[Federal Register Volume 80, Number 204 (Thursday, October 22, 2015)]
[Rules and Regulations]
[Pages 64261-64298]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2015-25840]



[[Page 64261]]

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

[[Page 64262]]


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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: (202) 343-9263; fax number: (202) 343-2342; email address: 
[email protected]. 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

[[Page 64263]]

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).

[[Page 64264]]

    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.

[[Page 64265]]

 
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

[[Page 64266]]

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

[[Page 64267]]

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

[[Page 64268]]

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

[[Page 64269]]

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

[[Page 64270]]

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,

[[Page 64271]]

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

[[Page 64272]]

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

[[Page 64273]]

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

[[Page 64274]]

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.

[[Page 64275]]

2. Summary of Comments and Responses
    Comment: Several commenters noted that not all intrastate pipelines 
are subject to section 311 of the NGPA and asked the EPA to clarify 
which intrastate pipelines are subject to reporting. One commenter 
requested that the EPA clarify that intrastate pipelines not subject to 
the NGPA are not required to report under subpart W. Another commenter 
suggested revising the definition of owner or operator to state that if 
section 311 of the NGPA does not apply, the intrastate transmission 
pipeline owner or operator is the owner or operator identified on 
required reports with the appropriate state agency.
    Response: It was our intent to include transmission pipelines 
(including intrastate pipelines) that meet the already existing subpart 
W definition of ``transmission pipeline'' in the Onshore Natural Gas 
Transmission Pipeline segment. A transmission pipeline in subpart W is 
defined in 40 CFR 98.238 as a Federal Energy Regulatory Commission 
(FERC) rate-regulated Interstate pipeline, a state rate-regulated 
Intrastate pipeline, or a pipeline that falls under the ``Hinshaw 
Exemption'' as referenced in section 1(c) of the Natural Gas Act, 15 
U.S.C. 717-717 (w)(1994). After reviewing the comments on the proposed 
rule, we re-reviewed section 311 of the NGPA and found that only 
operators of some intrastate pipelines, including those that transport 
natural gas on behalf of an interstate pipeline or sell natural gas to 
an interstate pipeline, are required to prepare a Statement of 
Operating Conditions for compliance under section 311 of the NGPA. 
Therefore, to clarify how to determine the owner and operator of 
intrastate transmission pipelines, the finalized definition of 
``onshore natural gas transmission pipeline owner or operator'' 
specifies that for intrastate transmission pipelines not subject to 
section 311 of the NGPA, the owner or operator is the person identified 
as the owner or operator on reports to the state regulatory body 
regulating rates and charges for the sale of natural gas to consumers. 
The EPA also found that the proposed definition of ``onshore natural 
gas transmission pipeline owner or operator'' did not specify how to 
determine the owner or operator of pipelines that fall under the 
``Hinshaw Exemption.'' The EPA notes that similar to intrastate 
pipelines, pipelines that fall under the ``Hinshaw Exemption'' must 
apply for a ``blanket certificate'' under 18 CFR 284.224 in order to 
transport petroleum or natural gas on behalf of interstate pipelines. 
Therefore, the finalized definition of ``onshore natural gas 
transmission pipeline owner or operator'' also specifies that for a 
pipeline that falls under the ``Hinshaw Exemption,'' the owner or 
operator is the person identified as the owner or operator on blanket 
certificates issued under 18 CFR 284.224.
    Comment: Commenters appreciated that the EPA provided a threshold 
of 50 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

[[Page 64276]]

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

    \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.
---------------------------------------------------------------------------

    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

[[Page 64277]]

sources for all wells in a sub-basin included in the reported emissions 
data.
    The EPA is finalizing the proposed change to update references to 
the ``API well number'' in subpart W to ``well identification number.'' 
The EPA is not otherwise changing the well identification reporting 
requirements finalized in 2014 (79 FR 70352; November 25, 2014). 
Reporters will still need to report well identification numbers for 
liquids unloading and for any exploratory wells for which reporting has 
been delayed for 2 years.
2. Summary of Comments and Responses
    Comment: While one commenter supported the addition of well 
identification number reporting, most commenters opposed the proposal 
to require reporting of well identification numbers. These commenters 
asserted that requiring reporting of well identification numbers is an 
overreach of the EPA's authority for the reporting program under CAA 
section 114 and that the EPA has not provided a reasoned basis for the 
departure from the previous EPA approach that 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

[[Page 64278]]

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

E. Summary of Final Amendments to Best Available Monitoring Methods

1. Summary of Final Amendments
    As proposed, reporters will be allowed to use BAMM for the 2016 
reporting year for the new industry segments and emission sources 
included in this action. These include calculating and reporting 
emissions from oil well completions and workovers with hydraulic 
fracturing, from onshore petroleum and natural gas gathering and 
boosting systems, and for transmission pipeline blowdown emissions. 
Reporters are allowed to use BAMM to estimate inputs to emission 
equations for the newly finalized emission sources for cases where the 
monitoring of these inputs would not be possible beginning on January 
1, 2016. The use of BAMM is not allowed for the reporting of well 
identification numbers because reporters should already have well 
identification numbers readily available for all wells and associated 
equipment to which this reporting requirement applies and because the 
well identification number is not a parameter that requires monitoring 
equipment to be measured and, therefore, does not meet the requirements 
for BAMM.
    For these sources, the EPA is finalizing a longer timeline for BAMM 
than was proposed. Reporters have the option of using BAMM for the new 
industry segments and emission sources included in this action from 
January 1, 2016, to December 31, 2016, without seeking prior EPA 
approval. The provision providing a set amount of automatic 
transitional BAMM will allow reporters to prepare for data collection 
while automatically being able to use BAMM, which is consistent with 
the approach of prior part 98 rulemakings. This additional time for 
reporters to comply with the revised monitoring methods in subpart W 
will allow facilities to install the necessary monitoring equipment 
during other planned (or unplanned) process unit downtime, thus 
avoiding process interruptions, and is responsive to comments received 
on the proposed rule provisions.
    The EPA is not finalizing the proposed provision to allow reporters 
the opportunity to request an extension for the use of BAMM. The EPA 
will not accept requests for an extension for the use of BAMM beyond 
the time periods listed above. As proposed, the EPA also is not 
providing transitional BAMM for these new requirements beyond December 
31, 2016.
    The EPA is not allowing the use of BAMM beyond 2016 and does not 
anticipate that BAMM will be needed beyond 2016 for the new segments 
and emissions sources being finalized in this rule.
2. Summary of Comments and Responses
    Comment: Several commenters stated that only 3 months of automatic 
BAMM and 1 year of transitional BAMM is not enough time to implement 
the monitoring and measurement requirements for facilities newly 
subject to subpart W and newly added emission sources. The commenter 
stated that adding a new segment is a significant amendment and the EPA 
has set the precedent of providing at least 1 year of automatic BAMM 
when adding a new segment to subpart W. The commenters noted that not 
all gathering and boosting reporters are already reporting as Onshore 
Petroleum and Natural Gas Production facilities, so they will not 
necessarily all be familiar with the monitoring and calculation 
methodologies. The commenters also noted that nearly all reporters will 
be spending the first month working on BAMM requests for the rest of 
2016.
    The commenters had a variety of suggestions for how long the EPA 
should provide BAMM for these new emission sources. Several commenters 
suggested 1 year (through the end of 2016) for automatic BAMM. Another 
commenter suggested March 31, 2017 (i.e., 1 year in addition to the 
EPA's proposed 3 months), and another stated that 3 years would be 
consistent with the length of time provided when the Onshore Petroleum 
and Natural Gas Production segment was added to subpart W. Some 
commenters addressed the length of transitional BAMM with the EPA's 
approval. One commenter noted that a new reporter/facility could become 
subject to one of the new segments beyond the end of 2016, so there 
should be no deadline for submitting a request for BAMM to the EPA. 
Another requested transitional BAMM through the end of 2018.
    Response: The EPA recognizes that most of the amendments being 
finalized in this rulemaking are new requirements rather than 
clarifications of existing reporting requirements for facilities 
already subject to subpart W and may require the development and 
implementation of new systems of data collection and monitoring. 
Therefore, the EPA is finalizing 1 year of automatic transitional BAMM 
in place of the proposed 3 months of automatic transitional BAMM. This 
additional time for reporters to comply with the revised monitoring 
methods in subpart W will allow facilities to install the necessary 
monitoring equipment and implement any new systems of data collection 
that may be required. Because the amount of time for which automatic 
BAMM is available should be sufficient time to comply with the 
requirements of subpart W for the new segments and emission sources, 
the EPA will not provide additional BAMM beyond the automatic BAMM 
provisions in 40 CFR 98.234(g).
    We note that 40 CFR 98.235(e) and(f) provides 6 months of reporting 
flexibility for facilities that become subject to subpart W or acquire 
new sources after reporting year 2016. Reporters may also refer to the 
provisions of 40 CFR 98.235 after reporting year 2016 for guidance on 
reporting emissions if certain required data are not collected.

III. Confidentiality Determinations

A. Summary of Final Confidentiality Determinations for New Subpart W 
Data Elements

    In the proposed rule, we assigned new data elements to the 
appropriate direct emitter data categories created in the 2011 Final 
CBI Rule based on the type and characteristics of each data 
element.\10\ For data elements the EPA assigned to a direct emitter 
category with a categorical determination, the EPA proposed that the 
categorical determination for the category be applied to the proposed 
new data element. For data elements assigned to the ``Unit/Process 
`Static' Characteristics that Are Not Inputs to Emission Equations'' 
and ``Unit/Process Operating Characteristics that Are Not Inputs to 
Emission Equations,'' we proposed confidentiality determinations on a 
case-by-case basis taking into

[[Page 64279]]

consideration the criteria in 40 CFR 2.208, consistent with the 
approach used for data elements previously assigned to these two data 
categories. We also proposed individual confidentiality determinations 
for six new data elements without making a data category assignment. 
Refer to the preamble to the proposed rule (79 FR 76267; December 9, 
2014) for additional information regarding the proposed confidentiality 
determinations.
---------------------------------------------------------------------------

    \10\ ``Confidentiality Determinations for Data Required Under 
the Mandatory Greenhouse Gas Reporting Rule and Amendments to 
Special Rules Governing Certain Information Obtained Under the Clean 
Air Act'' (76 FR 30782, May 26, 2011).
---------------------------------------------------------------------------

