[Federal Register Volume 79, Number 236 (Tuesday, December 9, 2014)]
[Proposed Rules]
[Pages 73147-73190]
[FR Doc No: 2014-28395]

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

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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:
     Federal eRulemaking Portal: http://www.regulations.gov.
Follow the online instructions for submitting comments.
     Email<EMAIL_ADDRESS>Include Docket ID No. EPA-
HQ-OAR-2014-0831 or RIN No. 2060-AS37 in the subject line of the
message.
     Fax:<PHONE_NUMBER>.
     Mail: Environmental Protection Agency, EPA Docket Center
(EPA/DC), Mailcode 28221T, Attention Docket ID No. EPA-HQ-OAR-2014-
0831, 1200 Pennsylvania Avenue NW., Washington, DC 20460. In addition,
please mail a copy of your comments on the information collection
provisions to the Office of Information and Regulatory Affairs, Office
of Management and Budget (OMB), Attn: Desk Officer for EPA, 725 17th
Street, NW., Washington, DC 20503.
     Hand/Courier Delivery: EPA Docket Center, Room 3334, EPA
WJC West Building, 1301 Constitution Avenue NW., Washington, DC 20004.
Such deliveries are accepted only during the normal hours of operation
of the Docket Center, and special arrangements should be made for
deliveries of boxed information.
    Additional Information on Submitting Comments: To expedite review
of your comments by agency staff, you are encouraged to send a separate
copy of your comments, in addition to the copy you submit to the
official docket, to Carole Cook, U.S. EPA, Office of Atmospheric
Programs, Climate Change Division, Mail Code 6207A, 1200 Pennsylvania
Avenue NW., Washington, DC 20460, telephone<PHONE_NUMBER>, email
address<EMAIL_ADDRESS>    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<PHONE_NUMBER>, and the telephone
number for the Air Docket is<PHONE_NUMBER>.

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:<PHONE_NUMBER>; fax number:

(202) 343-2342; email address<EMAIL_ADDRESS>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
CO2 carbon dioxide
CO2e carbon dioxide equivalent
EPA Environmental Protection Agency
EIA Energy Information Administration
FERC Federal Energy Regulatory Commission
FR Federal Register
GHG greenhouse gas
GHGRP Greenhouse Gas Reporting Program
GOR gas-to-oil ratio
ICR Information Collection Request
ISBN International Standard Book Number
LDC local distribution company
MMscfd million standard cubic feet per day
NAICS North American Industry Classification System
NESHAP national emission standards for hazardous air pollutants
NGO non-government organization
NGPA Natural Gas Policy Act
NTTAA National Technology Transfer and Advancement Act of 1995
OMB Office of Management and Budget
PPDM Professional Petroleum Data Management
REC reduced emission completion
RFA Regulatory Flexibility Act
SBA Small Business Administration
SBREFA Small Business Regulatory Enforcement and Fairness Act
U.S. United States
UMRA Unfunded Mandates Reform Act of 1995

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

I. Background
    A. Organization of This Preamble
    B. Background on the Proposed Action
    C. Legal Authority
    D. How would these amendments apply to 2015 and 2016 reports?
II. Revisions and Other Amendments
    A. Oil Wells With Hydraulic Fracturing
    B. Onshore Petroleum and Natural Gas Gathering and Boosting
Segment
    C. Natural Gas Transmission Lines Between Compressor Stations
    D. Well Identification Numbers
    E. Advanced Innovative Monitoring Methods
    F. Best Available Monitoring Methods
III. Proposed Confidentiality Determinations
    A. Overview and Background
    B. Approach to Proposed CBI Determinations
    C. Proposed Confidentiality Determinations for Data Elements
Assigned to the ``Unit/Process `Static' Characteristics That Are Not
Inputs to Emission Equations'' and ``Unit/Process Operating
Characteristics That Are Not Inputs to Emission Equations'' Data
Categories
    D. Other Proposed Case-by-Case Confidentiality Determinations
for Subpart W
    E. Request for Comments on Proposed Confidentiality
Determinations
IV. Impacts of the Proposed Amendments to Subpart W
    A. Costs of the Proposed Amendments
    B. Impacts of the Proposed Amendments on Small Businesses
V. Statutory and Executive Order Reviews
    A. Executive Order 12866: Regulatory Planning and Review and
Executive Order 13563: Improving Regulation and Regulatory Review
    B. Paperwork Reduction Act
    C. Regulatory Flexibility Act
    D. Unfunded Mandates Reform Act
    E. Executive Order 13132: Federalism
    F. Executive Order 13175: Consultation and Coordination With
Indian Tribal Governments
    G. Executive Order 13045: Protection of Children From
Environmental Health Risks and Safety Risks
    H. Executive Order 13211: Actions That Significantly Affect
Energy Supply, Distribution, or Use
    I. National Technology Transfer and Advancement Act
    J. Executive Order 12898: Federal Actions To Address
Environmental Justice in Minority Populations and Low-Income
Populations

