[Federal Register Volume 80, Number 204 (Thursday, October 22, 2015)]
[Rules and Regulations]
[Pages 64261-64298]
[FR Doc No: 2015-25840]

Vol. 80

Thursday,

No. 204

October 22, 2015

Part V

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; Final Rule

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

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ENVIRONMENTAL PROTECTION AGENCY

40 CFR Part 98

[EPA-HQ-OAR-2014-0831; FRL-9935-50-OAR]
RIN 2060-AS37

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

AGENCY: Environmental Protection Agency (EPA).

ACTION: Final rule.

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SUMMARY: The Environmental Protection Agency (EPA) is finalizing
revisions and confidentiality determinations for the petroleum and
natural gas systems source category of the Greenhouse Gas Reporting
Rule. These revisions include the addition of calculation methods and
reporting requirements for greenhouse gas (GHG) emissions from
gathering and boosting facilities, completions and workovers of oil
wells with hydraulic fracturing, and blowdowns of natural gas
transmission pipelines between compressor stations. The revisions also
include the addition of well identification reporting requirements to
improve the EPA's ability to verify reported data and enhance
transparency. This action also finalizes confidentiality determinations
for new data elements contained in these amendments.

DATES: This final rule is effective on January 1, 2016.

ADDRESSES: The EPA has established a docket for this action under
Docket ID No. EPA-HQ-OAR-2014-0831. All documents in the docket are
listed on the http://www.regulations.gov Web site. Although listed in
the index, some information is not publicly available, e.g.,
confidential business information (CBI) or other information whose
disclosure is restricted by statute. Certain other material, such as
copyrighted material, is not placed on the Internet and will be
publicly available only in hard copy form. Publicly available docket
materials are available electronically through http://www.regulations.gov.

FOR FURTHER INFORMATION CONTACT: Carole Cook, Climate Change Division,
Office of Atmospheric Programs (MC-6207A), Environmental Protection
Agency, 1200 Pennsylvania Ave. NW., Washington, DC 20460; telephone
number:<PHONE_NUMBER>; fax number:<PHONE_NUMBER>; email address:
<EMAIL_ADDRESS>For technical information, please go to the
Greenhouse Gas Reporting Rule Web site, http://www.epa.gov/ghgreporting/. To submit a question, select Help Center, followed by
``Contact Us.''
    Worldwide Web (WWW). In addition to being available in the docket,
an electronic copy of this final rule will also be available through
the WWW. Following the Administrator's signature, a copy of this action
will be posted on the EPA's Greenhouse Gas Reporting Rule Web site at
http://www.epa.gov/ghgreporting/index.html.

SUPPLEMENTARY INFORMATION:
    Regulated Entities. This final rule adds calculation methods,
monitoring, and data reporting requirements and finalizes
confidentiality determinations for the petroleum and natural gas
systems source category of the Greenhouse Gas Reporting Rule (40 CFR
part 98). The Administrator determined that 40 CFR part 98 is subject
to the provisions of Clean Air Act (CAA) section 307(d). See CAA
section 307(d)(1)(V) (the provisions of section 307(d) apply to ``such
other actions as the Administrator may determine''). Entities affected
by this final rule are owners and operators of petroleum and natural
gas systems that directly emit GHGs, which include those listed in
Table 1 of this preamble:

           Table 1--Examples of Affected Entities by Category
------------------------------------------------------------------------
                                                    Examples of affected
             Category                  NAICS \a\         facilities
------------------------------------------------------------------------
Petroleum and Natural Gas Systems.          211111  Crude petroleum and
                                                     natural gas
                                                     extraction.
                                            211112  Natural gas liquid
                                                     extraction.
                                            221210  Natural gas
                                                     distribution.
                                            486210  Pipeline
                                                     transportation of
                                                     natural gas.
------------------------------------------------------------------------
\a\ North American Industry Classification System.

    Table 1 of this preamble is not intended to be exhaustive, but
rather provides a guide for readers regarding facilities likely to be
affected by this action. Types of facilities other than those listed in
the table could also be subject to reporting requirements. To determine
whether you are affected by this action, you should carefully examine
the applicability criteria found in 40 CFR part 98, subpart A and 40
CFR part 98, subpart W. If you have questions regarding the
applicability of this action to a particular facility, consult the
person listed in the preceding FOR FURTHER INFORMATION CONTACT section.
    What is the effective date? The final rule is effective on January
1, 2016.
    Judicial Review. Under CAA section 307(b)(1), judicial review of
this final rule is available only by filing a petition for review in
the U.S. Court of Appeals for the District of Columbia Circuit (the
Court) by December 21, 2015. Under CAA section 307(d)(7)(B), only an
objection to this final rule that was raised with reasonable
specificity during the period for public comment can be raised during
judicial review. Section 307(d)(7)(B) of the CAA also provides a
mechanism for the EPA to convene a proceeding for reconsideration,
``[i]f the person raising an objection can demonstrate to the EPA that
it was impracticable to raise such objection within [the period for
public comment] or if the grounds for such objection arose after the
period for public comment (but within the time specified for judicial
review) and if such objection is of central relevance to the outcome of
the rule.'' Any person seeking to make such a demonstration to us
should submit a Petition for Reconsideration to the Office of the
Administrator, Environmental Protection Agency, Room 3000, William
Jefferson Clinton Building, 1200 Pennsylvania Ave. NW., Washington, DC
20460, with a copy to the person listed in the preceding FOR FURTHER
INFORMATION CONTACT section, and the Associate General Counsel for the
Air and Radiation Law Office, Office of General Counsel (Mail Code
2344A), Environmental Protection Agency, 1200 Pennsylvania Ave. NW.,
Washington, DC 20004. Note that under CAA section 307(b)(2), the
requirements established by this final rule may not be challenged
separately in any civil or criminal proceedings brought by the EPA to
enforce these requirements.
    Acronyms and Abbreviations. The following acronyms and
abbreviations are used in this document.
AGR acid gas removal

API American Petroleum Institute
BAMM best available monitoring methods
CAA Clean Air Act
CBI confidential business information
CFR Code of Federal Regulations
CH4 methane
CO2 carbon dioxide
CO2e carbon dioxide equivalent
e-GGRT Electronic Greenhouse Gas Reporting Tool
EPA U.S. Environmental Protection Agency
FERC Federal Energy Regulatory Commission
FR Federal Register
ft\3\ cubic feet
GHG greenhouse gas
GHGRP Greenhouse Gas Reporting Program
GOR gas to oil ratio
GRI Gas Research Institute
ICR information collection request
ID identification
LDC local distribution company
N2O nitrous oxide
NAICS North American Industry Classification System
NGO non-government organization
NGPA Natural Gas Policy Act
NTTAA National Technology Transfer and Advancement Act
O&M operation and maintenance
OMB Office of Management and Budget
PHMSA Pipeline and Hazardous Materials Safety Administration
psi/ft pounds per square inch per foot
REC reduced emissions completion
RFA Regulatory Flexibility Act
scf standard cubic feet
scf/STB standard cubic feet per stock tank barrel
U.S. United States
UMRA Unfunded Mandates Reform Act of 1995
WWW worldwide web
    Organization of This Document. The following outline is provided to
aid in locating information in this preamble.

I. Background
    A. Organization of This Preamble
    B. Background on This Action
    C. Legal Authority
    D. How do these amendments apply to 2015 and 2016 reports?
II. Summary of Final Revisions and Other Amendments to Subpart W and
Responses to Public Comment
    A. Summary of Final Amendments for Oil Wells With Hydraulic
Fracturing
    B. Summary of Final Amendments for the Onshore Petroleum and
Natural Gas Gathering and Boosting Segment
    C. Summary of Final Amendments for the Onshore Natural Gas
Transmission Pipeline Segment
    D. Summary of Final Amendments for Well Identification Numbers
    E. Summary of Final Amendments to Best Available Monitoring
Methods
III. Final Confidentiality Determinations
    A. Summary of Final Confidentiality Determinations for New
Subpart W Data Elements
    B. Summary of Public Comments and Responses on the Proposed
Confidentiality Determinations
IV. Impacts of the Final Amendments to Subpart W
    A. Impacts of the Final Amendments
    B. Summary of Comments and Responses on the Impacts of the
Proposed Rule
V. Statutory and Executive Order Reviews
    A. Executive Order 12866: Regulatory Planning and Review and
Executive Order 13563: Improving Regulation and Regulatory Review
    B. Paperwork Reduction Act
    C. Regulatory Flexibility Act (RFA)
    D. Unfunded Mandates Reform Act (UMRA)
    E. Executive Order 13132: Federalism
    F. Executive Order 13175: Consultation and Coordination With
Indian Tribal Governments
    G. Executive Order 13045: Protection of Children From
Environmental Health Risks and Safety Risks
    H. Executive Order 13211: Actions Concerning Regulations That
Significantly Affect Energy Supply, Distribution or Use
    I. National Technology Transfer and Advancement Act
    J. Executive Order 12898: Federal Actions To Address
Environmental Justice in Minority Populations and Low-Income
Populations
    K. Congressional Review Act

I. Background

A. Organization of This Preamble

    Section I of this preamble provides background information
regarding the origin of the final amendments. This section also
discusses the EPA's legal authority under the CAA to promulgate and
amend 40 CFR part 98 of the Greenhouse Gas Reporting Rule (hereafter
referred to as ``part 98'') as well as the legal authority for making
confidentiality determinations for the data to be reported. Section II
of this preamble contains information on the final amendments to part
98, subpart W (Petroleum and Natural Gas Systems) (hereafter referred
to as ``subpart W''), including a summary of the major comments that
the EPA considered in the development of this final rule. Section III
of this preamble discusses the final confidentiality determinations for
new data reporting elements. Section IV of this preamble discusses the
impacts of the final amendments to subpart W. Finally, Section V of
this preamble describes the statutory and executive order requirements
applicable to this action.

B. Background on This Action

    The EPA's Greenhouse Gas Reporting Program (GHGRP) requires annual
reporting of GHG data and other relevant information from large sources
and suppliers in the United States. On October 30, 2009, the EPA
published part 98 for collecting information regarding GHG emissions
from a broad range of industry sectors (74 FR 56260). Although
reporting requirements for petroleum and natural gas systems were
originally proposed to be part of part 98 (75 FR 16448; April 10,
2009), the final October 2009 rule did not include the petroleum and
natural gas systems source category as one of the 29 source categories
for which reporting requirements were finalized. The EPA re-proposed
subpart W in 2010 (79 FR 18608; April 12, 2010), and a subsequent final
rule was published on November 30, 2010, with the requirements for the
petroleum and natural gas systems source category at 40 CFR part 98,
subpart W (75 FR 74458) (hereafter referred to as ``the final subpart W
rule''). Following promulgation, the EPA finalized actions revising
subpart W (76 FR 22825, April 25, 2011; 76 FR 59533, September 27,
2011; 76 FR 80554, December 23, 2011; 77 FR 51477, August 24, 2012; 78
FR 25392, May 1, 2013; 78 FR 71904, November 29, 2013; 79 FR 63750,
October 24, 2014; 79 FR 70352, November 25, 2014).
    On December 9, 2014, the EPA proposed ``2015 Revisions and
Confidentiality Determinations for Petroleum and Natural Gas Systems''
(79 FR 76267) to require the reporting of GHG emissions from several
sources that had not previously been included in subpart W. These
sources include completions and workovers of oil wells with hydraulic
fracturing, petroleum and natural gas gathering and boosting systems,
and transmission pipeline blowdowns between compressor stations. The
reporting requirements for completions and workovers of oil wells with
hydraulic fracturing were proposed to be included as part of the
existing Onshore Petroleum and Natural Gas Production industry segment.
For the other sources, the EPA proposed two new industry segments: The
Onshore Petroleum and Natural Gas Gathering and Boosting segment for
petroleum and natural gas gathering and boosting facilities, and the
Onshore Natural Gas Transmission Pipeline segment for transmission
pipeline blowdowns between compressor stations. The EPA also proposed
to require the reporting of a well identification number for oil and
gas wells covered in the Onshore Petroleum and Natural Gas Production
segment. In addition, the EPA proposed confidentiality determinations
for new data elements contained in the proposed amendments. The public
comment period for these proposed rule amendments ended on February 24,
2015, following a 2-week extension of the original comment period end
date (80 FR 6495; February 5, 2015).

