in paragraph (u)(2) of this section; for onshore natural gas 
transmission compression and underground natural gas storage, 
GHG<INF>i</INF> equals 0.975 for CH<INF>4</INF> and 1.1 x 
10<SUP>-2</SUP> for CO<INF>2</INF>; for LNG storage and LNG import 
and export equipment, GHG<INF>i</INF> equals 1 for CH<INF>4</INF> 
and 0 for CO<INF>2</INF>; and for natural gas distribution, 
GHG<INF>i</INF> equals 1 for CH<INF>4</INF> and 1.1 x 
10<SUP>-2</SUP> CO<INF>2</INF>.
T<INF>e</INF> = 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.
T<INF>w,avg</INF> = 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

[[Page 73181]]

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 CO<INF>2</INF> 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 CO<INF>2</INF>, CH<INF>4</INF>, and 
N<INF>2</INF>O 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 Sec.  98.236(z) and not according to 
the reporting requirements specified in subpart C of this part.
* * * * *
0
6. Section 98.234 is amended by adding paragraph (g) to read as 
follows:


Sec.  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 Sec.  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 Sec.  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 
Sec.  98.233(e), (g), (o), (p), and (r).
    (ii) Number of blowdowns, completions, workovers, or other events 
in Sec.  98.233(g) and (i).
    (iii) Cumulative volume produced, volume input or output, or volume 
of fuel used in paragraphs Sec.  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.

[[Page 73182]]

    (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.
* * * * *
0
7. Section 98.236 is amended by:
0
a. Revising paragraph (a) introductory text;
0
b. Adding paragraphs (a)(9) and (10);
0
c. Revising paragraphs (b)(1)(ii)(A) and (B) and (c) introductory text;
0
d. Redesignating paragraphs (c)(2) through (4) as paragraphs (c)(3) 
through (5), respectively;
0
e. Adding new paragraph (c)(2);
0
f. Revising paragraphs (d)(1) introductory text and (d)(1)(i);
0
g. Redesignating paragraphs (d)(1)(ii) through (vi) as paragraphs 
(d)(1)(iii) through (vii), respectively;
0
h. Adding new paragraph (d)(1)(ii);
0
i. Revising newly redesignated paragraph (d)(1)(vii);
0
j. Revising paragraphs (e)(1) introductory text and (e)(1)(i);
0
k. Redesignating paragraphs (e)(1)(ii) through (xviii) as paragraphs 
(e)(1)(iii) through (xix), respectively;
0
l. Adding new paragraph (e)(1)(ii);
0
m. Revising newly redesignated paragraphs (e)(1)(xvii) introductory 
text, (e)(1)(xviii) introductory text, and (e)(1)(xix);
0
n. Revising paragraph (e)(2) introductory text;
0
o. Redesignating paragraphs (e)(2)(ii) through (v) as paragraphs 
(e)(2)(iii) through (vi), respectively;
0
q. Adding new paragraph (e)(2)(ii);
0
p. Revising newly redesignated paragraphs (e)(2)(iii), (e)(1)(iv), 
(e)(2)(v) introductory text, and (e)(2)(vi) introductory text;
0
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);
0
r. Adding paragraph (g)(5)(iii);
0
s. Revising paragraph (g)(6);
0
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;
0
u. Adding paragraph (i)(3);
0
v. Revising paragraphs (j) introductory text and (j)(1) introductory 
text;
0
w. Redesignating paragraphs (j)(1)(ii) through (xiv) as paragraphs 
(j)(1)(iv) through (xvi), respectively;
0
x. Adding new paragraphs (j)(1)(ii) and (j)(1)(iii);
0
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;
0
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;
0
aa. Redesignating paragraphs (l)(1)(ii) through (vi) as paragraphs 
(l)(1)(iii) through (vii), respectively;
0
bb. Adding new paragraph (l)(1)(ii);
0
cc. Revising newly designated paragraph (l)(1)(v);
0
dd. Revising paragraph (l)(2) introductory text;
0
ee. Redesignating paragraphs (l)(2)(ii) through (vii) as paragraphs 
(l)(2)(iii) through (viii), respectively;
0
ff. Adding new paragraph (l)(2)(ii);
0
gg. Revising newly designated paragraph (l)(2)(v);
0
hh. Revising paragraph (l)(3) introductory text;
0
ii. Redesignating paragraphs (l)(3)(ii) through (v) as paragraphs 
(l)(3)(iii) through (vi), respectively;
0
jj. Adding new paragraph (l)(3)(ii);
0
kk. Revising newly designated paragraph (l)(3)(iv);
0
ll. Revising paragraph (l)(4) introductory text;
0
mm. Redesignating paragraphs (l)(4)(ii) through (vi) as paragraphs 
(l)(4)(iii) through (vii), respectively;
0
nn. Adding new paragraph (l)(4)(ii);
0
oo. Revising newly designated paragraph (l)(4)(iv);
0
pp. Revising paragraphs (m)(1), (m)(5), (m)(6), (m)(7)(i), (m)(8)(i), 
(n) introductory text and (n)(1);
0
qq. Adding paragraph (n)(13);
0
rr. Revising paragraphs (o) introductory text and (o)(5) introductory 
text;
0
ss. Redesignating paragraphs (o)(5)(ii) and (iii) as paragraphs 
(o)(5)(iii) and (iv), respectively;
0
tt. Adding new paragraph (o)(5)(ii);
0
uu. Revising paragraphs (p) introductory text and (p)(5) introductory 
text;
0
vv. Redesignating paragraphs (p)(5)(ii) and (iii) as paragraphs 
(p)(5)(iii) and (iv), respectively;
0
ww. Adding new paragraph (p)(5)(ii);
0
xx. Revising paragraphs (r)(1) introductory text, (r)(1)(i), (r)(3) 
introductory text, (r)(3)(ii), (w)(2), and (x) introductory text;
0
yy. Redesignating paragraphs (x)(2) through (4) as paragraphs (x)(3) 
through (5), respectively;
0
zz. Adding new paragraph (x)(2);
0
aaa. Revising paragraphs (z) introductory text and (z)(1) introductory 
text;
0
bbb. Adding new paragraph (z)(1)(iii);
0
ccc. Revising paragraph (z)(2) introductory text;
0
ddd. Redesignating paragraphs (z)(2)(ii) through (vi) as paragraphs 
(z)(2)(iii) through (vii), respectively;
0
eee. Adding new paragraph (z)(2)(ii);
0
fff. Revising paragraphs (aa) introductory text and (aa)(1)(ii)(D) 
through (H);
0
ggg. Adding paragraphs (aa)(10) and (11); and
0
hhh. Revising paragraph (cc).
    The revisions and additions read as follows:


Sec.  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.

[[Page 73183]]

    (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 Sec.  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 Sec.  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

[[Page 73184]]

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 sub-basin.
* * * * *
    (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 sub-basin 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 ``T<INF>p,i</INF>'' and 
sum of ``T<INF>p,s</INF>'' 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 Sec.  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 ``FR<INF>s,p</INF>'' 
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 Sec.  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 (``GOR<INF>p</INF>'' 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 (``V<INF>p</INF>'' 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 (``FV<INF>s,p</INF>'' 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 (``FR<INF>p,i</INF>'' 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 sub-basin 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 ``V<INF>p</INF>'' 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 Sec.  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 sub-basin 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 ``V<INF>p</INF>'' 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 Sec.  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 sub-basin 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 CO<INF>2</INF> emissions in metric tons CO<INF>2</INF>.

[[Page 73185]]

    (ii) Annual CH<INF>4</INF> emissions in metric tons CH<INF>4</INF>.
    (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 Sec.  
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 
CO<INF>2</INF> in flash gas from onshore production and onshore natural 
gas gathering and boosting storage tanks.
    (x) The minimum and maximum concentration (mole fraction) of 
CH<INF>4</INF> 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 Sec.  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 Sec.  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

[[Page 73186]]

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 Sec.  
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 Sec.  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 Sec.  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 ``V<INF>p,q</INF>'' 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 Sec.  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 
Sec.  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 Sec.  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 sub-basin.
    (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 Sec.  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 Sec.  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 Sec.  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 Sec.  
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

[[Page 73187]]

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 Sec.  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.

[[Page 73188]]

    (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 Sec.  98.3(b) introductory text.
0
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:


Sec.  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.
* * * * *
0
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   Emission factor (scf/
                    boosting                          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

[[Page 73189]]

 
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
------------------------------------------------------------------------
\1\ For multi-phase flow that includes gas, use the gas service
  emissions factors.
\2\ Emission Factor is in units of ``scf/hour/device.''
\3\ Emission Factor is in units of ``scf/hour/pump.''
\4\ Hydrocarbon liquids greater than or equal to 20[deg]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[deg]API are considered ``heavy
  crude.''
\7\ Emission factor is in units of ``scf/hour/mile of pipeline.''


[[Page 73190]]

0
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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