I. Background

A. Organization of This Preamble

    The first section of this preamble provides background information
regarding the proposed amendments. This section also discusses the
EPA's legal authority under the CAA to promulgate and amend 40 CFR part
98 (hereafter referred to as ``Part 98'') as well as the legal
authority for making confidentiality determinations for the data to be
reported. Section II of this preamble contains information on the
proposed revisions to 40 CFR part 98, subpart W (hereafter referred to
as ``subpart W''). Section III of this preamble discusses proposed
confidentiality determinations for new data reporting elements. Section
IV of this preamble discusses the impacts of the proposed amendments to
subpart W.

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

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

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 PRs,p (the average gas production flow
rate during the first 30 days of production after the completion or
workover), which is used as an input to Equation W-10A. In this
proposed Equation W-12C, the value of PRs,p would be
calculated by multiplying the GOR of the well by the measured oil
production rate during the first 30 days of production after the
completion or workover to calculate average gas production flow rate.
    The EPA is not proposing at this time to allow the use of
calculated flowback rate for oil wells based on well parameters, as
specified in Calculation Method 2 in 40 CFR 98.233(g). In the current
subpart W, Calculation Method 2 uses the measured gas pressure
differential across the well choke to estimate gas flow rate. Based on
the information available, the EPA concluded that this methodology may
not be appropriate for estimating emissions from oil well completions
because of the differences in operational conditions between oil and
gas production. The EPA is seeking comment on how an engineering
estimate of gas flow rate for oil wells might be performed as an
alternative to the proposed monitoring methods that would require
direct measurement of gas flow rate. Such an engineering estimate would
be analogous to the current Calculation Method 2, but with alternatives
to the current Equations 11-A and 11-B that would be applicable to oil
wells. If an appropriate and technically sound approach can be
identified, an engineering estimate methodology analogous to
Calculation Method 2 for gas wells would reduce the burden for
reporters of oil well completions and workovers with hydraulic
fracturing.
    Additionally, the EPA is seeking comment on whether to establish a
minimum GOR threshold such that oil wells with a very low GOR would not
be subject to the monitoring and reporting requirements for GHG
emissions from completions and workovers with hydraulic fracturing. The
EPA is also soliciting data and other supporting information that could
be used to establish a level for that threshold in the final rule
amendments, if that approach were adopted. Supporting data should
include, at a minimum, information sufficient to identify the location
of any wells for which data are provided (e.g., US Well Number), the
measured GOR, and whether the GOR for the well was measured during
completion or workover. Information that would allow the EPA to
estimate the typical emissions from wells with such a low GOR, and to
estimate the total emissions from all wells that would be exempt if
such a threshold were established, would be particularly helpful to
inform potential inclusion of a GOR threshold in the final rule. The
EPA particularly solicits specific data, rather than conclusory
statements, to support commenters' positions on whether the EPA should
include a minimum GOR threshold for monitoring and reporting.
    The EPA is also seeking comment on whether to establish a minimum
well pressure such that oil wells operating below a certain pressure
would not be subject to the monitoring and reporting requirements for
GHG emissions from completions and workovers with hydraulic fracturing.
Similar to the discussion on a potential GOR threshold above, the EPA
is also soliciting data and other supporting information that could be
used to establish a level for the well pressure threshold in the final
rule amendments, if that approach were adopted. Supporting data should
include, at a minimum, information sufficient to identify the location
of any wells for which data are provided (e.g., US Well Number), the
measured well pressure, and whether the well pressure was measured
during completion or workover. Information that would allow the EPA to
estimate the typical emissions from wells with low well pressures, and
to estimate the total emissions from all wells that would be exempt if
such a threshold were established, would be particularly helpful to
inform potential inclusion of a well pressure threshold in the final
rule. The EPA particularly solicits specific data, rather than
conclusory statements, to support commenters' positions on whether the
EPA should include a minimum well pressure threshold for monitoring and
reporting.