    In this action, the EPA is finalizing additions and revisions to
the subpart W calculation, monitoring, and reporting requirements for
new sources, with some changes made in response to public comments.
Responses to comments submitted on the proposed amendments can be found
in sections II, III, and IV of this preamble as well as in ``Response
to Public Comments on Greenhouse Gas Reporting Rule: 2015 Revisions and
Confidentiality Determinations for Petroleum and Natural Gas Systems''
in Docket ID No. EPA-HQ-OAR-2014-0831. As noted in the preamble to the
proposed amendments (79 FR 73148; December 9, 2014), these additions
and revisions further the EPA's goals of improving the completeness,
quality, accuracy, and transparency of data from this sector, and
improving the ability of agencies and the public to use these GHG data
to analyze emissions and understand emission trends.
    The Strategy to Reduce Methane Emissions in the President's Climate
Action Plan summarizes the sources of methane (CH4)
emissions, commits to new steps to cut emissions of this potent GHG,
and outlines the Administration's efforts to improve the measurement of
these emissions. The strategy builds on progress to date and takes
steps to further cut CH4 emissions from several sectors,
including the oil and natural gas sector. In the strategy, the EPA was
tasked to review regulatory requirements to address potential gaps in
coverage, improve methods, and help ensure high quality data
reporting.\1\ The final revisions to subpart W covered in this action
are responsive to this task by addressing data gaps in subpart W,
specifying methods for measuring CH4 emissions, and
providing data that can be used to further analyze CH4
emissions in this industry.
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    \1\ 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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    This action also addresses a petition the EPA received from a group
of non-government organizations (NGOs) requesting that the EPA collect
data from emissions sources not currently included in subpart W,
including well completion emissions from oil wells that co-produce
natural gas, facilities and pipelines in the gathering and boosting
segment, and transmission pipeline blowdown events (``Petition for
Rulemaking'').\2\ Table 2 of this preamble summarizes how the EPA has
responded to the Petition for Rulemaking. These revisions, and
previously finalized revisions where noted in Table 2, reflect the
EPA's complete response to the Petition for Rulemaking. It is our
position that we have fully responded to the NGO petition, however, any
requests included in the petition that have not been responded to in
Table 2 are considered denied.
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    \2\ 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.
Docket Item No. EPA-HQ-OAR-2014-0831-0005.

            Table 2--EPA Response to Petition for Rulemaking
------------------------------------------------------------------------
                                                           Final rule
      Request in petition           EPA's response       citations  (40
                                                              CFR)
------------------------------------------------------------------------
Clarify that oil wells that co- The EPA is not         98.232(c)(6)
 produce natural gas (``co-      changing the          98.232(c)(8)
 producing wells''),             definition of ``gas   98.236(g)
 specifically wells in tight-    well'' or ``oil
 oil formations like the         well.'' Instead, the
 Bakken and Eagle Ford, are      EPA is amending
 subject to the completion       subpart W to require
 reporting requirements as       the reporting of GHG
 currently written. Expand the   emissions from
 well completion reporting       completions and
 requirements to all wells,      workovers with
 ensuring co-producing wells     hydraulic fracturing
 in any formation type are       for wells in the
 required to report completion   Onshore Petroleum
 emissions.                      and Natural Gas
                                 Production segment,
                                 regardless of
                                 whether their
                                 primary product is
                                 oil or natural gas.
Require reporting from          The EPA is finalizing  98.230(a)(9)
 facilities and pipelines in     the proposal to       98.232(j)
 the gathering and boosting      amend subpart W to    98.233 (various)
 segment of the natural gas      add a new industry    98.236(a)(9)
 industry.                       segment, Onshore
                                 Petroleum and
                                 Natural Gas
                                 Gathering and
                                 Boosting, which
                                 covers emissions
                                 from equipment used
                                 by gathering
                                 pipeline systems
                                 that move petroleum
                                 and natural gas from
                                 the well to either
                                 larger gathering
                                 pipeline systems,
                                 natural gas
                                 processing plants,
                                 natural gas
                                 transmission
                                 pipelines, or
                                 natural gas
                                 distribution
                                 pipelines.
Require reporting from          The EPA is finalizing  98.230(a)(10)
 transmission pipeline           the proposal to add   98.232(m)
 blowdown events.                reporting             98.236(aa)(11)
                                 requirements for
                                 emissions from
                                 natural gas
                                 transmission
                                 pipeline blowdowns
                                 between compressor
                                 stations in a new
                                 Onshore Natural Gas
                                 Transmission
                                 Pipeline segment.
Require reporters to include    The EPA is requiring   98.236(f), (g),
 API well identification         the reporting of       (h), (l), and
 numbers along with their        well identification    (m)
 submissions to help the         numbers for the       98.238
 public and policymakers         Onshore Petroleum
 understand which sources are    and Natural Gas
 reporting and how the           Production segment
 threshold may be adjusted to    for information
 most effectively provide        related specifically
 emissions information.          to wells.
Phase out the use of best       Prior to these         98.234(f) and (g)
 available monitoring methods    amendments, BAMM was
 (BAMM), which will further      discontinued for all
 help to ensure Subpart W data   sources except
 are rigorous, and               specific sources
 comprehensive.                  that were affected
                                 by the amendments
                                 finalized on
                                 November 25, 2014
                                 (79 FR 70352); those
                                 BAMM provisions will
                                 be unavailable after
                                 December 31, 2015.
                                 Reporters will be
                                 allowed to use BAMM
                                 for the 2016
                                 reporting year for
                                 only the new
                                 industry segments
                                 and emission sources
                                 included in this
                                 action. The EPA is
                                 not allowing the use
                                 of BAMM beyond 2016.

Consider including advanced     The agency is          .................
 innovative monitoring methods   assessing the
 as a way to accelerate          potential
 development and deployment of   opportunities for
 real-time continuous CH4        application of
 emission monitoring in the      remote sensing
 oil and natural gas sector.     technologies and
                                 other innovations in
                                 measurement or
                                 monitoring
                                 technology to
                                 identifying and
                                 calculating
                                 emissions from
                                 affected sources
                                 under subpart W and
                                 requested comment in
                                 the proposal. The
                                 EPA received
                                 multiple comments in
                                 response to the
                                 request for comments
                                 on the feasibility,
                                 possible regulatory
                                 approaches, and
                                 provisions necessary
                                 to incorporate or
                                 allow the use of
                                 advanced measurement
                                 or monitoring
                                 methods in subpart
                                 W. All of the
                                 comments received
                                 are included in
                                 ``Response to Public
                                 Comments on
                                 Greenhouse Gas
                                 Reporting Rule: 2015
                                 Revisions and
                                 Confidentiality
                                 Determinations for
                                 Petroleum and
                                 Natural Gas
                                 Systems'' in Docket
                                 ID No. EPA-HQ-OAR-
                                 2014-0831. The EPA
                                 is not including
                                 provisions related
                                 to advanced
                                 measurement or
                                 monitoring methods
                                 in this rule and is
                                 not responding to
                                 these comments in
                                 this rulemaking.
                                 Instead, following
                                 review of the data
                                 and information
                                 received in
                                 comments, the EPA
                                 may propose
                                 amendments related
                                 to the use of
                                 innovative
                                 technologies in
                                 reporting to the
                                 GHGRP in a future
                                 rulemaking.
------------------------------------------------------------------------

Legal Authority

    The EPA is finalizing these rule amendments under its existing CAA
authority provided in CAA section 114. As stated in the preamble to the
2009 final GHG reporting rule (74 FR 56260; October 30, 2009), CAA
section 114(a)(1) provides the EPA broad authority to require the
information to be gathered by this rule because such data would inform
and are relevant to the EPA's carrying out a wide variety of CAA
provisions. See the preambles to the proposed (74 FR 16448; April 10,
2009) and final GHG reporting rule (74 FR 56260; October 30, 2009) for
further information.
    In addition, pursuant to sections 114, 301, and 307 of the CAA, the
EPA is publishing final confidentiality determinations for the new data
elements required by these amendments. Section 114(c) requires that the
EPA make information obtained under section 114 available to the
public, except for information that qualifies for confidential
treatment. The Administrator has determined that this action is subject
to the provisions of section 307(d) of the CAA.

D. How do these amendments apply to 2015 and 2016 reports?

    These amendments are effective on January 1, 2016. Thus, beginning
on January 1, 2016, facilities must follow the revised methods in
subpart W, as amended, to calculate emissions occurring during the 2016
calendar year (i.e., reporting year 2016). The first annual reports of
emissions calculated using the amended requirements will be those
submitted by March 31, 2017, covering reporting year 2016. For
reporting year 2015, reporters will continue to calculate emissions and
other relevant data for the reports that are submitted according to the
requirements in part 98 that are applicable to reporting year 2015
(i.e., the requirements in place until the effective date of this final
rule).
    For reporting year 2016 only, we are allowing the use of best
available monitoring methods (BAMM) on a short-term transitional basis
for facilities new to reporting under subpart W as well as reporters of
facilities subject to new monitoring requirements associated with these
revisions. Reporters have the option of using BAMM for only the new
industry segments and emission sources included in this action from
January 1, 2016, to December 31, 2016, without seeking prior EPA
approval. The EPA will not accept requests for an extension for the use
of BAMM beyond the time periods listed above. The EPA is not allowing
the use of BAMM for the new well identification number provisions in
the Onshore Petroleum and Natural Gas Production segment because the
well identification number is not a parameter that requires monitoring
equipment to be measured and, therefore, does not meet the requirements
for BAMM. In addition, reporters should already have well
identification numbers readily available for all wells and associated
equipment to which this reporting requirement applies. See section II.E
of this preamble for more information.

II. Summary of Final Revisions and Other Amendments to Subpart W and
Responses to Public Comment

    In this action, the EPA is amending subpart W to require the
reporting of GHG emissions from completions and workovers of oil wells
with hydraulic fracturing as part of the existing Onshore Petroleum and
Natural Gas Production industry segment. The EPA is also adding
requirements for two new industry segments: the Onshore Petroleum and
Natural Gas Gathering and Boosting segment for petroleum and natural
gas gathering and boosting systems, and the Onshore Natural Gas
Transmission Pipeline segment for transmission pipeline blowdowns
between compressor stations. Finally, the EPA is requiring the
reporting of well identification numbers for oil and gas well-specific
information (e.g., completions and workovers, associated gas venting
and flaring) reported in the Onshore Petroleum and Natural Gas
Production segment. The comments received on this rule generally did
not dispute the merit of adding these new segments and sources to
subpart W, but they did provide a number of suggestions regarding the
technical details of monitoring, reporting, and applicability.
    Sections II.A through II.E of this preamble describe the
requirements and other amendments that we are finalizing in this
rulemaking. Section II.A describes the final amendments for the

reporting of GHG emissions from completions and workovers of oil wells
with hydraulic fracturing. Section II.B describes the final amendments
for the reporting of GHG emissions from sources in the new Onshore
Petroleum and Natural Gas Gathering and Boosting segment. Section II.C
describes the final amendments for the reporting of GHG emissions from
sources in the new Onshore Natural Gas Transmission Pipeline segment.
Section II.D describes the requirements for reporting well
identification numbers for the Onshore Petroleum and Natural Gas
Production segment. Finally, section II.E provides a summary of the
final amendments to the best available monitoring method requirements.
The amendments described in each section are followed by a summary of
the major comments on those amendments and the EPA's responses. See
``Response to Public Comments on Greenhouse Gas Reporting Rule: 2015
Revisions and Confidentiality Determinations for Petroleum and Natural
Gas Systems'' in Docket ID No. EPA-HQ-OAR-2014-0831 for a complete
listing of all comments and the EPA's responses.
    Finally, in the preamble to the proposed rule, the EPA stated that
the agency is ``assessing the potential opportunities for applying
remote sensing technologies and other innovations in measurement or
monitoring technology to identifying and calculating emissions from
affected sources under subpart W'' (79 FR 73148; December 9, 2014). The
EPA did not propose, and therefore is not finalizing, any amendments to
subpart W to this effect, but the EPA did request comment on the
feasibility, possible regulatory approaches, provisions necessary to
incorporate or allow the use of advanced measurement or monitoring
methods in subpart W, and methods to ensure compliance with those
provisions in an efficient manner. The EPA also requested comment on
the memorandum ``Discussion Paper on Potential Implementation of
Alternative Monitoring under the GHGRP'' in Docket ID No. EPA-HQ-OAR-
2014-0831. All of the comments received are included in ``Response to
Public Comments on Greenhouse Gas Reporting Rule: 2015 Revisions and
Confidentiality Determinations for Petroleum and Natural Gas Systems''
in Docket ID No. EPA-HQ-OAR-2014-0831. The EPA will consider these
comments in the context of any future action related to alternative
monitoring.
    The amendments in this action will advance EPA's goal of maximizing
rule effectiveness. For example, these amendments provide clear
monitoring, calculation and reporting requirements for new segments and
sources in subpart W, thus enabling government, regulated entities, and
the public to easily identify and understand rule requirements. In
addition, specific changes such as increasing the flexibility and time
period for transitional BAMM will make compliance easier than non-
compliance.
    These amendments will also improve the EPA's ability to assess
compliance by adding reporting elements that allow the EPA to more
thoroughly verify greenhouse gas data and understand trends in
emissions. For example, the requirement for the Onshore Petroleum and
Natural Gas Production segment to report well identification numbers
will allow the EPA to link GHGRP data with other data sources and
assess the completeness and representativeness of the data collected
relative to all activity in the U.S. oil and gas production sector.
Lastly, these amendments further advance the ability of the GHGRP to
provide access to quality data on greenhouse gas emissions by adding
key petroleum and natural gas emission sources to this program. One
example is the addition of the Onshore Petroleum and Natural Gas
Gathering and Boosting segment, a significant greenhouse gas emissions
segment that had not been previously covered under the GHGRP.