    With consideration of the data provided by commenters, the EPA is 
finalizing the confidentiality determinations as proposed. 
Specifically, the EPA is finalizing the proposed decision to require 
each of the new data elements to be designated as ``not CBI.''
    The EPA proposed to provide reporters with the option to delay 
reporting of five data elements for 2 reporting years in situations 
where exploratory wells are the only wells in a sub-basin. We received 
comment requesting that the EPA provide the same 2-year delay for 
additional data elements associated with exploratory wells. The comment 
and the EPA's response are included in section III.B of this preamble. 
Based on consideration of the comment and consistent with the EPA's 
previous decisions related to exploratory wells under part 98 (79 FR 
63750, October 24, 2014; 79 FR 70352, November 25, 2014), the EPA is 
finalizing provisions to provide reporters with the option to delay 
reporting of five data elements as proposed and, based on comments 
received, an additional two data elements for 2 reporting years in 
situations where exploratory wells are the only wells in a sub-basin. 
For a given sub-basin, in situations where wildcat wells and/or 
delineation wells are the only wells in a sub-basin that can be used 
for the required measurement, the following seven data elements 
associated with the delineation or wildcat well may be delayed for 2 
reporting years: (1) The cumulative gas flowback time, in hours, for 
each sub-basin, from when gas is first detected until sufficient 
quantities are present to enable separation (40 CFR 98.236(g)(5)(i)); 
(2) the cumulative flowback time, in hours, for each sub-basin, after 
sufficient quantities of gas are present to enable separation (40 CFR 
98.236(g)(5)(i)); (3) the measured flowback rate, in standard cubic 
feet per hour, for each sub-basin (40 CFR 98.236(g)(5)(ii)); (4) the 
gas to oil ratio for the well (40 CFR 98.236(g)(5)(iii)(A)); (5) the 
volume of oil produced during the first 30 days of production after 
completions of each newly drilled well or well workover using hydraulic 
fracturing (40 CFR 98.236(g)(5)(iii)(B)); (6) the total annual gas-
liquid separator oil volume that is sent to applicable onshore storage 
tanks, in barrels (40 CFR 98.236(j)(1)(iii)); and (7) the total annual 
oil throughput that is sent to all atmospheric tanks, in barrels (40 
CFR 98.236(j)(2)(i)(A).
    Four of the seven data elements for which reporting may be delayed 
by 2 years are inputs to emission equations and the EPA provided the 
same option in the EPA's previous decisions related to exploratory 
wells under part 98 (79 FR 63750, October 24, 2014). Two of the seven 
data elements are inputs only when the applicable data are related to a 
single well (the two data elements in 40 CFR 98.236(g)(5)(i)), and one 
data element is never an input (40 CFR 98.236(j)(2)(i)(A)). Where the 
EPA agrees that there are early disclosure concerns related to 
exploratory wells, the EPA decided to treat those early disclosure 
concerns consistently throughout subpart W by providing the option to 
delay reporting by 2 years to all seven data elements listed above.
    At proposal, in cases where the two data elements in 40 CFR 
98.236(g)(5)(i)) are not inputs to equations, they were assigned to the 
``Unit/Process Operating Characteristics that are Not Inputs to 
Emission Equations'' category and were proposed to be ``not CBI.'' The 
EPA is finalizing this determination as proposed. Specifically, the 
``not CBI'' determination applies to all situations except for when the 
data elements are inputs to equations.
    For the situations when the data elements are used as inputs to 
equations, the EPA is assigning them to the ``Inputs to Emission 
Equations'' data category and is not making confidentiality 
determinations for these data. The EPA evaluated and summarized any 
potential disclosure concerns with the reporting of the data elements 
assigned to the ``Inputs to Emission Equations'' data category in the 
memo titled ``Review for Potential Disclosure Concerns for Inputs to 
Emission Equations Affected by the 2015 Revisions and Confidentiality 
Determinations for Petroleum and Natural Gas Systems'' available in 
Docket ID No. EPA-HQ-OAR-2014-0831. Other than the exception of the 
early disclosure concerns for certain data elements related to 
exploratory wells discussed earlier in this section, the EPA has 
concluded that there are no disclosure concerns with the reporting of 
these data elements.
    The data element collected under 40 CFR 98.236(j)(2)(i)(A) was 
proposed as ``not CBI'' and was not assigned to a data category. The 
EPA is finalizing this determination as proposed as well. For the data 
elements reported under 40 CFR 98.236(g)(5)(i)) (in cases where they 
are not inputs to equations) and 40 CFR 98.236(j)(2)(i)(A), the ``not 
CBI'' determinations will apply once the data are reported to the EPA 
following the 2-year delay.

B. Summary of Comments and Responses

    This section summarizes the major comments and responses related to 
the proposed categorical assignments and confidentiality 
determinations. See ``Response to Public Comments on Greenhouse Gas 
Reporting Rule: 2015 Revisions and Confidentiality Determinations for 
Petroleum and Natural Gas Systems'' in Docket ID No. EPA-HQ-OAR-2014-
0831 for a complete listing of all comments and responses. See the 
memorandum ``Final Data Category Assignments and Confidentiality 
Determinations for Data Elements (excluding inputs to emission 
equations) in the `Greenhouse Gas Reporting Rule: 2015 Revisions and 
Confidentiality Determinations for Petroleum and Natural Gas Systems; 
Final Rule' '' in Docket ID No. EPA-HQ-OAR-2014-0831 for a complete 
listing of final data category assignments and confidentiality 
determinations, and a discussion of changes since proposal.
    Comment: One commenter requested that the EPA reconsider the 
determination that the quantity of produced gas throughput in the 
calendar year and the quantity of produced gas consumed by the facility 
in the calendar year are ``not CBI.'' The commenter noted that the 
quantity of natural gas received and the quantity of processed gas 
leaving processing plants was maintained as CBI in the 2014 amendments 
(79 FR 70352; November 25, 2014). The commenter also stated that 
information on fuel consumed at gathering and boosting facilities is 
not typically publically available, and when this information is 
combined with the quantity of produced gas throughput, it directly 
indicates the fuel efficiency of a station. The commenter noted that 
while the EPA is correct that the agreements are long-term for a given 
well, revealing information about one facility's fuel efficiency could 
cause competitive harm by affecting contracts for other facilities 
owned by that company, especially if there are smaller gathering and 
boosting facilities in the area that do not have to report this 
information to the GHGRP.
    The commenter also requested that the EPA clarify a number of the 
reporting elements in 40 CFR

[[Page 64280]]

98.236(aa)(10). Specifically, the commenter requested clarification of 
the terms ``produced gas,'' ``produced condensate,'' ``produced oil,'' 
``throughput,'' and ``consumed'' as they are used in proposed 40 CFR 
98.236(aa)(10). The commenter also asserted that the data element in 40 
CFR 98.236(aa)(10)(ii) (``quantity of produced gas consumed'') would be 
redundant with subpart C and should not be finalized. Finally, the 
commenter stated that the requirement to report the ``quantity of gas 
flared, vented and/or unaccounted for in the calendar year'' in 40 CFR 
98.236(10)(aa)(v) would undermine over 5 years of rule development, 
public comment, reconsiderations, and petitioner negotiations because 
it would require reporting of emissions that are otherwise exempted 
(e.g., blowdowns below 50 ft\3\).
    Response: The EPA reviewed these comments and has clarified the 
reporting elements in 40 CFR 98.236(aa)(10) for the final rule. The 
final reporting requirements include: (1) The quantity of gas received 
by the gathering and boosting facility in the calendar year, in 
thousand standard cubic feet; (2) the quantity of gas transported to a 
natural gas processing facility, a natural gas transmission pipeline, a 
natural gas distribution pipeline, or another gathering and boosting 
facility in the calendar year, in thousand standard cubic feet; (3) the 
quantity of all hydrocarbon liquids received by the gathering and 
boosting facility in the calendar year, in barrels; and (4) the 
quantity of all hydrocarbon liquids transported to a natural gas 
processing facility, a natural gas transmission pipeline, a natural gas 
distribution pipeline, or another gathering and boosting facility in 
the calendar year, in barrels. The EPA has determined that these 
quantities will be easily accessible for all reporters and are more 
consistent with the reporting requirements for the Onshore Natural Gas 
Processing segment. The EPA is finalizing the CBI determinations for 
these quantities as ``not CBI,'' as proposed.
    The final reporting requirements do not include the terms 
``produced gas,'' ``produced condensate,'' ``produced oil,'' 
``throughput,'' or ``consumed,'' so no clarification regarding the use 
of those terms is needed. In particular, the final rule does not 
include a requirement to report the quantity of produced gas consumed 
by the facility. The difference between the quantities received by a 
gathering and boosting facility and the quantities exiting the 
gathering and boosting facility is expected to include the quantity of 
gas consumed by the facility as well as the quantity of gas flared or 
vented in one lump sum. Therefore, the reporting requirements do not 
directly indicate the fuel efficiency of the stations in a gathering 
and boosting facility.
    Comment: One commenter reiterated previously stated concerns over 
the disclosure of information for exploratory wells, especially when 
they are located in stepout areas where no prior reporting exists for a 
given sub-basin. The commenter supported the EPA's proposal to defer 
reporting of data elements related to oil well completions and 
workovers with hydraulic fracturing for exploratory wells, but 
expressed concern that EPA has not provided such a delay in reporting 
for all emissions data and data elements that are associated with 
exploratory wells. Specifically, the commenter stated that the EPA 
failed to provide a necessary 2-year deferral in reporting for the 
following data elements, which are as business sensitive and 
confidential as the other information for which the EPA proposed to 
defer reporting for 2 years:

     40 CFR 98.236(g)(5)(iii)(A)--If you used Equation W-12C 
to calculate the average gas production rate for an oil well, the 
gas to oil ratio for the well in standard cubic feet of gas per 
barrel of oil.
     40 CFR 98.236(g)(5)(iii)(B)--If you used Equation W-12C 
to calculate the average gas production rate for an oil well, the 
volume of oil produced during the first 30 days of production after 
completions of each newly drilled well or well workover using 
hydraulic fracturing, in barrels.
     40 CFR 98.236(g)(6)(i)--If you used Equation W-10B to 
calculate annual volumetric total gas emissions for completions that 
vent gas to the atmosphere, the vented natural gas volume, in 
standard cubic feet, for each well in the sub-basin.
     40 CFR 98.236(g)(6)(ii)--If you used Equation W-10B to 
calculate annual volumetric total gas emissions for completions that 
vent gas to the atmosphere, the flow rate at the beginning of the 
period of time when sufficient quantities of gas are present to 
enable separation, in standard cubic feet per hour, for each well in 
the sub-basin.
     40 CFR 98.236(g)(7)--For each oil well completion or 
workover and well type combination, annual gas emissions.
     40 CFR 98.236(g)(8)--For each oil well completion or 
workover and well type combination, annual CO2 emissions.
     40 CFR 98.236(g)(9)--For each oil well completion or 
workover and well type combination, annual CH4 emissions.
     40 CFR 98.236(g)(10)--For each oil well completion or 
workover and well type combination, the total N2O 
emissions, if the well emissions were vented to a flare.