B. Onshore Petroleum and Natural Gas Gathering and Boosting Segment

    The EPA is proposing to add a new industry segment to subpart W,
Onshore Petroleum and Natural Gas Gathering and Boosting, that would
cover emissions from equipment used by gathering pipeline systems that
move petroleum and natural gas from the well to either larger gathering
pipeline systems, natural gas processing plants, natural gas
transmission pipelines, or natural gas distribution pipelines. A

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\
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    \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 (CO2e) or
more per year. The basin-level reporting approach that the EPA is
proposing for onshore petroleum and natural gas gathering and boosting
facilities is currently being used for reporting in the Onshore
Petroleum and Natural Gas Production sector. The proposed basin-level
approach for the Onshore Petroleum and Natural Gas Gathering and
Boosting

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

Processing segment, the same methods would be applicable.
    For compressors and equipment leaks, subpart W contains one method
in the Onshore Petroleum and Natural Gas Production segment and a
different method for the same emission source in the Onshore Natural
Gas Processing segment. We are proposing that the gathering and
boosting reporters use the same method as in the Onshore Petroleum and
Natural Gas Production segment. The method for the Onshore Petroleum
and Natural Gas Production segment for compressors and equipment leaks
relies on the reporter counting the number of compressors or components
(e.g., population counts) and then applying emission factors per
compressor or component for that population. Alternatively, for
equipment leaks, the reporter may count the number of pieces of major
equipment, assume the default component counts in Table W-1B, and then
apply emission factors per component. This proposed population count
approach is appropriate for the Onshore Petroleum and Natural Gas
Gathering and Boosting segment because, as in the Onshore Petroleum and
Natural Gas Production segment, the equipment is often geographically
dispersed and may be visited only intermittently. Under the proposed
approach, a reporter would need to establish an inventory of the
components or equipment subject to the population counts, apply the
emission factors, and then update the inventory each year to account
for new or retired components or equipment. The EPA also seeks comment
on the appropriateness of the methods used in the Onshore Natural Gas
Processing segment for compressors and equipment leaks, which are
outlined in 40 CFR 98.234(a).
    For gathering pipelines, the EPA is proposing to use an emission
factor approach that is essentially the same as the approach used for
equipment leaks in the Onshore Petroleum and Natural Gas Production
segment. For gathering lines, reporters would use the population count
and emission factor approach in 40 CFR 98.233(r). The emission factors
that are being proposed, which would be added to an amended Table W-1A,
are whole gas emission factors based on the U.S. GHG Inventory. The
population count would be the miles of gathering pipeline, similar to
the approach used for calculating emissions from natural gas
distribution pipelines in the Natural Gas Distribution segment.
    The EPA has determined that the proposed monitoring and reporting
requirements minimize the potential confusion associated with
calculating emissions from the Onshore Petroleum and Natural Gas
Gathering and Boosting segment by adopting the same methods used for
calculating emissions that are used in the Onshore Petroleum and
Natural Gas Production segment and the Onshore Natural Gas Processing
segment. The EPA requests comment on whether the proposed monitoring
and reporting requirements for the proposed Onshore Petroleum and
Natural Gas Gathering and Boosting segment are appropriate for these
emission sources, and if not, what methodologies would be more
appropriate.
    Data collected through the proposed reporting requirements for the
Onshore Petroleum and Natural Gas Gathering and Boosting segment in
subpart W would improve the EPA's estimates and understanding of
emissions from sources covered by the new segment and from the
petroleum and natural gas sector. The improved data would provide a
better understanding of sources in the petroleum and natural gas
industry for which the public currently has little information. For
example, the data that would be collected through these proposed
revisions would inform updates to the U.S. GHG Inventory.
    The proposed requirements would require the reporting of GHG
emissions from an entire gathering and boosting facility instead of the
partial approach that currently exists under the GHGRP. Specifically,
some gathering and boosting emission sources, such as natural gas
compression stations, are only required to report GHG emissions if the
facility exceeds the 25,000 metric tons CO2e annual emission
reporting threshold in subpart A, 40 CFR 98.2(a)(2), based on
combustion emissions that are reported under subpart C. Subpart W does
currently require reporting from facilities that perform ``natural gas
processing'' in 40 CFR 98.230(a)(3), but this requirement is only for
those facilities that perform separation of natural gas liquids or 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