A. Summary of Final Amendments for Oil Wells With Hydraulic Fracturing

1. Summary of Final Amendments
    The EPA is amending subpart W to require the reporting of GHG
emissions from completions and workovers with hydraulic fracturing for
wells in the Onshore Petroleum and Natural Gas Production segment,
regardless of whether their primary product is oil or natural gas. In
general, commenters supported inclusion of emissions from completions
and workovers of oil wells with hydraulic fracturing in subpart W, and
a few commenters provided targeted technical edits and suggestions for
this source. Consistent with the requirements for completions and
workovers of gas wells with hydraulic fracturing, and consistent with
the proposed requirements, the new provisions include the reporting of
activity data on the number of completions and workovers of oil wells
with hydraulic fracturing and on the use of flaring and reduced
emission completions (RECs). In response to public comments, the final
monitoring and reporting amendments do not apply to completions and
workovers of oil wells with hydraulic fracturing that have a gas to oil
ratio (GOR) of less than 300 standard cubic feet per stock tank barrel
(scf/STB).
    The EPA is also amending the equations and definitions in 40 CFR
98.233(g) to reflect applicability to completions and workovers of all
gas and oil wells with hydraulic fracturing. As in the proposal, the
final amendments require the use of either Equation W-10A or W-10B for
calculating GHG emissions from completions and workovers of oil wells
with hydraulic fracturing. Equation W-10A is used to calculate
emissions from wells using inputs obtained from a representative sample
of wells within a sub-basin and the ratio of the gas flowback rate to
the production flow rate, and Equation W-10B is used to calculate
emissions using inputs obtained from all wells within a sub-basin and
the flow rate and flow volume of the gas vented or flared. As proposed,
the EPA is finalizing that emissions be calculated and reported
separately for gas wells and oil wells by sub-basin and well type
combination.\3\ Furthermore, as proposed, the final amendments require
the use of Calculation Method 1 for calculating inputs to Equations W-
12A and W-12B for oil wells. Calculation Method 1 relies on direct
measurement of gas flow rate during flowback to develop calculation
inputs; the requirements for the location of the flow meter used to
measure the gas flow rate for oil wells are the same as the location
requirements for gas wells. Other provisions that apply to completions
and workovers of gas wells with hydraulic fracturing also apply to
completions and workovers of oil wells with hydraulic fracturing,
including the determination of wells that constitute a representative
sample for use in Equation W-10A.
---------------------------------------------------------------------------

    \3\ 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. See the definition of ``Sub-basin
category, for onshore natural gas production'' in 40 CFR 98.238.
---------------------------------------------------------------------------

    For oil wells that do not meter gas production, such as some wells
with a relatively low GOR, the EPA is adding a new Equation W-12C as
proposed to calculate, rather than measure, the value of
PRs,p (the average gas production flow rate during the first
30 days of production after the completion or workover), which is used
as an input to Equation W-10A. In this Equation W-12C, the value of
PRs,p is calculated by multiplying the GOR of the well by
the measured oil production rate over the

first 30 days of production after the completion or workover.
2. Summary of Comments and Responses
    Comment: Several commenters responded to the EPA's request for
comment on whether to establish a minimum GOR threshold such that oil
wells with a very low GOR would not be subject to the monitoring and
reporting requirements for GHG emissions from completions and workovers
with hydraulic fracturing. Most of these commenters supported
establishment of a cutoff for wells with very low emissions. One
commenter urged the EPA to require monitoring and reporting for all
completions and workovers with hydraulic fracturing but stated that if
a threshold is set, it should be set at a level that ensures that all
significant emissions sources are included and that sources are able to
clearly determine whether they are required to report. Three commenters
supported setting a minimum GOR threshold. One commenter suggested a
minimum GOR threshold of 300 and stated that, based on industry
experience, oil wells with GOR values less than 300 do not have
sufficient gas to operate a separator. The second commenter agreed that
operators should only have to monitor and report emissions if the GOR
is great enough to operate a separator and direct measurement is
possible. The third commenter supporting a minimum GOR threshold did
not provide a suggestion for a specific numeric threshold but stated
that the emissions from wells with a low GOR are insignificant, and the
time and resources involved in measuring the flowback and reporting
emissions for wells expected to have minimal emissions would outweigh
any contribution of these emissions to the overall source category
totals. This commenter supported the inclusion of a threshold so that
only significant sources of emissions would be included.
    Response: The EPA agrees that including a minimum GOR threshold
will help minimize reporting burden while still capturing most of the
emissions from this source. Energy Information Administration data show
that the number of ``oil only'' wells drilled from 2007-2012 was less
than 20 percent of all new wells.\4\ These wells would have a GOR
approaching zero and, therefore, would be expected to have low
emissions. We believe that having no threshold may create an
unnecessary burden for operators to report emissions for these wells
with just a trace of gas. Given that the EPA is finalizing the proposed
requirement that the oil well flow meter be located downstream of the
separator, the separator must be operating for the owner or operator to
be able to measure the flow rate and estimate emissions from
completions and workovers of oil wells with hydraulic fracturing. One
commenter, an industry trade association, suggested a threshold of 300
scf/STB based on the industry trade association's experience that
separators typically do not operate at a GOR less than 300 scf/STB.
---------------------------------------------------------------------------

    \4\ In this analysis, all hydrocarbon production in the liquid
state at the wellhead was considered oil. J. Lieskovsky and S.
Gorgen. ``Drilling often results in both oil and natural gas
production.'' Today in Energy, U.S. Energy Information
Administration, October 29, 2013. http://www.eia.gov/todayinenergy/detail.cfm?id=13571. Accessed June 9, 2015.
---------------------------------------------------------------------------

    The primary concern when determining the level for a threshold is
volatility; the threshold must be low enough that the oil produced is
considered non-volatile. Non-volatile ``black oils'' (i.e., oil likely
to not have gases or light hydrocarbons associated with it) are
generally defined as having GOR values in the range of 200 to 900 scf/
STB.\5\ Oil wells with a GOR less than the 300 scf/STB suggested by the
commenter are at the lower end of this range, and completions and
workovers with hydraulic fracturing of these wells will not likely have
enough gas associated that can be separated. Therefore, the final
monitoring and reporting requirements do not apply to completions and
workovers of oil wells with hydraulic fracturing that have a GOR of
less than 300 scf/STB.
---------------------------------------------------------------------------

    \5\ M.P. Walsh. ``Oil Reservoir Primary Drive Mechanisms.'' In
Petroleum Engineering Handbook, Volume V: Reservoir Engineering and
Petrophysics, E.D. Holstein (Ed.), L.W. Lake (Ed. in Chief), pp. V-
895-980. Society of Petroleum Engineers, 2007.
---------------------------------------------------------------------------

    Comment: Several commenters responded to the EPA's request for
comment on whether to establish a minimum well pressure threshold such
that oil wells with a very low well pressure would not be subject to
the monitoring and reporting requirements for GHG emissions from
completions and workovers with hydraulic fracturing. Most of these
commenters supported establishment of a cutoff for wells with very low
well pressure. One commenter urged the EPA to require monitoring and
reporting for all completions and workovers with hydraulic fracturing
but stated that if a threshold is set, it should be set at a level that
ensures that all significant emissions sources are included and that
sources are able to clearly determine whether they are required to
report. Three commenters supported setting a minimum well pressure
threshold. One commenter suggested a minimum well pressure threshold of
0.4645 pounds per square inch per foot (psi/ft) because this is the
vertical pressure gradient needed for a well to flow back, based on
experience with the Natural Gas STAR program. The second commenter
suggested that operators should only have to monitor and report
emissions if the pressure of the reservoir during oil well completions
and workovers is greater than the pressure gradient of 0.433 psi/ft and
noted that the pressure needed varies based on the density of the
materials in the column and the depth of the well. The third commenter
supporting a minimum well pressure threshold did not provide a
suggestion for a threshold but supported the inclusion of a threshold
so that only significant sources of emissions would be included.
    Response: The EPA evaluated the commenters' suggestions and has
decided not to include a minimum well pressure threshold. Both
commenters who suggested a specific value noted in their comments that
these pressure gradients are the minimum needed for the well to
produce. In other words, according to the commenters' rationale, wells
with pressures below the suggested pressure thresholds would not have
any production, regardless of whether a threshold is included in the
final rule. As a result, specifying that reporting of emissions from
completions and workovers of oil wells with hydraulic fracturing is not
required below those pressures is redundant. Therefore, the final rule
does not include a minimum well or reservoir pressure threshold for
completions and workovers of oil wells with hydraulic fracturing.

B. Summary of Final Amendments for the Onshore Petroleum and Natural
Gas Gathering and Boosting Segment

    The EPA is amending subpart W to add a new industry segment,
Onshore Petroleum and Natural Gas Gathering and Boosting, that covers
emissions from equipment used by gathering pipeline systems that move
petroleum and natural gas from the well to either larger gathering
pipeline systems, natural gas processing plants, natural gas
transmission pipelines, or natural gas distribution pipelines. A
gathering and boosting system is a single network of pipelines,
compressors and process equipment, including equipment to perform
natural gas compression, dehydration, and acid gas removal, that has
one or more well-defined connection points to gas and oil production
and a well-defined downstream endpoint, typically a gas