    Response: The EPA reviewed the data elements identified by the 
commenter as having disclosure concerns for exploratory wells 
(delineation wells and wildcat wells). Consistent with the EPA's 
previous decisions related to exploratory wells under part 98 (79 FR 
63750, October 24, 2014; 79 FR 70352, November 25, 2014), the EPA has 
determined that, for gas well completions or workovers with hydraulic 
fracturing of wildcat wells and/or delineation wells, early public 
disclosure of some of the additional data elements identified by the 
commenter could reveal the well productivity of wildcat wells and/or 
delineation wells, thereby resulting in the loss of investment value.
    The additional data elements that could reveal well productivity 
for wildcat and/or delineation wells are as follows:

     The gas to oil ratio for the well (40 CFR 
98.236(g)(5)(iii)(A))
     The volume of oil produced during the first 30 days of 
production after completions of each newly drilled well or well 
workover using hydraulic fracturing (40 CFR 98.236(g)(5)(iii)(B))

    As the EPA has previously noted (79 FR 70352, November 25, 2014), 
in the interim period before these data are reported to the EPA, the 
EPA will be able to verify the majority of the emissions using data 
elements that will be reported to the EPA. For the seven total data 
elements that may be delayed for 2 years, the EPA will verify emissions 
using other data reported to the EPA, and will conclude verification 
upon receipt of the data. The EPA agrees with the commenter that a 2-
year delay of reporting is sufficient to prevent early public 
disclosure of these data and will provide sufficient time for the 
reporter to thoroughly conduct an assessment of the well. Given the 
results of this evaluation, the EPA determined that, for these data 
elements, in those cases where delineation wells or wildcat wells are 
the only wells in a sub-basin, reporters should be provided an option 
to delay reporting of the given data element for 2 reporting years 
starting in 2015. In such cases, if the 2-year delay in reporting is 
used, the reporter must indicate for each delayed reporting element 
that wildcat wells and/or delineation wells are the only wells in a 
sub-basin that can be used for the measurement in the current reporting 
year. In addition, when reporters report the delayed data elements 
after the 2-year delay, they must also report the well identification 
numbers for the applicable wildcat and/or delineation wells in the sub-
basin for which the reporting element was delayed. For example, if a 
delineation or wildcat well is completed in 2015 in a sub-basin that

[[Page 64281]]

has only delineation or wildcat wells or these are the only wells for 
which measurements can be made, then the reporter may: (1) Elect to 
report these seven data elements in their 2016 annual report submitted 
by March 31, 2017, or (2) elect to delay reporting of these data 
elements for up to 2 years. If the reporter elects to delay reporting, 
then the well identification numbers for the wildcat and delineation 
wells in the sub-basin for which reporting has been delayed and the 
data elements delayed from reporting must be reported no later than 
March 31, 2019.
    The following inputs meet the definition of emission data in 40 CFR 
2.301(a)(2)(i) because they indicate the amount or frequency of gas 
emitted by the facility: Volume of natural gas vented (reported under 
40 CFR 98.236(g)(6)(i)) and flow rate at the beginning of the period of 
time when sufficient quantities of gas are present to enable separation 
(reported under 40 CFR 98.236(g)(6)(ii)). Without corresponding 
activity data, such as a count of the exploratory wells in a sub-basin 
or production or flow rate data for a sub-basin containing only 
exploratory wells, there is no potential to disclose business sensitive 
information based on these data elements. Therefore, the EPA is not 
providing an option to delay reporting of these data elements for 2 
reporting years.
    Similarly, the data element annual gas emissions (reported under 40 
CFR 98.236(g)(7)) meets the definition of emission data in 40 CFR 
2.301(a)(2)(i) and is assigned to the ``Emissions'' data category 
because it indicates the amount of gas emitted by the facility. In 
addition, the following data elements meet the definition of emission 
data in 40 CFR 2.301(a)(2)(i) and are assigned to the ``Emissions'' 
data category because they are emissions of pollutants emitted by the 
source: annual CO2 emissions (reported under 40 CFR 
98.236(g)(8)), annual CH4 emissions (reported under 40 CFR 
98.236(g)(9)), and annual nitrous oxide (N2O) emissions if 
the well emissions were vented to a flare (reported under 40 CFR 
98.236(g)(10)). For these data elements that are assigned to the 
``Emissions'' data category, the commenter did not claim or provide any 
justification for why these data elements do not meet the definition of 
emission data. Without corresponding activity data, such as a count of 
the exploratory wells in a sub-basin or production or flow rate data 
for a sub-basin containing only exploratory wells, there is no 
potential to disclose business sensitive information based on these 
data elements. Therefore, the EPA is not providing an option to delay 
reporting of these data elements for 2 reporting years.

IV. Impacts of the Final Amendments to Subpart W

A. Impacts of the Final Amendments

    The final amendments to subpart W add monitoring and reporting 
requirements for reporters in three industry segments: Onshore 
Petroleum and Natural Gas Production, Onshore Petroleum and Natural Gas 
Gathering and Boosting, and Onshore Natural Gas Transmission Pipeline. 
The EPA is adding 213 new data elements to the reporting requirements. 
The new data elements impose additional burden and costs because, for 
each of the new data elements that are required to be reported, 
reporters are required to calculate the data element using readily 
available data and report the value to the EPA via e-GGRT as part of 
the annual report currently required under part 98.
    The EPA calculated the increase in reporting and recordkeeping 
burden associated with the new data elements by adjusting labor hours 
upwards per reporter for all affected industry segments. For all three 
segments, an estimate of 10 hours per year per reporter was allotted 
for reporting via e-GGRT and 10 hours per year per reporter was 
allotted for recordkeeping.
    Costs to reporters associated with this rulemaking are expressed as 
labor costs (i.e., the cost of labor by facility staff to comply with 
the amendments), capital costs for equipment and travel, and operation 
and maintenance (O&M) costs.
    Reporters in the Onshore Petroleum and Natural Gas Production 
segment have to monitor and report emissions and data elements 
associated with oil well completions and workovers with hydraulic 
fracturing. Reporters in this segment also have to report the well 
identification numbers associated with individual oil and gas wells. 
The addition of the requirement to report emissions associated with oil 
well completions and workovers with hydraulic fracturing is expected to 
cause an increase in the amount of emissions that count towards 
determining applicability under subpart W. The addition of reporting 
requirements for oil wells with hydraulic fracturing is expected to 
affect 246 existing reporters and to cause approximately 50 new 
reporters to exceed the reporting threshold for the onshore petroleum 
and natural gas production facility. These numbers have not changed 
from proposal.
    The 50 new reporters will be required to estimate and report 
emissions data and related data elements associated with several 
different emission sources within this new industry segment, including 
acid gas removal units, associated natural gas venting and flaring, 
storage tanks, dehydrators, equipment leaks, liquids unloading, and 
pneumatic devices.
    Reporters in the Onshore Petroleum and Natural Gas Gathering and 
Boosting segment must estimate and report emissions data and related 
data elements associated with several different emission sources within 
this new industry segment, including acid gas removal units, storage 
tanks, blowdown vents, dehydrators, equipment leaks, flare stacks, and 
pneumatic devices. Approximately 200 new reporters are expected to be 
subject to subpart W due to the amendments for the Onshore Petroleum 
and Natural Gas Gathering and Boosting segment in this rulemaking. This 
number has not changed from proposal.
    Reporters in the Onshore Natural Gas Transmission Pipeline segment 
will need to estimate and report emissions data and related data 
elements associated with transmission pipeline blowdown activities. 
Approximately 183 new reporters in this segment are expected to be 
subject to subpart W. This number increased from 150 to 183 since 
proposal due to public comment.
    The EPA received multiple comments regarding the impacts of the 
proposed amendments. After evaluating these comments and reviewing 
other changes from proposal, the EPA revised the impacts assessment 
slightly from proposal. The final amendments to subpart W are not 
expected to significantly change the burden calculated at proposal.
    The EPA has determined that the cost associated with this final 
action will be $7,190,235 each year and has worked to minimize burden 
to reporters where practicable. See the memorandum, ``Assessment of 
Impacts of the 2015 Final Revisions to Subpart W'' in Docket ID No. 
EPA-HQ-OAR-2014-0831 for additional information.

B. Summary of Comments and Responses

    This section summarizes the major comments and responses related to 
the impacts of the proposed amendments to subpart W of part 98. We note 
that numerous commenters asserted that the burden was underestimated, 
and some provided suggestions for improvement, but most of those 
comments did not include the detailed information the EPA needed to 
assess the comment

[[Page 64282]]

fully, such as a suggestion for a revised burden estimate, support for 
the suggestion, and an explanation of why the suggested value is 
representative of all sources subject to the same requirements. See 
``Response to Public Comments on Greenhouse Gas Reporting Rule: 2015 
Revisions and Confidentiality Determinations for Petroleum and Natural 
Gas Systems'' in Docket ID No. EPA-HQ-OAR-2014-0831 for a complete 
listing of all comments and responses.
    Comment: One commenter asked for an explanation for the estimate of 
200 respondents in the Onshore Petroleum and Natural Gas Gathering and 
Boosting segment. The commenter noted that the EPA estimated the number 
of reporters in the Onshore Natural Gas Processing industry segment as 
291 reporters. The commenter stated by the nature of the industry, any 
company with a processing plant will most likely also have an 
associated gathering system subject to reporting and suggested that the 
number of reporters in the Onshore Petroleum and Natural Gas Gathering 
and Boosting industry segment should total 291, at minimum, but 
potentially more.
    Response: Due to differences in the definitions of the two industry 
segments, the EPA disagrees that the number of reporters in the Onshore 
Petroleum and Natural Gas Gathering and Boosting segment should match 
the number of reporters in the Onshore Natural Gas Processing segment. 
The EPA estimate of 200 respondents was based on the regulatory 
analysis for Office of Pipeline Safety (OPS) safety regulations. In the 
analysis, it was estimated that 50 percent of the 400 natural gas 
gathering pipeline operators under regulation are small entities 
operating small diameter, low pressure (Type B) gathering lines and 
fifty percent are large diameter, high pressure lines (Type A) 
potentially subject to the safety regulation (depending upon proximity 
to population centers).\11\
---------------------------------------------------------------------------

    \11\ U.S. Department of Transportation. Pipeline and Hazardous 
Materials Safety Administration. Draft Regulatory Evaluation, 
Regulated Natural Gas Gathering Lines, Regulatory Analysis, Docket 
RSPA-1998-4868. Available at www.viadata.com/pipeliner/library_docs/Gatheringanalysis.pdf.
---------------------------------------------------------------------------

    Comment: One commenter noted that the EPA estimated that there are 
150 reporters for Onshore Natural Gas Transmission Pipeline facilities 
at proposal. However, the commenter stated that the EPA should expect 
183 reporters in the segment based on the number of operators that are 
required to complete a PHMSA annual report (PHMSA F-7100-2) or are 
regulated by FERC under section 311 of the NGPA.
    Response: The EPA agrees with the suggested change. The preamble to 
the final amendments, the final Supporting Statement, and the 
memorandum ``Assessment of Impacts of the 2015 Final Revisions to 
Subpart W'' (see Docket ID No. EPA-HQ-OAR-2014-0831) have been updated 
to reflect the change from 150 reporters to 183 reporters in the 
Onshore Natural Gas Transmission Pipeline segment.
    Comment: Two commenters objected to the collection of well 
identification numbers. One commenter noted that collection would 
require significant resources and would be unduly burdensome on 
operators. The other commenter stated that the burdens associated with 
collecting and reporting this data far outweigh any minimal benefits in 
data quality.
    Response: The EPA is finalizing the well identification number 
reporting requirements for well-specific data as proposed, but the EPA 
is not requiring well identification numbers to be reported in this 
rulemaking for equipment other than wells. See section II.D of this 
preamble for additional discussion responding to this comment.