reporting because they do not, as a facility defined in 40 CFR 98.6,
exceed the 25,000 metric tons CO2e per year reporting
threshold in subpart A, 40 CFR 98.2(a)(2). However, when aggregated
with the gathering pipelines and other compressor stations that are
under common ownership and control within a system, the complete system
may exceed the reporting threshold and would be required to begin
reporting.
    The EPA considered other reporting options for defining the
facility and the level of reporting, but none of them would have
achieved the same balance of geographically specific information and
reduced industry burden as the proposed option. One option considered
was using the definition of ``facility'' found in 40 CFR 98.6 that
states, ``Facility means any physical property, plant, building,
structure, source, or stationary equipment located on one or more
contiguous or adjacent properties in actual physical contact or
separated solely by a public roadway or other public right-of-way and
under common ownership or common control, that emits or may emit any
greenhouse gas. Operators of military installations may classify such
installations as more than a single facility based on distinct and
independent functional groupings within contiguous military
properties.'' This would mean that each piece of property (or adjacent
properties under common ownership or common control) with gathering and
boosting equipment that exceeded the 25,000 metric tons CO2e
annual threshold would be considered its own ``facility''. This option
provided limited data on the segment as a whole due to decreased
coverage compared to other options, though more granular, site-specific
data would likely be achievable for this option. This option would also
require separate reports for each compressor station and/or gathering
line, which would have resulted in a high reporting burden on owners/
operators in this segment. Therefore, the EPA concluded that this
option would not achieve the goals of having a thorough data set and
transparent, complete information for this sector while minimizing
burden to reporters. The EPA also considered an option that would have
separated the gathering pipelines and gathering and boosting stations
(e.g., facilities with compressors, dehydration, and acid gas removal)
into different segments. The gathering and boosting stations would have
reported at the basin level, and the pipelines at the national level
(e.g. all gathering pipelines owned by a person or entity within the
United States). However, the EPA is not proposing this option because
it would have potentially resulted in higher burden to reporters by
requiring reporting of additional facilities under their ownership. The
EPA is seeking comment on whether these options should be considered
and how they might achieve transparent and complete data for this
segment without imposing additional burden on reporters compared to the
proposed option. For more information regarding the options considered
for defining the facility, see ``Greenhouse Gas Reporting Rule:
Technical Support for 2015 Revisions and Confidentiality Determinations
for Petroleum and Natural Gas Systems; Proposed Rule.''