processing plant or transmission pipeline. Gathering pipelines are
pipelines used to transport gas from the furthermost downstream point
in an onshore production facility to certain endpoints, generally
either a gas processing facility or point of connection to a
transmission pipeline. Compressors located along the gathering and
boosting system are used to control or ``boost'' the pressure of the
gas in the pipeline and keep the gas moving downstream. Commenters
generally supported inclusion of gathering and boosting system
emissions in subpart W, and many commenters suggested targeted
revisions concerning definitions, what emission sources should be
included in the segment and methods for individual emission sources.
    The remainder of this section describes the final reporting
requirements for this new industry segment, including the segment
description, definitions, calculation methods, and information to be
reported. The amendments described in each section are followed by a
summary of the major comments, if any, on those amendments and the
EPA's responses. See ``Response to Public Comments on Greenhouse Gas
Reporting Rule: 2015 Revisions and Confidentiality Determinations for
Petroleum and Natural Gas Systems'' in Docket ID No. EPA-HQ-OAR-2014-
0831 for a complete listing of all comments and the EPA's responses.
1. Segment Description for the Onshore Petroleum and Natural Gas
Gathering and Boosting Segment
a. Summary of Final Amendments
    The EPA is finalizing the definition of the Onshore Petroleum and
Natural Gas Gathering and Boosting segment in 40 CFR 98.230 as
gathering pipelines and other equipment used to collect petroleum and/
or natural gas from onshore production gas or oil wells and used to
compress, dehydrate, sweeten, or transport the petroleum and/or natural
gas to a natural gas processing facility, a natural gas transmission
pipeline, or a natural gas distribution pipeline. Gathering and
boosting equipment includes, but is not limited to, gathering
pipelines, separators, compressors, acid gas removal (AGR) units,
dehydrators, pneumatic devices/pumps, storage vessels, engines,
boilers, heaters, and flares. The Onshore Petroleum and Natural Gas
Gathering and Boosting segment does not include equipment and pipelines
that are reported under any other industry segment defined in subpart
W. The segment definition is being finalized as proposed, except that
the final amendments provide two clarifications regarding gathering
pipelines. First, gathering pipelines operating on a vacuum are not
included because they would not be expected to have emissions. Second,
to address comments regarding the inclusion of liquid and multiphase
streams in the segment, the definition clarifies that gathering
pipelines with a GOR less than 300 scf/STB are not a part of the
segment.
b. Summary of Comments and Responses
    Comment: Commenters requested that the EPA remove ``Petroleum and''
from the proposed segment name, ``Onshore Petroleum and Natural Gas
Gathering and Boosting.'' The commenters asserted that the removal
would provide a clear demarcation between onshore petroleum and natural
gas production and onshore natural gas gathering and boosting. They
also stated that such a change would be more consistent with the
segment definition, which includes pipelines and equipment ``used to
compress, dehydrate, sweeten, or transport the gas to a natural gas
processing facility, a natural gas transmission pipeline or to a
natural gas distribution pipeline.'' The commenter stated that the type
of equipment included in the gathering and boosting segment is
``synonymous'' with gas gathering and boosting systems, not liquid or
petroleum, and they noted that the emission factor for equipment leaks
from gathering pipelines is not applicable to gathering pipelines that
carry mostly liquid.
    Commenters also specifically requested that the EPA exclude
petroleum gathering pipelines from the gathering and boosting segment
because the fugitive gas emissions from these gathering pipelines would
be negligible. Both commenters stated that the proposed emission factor
for gathering pipeline leaks is only applicable to gas gathering
pipelines. Two commenters also requested that multi-phase flow lines
from wells to a centralized production facility where initial
separation occurs be retained in the Onshore Petroleum and Natural Gas
Production segment rather than included in the new gathering and
boosting segment.
    Response: The EPA is finalizing the segment name as proposed and
not removing ``Petroleum and'' from the segment name or moving
multiphase gathering pipelines to the Onshore Petroleum and Natural Gas
Production segment. We proposed including ``Petroleum and'' in the
segment name to reflect the complex nature of upstream operations where
wells can produce oil, natural gas, or a mixture of both and to signify
the inclusion of GHG emissions from gathering and boosting systems
moving high volatility liquids in this new segment. Even in wells that
produce primarily liquids at surface temperature and pressure
conditions, there is often a volatile gaseous component. This
associated gas is usually considered wet due to the high content of
natural gas liquids (volatile components) to go along with gaseous
CH4. Similarly, the inclusion of all petroleum gathering
pipelines in the Onshore Petroleum and Natural Gas Gathering and
Boosting segment, including multiphase pipelines, is appropriate,
because gathering lines are a key component to gathering and boosting
systems. Therefore, all gathering pipelines that collect petroleum and/
or natural gas from onshore production gas or oil wells and transport
the petroleum and/or natural gas to a natural gas processing facility,
a natural gas transmission pipeline or to a natural gas distribution
pipeline are considered part of the final Onshore Petroleum and Natural
Gas Gathering and Boosting segment.
    However, the EPA does agree that gathering pipelines carrying
mostly oil have a low potential for GHG emissions. We note that the
ratio of CH4 to volatile components increases as the GOR
increases. Therefore, to clarify our intent to exclude gathering
pipelines containing oil, the final rule clarifies that the Onshore
Petroleum and Natural Gas Gathering and Boosting segment does not
include gathering pipelines with a GOR of less than 300 scf/STB.
Operators of gathering pipelines below that threshold are not required
to include those pipelines in their gathering and boosting facility.
See section II.B.5 of this preamble for additional discussion.
    Finally, as part of evaluating this comment, the EPA reviewed the
proposed definitions related to the Onshore Petroleum and Natural Gas
Gathering and Boosting segment and recognizes that two of them referred
to ``the gas'' rather than ``the petroleum and/or natural gas.'' One
was the proposed description of the Onshore Petroleum and Natural Gas
Gathering and Boosting segment in 40 CFR 98.230, as identified by the
commenters, and the other was the definition of ``gathering and
boosting system owner or operator'' in 40 CFR 98.238. For consistency
throughout the final rule with the intent stated in this response, the
final description of the Onshore

Petroleum and Natural Gas Gathering and Boosting segment in 40 CFR
98.230 refers to ``petroleum and/or natural gas'' and the final
definition of ``gathering and boosting system owner or operator'' in 40
CFR 98.238 refers to ``the petroleum or natural gas transported.''
    Comment: One commenter stated that there may be confusion regarding
which equipment should be reported in the different industry segments,
which could lead to emissions being mistakenly excluded or double-
counted. For example, gathering and boosting equipment located on a
single well pad or associated with a single well pad could be double-
counted, especially if it is operated by one entity but owned by
another. The commenter also noted that confusion over the proper
segment for this type of equipment could make the difference between
reporting emissions or not reporting emissions if a facility is close
to the reporting threshold of 25,000 metric tons carbon dioxide
equivalent (CO2e). Therefore, the commenter requested that
the EPA incorporate by reference the U.S. Department of
Transportation's Pipeline and Hazardous Materials Safety Administration
(PHMSA) federally defined boundaries of production, gathering and
boosting, and transmission segments to ensure state/federal
transparency and consistency.
    Response: The EPA is not changing the segment description for the
Onshore Petroleum and Natural Gas Production segment in 40 CFR
98.230(a)(2) or the Onshore Natural Gas Processing segment in 40 CFR
98.230(a)(3). As stated at proposal, the EPA decided not to make any
changes to the existing segment descriptions to provide consistency for
reporters in that segment. This decision allows the EPA to ensure that
the data gap in subpart W related to gathering and boosting systems is
addressed while minimizing confusion over changes to other segments.
Instead, the EPA is reiterating the intention for the Onshore Petroleum
and Natural Gas Gathering and Boosting segment to cover equipment and
emission sources not included in reporting for the existing Onshore
Petroleum and Natural Gas Production or Onshore Natural Gas Processing
segments.
    The EPA does not agree that emissions from the same equipment will
be reported under more than one industry segment in a given reporting
year; however, we acknowledge that similar equipment may exist in
adjacent industry segments as defined in subpart W. The owner or
operator of the equipment in question should first determine if that
equipment is subject to reporting in another segment of subpart W, such
as the Onshore Petroleum and Natural Gas Production or Onshore Natural
Gas Processing segments. If the equipment is not subject to reporting
in another segment of subpart W, then the owner or operator should
evaluate whether or not the equipment is included in the Onshore
Petroleum and Natural Gas Gathering and Boosting source category. For
example, if a gathering and boosting owner or operator also owns or
operates equipment on or associated with a single well pad (40 CFR
98.230(a)(2)), that equipment is part of the Onshore Petroleum and
Natural Gas Production segment, not the Onshore Petroleum and Natural
Gas Gathering and Boosting segment. Therefore, emissions from that
equipment should not be included when determining if the gathering and
boosting facility exceeds the reporting threshold.
    Comment: One commenter requested that the EPA clarify the proper
segment for AGR units and revise the rule accordingly. The commenter
suggested that the Natural Gas Processing segment should explicitly
exclude sulfur dioxide and carbon dioxide (CO2) removal
units, so that it is clear that those units do not report under both
the Natural Gas Processing segment and the Onshore Petroleum and
Natural Gas Gathering and Boosting segment. The commenter stated that
this revision would be more consistent with the definition of gas
processing plant in other EPA rules. If the EPA does not make this
change, the commenter stated that AGR units should not be included in
the Onshore Petroleum and Natural Gas Gathering and Boosting segment
because they are already included in the Natural Gas Processing
segment. The commenter noted that AGR units are specifically defined in
40 CFR 98.238 as a process unit that separates hydrogen sulfide and/or
CO2 from sour natural gas using liquid or solid absorbents
or membrane separators.
    Response: The EPA agrees that emissions from a particular acid gas
removal unit should not be reported under both the Natural Gas
Processing segment and the Onshore Petroleum and Natural Gas Gathering
and Boosting segment. However, as noted previously in this preamble,
the EPA is not changing the segment description for the Onshore
Petroleum and Natural Gas Production segment in 40 CFR 98.230(a)(2) or
the Onshore Natural Gas Processing segment in 40 CFR 98.230(a)(3).
Instead, the EPA is reiterating the intention for the Onshore Petroleum
and Natural Gas Gathering and Boosting segment to cover equipment and
emission sources not included in reporting for the Onshore Petroleum
and Natural Gas Production or Onshore Natural Gas Processing segments.
The final segment description for the Onshore Petroleum and Natural Gas
Gathering and Boosting segment in 40 CFR 98.230(a)(10) specifies that
gathering and boosting equipment does not include equipment reported
under any other industry segment defined in 40 CFR 98.230(a), which
should address the commenter's concern about reporting under multiple
segments.
    Regarding the commenter's suggestion to exclude AGR units from the
Onshore Petroleum and Natural Gas Gathering and Boosting segment, the
EPA believes AGR units should be reported under subpart W and that the
current requirements, coupled with the revisions in this rulemaking,
allow for a clear demarcation of where they should be included and
reported. While most AGR units will be included in the Onshore Natural
Gas Processing segment, the EPA does not agree that the Onshore Natural
Gas Processing segment includes all AGR vents, particularly those in
processes that do not fractionate gas liquids with an annual average
throughput of less than 25 million scf per day. Therefore, the final
Onshore Petroleum and Natural Gas Gathering and Boosting segment
includes AGR vents that do not meet the segment descriptions for the
Onshore Petroleum and Natural Gas Production segment in 40 CFR
98.230(a)(2) or the Onshore Natural Gas Processing segment in 40 CFR
98.230(a)(3) but do meet the Onshore Petroleum and Natural Gas
Gathering and Boosting segment description in 40 CFR 98.230(a)(10).
2. Definitions
a. Summary of Final Amendments
    The EPA is finalizing the definition of ``gathering and boosting
system'' as proposed and is finalizing the definition of ``gathering
and boosting system owner or operator'' as proposed with a
clarification that the fluid being transported may be petroleum or
natural gas. Specifically, a gathering and boosting system is a single
network of pipelines, compressors and process equipment, including
equipment to perform natural gas compression, dehydration, and acid gas
removal, that has one or more connection points to gas and oil
production and a downstream endpoint, typically a gas processing plant,
transmission pipeline, local distribution company (LDC) pipeline, or
other gathering and boosting system. A gathering and