V. Statutory and Executive Order Reviews

A. Executive Order 12866: Regulatory Planning and Review and Executive 
Order 13563: Improving Regulation and Regulatory Review

    This action is not a significant regulatory action and was 
therefore not submitted to the Office of Management and Budget (OMB) 
for review.
    In addition, the EPA prepared an analysis of the potential costs 
associated with the final amendments to subpart W. This analysis is 
contained in the memorandum ``Assessment of Impacts of the 2015 Final 
Revisions to Subpart W.'' A copy of the analysis is available in the 
docket for this action (see Docket ID No. EPA-HQ-OAR-2014-0831) and the 
analysis is briefly summarized in section IV of this preamble.

B. Paperwork Reduction Act (PRA)

    The information collection activities in this rule have been 
submitted for approval to the OMB under the PRA. The Information 
Collection Request (ICR) document that the EPA prepared has been 
assigned EPA ICR number 2300.16. You can find a copy of the ICR in the 
docket for this rule, and it is briefly summarized here. The 
information collection requirements are not enforceable until OMB 
approves them.
    This action adds monitoring and reporting requirements for 
reporters in three industry segments: Onshore Petroleum and Natural Gas 
Production, Onshore Petroleum and Natural Gas Gathering and Boosting, 
and Onshore Natural Gas Transmission Pipeline. Data collection 
complements the Inventory of U.S. Greenhouse Gas Emissions and Sinks 
(Inventory) and provides a critical tool for communities to identify 
nearby sources of GHGs and provide information to state and local 
governments. The data can be used to complement atmospheric GHG studies 
and inform updates to emission inventories. Various activity data are 
collected that can be used to improve understanding of the occurrence 
of emissions from a variety of sources.
    Data collected must be made available to the public unless the data 
qualify for CBI treatment under the CAA and EPA regulations. All data 
determined by the EPA to be CBI are safeguarded in accordance with 
regulations in 40 CFR chapter 1, part 2, subpart B.
    Respondents/Affected Entities: The respondents in this information 
collection include owners and operators of petroleum and natural gas 
systems facilities that must report their GHG emissions to the EPA to 
comply with subpart W of part 98.
    Respondent's Obligation To Respond: The respondent's obligation to 
respond is mandatory under the authority provided in CAA section 114.
    Estimated Number of Respondents: Approximately 3,300 respondents 
per year.
    Frequency of Response: Annual.
    Total Estimated Burden: 317,100 hours (per year). Burden is defined 
at 5 CFR 1320.3(b).
    Total Estimated Cost: $29.2 million (per year), includes $1.1 
million annualized capital and 2.8 million operation & maintenance 
costs.
    An agency may not conduct or sponsor, and a person is not required 
to respond to, a collection of information unless it displays a 
currently valid OMB control number. The OMB control numbers for the 
EPA's regulations in 40 CFR are listed in 40 CFR part 9. When OMB 
approves this ICR, the Agency will announce that approval in the 
Federal Register and publish a technical amendment to 40 CFR part 9 to 
display the OMB control number for the approved information collection 
activities contained in this final rule.

C. Regulatory Flexibility Act (RFA)

    I certify that this action will not have a significant economic 
impact on a substantial number of small entities under the RFA. The 
small entities

[[Page 64283]]

subject to the requirements of this action are: (1) A small business as 
defined by the Small Business Administration's regulations at 13 CFR 
121.201; (2) a small governmental jurisdiction that is a government of 
a city, county, town, school district or special district with a 
population of less than 50,000; and (3) a small organization that is 
any not-for-profit enterprise which is independently owned and operated 
and is not dominant in its field.
    The Agency has determined that a few small businesses may 
experience an insignificant impact. Details of this analysis are 
presented in section IV.B of the preamble to the proposed amendments 
(79 FR 76267; December 9, 2014).
    Although this final rule will not have a significant economic 
impact on a substantial number of small entities, the EPA nonetheless 
has tried to reduce the impact of this rule on small entities. As part 
of the process of finalizing the subpart W 2010 final rule, the EPA 
took several steps to evaluate the effect of the rule on small 
entities. For example, the EPA determined appropriate thresholds that 
reduced the number of small businesses reporting. In addition, the EPA 
supports a ``help desk'' for the rule, which is available to answer 
questions on the provisions in the rule. Finally, the EPA continues to 
conduct significant outreach on the GHG reporting rule and maintains an 
``open door'' policy for stakeholders to help inform the EPA's 
understanding of key issues for the industries.

D. Unfunded Mandates Reform Act (UMRA)

    This action does not contain an unfunded mandate of $100 million or 
more as described in UMRA, 2 U.S.C. 1531-1538, and does not 
significantly or uniquely affect small governments. This action imposes 
no enforceable duty on any state, local, or tribal governments or the 
private sector.

E. Executive Order 13132: Federalism

    This action does not have federalism implications. It will not have 
substantial direct effects on the states, on the relationship between 
the national government and the states, or on the distribution of power 
and responsibilities among the various levels of government.

F. Executive Order 13175: Consultation and Coordination With Indian 
Tribal Governments

    This action has tribal implications. However, it will neither 
impose substantial direct compliance costs on federally recognized 
tribal governments, nor preempt tribal law. This regulation will apply 
directly to petroleum and natural gas facilities that emit GHGs. 
Although few facilities that will be subject to the rule are likely to 
be owned by tribal governments, the EPA has sought opportunities to 
provide information to tribal governments and representatives during 
the development of the proposed and final subpart W that was 
promulgated on November 30, 2010 (75 FR 74458).
    The EPA consulted with tribal officials under the EPA Policy on 
Consultation and Coordination with Indian Tribes early in the process 
of developing this regulation to permit them to have meaningful and 
timely input into its development. A summary of that consultation is 
provided in section IV.F of the preamble to the re-proposal of subpart 
W published on April 12, 2010 (75 FR 18608), and section IV.F of the 
preamble to the subpart W 2010 final rule published on November 30, 
2010 (75 FR 74458).

G. Executive Order 13045: Protection of Children From Environmental 
Health Risks and Safety Risks

    The EPA interprets Executive Order 13045 as applying only to those 
regulatory actions that concern environmental health or safety risks, 
that the EPA has reason to believe may disproportionately affect 
children, per the definition of ``covered regulatory action'' in 
section 2-202 of the Executive Order. This action is not subject to 
Executive Order 13045 because it does not concern an environmental 
health risk or safety risks.

H. Executive Order 13211: Actions That Significantly Affect Energy 
Supply, Distribution, or Use

    This action is not subject to Executive Order 13211, because it is 
not a significant regulatory action under Executive Order 12866.

I. National Technology Transfer and Advancement Act (NTTAA)

    This rulemaking does not involve technical standards.

J. Executive Order 12898: Federal Actions To Address Environmental 
Justice in Minority Populations and Low-Income Populations

    The EPA believes the human health or environmental risk addressed 
by this action will not have potential disproportionately high and 
adverse human health or environmental effects on minority, low-income 
or indigenous populations because it does not affect the level of 
protection provided to human health or the environment. Instead, this 
rule addresses information collection and reporting procedures.

K. Congressional Review Act (CRA)

    This action is subject to the CRA, and the EPA will submit a rule 
report to each House of the Congress and to the Comptroller General of 
the United States. This action is not a ``major rule'' as defined by 5 
U.S.C. 804(2).

List of Subjects in 40 CFR Part 98

    Environmental protection, Administrative practice and procedure, 
Greenhouse gases, Reporting and recordkeeping requirements.

    Dated: October 1, 2015.
Gina McCarthy,
Administrator.

    For the reasons stated in the preamble, title 40, chapter I, of the 
Code of Federal Regulations is amended as follows:

PART 98--MANDATORY GREENHOUSE GAS REPORTING

0
1. The authority citation for part 98 continues to read as follows:

    Authority: 42 U.S.C. 7401, et seq.

Subpart W--Petroleum and Natural Gas Systems

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


Sec.  98.230  Definition of the source category.

    (a) * * *
    (9) Onshore petroleum and natural gas gathering and boosting. 
Onshore petroleum and natural gas gathering and boosting means 
gathering pipelines and other equipment used to collect petroleum and/
or natural gas from onshore production gas or oil wells and used to 
compress, dehydrate, sweeten, or transport the petroleum and/or natural 
gas to a natural gas processing facility, a natural gas transmission 
pipeline or to a natural gas distribution pipeline. Gathering and 
boosting equipment includes, but is not limited to gathering pipelines, 
separators, compressors, acid gas removal units, dehydrators, pneumatic 
devices/pumps, storage vessels, engines, boilers, heaters, and flares. 
Gathering and boosting equipment does not include equipment reported 
under any other industry segment defined in this section. Gathering 
pipelines operating on a vacuum and gathering pipelines with a GOR) 
less than 300 standard cubic feet per stock tank barrel (scf/STB) are 
not included in this industry segment (oil

[[Page 64284]]

here refers to hydrocarbon liquids of all API gravities).
    (10) Onshore natural gas transmission pipeline. Onshore natural gas 
transmission pipeline means all natural gas transmission pipelines as 
defined in Sec.  98.238.
* * * * *

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


Sec.  98.231  Reporting threshold.