C. Natural Gas Transmission Lines Between Compressor Stations

    The EPA is proposing to add reporting requirements for emissions
from natural gas transmission pipeline blowdowns between compressor
stations in a new Onshore Natural Gas Transmission Pipeline segment.
For purposes of the Onshore Natural Gas Transmission Pipeline segment,
a blowdown is the release of gas from transmission pipelines for the
purpose of reducing system pressure or complete depressurization.
Transmission pipeline blowdowns occur when, a segment of pipeline is
isolated from the rest of the line and the natural gas inside is purged
through a blowdown vent stack. These blowdowns are needed to safely
inspect and maintain the pipelines, but the purging of natural gas
produces methane emissions that are currently not included in subpart
W. In the U.S. GHG Inventory, the EPA estimated that there were over
300,000 miles of transmission pipelines in 2012, and the blowdown
emissions associated with those pipelines were estimated to be 85,000
metric tons of methane a year. Although subpart W does require
reporting of emissions from onshore natural gas transmission
compression stations, it currently does not cover onshore natural gas
transmission pipelines in between compressor stations. This represents
a gap in the coverage of emission sources from the petroleum and
natural gas systems source category covered by subpart W.
    The EPA is proposing to define the onshore natural gas transmission
pipeline owner or operator depending on whether the transmission
pipeline is interstate or intrastate. For interstate pipelines, the
onshore natural gas transmission pipeline owner or operator would be
the person identified as the transmission pipeline owner or operator on
the Certificate of Public Convenience and Necessity issued under 15
U.S.C. 717f. For intrastate pipelines, the onshore natural gas
transmission pipeline owner or operator would be the person identified
as the owner or operator on the transmission pipeline's Statement of
Operating Conditions under section 311 of the Natural Gas Policy Act
(NGPA). The Certificate of Public Convenience and Necessity is a
certificate issued by the Federal Energy Regulatory Commission (FERC)
that allows the pipeline company to engage in the transportation and/or
sale for resale of natural gas in interstate commerce or to acquire and
operate facilities needed to accomplish this. The certificate is issued
by FERC after FERC has approved the construction of a pipeline, and it
allows the holder to build and operate the pipeline. Operators of
intrastate pipelines are required to prepare a Statement of Operating
Conditions for compliance under section 311 of the NGPA. Section 311 of
the NGPA allows an interstate pipeline company to sell or transport gas
on behalf of any intrastate pipeline or local distribution company
without prior FERC approval.
    The EPA is proposing that the facility for the new Onshore Natural
Gas Transmission Pipeline segment would be defined as the total U.S.
mileage of natural gas transmission pipelines owned or operated by an
onshore natural gas transmission pipeline owner or operator. If an
entity owned and operated multiple pipelines in the U.S., the facility
would be considered the aggregate of those pipelines, even if they are
not interconnected. In defining the facility, the EPA considered other
options, such as the facility being the amount of pipeline owned and
operated by an entity within a state or basin, or the facility being
each separate pipeline. In considering these other options, the EPA had
to take into account that many major pipeline systems are essentially
linear systems to move gas from one part of the U.S. to another, and
requiring reporters to file separate reports for each portion of the
system in any one state or other defined geography would impose higher
reporting burden on those subject to this source category without
providing the EPA with additional, specific information. The EPA also
took into account the fact that many entities own and operate pipeline
segments that may not be directly interconnected, but are connected
with pipelines owned and operated by other entities as part of the
national network of natural gas transmission pipelines. The proposed
approach limits the burden on reporters to correlate the pipeline
ownership transfer points with

specific geographical segments. Instead, the reporters can track the
required information for their various pipelines, regardless of
location, and submit data associated with all of them in one report.
    The EPA is proposing that reporters would use the methods in 40 CFR
98.233(i) to calculate or measure emissions from pipeline blowdown
events. One method allows a reporter to calculate emissions based on
the volume of the pipeline segment between isolation valves that is
blown down and the pressure and temperature of the gas within the
pipeline. This method uses information that should be readily available
to the reporter (e.g., pipeline length, diameter, and operating
pressure) and so should not be overly burdensome. The second method
allows the reporter to measure the emissions from the blowdown using a
flow meter on the blowdown vent stack. In both methods, the reporter
would calculate both methane and carbon dioxide (CO2)
emissions from the volume of natural gas vented using either default
gas composition or engineering estimates of composition as specified in
40 CFR 98.233(u)(2)(iii). In addition to the total annual emissions of
methane and CO2, natural gas transmission pipeline reporters
would also report the methane and CO2 emissions and location
of each blowdown event.
    The EPA previously considered fugitive emissions that result from
leaks in transmission pipelines in the 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

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.9 10
---------------------------------------------------------------------------

    \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

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

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

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

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).

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[GRAPHIC] [TIFF OMITTED] TP09DE14.007

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

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
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\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.

    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