boosting system owner or operator is any person that: (1) Holds a
contract in which they agree to transport petroleum or natural gas from
one or more onshore petroleum and natural gas production wells to a
natural gas processing facility, another gathering and boosting system,
a natural gas transmission pipeline, or a distribution pipeline; or (2)
is responsible for custody of the petroleum or natural gas transported.
In complex ownership scenarios, the owner/operator assigns a designated
representative responsible for reporting consistent with 40 CFR 98.4.
    The EPA is also finalizing the definition of ``facility with
respect to onshore petroleum and natural gas gathering and boosting''
in 40 CFR 98.238 as proposed. A facility with respect to onshore
petroleum and natural gas gathering and boosting is all gathering
pipelines and other equipment located along those pipelines that are
under common ownership or common control by a gathering and boosting
system owner or operator and that are located in a single hydrocarbon
basin as defined in 40 CFR 98.238. Where a person owns or operates more
than one gathering and boosting system in a basin (for example,
separate gathering lines that are not connected), then all gathering
and boosting systems and equipment that the person owns or operates in
the basin are considered one facility. Any gathering and boosting
equipment that is associated with a single gathering and boosting
system, including leased, rented, or contracted activities, is
considered to be under common control of the owner or operator of the
gathering and boosting system. Emissions from an onshore petroleum and
natural gas gathering and boosting facility only need to be reported if
the collection of emission sources emits 25,000 metric tons
CO2e or more per year.
b. Summary of Comments and Responses
    Comment: Multiple commenters provided comments on the definition of
``facility with respect to onshore petroleum and natural gas gathering
and boosting.'' Some commenters supported the basin-level approach that
the EPA proposed, although a few asked the EPA to clarify how to report
their emissions if their gathering and boosting system is in more than
one basin. Other commenters disagreed with the basin-level approach and
suggested that the EPA should use the definition of facility in 40 CFR
98.6. These commenters asserted that the basin-level approach would
result in an expansive definition of facility that includes huge
numbers of emissions sources and that this approach is not consistent
with how a facility is defined elsewhere in the GHGRP or with
traditional notions of aggregation under the CAA. One commenter
asserted that defining a facility in a way that is not consistent with
other CAA programs will make it difficult for the EPA to use the GHGRP
data to inform future policy decisions. The commenter also stated that
the EPA has not provided any explanation of why basin-wide aggregation
is a reasonable data request under section 114 of the CAA.
    Commenters opposing the basin-level facility definition noted that
the Onshore Petroleum and Natural Gas Gathering and Boosting segment
has very different characteristics from the Onshore Petroleum and
Natural Gas Production segment, which also uses the basin-level
approach to defining a facility. One commenter specifically noted that
production sources are located at well-defined, discrete locations,
owners and operators of production sites know where the wells are
physically located and how many operate in a single production basin.
In contrast, the commenter stated, the gathering and boosting
operations of one owner or operator in a single hydrocarbon basin may
include hundreds or thousands of miles of pipelines with multiple
sites, including interconnects, meter stations, scrubber stations,
pigging stations, compressor stations, and gas treating plants. Another
commenter stated that gathering and boosting sites have the ability to
boost and move gas from multiple basins within the same site, whereas
production typically maintains operations and moves gas within one
basin.
    Another commenter also disagreed with the basin-level approach,
noting that the term ``basin'' is not common terminology that is used
in the gathering and boosting industry segment. The commenter suggested
that the EPA use a county- or parish-level approach with an equipment
threshold (to determine which equipment should be counted when
determining if the 25,000 metric tons CO2e reporting
threshold has been exceeded).
    Response: The EPA is finalizing the definition of ``facility with
respect to onshore petroleum and natural gas gathering and boosting''
as proposed. As noted in the preamble to the proposed amendments, the
basin-level approach to defining a facility for the Onshore Petroleum
and Natural Gas Gathering and Boosting segment is expected to achieve a
balance of providing geographically specific information while also
reducing burden on reporters. This approach also recognizes the fact
that gathering and boosting facilities are more dispersed than
processing facilities and are geographically similar to the Onshore
Petroleum and Natural Gas Production segment in size and number of
sources because, by their nature, they are needed to process and
transport the petroleum and natural gas produced in a given basin.
While some gathering and boosting operations may span multiple basins
or may only be present in a portion of a basin, as will some onshore
production operations, the EPA has concluded that a basin-level
facility definition is the best reflection of how this industry is
organized operationally.
    In ``Greenhouse Gas Reporting Rule: Technical Support for 2015
Revisions and Confidentiality Determinations for Petroleum and Natural
Gas Systems; Proposed Rule'' (Docket Item No. EPA-HQ-OAR-2014-0831-
0018), we evaluated the option of using the definition of ``facility''
found in 40 CFR 98.6 for gathering and boosting facilities, and we
found that this definition would provide limited data on the proposed
Onshore Petroleum and Natural Gas Gathering and Boosting segment
compared to the basin-level approach, due to the fact that fewer
facilities would exceed the 25,000 metric tons CO2e
reporting threshold. It would also likely be more burdensome overall to
reporters, because a larger number of facilities would have to be
evaluated to determine whether they exceed the 25,000 metric tons
CO2e reporting threshold, and a larger number of
``facility'' reports would be required for each owner or operator. The
commenters did not provide any new information that would enable us to
re-evaluate this conclusion. A county- or parish-level approach would
similarly result in a larger number of smaller facilities to be
evaluated to determine whether they exceed the reporting threshold than
the basin-level approach. This approach would result in fewer
facilities reporting than a basin-level definition, especially if an
equipment threshold were defined as requested by the commenter, as well
as a higher burden for owners or operators with multiple facilities in
a basin that exceed the 25,000 metric tons CO2e reporting
threshold. Therefore, the EPA concluded that these options would not
achieve the goals that were articulated in the preamble to the proposed
rule of ``having a thorough data set and transparent, complete
information for this sector while minimizing burden to reporters'' (79
FR 73156; December 9,

2014). For more detail on this analysis, see ``Greenhouse Gas Reporting
Rule: Technical Support for Final 2015 Revisions and Confidentiality
Determinations for Petroleum and Natural Gas Systems'' in Docket ID No.
EPA-HQ-OAR-2014-0831. We disagree with the comment that aggregation of
data would not provide a data set that the EPA can use to inform future
policy decisions. The purpose of this rule is to collect emissions and
activity data for this industry and understand the relative emission
sources, which we anticipate the aggregated data will help to promote.
Therefore, the aggregated data can still inform future GHG policy. As
we have pointed out previously, the EPA's definition of ``facility''
for purposes of part 98 in no way impacts the ``facility'' definition
for similar sources under existing CAA programs.\6\ Information
collected under part 98 can inform a number of different CAA programs
and the Agency's authority under CAA section 114 as the basis for part
98 is independent from the EPA's authority for other CAA programs.
---------------------------------------------------------------------------

    \6\ Mandatory Greenhouse Gas Reporting Rule: EPA's Response to
Public Comments, Subpart W: Petroleum and Natural Gas Systems,
Docket Id. No. EPA-HQ-OAR-2009-0923.
---------------------------------------------------------------------------

    To address the commenters' question about reporting a system in two
basins, we are confirming in this response that reporters should submit
one report per basin (i.e., per facility as it is defined in subpart W)
and that the 25,000 metric tons CO2e per year reporting
threshold applies to each basin/facility separately. In other words,
the reporter should determine the emissions from the portion of
gathering and boosting system associated with each basin. If the total
emissions in each basin exceed the 25,000 metric tons CO2e
per year reporting threshold, then the reporter submits two reports. If
the total emissions in one basin exceed the 25,000 metric tons
CO2e threshold, but the emissions in the other basin are
below the threshold, then the reporter submits one report (for the
facility that exceeds the threshold).
    Regarding the commenter's question regarding the reasonableness of
collecting data at the basin-level under the CAA, the EPA established
its basis for collecting basin-level data in the final subpart W rule,
when the EPA finalized the requirements for the Onshore Petroleum and
Natural Gas Production segment. Additionally, as noted earlier in this
section, more granular collection of data for this segment would result
in higher burden for owners or operators with multiple operations in a
basin that exceed the 25,000 metric tons CO2e reporting
threshold. See also, ``Greenhouse Gas Emissions Reporting from the
Petroleum and Natural Gas Industry, Background Technical Support
Document (Docket Item No. EPA-HQ-OAR-2009-0923-3610) and ``Mandatory
Greenhouse Gas Reporting Rule Subpart W--Petroleum and Natural Gas:
EPA's Response to Public Comments'' (Docket Item No. EPA-HQ-OAR-2009-
0923-3608).
3. Blowdown Vent Stacks
a. Summary of Final Amendments
    The EPA is finalizing the requirements for blowdowns of equipment
in the Onshore Petroleum and Natural Gas Gathering and Boosting segment
with some clarifications from proposal. Emissions should be calculated
using the same methods that are used for the Onshore Natural Gas
Processing segment. The same exemptions, including those for volumes
less than 50 cubic feet (ft\3\) and for desiccant dehydrator reloading,
apply to the Onshore Petroleum and Natural Gas Gathering and Boosting
segment. In response to comments that the segment is geographically
dispersed and blowdowns may occur without personnel on-site or nearby,
making it difficult to determine emissions from a blowdown event, the
final amendments specify that for emergency blowdowns, reporters may
use engineering estimates based on best available information to
determine the temperature and pressure used in Equation W-14A.
b. Summary of Comments and Responses
    Comment: Commenters stated that the EPA should not include
reporting of blowdown vent stack emissions due to the large burden on
the reporter. Instead, the commenters stated, blowdowns in the Onshore
Petroleum and Natural Gas Gathering and Boosting segment should be
treated similarly to blowdowns in the Onshore Petroleum and Natural Gas
Production segment, where they are excluded because they are not
located at consolidated facility sites and are not manned. Commenters
also stated that blowdowns from gathering and boosting systems
contribute minimally to overall GHG emissions. One commenter noted that
while there is an exemption for any blowdown of a volume less than 50
ft\3\, there is also a burden to determine if the physical volume meets
this reporting threshold. To reduce the burden, some commenters
suggested only including emissions from blowdown vent stacks located at
a facility site (e.g., compressor station, central tank battery). Other
commenters stated if blowdowns remain in the segment, the EPA should
allow reporters to use an emission factor approach to calculate
emissions. Another commenter stated that the EPA's supporting
documentation focuses on gathering pipeline blowdowns, but the
regulatory text appears to include all the blowdowns occurring within a
basin, including individual equipment blowdowns. The commenter
requested that the EPA clarify its intent if blowdowns remain in the
segment.
    Response: The EPA has evaluated these comments and has decided to
finalize the reporting requirements for blowdowns in the Onshore
Petroleum and Natural Gas Gathering and Boosting segment with some
revisions to address the commenters' concerns. While the EPA does
recognize that many gathering and boosting systems are geographically
dispersed, as noted by the commenters, the nature of the Onshore
Petroleum and Natural Gas Gathering and Boosting segment is such that
the amount of fluid passing through a gathering and boosting system
will be much greater than the amount of fluid at individual well pads.
Therefore, the EPA has determined that the potential for emissions from
blowdowns in the Onshore Petroleum and Natural Gas Gathering and
Boosting segment is higher than blowdowns in the Onshore Petroleum and
Natural Gas Production segment, and they should not be excluded.
However, the EPA acknowledges that the geographic dispersion of the
segment, and the fact that some blowdowns occur without facility
personnel on site, may make it difficult to measure emissions from
blowdowns, particularly emergency blowdowns. Therefore, the final
amendments include a provision specifying that for emergency blowdowns,
reporters may use engineering estimates based on best available
information to determine the temperature at actual conditions in the
unique physical volume and absolute pressure at actual conditions in
the unique physical volume for use in Equation W-14A.
    To respond to the commenter's request regarding whether only
gathering pipeline blowdowns or all equipment blowdowns should be
included, the EPA is clarifying that the intent is to include emissions
from the ``blowdown vent stacks'' source type as defined in subpart A
of part 98. The focus on blowdown vent stacks located on gathering
pipelines in the supporting documentation was not intended to imply
that only gathering pipeline blowdowns should be reported. On the