    (a) You must report GHG emissions under this subpart if your 
facility contains petroleum and natural gas systems and the facility 
meets the requirements of Sec.  98.2(a)(2), except for the industry 
segments in paragraphs (a)(1) through (4) of this section.
    (1) Facilities must report emissions from the onshore petroleum and 
natural gas production industry segment only if emission sources 
specified in Sec.  98.232(c) emit 25,000 metric tons of CO2 
equivalent or more per year.
    (2) Facilities must report emissions from the natural gas 
distribution industry segment only if emission sources specified in 
Sec.  98.232(i) emit 25,000 metric tons of CO2 equivalent or 
more per year.
    (3) Facilities must report emissions from the onshore petroleum and 
natural gas gathering and boosting industry segment only if emission 
sources specified in Sec.  98.232(j) emit 25,000 metric tons of 
CO2 equivalent or more per year.
    (4) Facilities must report emissions from the onshore natural gas 
transmission pipeline industry segment only if emission sources 
specified in Sec.  98.232(m) emit 25,000 metric tons of CO2 
equivalent or more per year.
* * * * *

0
4. Section 98.232 is amended by:
0
a. Revising paragraphs (a) and (c)(6) and (8);
0
b. Adding paragraph (j);
0
c. Revising paragraph (k); and
0
d. Adding paragraph (m).
    The revisions and additions read as follows:


Sec.  98.232  GHGs to report.

    (a) You must report CO2, CH4, and 
N2O emissions from each industry segment specified in 
paragraphs (b) through (j) and (m) of this section, CO2, 
CH4, and N2O emissions from each flare as 
specified in paragraphs (b) through (j) of this section, and stationary 
and portable combustion emissions as applicable as specified in 
paragraph (k) of this section.
* * * * *
    (c) * * *
    (6) Well venting during well completions with hydraulic fracturing 
that have a GOR of 300 scf/STB or greater (oil here refers to 
hydrocarbon liquids produced of all API gravities).
* * * * *
    (8) Well venting during well workovers with hydraulic fracturing 
that have a GOR of 300 scf/STB or greater (oil here refers to 
hydrocarbon liquids produced of all API gravities).
* * * * *
    (j) For an onshore petroleum and natural gas gathering and boosting 
facility, report CO2, CH4, and N2O 
emissions from the following source types:
    (1) Natural gas pneumatic device venting.
    (2) Natural gas driven pneumatic pump venting.
    (3) Acid gas removal vents.
    (4) Dehydrator vents.
    (5) Blowdown vent stacks.
    (6) Storage tank vented emissions.
    (7) Flare stack emissions.
    (8) Centrifugal compressor venting.
    (9) Reciprocating compressor venting.
    (10) Equipment leaks from valves, connectors, open ended lines, 
pressure relief valves, pumps, flanges, and other equipment leak 
sources (such as instruments, loading arms, stuffing boxes, compressor 
seals, dump lever arms, and breather caps).
    (11) Gathering pipeline equipment leaks.
    (12) You must use the methods in Sec.  98.233(z) and report under 
this subpart the emissions of CO2, CH4, and 
N2O from stationary or portable fuel combustion equipment 
that cannot move on roadways under its own power and drive train, and 
that is located at an onshore petroleum and natural gas gathering and 
boosting facility as defined in Sec.  98.238. Stationary or portable 
equipment includes the following equipment, which are integral to the 
movement of natural gas: Natural gas dehydrators, natural gas 
compressors, electrical generators, steam boilers, and process heaters.
    (k) Report under subpart C of this part (General Stationary Fuel 
Combustion Sources) the emissions of CO2, CH4, 
and N2O from each stationary fuel combustion unit by 
following the requirements of subpart C except for facilities under 
onshore petroleum and natural gas production, onshore petroleum and 
natural gas gathering and boosting, and natural gas distribution. 
Onshore petroleum and natural gas production facilities must report 
stationary and portable combustion emissions as specified in paragraph 
(c) of this section. Natural gas distribution facilities must report 
stationary combustion emissions as specified in paragraph (i) of this 
section. Onshore petroleum and natural gas gathering and boosting 
facilities must report stationary and portable combustion emissions as 
specified in paragraph (j) of this section.
* * * * *
    (m) For onshore natural gas transmission pipeline, report pipeline 
blowdown CO2 and CH4 emissions from blowdown vent 
stacks.

0
5. Section 98.233 is amended by:
0
a. Revising the parameters ``EFt'' and ``GHGi'' 
of Equation W-1 in paragraph (a);
0
b. Revising paragraph (a)(2);
0
c. Revising the parameter ``EF'' of Equation W-2 in paragraph (c);
0
d. Revising paragraph (d)(8)(iii);
0
e. Revising paragraphs (g) introductory text, (g)(1) introductory text, 
(g)(1)(i), and paragraph (g)(1)(ii) heading;
0
f. Revising the parameters ``FRMs,'' ``FRs,p'' 
and ``PRs,p'' of Equation W-12A in paragraph (g)(1)(iii);
0
g. Revising the parameters ``FRMi,'' and 
``PRs,p'' of Equation W-12B in paragraph (g)(1)(iv);
0
h. Revising paragraphs (g)(1)(v) and (vi);
0
i. Adding paragraph (g)(1)(vii);
0
j. Revising paragraph (g)(2) introductory text;
0
k. Adding paragraph (g)(2)(iv);
0
l. Revising paragraph (g)(4) introductory text;
0
m. Revising paragraph (i)(2) introductory text;
0
n. Revising the parameters ``Ta'' and ``Pa'' of 
Equation W-14A in paragraph (i)(2)(i);
0
o. Revising paragraphs (j) introductory text, (j)(1) through (3), and 
(j)(6);
0
p. Revising paragraph (n)(2)(i);
0
q. Revising paragraphs (o) introductory text and (o)(10);
0
r. Revising paragraphs (p) introductory text and (p)(10);
0
s. Revising paragraphs (r) introductory text, (r)(2) introductory text, 
and (r)(2)(i);
0
t. Revising paragraphs (u)(2)(i) and (iii); and
0
x. Revising paragraphs (z) introductory text and (z)(1)(ii).
    The revisions and additions read as follows:


Sec.  98.233  Calculating GHG emissions.

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

EFt = Population emission factors for natural gas 
pneumatic device vents (in standard cubic feet per hour per device) 
of each type ``t'' listed in Tables W-1A, W-3, and W-4 of this 
subpart for onshore petroleum and natural gas production,

[[Page 64285]]

onshore natural gas transmission compression, and underground 
natural gas storage facilities, respectively. Onshore petroleum and 
natural gas gathering and boosting facilities must use the 
population emission factors listed in Table W-1A of this subpart.
GHGi = For onshore petroleum and natural gas production 
facilities, onshore petroleum and natural gas gathering and boosting 
facilities, onshore natural gas transmission compression facilities, 
and underground natural gas storage facilities, concentration of 
GHGi, CH4 or CO2, in produced 
natural gas or processed natural gas for each facility as specified 
in paragraphs (u)(2)(i), (iii), and (iv) of this section.

* * * * *
    (2) For the onshore petroleum and natural gas production industry 
segment, you have the option in the first two consecutive calendar 
years to determine ``Countt'' for Equation W-1 of this 
section for each type of natural gas pneumatic device (continuous high 
bleed, continuous low bleed, and intermittent bleed) using engineering 
estimates based on best available data. For the onshore petroleum and 
natural gas gathering and boosting industry segment, you have the 
option in the first two consecutive calendar years to determine 
``Countt'' for Equation W-1 for each type of natural gas 
pneumatic device (continuous high bleed, continuous low bleed, and 
intermittent bleed) using engineering estimates based on best available 
data.
* * * * *
    (c) * * *
* * * * *

EF = Population emissions factors for natural gas driven pneumatic 
pumps (in standard cubic feet per hour per pump) listed in Table W-
1A of this subpart for onshore petroleum and natural gas production 
and onshore petroleum and natural gas gathering and boosting 
facilities.

* * * * *
    (d) * * *
    (8) * * *
    (iii) If a continuous gas analyzer is not available or installed, 
you may use the outlet pipeline quality specification for 
CO2 in natural gas.
* * * * *
    (g) Well venting during completions and workovers with hydraulic 
fracturing. Calculate annual volumetric natural gas emissions from gas 
well and oil well venting during completions and workovers involving 
hydraulic fracturing using Equation W-10A or Equation W-10B of this 
section. Equation W-10A applies to well venting when the gas flowback 
rate is measured from a specified number of example completions or 
workovers and Equation W-10B applies when the gas flowback vent or 
flare volume is measured for each completion or workover. Completion 
and workover activities are separated into two periods, an initial 
period when flowback is routed to open pits or tanks and a subsequent 
period when gas content is sufficient to route the flowback to a 
separator or when the gas content is sufficient to allow measurement by 
the devices specified in paragraph (g)(1) of this section, regardless 
of whether a separator is actually utilized. If you elect to use 
Equation W-10A, you must follow the procedures specified in paragraph 
(g)(1). If you elect to use Equation W-10B, you must use a recording 
flow meter installed on the vent line, downstream of a separator and 
ahead of a flare or vent, to measure the gas flowback. For either 
equation, emissions must be calculated separately for completions and 
workovers, for each sub-basin, and for each well type combination 
identified in paragraph (g)(2) of this section. You must calculate 
CH4 and CO2 volumetric and mass emissions as 
specified in paragraph (g)(3) of this section. If emissions from well 
venting during completions and workovers with hydraulic fracturing are 
routed to a flare, you must calculate CH4, CO2, 
and N2O annual emissions as specified in paragraph (g)(4) of 
this section.
[GRAPHIC] [TIFF OMITTED] TR22OC15.007

Where:

Es,n = Annual volumetric natural gas emissions in 
standard cubic feet from gas venting during well completions or 
workovers following hydraulic fracturing for each sub-basin and well 
type combination.
W = Total number of wells completed or worked over using hydraulic 
fracturing in a sub-basin and well type combination.
Tp,s = Cumulative amount of time of flowback, after 
sufficient quantities of gas are present to enable separation, where 
gas vented or flared for the completion or workover, in hours, for 
each well, p, in a sub-basin and well type combination during the 
reporting year. This may include non-contiguous periods of venting 
or flaring.
Tp,i = Cumulative amount of time of flowback to open 
tanks/pits, from when gas is first detected until sufficient 
quantities of gas are present to enable separation, for the 
completion or workover, in hours, for each well, p, in a sub-basin 
and well type combination during the reporting year. This may 
include non-contiguous periods of routing to open tanks/pits but 
does not include periods when the oil well ceases to produce fluids 
to the surface.
FRMs = Ratio of average gas flowback, during the period 
when sufficient quantities of gas are present to enable separation, 
of well completions and workovers from hydraulic fracturing to 30-
day production rate for the sub-basin and well type combination, 
calculated using procedures specified in paragraph (g)(1)(iii) of 
this section.
FRMi = Ratio of initial gas flowback rate during well 
completions and workovers from hydraulic fracturing to 30-day gas 
production rate for the sub-basin and well type combination, 
calculated using procedures specified in paragraph (g)(1)(iv) of 
this section, for the period of flow to open tanks/pits.
PRs,p = Average gas production flow rate during the first 
30 days of production after completions of newly drilled wells or 
well workovers using hydraulic fracturing in standard cubic feet per 
hour of each well p, that was measured in the sub-basin and well 
type combination. If applicable, PRs,p may be calculated 
for oil wells using procedures specified in paragraph (g)(1)(vii) of 
this section.
EnFs,p = Volume of N2 injected gas in cubic 
feet at standard conditions that was injected into the reservoir 
during an energized fracture job or during flowback for each well, 
p, as determined by using an appropriate meter according to methods 
described in Sec.  98.234(b), or by using receipts of gas purchases 
that are used for the energized fracture job or injection during 
flowback. Convert to standard conditions using paragraph (t) of this 
section. If the fracture process did

[[Page 64286]]

not inject gas into the reservoir or if the injected gas is 
CO2 then EnFs,p is 0.
FVs,p = Flow volume of vented or flared gas for each 
well, p, in standard cubic feet measured using a recording flow 
meter (digital or analog) on the vent line to measure gas flowback 
during the separation period of the completion or workover according 
to methods set forth in Sec.  98.234(b).
FRp,i = Flow rate vented or flared of each well, p, in 
standard cubic feet per hour measured using a recording flow meter 
(digital or analog) on the vent line to measure the flowback, at the 
beginning of the period of time when sufficient quantities of gas 
are present to enable separation, of the completion or workover 
according to methods set forth in Sec.  98.234(b).

    (1) If you elect to use Equation W-10A of this section on gas 
wells, you must use Calculation Method 1 as specified in paragraph 
(g)(1)(i) of this section, or Calculation Method 2 as specified in 
paragraph (g)(1)(ii) of this section, to determine the value of 
FRMs and FRMi. If you elect to use Equation W-10A 
of this section on oil wells, you must use Calculation Method 1 as 
specified in paragraph (g)(1)(i) to determine the value of 
FRMs and FRMi. These values must be based on the 
flow rate for flowback gases, once sufficient gas is present to enable 
separation. The number of measurements or calculations required to 
estimate FRMs and FRMi must be determined 
individually for completions and workovers per sub-basin and well type 
combination as follows: Complete measurements or calculations for at 
least one completion or workover for less than or equal to 25 
completions or workovers for each well type combination within a sub-
basin; complete measurements or calculations for at least two 
completions or workovers for 26 to 50 completions or workovers for each 
sub-basin and well type combination; complete measurements or 
calculations for at least three completions or workovers for 51 to 100 
completions or workovers for each sub-basin and well type combination; 
complete measurements or calculations for at least four completions or 
workovers for 101 to 250 completions or workovers for each sub-basin 
and well type combination; and complete measurements or calculations 
for at least five completions or workovers for greater than 250 
completions or workovers for each sub-basin and well type combination.
    (i) Calculation Method 1. You must use Equation W-12A of this 
section as specified in paragraph (g)(1)(iii) of this section to 
determine the value of FRMs. You must use Equation W-12B of 
this section as specified in paragraph (g)(1)(iv) of this section to 
determine the value of FRMi. The procedures specified in 
paragraphs (g)(1)(v) and (vi) of this section also apply. When making 
gas flowback measurements for use in Equations W-12A and W-12B of this 
section, you must use a recording flow meter (digital or analog) 
installed on the vent line, downstream of a separator and ahead of a 
flare or vent, to measure the gas flowback rates in units of standard 
cubic feet per hour according to methods set forth in Sec.  98.234(b).
    (ii) Calculation Method 2 (for gas wells). * * *
    (iii) * * *
* * * * *

FRMs = Ratio of average gas flowback rate, during the 
period of time when sufficient quantities of gas are present to 
enable separation, of well completions and workovers from hydraulic 
fracturing to 30-day gas production rate for each sub-basin and well 
type combination.
FRs,p = Measured average gas flowback rate from 
Calculation Method 1 described in paragraph (g)(1)(i) of this 
section or calculated average flowback rate from Calculation Method 
2 described in paragraph (g)(1)(ii) of this section, during the 
separation period in standard cubic feet per hour for well(s) p for 
each sub-basin and well type combination. Convert measured and 
calculated FRa values from actual conditions upstream of 
the restriction orifice (FRa) to standard conditions 
(FRs,p) for each well p using Equation W-33 in paragraph 
(t) of this section. You may not use flow volume as used in Equation 
W-10B of this section converted to a flow rate for this parameter.
PRs,p = Average gas production flow rate during the first 
30 days of production after completions of newly drilled wells or 
well workovers using hydraulic fracturing, in standard cubic feet 
per hour for each well, p, that was measured in the sub-basin and 
well type combination. For oil wells for which production is not 
measured continuously during the first 30 days of production, the 
average flow rate may be based on individual well production tests 
conducted within the first 30 days of production. Alternatively, if 
applicable, PRs,p may be calculated for oil wells using 
procedures specified in paragraph (g)(1)(vii) of this section.

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

FRMi = Ratio of initial gas flowback rate during well 
completions and workovers from hydraulic fracturing to 30-day gas 
production rate for the sub-basin and well type combination, for the 
period of flow to open tanks/pits.
* * * * *
PRs,p = Average gas production flow rate during the first 
30-days of production after completions of newly drilled wells or 
well workovers using hydraulic fracturing, in standard cubic feet 
per hour of each well, p, that was measured in the sub-basin and 
well type combination. For oil wells for which production is not 
measured continuously during the first 30 days of production, the 
average flow rate may be based on individual well production tests 
conducted within the first 30 days of production. Alternatively, if 
applicable, PRs,p may be calculated for oil wells using 
procedures specified in paragraph (g)(1)(vii) of this section.

* * * * *
    (v) For Equation W-10A of this section, the ratio of gas flowback 
rate during well completions and workovers from hydraulic fracturing to 
30-day gas production rate are applied to all well completions and well 
workovers, respectively, in the sub-basin and well type combination for 
the total number of hours of flowback and for the first 30 day average 
gas production rate for each of these wells.
    (vi) For Equations W-12A and W-12B of this section, calculate new 
flowback rates for well completions and well workovers in each sub-
basin and well type combination once every two years starting in the 
first calendar year of data collection.
    (vii) For oil wells where the gas production rate is not metered 
and you elect to use Equation W-10A of this section, calculate the 
average gas production rate (PRs,p) using Equation W-12C of 
this section. If GOR cannot be determined from your available data, 
then you must use one of the procedures specified in paragraph 
(g)(1)(vii)(A) or (B) of this section to determine GOR. If GOR from 
each well is not available, use the GOR from a cluster of wells in the 
same sub-basin category.
[GRAPHIC] [TIFF OMITTED] TR22OC15.008


[[Page 64287]]


Where:

PRs,p = Average gas production flow rate during the first 
30 days of production after completions of newly drilled wells or 
well workovers using hydraulic fracturing in standard cubic feet per 
hour of well p, in the sub-basin and well type combination.
GORp = Average gas to oil ratio during the first 30 days 
of production after completions of newly drilled wells or workovers 
using hydraulic fracturing in standard cubic feet of gas per barrel 
of oil for each well p, that was measured in the sub-basin and well 
type combination; oil here refers to hydrocarbon liquids produced of 
all API gravities.
Vp = Volume of oil produced during the first 30 days of 
production after completions of newly drilled wells or well 
workovers using hydraulic fracturing in barrels of each well p, that 
was measured in the sub-basin and well type combination.
720 = Conversion from 30 days of production to hourly production 
rate.

    (A) You may use an appropriate standard method published by a 
consensus-based standards organization if such a method exists.
    (B) You may use an industry standard practice as described in Sec.  
98.234(b).
    (2) For paragraphs (g) introductory text and (g)(1) of this 
section, measurements and calculations are completed separately for 
workovers and completions per sub-basin and well type combination. A 
well type combination is a unique combination of the parameters listed 
in paragraphs (g)(2)(i) through (iv) of this section.
* * * * *
    (iv) Oil well or gas well.
* * * * *
    (4) Calculate annual emissions from well venting during well 
completions and workovers from hydraulic fracturing where all or a 
portion of the gas is flared as specified in paragraphs (g)(4)(i) and 
(ii) of this section.
* * * * *
    (i) * * *
    (2) Method for determining emissions from blowdown vent stacks 
according to equipment or event type. If you elect to determine 
emissions according to each equipment or event type, using unique 
physical volumes as calculated in paragraph (i)(1) of this section, you 
must calculate emissions as specified in paragraph (i)(2)(i) of this 
section and either paragraph (i)(2)(ii) or, if applicable, paragraph 
(i)(2)(iii) of this section for each equipment or event type. For 
industry segments other than onshore natural gas transmission pipeline, 
equipment or event types must be grouped into the following seven 
categories: Facility piping (i.e., piping within the facility boundary 
other than physical volumes associated with distribution pipelines), 
pipeline venting (i.e., physical volumes associated with distribution 
pipelines vented within the facility boundary), compressors, scrubbers/
strainers, pig launchers and receivers, emergency shutdowns (this 
category includes emergency shutdown blowdown emissions regardless of 
equipment type), and all other equipment with a physical volume greater 
than or equal to 50 cubic feet. If a blowdown event resulted in 
emissions from multiple equipment types and the emissions cannot be 
apportioned to the different equipment types, then categorize the 
blowdown event as the equipment type that represented the largest 
portion of the emissions for the blowdown event. For the onshore 
natural gas transmission pipeline segment, pipeline segments or event 
types must be grouped into the following eight categories: Pipeline 
integrity work (e.g., the preparation work of modifying facilities, 
ongoing assessments, maintenance or mitigation), traditional operations 
or pipeline maintenance, equipment replacement or repair (e.g., 
valves), pipe abandonment, new construction or modification of 
pipelines including commissioning and change of service, operational 
precaution during activities (e.g. excavation near pipelines), 
emergency shutdowns including pipeline incidents as defined in 49 CFR 
191.3, and all other pipeline segments with a physical volume greater 
than or equal to 50 cubic feet. If a blowdown event resulted in 
emissions from multiple categories and the emissions cannot be 
apportioned to the different categories, then categorize the blowdown 
event in the category that represented the largest portion of the 
emissions for the blowdown event.
    (i) * * *
* * * * *

Ta = Temperature at actual conditions in the unique 
physical volume ([deg]F). For emergency blowdowns at onshore 
petroleum and natural gas gathering and boosting facilities, 
engineering estimates based on best available information may be 
used to determine the temperature.
* * * * *
Pa = Absolute pressure at actual conditions in the unique 
physical volume (psia). For emergency blowdowns at onshore petroleum 
and natural gas gathering and boosting facilities, engineering 
estimates based on best available information may be used to 
determine the pressure.