contrary, the proposal supporting documentation reflects the fact that
the EPA expected that blowdown vent stacks located at boosting stations
would be similar to blowdown vent stacks in other industry segments and
conducted a separate evaluation to determine whether the same
calculation methods would be appropriate for gathering pipeline
blowdown vent stacks. The final rule supporting documentation more
clearly reflects this intent. The EPA also notes that while measuring
equipment to determine whether it exceeds the 50 ft\3\ physical volume
threshold for reporting may create an initial burden on reporters, the
threshold will lead to a burden reduction as reporters become familiar
with the identification process.
4. Storage Tank Vented Emissions
a. Summary of Final Amendments
    The EPA is finalizing the same methods for calculating emissions
for atmospheric storage tanks located in the Onshore Petroleum and
Natural Gas Gathering and Boosting segment as in the Onshore Petroleum
and Natural Gas Production segment, as proposed but with a few
clarifications. Specifically, the EPA is clarifying some of the
language within 40 CFR 98.233(j) and 40 CFR 98.236(j) that was
originally written to apply to Onshore Petroleum and Natural Gas
Production facilities and not proposed to be amended to also apply to
storage tanks in the Onshore Petroleum and Natural Gas Gathering and
Boosting segment. In particular, references to a ``wellhead separator''
have been clarified to refer simply to a ``separator,'' which is a
defined term in 40 CFR 98.238. To accommodate Onshore Petroleum and
Natural Gas Gathering and Boosting storage tanks that do not receive
hydrocarbon liquids from a separator or well, Calculation Methods 1 and
2 have been amended to specify how to estimate emissions if liquids are
received from non-separator equipment. In addition, certain instances
of ``sub-basin'' have been amended to refer to ``county'' to clarify
the requirements for Onshore Petroleum and Natural Gas Gathering and
Boosting reporters. All other provisions in 40 CFR 98.233(j) apply to
the Onshore Petroleum and Natural Gas Gathering and Boosting segment,
including the 10 barrels per day threshold for determining which
calculation method may be used for estimating emissions.
b. Summary of Comments and Responses
    Comment: One commenter stated that combining the requirements for
storage tanks in the Onshore Petroleum and Natural Gas Gathering and
Boosting segment and the Onshore Petroleum and Natural Gas Production
segment results in confusing terminology and unclear requirements. In
particular, the commenter noted that the terms ``separator(s),'' ``gas-
liquid separator(s),'' ``wellhead separator(s),'' and ``wellhead gas-
liquid separator(s),'' appear throughout the storage tank requirements.
The commenter asked whether the EPA intended all of these terms to
refer to the same equipment. The commenter also noted that not all
gathering and boosting system storage tanks receive liquids directly
from separators, and no gathering and boosting storage tanks receive
liquids directly from wellhead separators. Therefore, the commenter
stated, the requirements for storage tanks in the Onshore Petroleum and
Natural Gas Gathering and Boosting segment are unclear.
    The commenter also noted inconsistency between use of the terms
``oil,'' ``sales oil,'' and ``stabilized oil'' in 40 CFR 98.233(j) and
40 CFR 98.236(j). The commenter stated that Onshore Petroleum and
Natural Gas Gathering and Boosting facilities may process condensate
but not oil, and the commenter asked the EPA to clarify how those terms
should be applied to the Onshore Petroleum and Natural Gas Gathering
and Boosting segment.
    Finally, the commenter noted that Calculation Method 1 for storage
tanks requires use of the latest available analysis that is
representative of produced crude oil or condensate from the sub-basin
category. The commenter stated that the term ``sub-basin'' has no
relevance to the Onshore Petroleum and Natural Gas Gathering and
Boosting segment because the composition of condensate processed at a
compressor station may have little relationship to the oil or gas
formation below the compressor station.
    Response: The EPA agrees that the language in 40 CFR 98.233(j) and
40 CFR 98.236(j) should be clear for all Onshore Petroleum and Natural
Gas Production facilities and all Onshore Petroleum and Natural Gas
Gathering and Boosting facilities to which it applies. The existing
definition of ``separator'' in 40 CFR 98.238 is a vessel in which
streams of multiple phases are gravity separated into individual
streams of single phase. This general definition and the general term
``gas-liquid separator'' apply to both Onshore Petroleum and Natural
Gas Production facilities and all Onshore Petroleum and Natural Gas
Gathering and Boosting facilities. Therefore, the EPA has reviewed the
language and is amending references to a ``well,'' ``well pad,'' or
``wellhead,'' which are terms that are not expected to apply to most
Onshore Petroleum and Natural Gas Gathering and Boosting facilities.
The final provisions in 40 CFR 98.233(j) and 40 CFR 98.236(j) refer
more generally to separators or gas-liquid separators. To address the
comment that not all gathering and boosting system storage tanks
receive liquids directly from separators, the EPA has amended 40 CFR
98.233(j)(1) and (2) to specify how those calculation methodologies may
be used for Onshore Petroleum and Natural Gas Gathering and Boosting
storage tanks receiving hydrocarbon liquids from non-separator
equipment (i.e., without a well or separator directly upstream of the
storage tank).
    Regarding the particular material being stored in storage tanks,
the EPA agrees that there is inconsistency in some of the terms that
could cause some confusion. The EPA is clarifying in this response that
for the Onshore Petroleum and Natural Gas Gathering and Boosting
segment, the intent is for ``oil'' to refer more generally to
hydrocarbon liquids, which is consistent with the statement in 40 CFR
98.233(j) that reporters are required to calculate emissions ``from
atmospheric pressure fixed roof storage tanks receiving hydrocarbon
produced liquids.'' The proposed separate reporting requirements for
quantity of produced oil throughput and produced condensate throughput
in 40 CFR 98.236(aa)(10) have been revised, and the final rule requires
reporting of the hydrocarbon liquids received by the facility and the
hydrocarbon liquids leaving the facility. Finally, the EPA notes that
the term ``sales oil'' is already defined in Subpart A to include
``produced crude oil or condensate,'' so there is no further
clarification needed.
    Regarding the term ``sub-basin,'' the EPA agrees with the commenter
that the definition of ``sub-basin category, for onshore natural gas
production'' in 40 CFR 98.238 is not relevant for Onshore Petroleum and
Natural Gas Gathering and Boosting facilities. The EPA also agrees that
the operations within a section of a gathering and boosting system may
not be related to the formation type below the surface of the ground at
that location, especially as the material travels further from the
wells supplying gas and hydrocarbon liquids to the system. As a result
of this comment, the EPA reviewed the use of the term ``sub-basin'' as
it was proposed to apply to Onshore Petroleum and Natural Gas Gathering
and Boosting facilities. In 40 CFR 98.233(j), the calculation methods
provide options to

estimate unknown parameters using information from a previous analysis
of the composition in the sub-basin category. In these cases, the
intent is to estimate unknown parameters from a representative unit
(e.g., well, separator). To reflect a similar intent for Onshore
Petroleum and Natural Gas Gathering and Boosting facilities, 40 CFR
98.233(j)(1)(vii)(B) and 40 CFR 98.233(j)(1)(vii)(C) in Calculation
Method 1 clarify that representative separators or non-separator
equipment are located within the same county for Onshore Petroleum and
Natural Gas Gathering and Boosting reporters. For Calculation Method 2,
the term ``sub-basin category'' is used to describe calculation of
emissions for flow to storage tanks directly from wells. The final rule
includes a new paragraph 40 CFR 98.233(j)(2)(iii) to address
calculation of emissions from flow to a tank from equipment other than
a well or separator (such as a stabilizer or slug catcher), and this
paragraph also clarifies that representative analyses should come from
other non-separator equipment located within the same county. Finally,
there are reporting requirements for a ``sub-basin ID'' in 40 CFR
98.236. The final rule specifies that for Onshore Petroleum and Natural
Gas Gathering and Boosting, the information to be reported is the
county in which the equipment is located.
5. Gathering Pipelines
a. Summary of Final Amendments
    The EPA is finalizing the requirements for calculating emissions
from gathering pipelines defined to be included in the Onshore
Petroleum and Natural Gas Gathering and Boosting segment as proposed.
The methodology is similar to the approach used for equipment leaks in
the Onshore Petroleum and Natural Gas Production segment. For gathering
lines, reporters use the population count and emission factor approach
in 40 CFR 98.233(r). The emission factors in Table W-1A for gathering
pipelines are whole gas emission factors based on the U.S. GHG
Inventory. The population count is the miles of gathering pipeline,
similar to the approach used for calculating emissions from natural gas
distribution pipelines in the Natural Gas Distribution segment. As
noted in section II.B.1.a of this preamble, gathering pipelines with a
GOR less than 300 scf/STB are not included in this segment.
b. Summary of Comments and Responses
    Comment: One commenter asserted that the EPA should revise the
proposed emission factor of 2.81 standard cubic feet (scf)/hour/mile
for leaks from gathering pipelines to be based on characteristics of
currently operating gathering pipelines rather than distribution
pipelines or older data on gathering pipelines. The commenter also
noted that this emission factor is not applicable to gathering
pipelines that carry primarily liquids, as there is no gas stream until
after separation. The commenter identified gathering pipeline-specific
data from PHMSA and used the data to calculate a suggested emission
factor of 2.23 scf/hour/mile.
    Response: We reviewed the underlying data used to develop the
proposed emission factor, and we agree with the commenter that the
proposed emission factor could better account for differences between
pipeline types and for currently operating gathering pipelines. In the
1996 Gas Research Institute (GRI)/EPA report that is the basis of the
emission factor, material-specific emissions factors for gathering
lines were developed using data from direct measurement of distribution
pipelines conducted in the 1990s, not gathering pipelines. These
material-specific emission factors are the same emission factors used
by the commenter as the starting point for their revised emission
factor.
    We agree with the commenter that the emission factors should better
represent currently operating gathering pipelines; however, there is
significant variability in gathering pipelines and gathering system
configurations. Owners and operators currently report the mileage of
pipeline by gathering pipeline type to PHMSA.\7\ Therefore, rather than
calculate a single emission factor for gathering pipelines based on a
distribution of gathering pipeline materials, as was done at proposal,
the EPA determined that the most appropriate approach is to develop
gathering pipeline emission factors for four pipeline material types:
Protected steel, unprotected steel, plastic, and cast iron. (For more
information about the development of these emission factors, see
``Greenhouse Gas Reporting Rule: Technical Support for Final 2015
Revisions and Confidentiality Determinations for Petroleum and Natural
Gas Systems'' in Docket ID No. EPA-HQ-OAR-2014-0831.) The final
amendments require reporters to estimate emissions using material-
specific emission factors provided in the rule and to report gathering
pipeline mileage by material type.
---------------------------------------------------------------------------

    \7\ U.S. Department of Transportation Pipeline and Hazardous
Materials Safety Administration. Natural and Other Gas Transmission
and Gathering Pipeline Systems: Annual Report for Calendar Year.
Form PHMSA F 7100.2-1 (rev 10-2014). OMB No. 2137-0522, Expires: 10/
31/2016.
---------------------------------------------------------------------------

    The EPA also notes that reporters will not need to calculate
emissions from gathering pipelines that carry hydrocarbon liquids if
they are below the minimum GOR threshold for the Onshore Petroleum and
Natural Gas Gathering and Boosting segment.
6. Other Emission Sources
a. Summary of Final Amendments
    The EPA is finalizing the requirements for natural gas pneumatic
devices and pneumatic pumps located in the Onshore Petroleum and
Natural Gas Gathering and Boosting segment as proposed. Gathering and
boosting reporters will use the same methods for calculating emissions
as in the Onshore Petroleum and Natural Gas Production segment. The EPA
is also finalizing the requirements for acid gas removal units,
dehydrators, and flare stacks as proposed. The methods are the same as
the methods for these sources in both the Onshore Petroleum and Natural
Gas Production segment and the Onshore Natural Gas Processing segment.
The EPA is also finalizing the requirements for compressors and
equipment leaks as proposed, with one clarification regarding how to
count ``meters/piping'' for equipment leaks. Gathering and boosting
reporters use the same method as in the Onshore Petroleum and Natural
Gas Production segment. Specifically, a reporter will need to establish
an inventory of the components or equipment subject to the population
counts, apply the emission factors, and then update the inventory each
year to account for new or retired components or equipment.
b. Summary of Comments and Responses
    Comment: Two commenters stated that the major equipment categories
for calculating equipment leaks by population count are not clear for
the Onshore Petroleum and Natural Gas Gathering and Boosting segment.
Both commenters requested that the EPA clarify how to count ``meters/
piping'' for the Onshore Petroleum and Natural Gas Gathering and
Boosting segment. One commenter also requested clarification regarding
separators, compressors, and in-line heaters (specifically, whether
small heating systems used to ensure a temperate environment for a
meter are considered in-line heaters). The

commenter also noted that there was limited time to evaluate the
appropriateness of the emission factors in Table W-1A and the component
counts in Table W-1B for gathering and boosting systems.
    Response: The categories in Table W-1B represent the types of
equipment that are generally expected to be found in the field for
Onshore Petroleum and Natural Gas Production and Onshore Petroleum and
Natural Gas Gathering and Boosting facilities.\8\ For the Onshore
Petroleum and Natural Gas Gathering and Boosting segment, the EPA
realizes that reporters will only use those categories that apply
(e.g., reporters will not include wellheads, as that equipment type is
specific to Onshore Petroleum and Natural Gas Production facilities).
---------------------------------------------------------------------------

    \8\ See the memorandum ``Equipment-Level Population Emission
Factors for Onshore Production,'' Docket Item No. EPA-HQ-OAR-2009-
0923-3582, for more information regarding the derivation of this
table.
---------------------------------------------------------------------------

    Most of the major equipment categories are described by function in
the rule. For the example of a separator, 40 CFR 98.238 defines a
separator as ``a vessel in which streams of multiple phases are gravity
separated into individual streams of single phase.'' Any device meeting
this functional definition will fall into this major equipment
category. Other major categories are described in the rule by their
functional role, including dehydrators and compressors. For the in-line
heater example for which the commenter requested clarification, the
equipment described is not located in line with the fluid flow and
therefore would not be considered in this equipment category.
    The EPA agrees with both commenters that the measurement of meters/
piping in the Onshore Petroleum and Natural Gas Gathering and Boosting
segment was not clear as proposed. The final rule specifies that
reporters in the Onshore Petroleum and Natural Gas Gathering and
Boosting segment should count the number of meters in the facility and
use that as the count for ``meters/piping.''
    Comment: Two commenters supported the use of calculation methods
that include emission factors for the Onshore Petroleum and Natural Gas
Gathering and Boosting segment because they are less burdensome to the
industry. However, the commenters also requested that the EPA allow
reporters the option to use any available data/information that
provides the best representation of emissions from their specific
sources, including manufacturer data, test data, measurement and/or
monitoring data. The commenters compared this option to the approach in
state-level emissions inventories that require an emissions reporting
hierarchy. The commenters noted that this approach will provide the EPA
with more accurate emissions data that could be used to update the
emission factors for the Onshore Petroleum and Natural Gas Gathering
and Boosting segment.
    Response: The calculation methods provided in subpart W were
selected to minimize burden on industry while maintaining the necessary
quality and consistency of data to inform policy. Therefore, outside of
the BAMM provisions being finalized in this rulemaking, the EPA does
not agree to allow reporters to use customized, individual information
for their emission sources at this time. The EPA is currently
investigating additional calculation methods for subpart W sources and
may propose additional calculation methods in the future.

C. Summary of Final Amendments for the Onshore Natural Gas Transmission
Pipeline Segment

1. Summary of Final Amendments
    The EPA is finalizing the proposal to add reporting requirements
for emissions from natural gas transmission pipeline blowdowns between
compressor stations in a new Onshore Natural Gas Transmission Pipeline
segment. Commenters generally had no objections to the merit of
including this segment in subpart W but did suggest technical edits and
clarifications for targeted provisions. As noted in the preamble to the
proposed amendments, a blowdown is the release of gas from transmission
pipelines that causes a reduction in system pressure or a complete
depressurization. The EPA is clarifying that for the purposes of the
Onshore Natural Gas Transmission Pipeline segment, the blowdowns that
must be reported are blowdowns of a pipeline or section of pipeline.
    The EPA is finalizing clarifications to the proposed definition of
onshore natural gas transmission pipeline owner or operator. For
interstate pipelines, the onshore natural gas transmission pipeline
owner or operator is the person identified as the transmission pipeline
owner or operator on the Certificate of Public Convenience and
Necessity issued under 15 U.S.C. 717f, as proposed. For intrastate
pipelines, the onshore natural gas transmission pipeline owner or
operator is the person identified as the owner or operator on the
transmission pipeline's Statement of Operating Conditions under section
311 of the Natural Gas Policy Act (NGPA). If the intrastate pipeline is
not subject to section 311 of the NGPA, the onshore natural gas
transmission pipeline owner or operator is the person identified as the
owner or operator on reports to the state regulatory body regulating
rates and charges for the sale of natural gas to consumers. Finally,
the owner or operator of a pipeline that falls under the ``Hinshaw
Exemption'' is the person identified as the owner or operator on
blanket certificates issued under 18 CFR 284.224.
    The EPA is finalizing the definition of facility for the new
Onshore Natural Gas Transmission Pipeline segment as proposed; the
facility is the total U.S. mileage of natural gas transmission
pipelines owned or operated by an onshore natural gas transmission
pipeline owner or operator. If an owner or operator has multiple
pipelines in the United States, the facility is considered the
aggregate of those pipelines, even if they are not interconnected.
    The EPA is finalizing the requirement that reporters use the
methods in 40 CFR 98.233(i) to calculate or measure emissions from
pipeline blowdown events as proposed. One method allows a reporter to
calculate emissions based on the volume of the pipeline segment between
isolation valves that is blown down and the pressure and temperature of
the gas within the pipeline. The second method allows the reporter to
measure the emissions from the blowdown using a flow meter on the
blowdown vent stack. In both methods, the reporter calculates both
CH4 and CO2 emissions from the volume of natural
gas vented using either default gas composition or engineering
estimates of composition as specified in 40 CFR 98.233(u)(2)(iii).
    The EPA is not finalizing the proposed requirement to report the
emissions and location (latitude and longitude) of each blowdown event.
Instead, the EPA is requiring that Onshore Natural Gas Transmission
Pipeline reporters report the total CH4 and CO2
emissions in each state, the number of blowdowns in each state, and the
miles of pipeline in each state. In addition, instead of requiring
Onshore Natural Gas Transmission Pipeline reporters to use the same
equipment and event type categories as other industry segments
reporting blowdown emissions, the EPA is including reporting categories
specific to the Onshore Natural Gas Transmission Pipeline segment.

2. Summary of Comments and Responses
    Comment: Several commenters noted that not all intrastate pipelines
are subject to section 311 of the NGPA and asked the EPA to clarify
which intrastate pipelines are subject to reporting. One commenter
requested that the EPA clarify that intrastate pipelines not subject to
the NGPA are not required to report under subpart W. Another commenter
suggested revising the definition of owner or operator to state that if
section 311 of the NGPA does not apply, the intrastate transmission
pipeline owner or operator is the owner or operator identified on
required reports with the appropriate state agency.
    Response: It was our intent to include transmission pipelines
(including intrastate pipelines) that meet the already existing subpart
W definition of ``transmission pipeline'' in the Onshore Natural Gas
Transmission Pipeline segment. A transmission pipeline in subpart W is
defined in 40 CFR 98.238 as a Federal Energy Regulatory Commission
(FERC) rate-regulated Interstate pipeline, a state rate-regulated
Intrastate pipeline, or a pipeline that falls under the ``Hinshaw
Exemption'' as referenced in section 1(c) of the Natural Gas Act, 15
U.S.C. 717-717 (w)(1994). After reviewing the comments on the proposed
rule, we re-reviewed section 311 of the NGPA and found that only
operators of some intrastate pipelines, including those that transport
natural gas on behalf of an interstate pipeline or sell natural gas to
an interstate pipeline, are required to prepare a Statement of
Operating Conditions for compliance under section 311 of the NGPA.
Therefore, to clarify how to determine the owner and operator of
intrastate transmission pipelines, the finalized definition of
``onshore natural gas transmission pipeline owner or operator''
specifies that for intrastate transmission pipelines not subject to
section 311 of the NGPA, the owner or operator is the person identified
as the owner or operator on reports to the state regulatory body
regulating rates and charges for the sale of natural gas to consumers.
The EPA also found that the proposed definition of ``onshore natural
gas transmission pipeline owner or operator'' did not specify how to
determine the owner or operator of pipelines that fall under the
``Hinshaw Exemption.'' The EPA notes that similar to intrastate
pipelines, pipelines that fall under the ``Hinshaw Exemption'' must
apply for a ``blanket certificate'' under 18 CFR 284.224 in order to
transport petroleum or natural gas on behalf of interstate pipelines.
Therefore, the finalized definition of ``onshore natural gas
transmission pipeline owner or operator'' also specifies that for a
pipeline that falls under the ``Hinshaw Exemption,'' the owner or
operator is the person identified as the owner or operator on blanket
certificates issued under 18 CFR 284.224.
    Comment: Commenters appreciated that the EPA provided a threshold
of 50 ft\3\ of physical volume for blowdown emissions reporting but
requested several changes. Commenters requested that the EPA include a
list of ancillary equipment, such as metering and/or regulating
stations, pipeline interconnects, and pig launchers and receivers, that
would be excluded from reporting of blowdown emissions. One commenter
suggested that, alternatively, the physical volume threshold could be
increased to 3,000 thousand cubic feet to clearly exclude blowdowns of
ancillary facilities along the pipeline. Another commenter stated that
it is not feasible to establish a specific de minimis volume threshold
to exclude all ancillary equipment.
    Response: The EPA is finalizing the reporting threshold of 50 ft\3\
of physical volume for blowdowns in the Onshore Natural Gas
Transmission Pipeline segment as proposed. This threshold excludes
smaller blowdown sources that have little contribution to emissions,
consistent with other industry segments within subpart W that must
report blowdown stack vent emissions. The EPA is not increasing the
physical volume reporting threshold to account for blowdowns from
ancillary equipment, as this would be inconsistent with the EPA's
previous analysis in ``Equipment Threshold for Blowdowns'' (see Docket
Item No. EPA-HQ-OAR-2009-0923-3581), and commenters were divided on
whether increasing the threshold would even address their primary
concern.
    The EPA agrees that the emphasis for the Onshore Natural Gas
Transmission Pipeline segment is on calculating and reporting blowdown
emissions from pipeline segments, not ancillary equipment. However, any
list of ancillary equipment that would be excluded from blowdown
reporting could be incomplete, resulting in reporting of emissions from
other equipment that is ancillary but not on the list in the rule. In
addition, some of the equipment identified as ``ancillary'' in this
segment is not considered ancillary in other industry segments, which
could lead to confusion among reporters. Instead, the final rule
clarifies that facilities in the Onshore Natural Gas Transmission
Pipeline segment report pipeline blowdown emissions from blowdown vent
stacks. If the blowdown does not include a pipeline segment or has a
physical volume of less than 50 ft\3\, then that blowdown is not
required to be reported.
    Comment: Several commenters stated that the blowdown equipment and
event type categories in 40 CFR 98.233(i)(2) were developed for
compressor station blowdowns and would not provide meaningful
information regarding pipeline blowdowns in the Onshore Natural Gas
Transmission Pipeline segment. The commenters provided suggestions for
categories that would be more applicable to Onshore Natural Gas
Transmission Pipeline blowdowns and would provide more valuable
information than relying on the categories in the existing rule.
    Response: The EPA agrees with the commenters that the rule should
include blowdown categories specific to blowdowns in the Onshore
Natural Gas Transmission Pipeline segment. The final rule specifies
that blowdowns must be grouped into one of the following categories:
Pipeline integrity work (e.g., the preparation work of modifying
facilities, ongoing assessments, maintenance or mitigation),
traditional operations or pipeline maintenance, equipment replacement
or repair (e.g., valves), pipe abandonment, new construction or
modification of pipelines including commissioning and change of
service, operational precaution during activities (e.g. excavation near
pipelines), emergency shutdowns including pipeline incidents as defined
by PHMSA, and all other pipeline segments with a physical volume
greater than or equal to 50 ft\3\.
    Comment: Commenters requested that the EPA not finalize the
requirement to report latitude and longitude for each blowdown event.
The commenters indicated this requirement would be burdensome, such
data are not currently collected, the requirement is inconsistent with
the Paperwork Reduction Act, and the data would not be useful in
determining the inventory. Some commenters also suggested aggregating
emissions at the state level or only at the national/facility level.
    Response: The requirement to report latitude and longitude of each
blowdown was included in the proposed rule to help characterize the
emissions from the new Onshore Natural Gas Transmission Pipeline
segment on a more granular level than the nationwide facility. The EPA
evaluated this comment and has noted the commenters' assertion that the
latitude and longitude of each

blowdown is not information currently reported elsewhere and may result
in additional burden. Therefore, the EPA is not finalizing the
requirement to report the emissions or latitude and longitude for each
individual blowdown. Instead, the EPA is finalizing requirements for
reporters to aggregate blowdown emissions by state and report the
number of blowdowns and mileage of pipeline per state.
    Comment: Two commenters questioned the requirement to report the
data elements in proposed 40 CFR 98.236(aa)(11). Two commenters noted
that the quantities of natural gas in this section are duplicative of
information reported to FERC annually in FERC Form 2, although the
units of measure are dekatherms rather than thousand standard cubic
feet. One commenter noted that for the GHGRP reporting, they would
assume 1 dekatherm is equivalent to 1,000 scf of natural gas, based on
the approximate heat value of natural gas. The other commenter opposed
these reporting requirements because they are duplicative and
inconsistent with the requirements of the PRA, which is intended to
reduce the information burden imposed by the federal government by
requiring that agencies ensure that reported information is not
duplicative of other available data and has a practical utility. This
commenter stated that the EPA has not followed the PRA. The commenter
also stated that the requested information is irrelevant to assisting
EPA in verifying pipeline blowdown emissions; in particular, the
information cannot be used to calculate pipeline blowdown volumes.
    Response: As the EPA has noted elsewhere, the data collected in the
GHGRP will be used to inform future policy decisions. As such,
information regarding emissions and the inputs needed to verify those
emissions is only part of the information that is needed. It is
important to understand that, to inform future policy, activity data is
often as useful as emissions estimates. The EPA has determined that
data elements in 40 CFR 98.236(aa)(11) are activity data that will be
used to determine how to use the emissions data to inform future policy
decisions. It is essential that reporters provide and certify the data
they gather under this rule so that EPA has a complete inventory from
all sources under this rule and can directly relate the activity data
to the emissions data reported, which will provide for appropriate
verification of the emissions data reported.
    The EPA agrees with the first commenter that for purposes of
reporting the data elements in 40 CFR 98.236(aa)(11), reporters may
consider 1 dekatherm equal to 1,000 scf.
    Comment: Several commenters asserted that the EPA has not been
consistent in its decisions on whether to include pipeline leaks across
the subpart W industry segments. Some commenters supported the EPA's
proposal not to include leaks from transmission pipelines and noted the
decision was consistent with the Onshore Petroleum and Natural Gas
Production segment. Conversely, one commenter stated that transmission
pipeline leaks should be reported, consistent with the new Onshore
Petroleum and Natural Gas Gathering and Boosting segment. This
commenter noted that accidental leaks at these facilities can be a
significant source of CH4 emissions, as evidenced by the
magnitude of emissions from pipeline incidents reported to PHMSA, and
leaks at remote locations may not be noticed or repaired immediately.
    Response: The EPA previously considered fugitive emissions that
result from leaks in transmission pipelines in the re-proposal of
subpart W in April 2010 (75 FR 18616; April 12, 2010) but did not
include provisions for these emissions in either the proposed or final
rules. The April 2010 preamble explained that the EPA did not propose
reporting requirements for fugitive emissions from leaks in natural gas
pipeline segments between compressor stations due to the dispersed
nature of the fugitive emissions and the fact that, once fugitives are
found, the leaks causing the emissions are usually addressed quickly
for safety reasons (75 FR 18616; April 12, 2010). The EPA also noted in
the proposal preamble for these amendments (79 FR 76267; December 9,
2014) that larger fugitive leaks are currently reported to PHMSA as
part of 49 CFR 191.3. Under this provision, any pipeline incident that
results in unintentional gas loss of 3 million ft\3\ or more must be
reported. The commenter that noted that emissions can be significant
cited the emissions reported to PHMSA under this provision, and the EPA
does not find it necessary to require owners and operators to report
this same information under the GHGRP. The focus of the PHMSA reporting
requirements is to identify major safety-related incidents that are not
a part of typical operations. Therefore, the EPA is not finalizing a
requirement to report fugitive emissions from transmission pipeline
leaks but will continue to review this source as part of the EPA's
ongoing effort to ensure comprehensive, high quality data in subpart W.