* * * * *
    (j) Onshore production and onshore petroleum and natural gas 
gathering and boosting storage tanks. Calculate CH4, 
CO2, and N2O (when flared) emissions from 
atmospheric pressure fixed roof storage tanks receiving hydrocarbon 
produced liquids from onshore petroleum and natural gas production 
facilities and onshore petroleum and natural gas gathering and boosting 
facilities (including stationary liquid storage not owned or operated 
by the reporter), as specified in this paragraph (j). For gas-liquid 
separators or onshore petroleum and natural gas gathering and boosting 
non-separator equipment (e.g., stabilizers, slug catchers) with annual 
average daily throughput of oil greater than or equal to 10 barrels per 
day, calculate annual CH4 and CO2 using 
Calculation Method 1 or 2 as specified in paragraphs (j)(1) and (2) of 
this section. For wells flowing directly to atmospheric storage tanks 
without passing through a separator with throughput greater than or 
equal to 10 barrels per day, calculate annual CH4 and 
CO2 emissions using Calculation Method 2 as specified in 
paragraph (j)(2) of this section. For hydrocarbon liquids flowing to 
gas-liquid separators or non-separator equipment or directly to 
atmospheric storage tanks with throughput less than 10 barrels per day, 
use Calculation Method 3 as specified in paragraph (j)(3) of this 
section. If you use Calculation Method 1 or Calculation Method 2 for 
separators, you must also calculate emissions that may have occurred 
due to dump valves not closing properly using the method specified in 
paragraph (j)(6) of this section. If emissions from atmospheric 
pressure fixed roof storage tanks are routed to a vapor recovery 
system, you must adjust the emissions downward according to paragraph 
(j)(4) of this section. If emissions from atmospheric pressure fixed 
roof storage tanks are routed to a flare, you must calculate 
CH4, CO2, and N2O annual emissions as 
specified in paragraph (j)(5) of this section.
    (1) Calculation Method 1. Calculate annual CH4 and 
CO2 emissions from onshore production storage tanks and 
onshore petroleum and natural gas gathering and boosting storage tanks 
using operating conditions in the last gas-liquid separator or non-
separator equipment before liquid transfer to storage tanks. Calculate 
flashing emissions with a software program, such as AspenTech 
HYSYS[supreg] or API 4697 E&P Tank, that uses the Peng-Robinson 
equation of state, models flashing emissions, and speciates 
CH4 and CO2 emissions that will result when the 
oil from the separator or non-separator equipment enters an atmospheric 
pressure storage tank. The following parameters must be determined for 
typical operating

[[Page 64288]]

conditions over the year by engineering estimate and process knowledge 
based on best available data, and must be used at a minimum to 
characterize emissions from liquid transferred to tanks:
    (i) Separator or non-separator equipment temperature.
    (ii) Separator or non-separator equipment pressure.
    (iii) Sales oil or stabilized oil API gravity.
    (iv) Sales oil or stabilized oil production rate.
    (v) Ambient air temperature.
    (vi) Ambient air pressure.
    (vii) Separator or non-separator equipment oil composition and Reid 
vapor pressure. If this data is not available, determine these 
parameters by using one of the methods described in paragraphs 
(j)(1)(vii)(A) through (C) of this section.
    (A) If separator or non-separator equipment oil composition and 
Reid vapor pressure default data are provided with the software 
program, select the default values that most closely match your 
separator or non-separator equipment pressure first, and API gravity 
secondarily.
    (B) If separator or non-separator equipment oil composition and 
Reid vapor pressure data are available through your previous analysis, 
select the latest available analysis that is representative of produced 
crude oil or condensate from the sub-basin category for onshore 
petroleum and natural gas production or from the county for onshore 
petroleum and natural gas gathering and boosting.
    (C) Analyze a representative sample of separator or non-separator 
equipment oil in each sub-basin category for onshore petroleum and 
natural gas production or each county for onshore petroleum and natural 
gas gathering and boosting for oil composition and Reid vapor pressure 
using an appropriate standard method published by a consensus-based 
standards organization.
    (2) Calculation Method 2. Calculate annual CH4 and 
CO2 emissions using the methods in paragraph (j)(2)(i) of 
this section for gas-liquid separators with annual average daily 
throughput of oil greater than or equal to 10 barrels per day. 
Calculate annual CH4 and CO2 emissions using the 
methods in paragraph (j)(2)(ii) of this section for wells with annual 
average daily oil production greater than or equal to 10 barrels per 
day that flow directly to atmospheric storage tanks in onshore 
petroleum and natural gas production and onshore petroleum and natural 
gas gathering and boosting (if applicable). Calculate annual 
CH4 and CO2 emissions using the methods in 
paragraph (j)(2)(iii) of this section for non-separator equipment with 
annual average daily hydrocarbon liquids throughput greater than or 
equal to 10 barrels per day that flow directly to atmospheric storage 
tanks in onshore petroleum and natural gas gathering and boosting.
    (i) Flow to storage tank after passing through a separator. Assume 
that all of the CH4 and CO2 in solution at 
separator temperature and pressure is emitted from oil sent to storage 
tanks. You may use an appropriate standard method published by a 
consensus-based standards organization if such a method exists or you 
may use an industry standard practice as described in Sec.  98.234(b) 
to sample and analyze separator oil composition at separator pressure 
and temperature.
    (ii) Flow to storage tank direct from wells. Calculate 
CH4 and CO2 emissions using either of the methods 
in paragraph (j)(2)(ii)(A) or (B) of this section.
    (A) If well production oil and gas compositions are available 
through a previous analysis, select the latest available analysis that 
is representative of produced oil and gas from the sub-basin category 
and assume all of the CH4 and CO2 in both oil and 
gas are emitted from the tank.
    (B) If well production oil and gas compositions are not available, 
use default oil and gas compositions in software programs, such as API 
4697 E&P Tank, that most closely match the well production gas/oil 
ratio and API gravity and assume all of the CH4 and 
CO2 in both oil and gas are emitted from the tank.
    (iii) Flow to storage tank direct from non-separator equipment. 
Calculate CH4 and CO2 emissions using either of 
the methods in paragraph (j)(2)(iii)(A) or (B) of this section.
    (A) If other non-separator equipment liquid and gas compositions 
are available through a previous analysis, select the latest available 
analysis that is representative of liquid and gas from non-separator 
equipment in the same county and assume all of the CH4 and 
CO2 in both hydrocarbon liquids and gas are emitted from the 
tank.
    (B) If non-separator equipment liquid and gas compositions are not 
available, use default liquid and gas compositions in software 
programs, such as API 4697 E&P Tank, that most closely match the non-
separator equipment gas/liquid ratio and API gravity and assume all of 
the CH4 and CO2 in both hydrocarbon liquids and 
gas are emitted from the tank.
    (3) Calculation Method 3. Calculate CH4 and 
CO2 emissions using Equation W-15 of this section:
[GRAPHIC] [TIFF OMITTED] TR22OC15.009

Where:

Es,i = Annual total volumetric GHG emissions (either 
CO2 or CH4) at standard conditions in cubic 
feet.
EFi = Population emission factor for separators, wells, 
or non-separator equipment in thousand standard cubic feet per 
separator, well, or non-separator equipment per year, for crude oil 
use 4.2 for CH4 and 2.8 for CO2 at 
60[emsp14][deg]F and 14.7 psia, and for gas condensate use 17.6 for 
CH4 and 2.8 for CO2 at 60 [deg]F and 14.7 
psia.
Count = Total number of separators, wells, or non-separator 
equipment with annual average daily throughput less than 10 barrels 
per day. Count only separators, wells, or non-separator equipment 
that feed oil directly to the storage tank.
1,000 = Conversion from thousand standard cubic feet to standard 
cubic feet.

* * * * *
    (6) If you use Calculation Method 1 or Calculation Method 2 in 
paragraph (j)(1) or (2) of this section, calculate emissions from 
occurrences of gas-liquid separator liquid dump valves not closing 
during the calendar year by using Equation W-16 of this section.
[GRAPHIC] [TIFF OMITTED] TR22OC15.010


[[Page 64289]]


Where:

Es,i,o = Annual volumetric GHG emissions at standard 
conditions from each storage tank in cubic feet that resulted from 
the dump valve on the gas-liquid separator not closing properly.
En = Storage tank emissions as determined in paragraphs 
(j)(1), (j)(2) and, if applicable, (j)(4) of this section in 
standard cubic feet per year.
Tn = Total time a dump valve is not closing properly in 
the calendar year in hours. Estimate Tn based on 
maintenance, operations, or routine separator inspections that 
indicate the period of time when the valve was malfunctioning in 
open or partially open position.
CFn = Correction factor for tank emissions for time 
period Tn is 2.87 for crude oil production. Correction 
factor for tank emissions for time period Tn is 4.37 for 
gas condensate production.
8,760 = Conversion to hourly emissions.