D. Summary of Final Amendments for Well Identification Numbers

1. Summary of Final Amendments
    The EPA is finalizing some of the proposed amendments to 40 CFR
98.236 to add reporting requirements for well identification numbers to
improve data quality by enabling identification of wells. These well
identification numbers will be reported for the first time in the
report covering 2016 emissions; reporters will not be required to
report well identification numbers for previous years. For the majority
of wells, the well identification number reported will be the US Well
Number (formerly referred to as the API Well Number, or API Number).\9\
For any well that does not already have a US Well Number, the reporter
will be required to provide the unique well number assigned by the
permitting authority for drilling of oil and gas wells. Commenters
varied in their level of support for the proposed provisions regarding
well identification numbers. The EPA is adjusting the final provisions
in response to concerns about these reporting provisions raised in
comments.
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    \9\ 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.
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    The EPA is requiring the reporting of well identification numbers
for the Onshore Petroleum and Natural Gas Production segment only for
information related specifically to wells. For reporters in the Onshore
Petroleum and Natural Gas Production segment that report emissions
using input data that are calculated from measurements at individual
wells or equipment associated with individual wells (e.g., if Equation
W-10A was used to calculate emissions from oil well completions and
workovers with hydraulic fracturing, well testing emissions), the
report must include the well identification number for which those
measurements were made and the well identification number(s) of other
wells to which the measurements will be applied. This includes a list
of the well identification numbers by sub-basin for the producing wells
at the end of the calendar year as well as lists of the well
identification numbers for the wells acquired, divested, completed, and
permanently taken out of production during the calendar year. The EPA
is not finalizing the proposed requirement that reporters in the
Onshore Petroleum and Natural Gas Production segment report a list of
well identification numbers associated with different emission

sources for all wells in a sub-basin included in the reported emissions
data.
    The EPA is finalizing the proposed change to update references to
the ``API well number'' in subpart W to ``well identification number.''
The EPA is not otherwise changing the well identification reporting
requirements finalized in 2014 (79 FR 70352; November 25, 2014).
Reporters will still need to report well identification numbers for
liquids unloading and for any exploratory wells for which reporting has
been delayed for 2 years.
2. Summary of Comments and Responses
    Comment: While one commenter supported the addition of well
identification number reporting, most commenters opposed the proposal
to require reporting of well identification numbers. These commenters
asserted that requiring reporting of well identification numbers is an
overreach of the EPA's authority for the reporting program under CAA
section 114 and that the EPA has not provided a reasoned basis for the
departure from the previous EPA approach that well-specific data was
not necessary under Subpart W. Commenters also noted that well
identification numbers are not needed to validate reported emissions.
One commenter noted that the EPA has not questioned the data collected
from wells thus far; nor has the EPA stated that the data already
collected are insufficient to inform policy without addition of well
identification numbers, so with this proposal, the EPA is no longer
balancing data collection with reporting burdens. Commenters stated
that mapping and maintaining a database of well identification numbers
is more burdensome than the EPA estimated, and one commenter stated
that it would be arbitrary and capricious to require companies to
expend the resources necessary to report these data. Commenters also
noted that it is not clear how to interpret the term ``associated
with'' in all cases. One commenter stated that matching specific wells
with emissions in the GHGRP could cause security concerns.
    Response: The EPA disagrees that requiring reporting of well
identification numbers is an overreach of our authority. The EPA has
determined that these data elements are useful and necessary for the
verification of existing data and for characterizing the emissions from
the industry segment. This final revision will allow the EPA to link
the GHGRP data to other databases (i.e. state permitting databases) to
more easily match the data reported under the GHGRP with other data
sources and will improve the accuracy and transparency of subpart W.
Additionally, being able to match the GHGRP data to other data sources
will provide the EPA with more options for analysis of the GHGRP data
to better inform future policy decisions related to GHG emissions from
the oil and natural gas production sector. The reporting of the well
identification numbers will also allow the EPA to assess the
completeness and representativeness of the data collected under the
GHGRP as a portion of all activity in the oil and natural gas
production sector. The EPA reiterates that CAA section 114 provides the
EPA with the authority to collect emissions data, which includes
information about the location of the source of emissions. Section 114
generally authorizes the EPA to gather information from any person who
owns or operates an emissions source, who is subject to a requirement
of the CAA, who manufactures control or process equipment, or who the
Administrator believes has information necessary for the purposes of
section 114(a). The EPA may gather information for purposes of
establishing implementation plans or emissions standards, determining
compliance, or ``carrying out any provision'' of the CAA. For these
reasons, the Administrator may request that a person, on a one-time,
periodic or continuous basis, establish and maintain records, make
reports, install and operate monitoring equipment and, among other
things, provide such information the Administrator may reasonably
require. This language has been interpreted to grant the EPA broad
authority. See, e.g., Dow Chemical Co. v. U.S., 467 U.S. 227, 233
(1986) (``Regulatory and enforcement authority generally carries with
it all modes of inquiring and investigation traditionally employed or
useful to execute the authority granted.''). See, generally Mandatory
Greenhouse Gas Reporting Rule: EPA's Response to Public Comments,
Volume No.: 9, Legal Issues (Docket Item No. EPA-HQ-OAR-2008-0508-
2264). The requirement to report well identification numbers for well-
specific data clearly fits within EPA's statutory authority. We also
believe, for the reasons stated above, that we are exercising this
authority reasonably in furtherance of the purposes of the Clean Air
Act. Further, the EPA disagrees that this is a deviation from our
previous approach to collecting data. As discussed in section II.B of
this preamble, the EPA is finalizing the requirement to report Onshore
Petroleum and Natural Gas Gathering and Boosting facilities at the
basin-level, which is consistent with our previous approach to the
Onshore Petroleum and Natural Gas Production segment.
    Therefore, the EPA is finalizing the requirements to report the
well identification number for well-specific data as proposed.
Specifically, for reporters in the Onshore Petroleum and Natural Gas
Production segment that report emissions using input data that are
calculated from measurements at individual wells or equipment or
operations associated with individual wells (e.g., if Equation W-10A is
used to calculate emissions from oil well completions and workovers
with hydraulic fracturing, well testing emissions, liquids unloading),
the report must include the well identification number for which those
measurements were made, or for which the equipment or operations are
associated. In addition, the EPA is finalizing the requirements in 40
CFR 98.236(aa)(1)(ii)(D) through (H) to include a list of the well
identification numbers by sub-basin for the producing wells at the end
of the calendar year and lists of the well identification numbers for
the wells acquired, divested, completed, and permanently taken out of
production during the calendar year. The EPA continues to expect that
this is a low burden to reporters because reporters already track and
maintain well identification numbers associated with measurements used
for the GHGRP input data.
    To respond to the comment that well identification numbers may not
be available for or assigned to equipment other than wells, the EPA
reviewed the permits and requirements in seven different states.
Although most of the states assign unique identifiers to each emission
source, the EPA found that only two of the seven states have a tracking
system that links individual emission sources to specific wells and
well identification numbers, and these two states are not consistent in
their approach. (See ``Greenhouse Gas Reporting Rule: Technical Support
for 2015 Revisions and Confidentiality Determinations for Petroleum and
Natural Gas Systems; Final Rule'' in Docket ID No. EPA-HQ-OAR-2014-0831
for more information on this analysis.) While it may be straightforward
to assign some emission sources directly to one well, particularly if
there is only one well on the single well pad and the reporter does not
operate any other wells nearby, the EPA's review of state requirements
shows that there may be multiple scenarios in which a reporter does not
know which well or wells are associated with a particular emission
source. For

example, there may be multiple wells on a single well pad and multiple
storage tanks associated with that well pad, and the tanks may have the
ability to receive hydrocarbon liquids from several of those wells.
Therefore, in light of the potential burden of requiring facilities to
develop new tracking systems that would assign and track emissions to
well identification numbers for the purposes of part 98, the EPA is not
requiring facilities in this rulemaking to report well identification
numbers for every emission source in a facility in the Onshore
Petroleum and Natural Gas Production segment.

E. Summary of Final Amendments to Best Available Monitoring Methods

1. Summary of Final Amendments
    As proposed, reporters will be allowed to use BAMM for the 2016
reporting year for the new industry segments and emission sources
included in this action. These include calculating and reporting
emissions from oil well completions and workovers with hydraulic
fracturing, from onshore petroleum and natural gas gathering and
boosting systems, and for transmission pipeline blowdown emissions.
Reporters are allowed to use BAMM to estimate inputs to emission
equations for the newly finalized emission sources for cases where the
monitoring of these inputs would not be possible beginning on January
1, 2016. The use of BAMM is not allowed for the reporting of well
identification numbers because reporters should already have well
identification numbers readily available for all wells and associated
equipment to which this reporting requirement applies and because the
well identification number is not a parameter that requires monitoring
equipment to be measured and, therefore, does not meet the requirements
for BAMM.
    For these sources, the EPA is finalizing a longer timeline for BAMM
than was proposed. Reporters have the option of using BAMM for the new
industry segments and emission sources included in this action from
January 1, 2016, to December 31, 2016, without seeking prior EPA
approval. The provision providing a set amount of automatic
transitional BAMM will allow reporters to prepare for data collection
while automatically being able to use BAMM, which is consistent with
the approach of prior part 98 rulemakings. This additional time for
reporters to comply with the revised monitoring methods in subpart W
will allow facilities to install the necessary monitoring equipment
during other planned (or unplanned) process unit downtime, thus
avoiding process interruptions, and is responsive to comments received
on the proposed rule provisions.
    The EPA is not finalizing the proposed provision to allow reporters
the opportunity to request an extension for the use of BAMM. The EPA
will not accept requests for an extension for the use of BAMM beyond
the time periods listed above. As proposed, the EPA also is not
providing transitional BAMM for these new requirements beyond December
31, 2016.
    The EPA is not allowing the use of BAMM beyond 2016 and does not
anticipate that BAMM will be needed beyond 2016 for the new segments
and emissions sources being finalized in this rule.
2. Summary of Comments and Responses
    Comment: Several commenters stated that only 3 months of automatic
BAMM and 1 year of transitional BAMM is not enough time to implement
the monitoring and measurement requirements for facilities newly
subject to subpart W and newly added emission sources. The commenter
stated that adding a new segment is a significant amendment and the EPA
has set the precedent of providing at least 1 year of automatic BAMM
when adding a new segment to subpart W. The commenters noted that not
all gathering and boosting reporters are already reporting as Onshore
Petroleum and Natural Gas Production facilities, so they will not
necessarily all be familiar with the monitoring and calculation
methodologies. The commenters also noted that nearly all reporters will
be spending the first month working on BAMM requests for the rest of
2016.
    The commenters had a variety of suggestions for how long the EPA
should provide BAMM for these new emission sources. Several commenters
suggested 1 year (through the end of 2016) for automatic BAMM. Another
commenter suggested March 31, 2017 (i.e., 1 year in addition to the
EPA's proposed 3 months), and another stated that 3 years would be
consistent with the length of time provided when the Onshore Petroleum
and Natural Gas Production segment was added to subpart W. Some
commenters addressed the length of transitional BAMM with the EPA's
approval. One commenter noted that a new reporter/facility could become
subject to one of the new segments beyond the end of 2016, so there
should be no deadline for submitting a request for BAMM to the EPA.
Another requested transitional BAMM through the end of 2018.
    Response: The EPA recognizes that most of the amendments being
finalized in this rulemaking are new requirements rather than
clarifications of existing reporting requirements for facilities