* * * * *
    (n) * * *
    (2) * * *
    (i) For onshore natural gas production and onshore petroleum and 
natural gas gathering and boosting, determine the GHG mole fraction 
using paragraph (u)(2)(i) of this section.
* * * * *
    (o) Centrifugal compressor venting. If you are required to report 
emissions from centrifugal compressor venting as specified in Sec.  
98.232(d)(2), (e)(2), (f)(2), (g)(2), and (h)(2), you must conduct 
volumetric emission measurements specified in paragraph (o)(1) of this 
section using methods specified in paragraphs (o)(2) through (5) of 
this section; perform calculations specified in paragraphs (o)(6) 
through (9) of this section; and calculate CH4 and 
CO2 mass emissions as specified in paragraph (o)(11) of this 
section. If emissions from a compressor source are routed to a flare, 
paragraphs (o)(1) through (11) do not apply and instead you must 
calculate CH4, CO2, and N2O emissions 
as specified in paragraph (o)(12) of this section. If emissions from a 
compressor source are captured for fuel use or are routed to a thermal 
oxidizer, paragraphs (o)(1) through (12) do not apply and instead you 
must calculate and report emissions as specified in subpart C of this 
part. If emissions from a compressor source are routed to vapor 
recovery, paragraphs (o)(1) through (12) do not apply. If you are 
required to report emissions from centrifugal compressor venting at an 
onshore petroleum and natural gas production facility as specified in 
Sec.  98.232(c)(19) or an onshore petroleum and natural gas gathering 
and boosting facility as specified in Sec.  98.232(j)(8), you must 
calculate volumetric emissions as specified in paragraph (o)(10); and 
calculate CH4 and CO2 mass emissions as specified 
in paragraph (o)(11).
* * * * *
    (10) Method for calculating volumetric GHG emissions from wet seal 
oil degassing vents at an onshore petroleum and natural gas production 
facility or an onshore petroleum and natural gas gathering and boosting 
facility. You must calculate emissions from centrifugal compressor wet 
seal oil degassing vents at an onshore petroleum and natural gas 
production facility or an onshore petroleum and natural gas gathering 
and boosting facility using Equation W-25 of this section.
[GRAPHIC] [TIFF OMITTED] TR22OC15.011

Where:

Es,i = Annual volumetric GHGi (either 
CH4 or CO2) emissions from centrifugal 
compressor wet seals, at standard conditions, in cubic feet.
Count = Total number of centrifugal compressors that have wet seal 
oil degassing vents.
EFi,s = Emission factor for GHGi. Use 1.2 x 
10\7\ standard cubic feet per year per compressor for CH4 
and 5.30 x 10\5\ standard cubic feet per year per compressor for 
CO2 at 60 [deg]F and 14.7 psia.

* * * * *
    (p) Reciprocating compressor venting. If you are required to report 
emissions from reciprocating compressor venting as specified in Sec.  
98.232(d)(1), (e)(1), (f)(1), (g)(1), and (h)(1), you must conduct 
volumetric emission measurements specified in paragraph (p)(1) of this 
section using methods specified in paragraphs (p)(2) through (5) of 
this section; perform calculations specified in paragraphs (p)(6) 
through (9) of this section; and calculate CH4 and 
CO2 mass emissions as specified in paragraph (p)(11) of this 
section. If emissions from a compressor source are routed to a flare, 
paragraphs (p)(1) through (11) do not apply and instead you must 
calculate CH4, CO2, and N2O emissions 
as specified in paragraph (p)(12) of this section. If emissions from a 
compressor source are captured for fuel use or are routed to a thermal 
oxidizer, paragraphs (p)(1) through (12) do not apply and instead you 
must calculate and report emissions as specified in subpart C of this 
part. If emissions from a compressor source are routed to vapor 
recovery, paragraphs (p)(1) through (12) do not apply. If you are 
required to report emissions from reciprocating compressor venting at 
an onshore petroleum and natural gas production facility as specified 
in Sec.  98.232(c)(11) or an onshore petroleum and natural gas 
gathering and boosting facility as specified in Sec.  98.232(j)(5), you 
must calculate volumetric emissions as specified in paragraph (p)(10); 
and calculate CH4 and CO2 mass emissions as 
specified in paragraph (p)(11).
* * * * *
    (10) Method for calculating volumetric GHG emissions from 
reciprocating compressor venting at an onshore petroleum and natural 
gas production facility or an onshore petroleum and natural gas 
gathering and boosting facility. You must calculate emissions from 
reciprocating compressor venting at an onshore petroleum and natural 
gas production facility or an onshore petroleum and natural gas 
gathering and boosting facility using Equation W-29D of this section.
[GRAPHIC] [TIFF OMITTED] TR22OC15.012

Where:

Es,i = Annual volumetric GHGi (either 
CH4 or CO2) emissions from reciprocating 
compressors, at standard conditions, in cubic feet.
Count = Total number of reciprocating compressors.
EFi,s = Emission factor for GHGi. Use 9.48 x 
10\3\ standard cubic feet per year per compressor for CH4 
and 5.27 x 10\2\ standard cubic feet per year per compressor for 
CO2 at 60 [deg]F and 14.7 psia.

* * * * *

[[Page 64290]]

    (r) Equipment leaks by population count. This paragraph (r) applies 
to emissions sources listed in Sec.  98.232 (c)(21), (f)(5), (g)(3), 
(h)(4), (i)(2), (i)(3), (i)(4), (i)(5), (i)(6), (j)(10), and (j)(11) on 
streams with gas content greater than 10 percent CH4 plus 
CO2 by weight. Emissions sources in streams with gas content 
less than or equal to 10 percent CH4 plus CO2 by 
weight are exempt from the requirements of this paragraph (r) and do 
not need to be reported. Tubing systems equal to or less than one half 
inch diameter are exempt from the requirements of paragraph (r) of this 
section and do not need to be reported. You must calculate emissions 
from all emission sources listed in this paragraph using Equation W-32A 
of this section, except for natural gas distribution facility emission 
sources listed in Sec.  98.232(i)(3). Natural gas distribution facility 
emission sources listed in Sec.  98.232(i)(3) must calculate emissions 
using Equation W-32B of this section and according to paragraph 
(r)(6)(ii) of this section.
[GRAPHIC] [TIFF OMITTED] TR22OC15.013

Where:

Es,e,i = Annual volumetric emissions of GHGi 
from the emission source type in standard cubic feet. The emission 
source type may be a component (e.g. connector, open-ended line, 
etc.), below grade metering-regulating station, below grade 
transmission-distribution transfer station, distribution main, 
distribution service, or gathering pipeline.
Es,MR,i = Annual volumetric emissions of GHGi 
from all meter/regulator runs at above grade metering regulating 
stations that are not above grade transmission-distribution transfer 
stations or, when used to calculate emissions according to paragraph 
(q)(9) of this section, the annual volumetric emissions of 
GHGi from all meter/regulator runs at above grade 
transmission-distribution transfer stations, in standard cubic feet.
Counte = Total number of the emission source type at the 
facility. For onshore petroleum and natural gas production 
facilities and onshore petroleum and natural gas gathering and 
boosting facilities, average component counts are provided by major 
equipment piece in Tables W-1B and Table W-1C of this subpart. Use 
average component counts as appropriate for operations in Eastern 
and Western U.S., according to Table W-1D of this subpart. Onshore 
petroleum and natural gas gathering and boosting facilities must 
also count the miles of gathering pipelines by material type 
(protected steel, unprotected steel, plastic, or cast iron). 
Underground natural gas storage facilities must count each component 
listed in Table W-4 of this subpart. LNG storage facilities must 
count the number of vapor recovery compressors. LNG import and 
export facilities must count the number of vapor recovery 
compressors. Natural gas distribution facilities must count: (1) The 
number of distribution services by material type; (2) miles of 
distribution mains by material type; and (3) number of below grade 
metering-regulating stations, by pressure type; as listed in Table 
W-7 of this subpart.
CountMR = Total number of meter/regulator runs at above 
grade metering-regulating stations that are not above grade 
transmission-distribution transfer stations or, when used to 
calculate emissions according to paragraph (q)(9) of this section, 
the total number of meter/regulator runs at above grade 
transmission-distribution transfer stations.
EFs,e = Population emission factor for the specific 
emission source type, as listed in Tables W-1A and W-4 through W-7 
of this subpart. Use appropriate population emission factor for 
operations in Eastern and Western U.S., according to Table W-1D of 
this subpart.
EFs,MR,i = Meter/regulator run population emission factor 
for GHGi based on all surveyed above grade transmission-
distribution transfer stations over ``n'' years, in standard cubic 
feet of GHGi per operational hour of all meter/regulator 
runs, as determined in Equation W-31 of this section.
GHGi = For onshore petroleum and natural gas production 
facilities and onshore petroleum and natural gas gathering and 
boosting facilities, concentration of GHGi, 
CH4, or CO2, in produced natural gas as 
defined in paragraph (u)(2) of this section; for onshore natural gas 
transmission compression and underground natural gas storage, 
GHGi equals 0.975 for CH4 and 1.1 x 
10-2 for CO2; for LNG storage and LNG import 
and export equipment, GHGi equals 1 for CH4 
and 0 for CO2; and for natural gas distribution, 
GHGi equals 1 for CH4 and 1.1 x 
10-2 CO2.
Te = Average estimated time that each emission source 
type associated with the equipment leak emission was operational in 
the calendar year, in hours, using engineering estimate based on 
best available data.
Tw,avg = Average estimated time that each meter/regulator 
run was operational in the calendar year, in hours per meter/
regulator run, using engineering estimate based on best available 
data.

* * * * *
    (2) Onshore petroleum and natural gas production facilities and 
onshore petroleum and natural gas gathering and boosting facilities 
must use the appropriate default whole gas population emission factors 
listed in Table W-1A of this subpart. Major equipment and components 
associated with gas wells and onshore petroleum and natural gas 
gathering and boosting systems are considered gas service components in 
reference to Table W-1A of this subpart and major natural gas equipment 
in reference to Table W-1B of this subpart. Major equipment and 
components associated with crude oil wells are considered crude service 
components in reference to Table W-1A of this subpart and major crude 
oil equipment in reference to Table W-1C of this subpart. Where 
facilities conduct EOR operations the emissions factor listed in Table 
W-1A of this subpart shall be used to estimate all streams of gases, 
including recycle CO2 stream. The component count can be 
determined using either of the calculation methods described in this 
paragraph (r)(2), except for miles of gathering pipelines by material 
type, which must be determined using Component Count Method 2 in 
paragraph (r)(2)(ii) of this section. The same calculation method must 
be used for the entire calendar year.
    (i) Component Count Method 1. For all onshore petroleum and natural 
gas production operations and onshore petroleum and natural gas 
gathering and boosting operations in the facility perform the following 
activities:
    (A) Count all major equipment listed in Table W-1B and Table W-1C 
of this subpart. For meters/piping, use one meters/piping per well-pad 
for onshore petroleum and natural gas production operations and the 
number of meters in the facility for onshore petroleum and natural gas 
gathering and boosting operations.
    (B) Multiply major equipment counts by the average component counts 
listed in Table W-1B of this subpart for onshore natural gas production 
and onshore petroleum and natural gas gathering and boosting; and Table 
W-1C of this subpart for onshore oil production. Use the appropriate 
factor

[[Page 64291]]

in Table W-1A of this subpart for operations in Eastern and Western 
U.S. according to the mapping in Table W-1D of this subpart.
* * * * *
    (u) * * *
    (2) * * *
    (i) GHG mole fraction in produced natural gas for onshore petroleum 
and natural gas production facilities and onshore petroleum and natural 
gas gathering and boosting facilities. If you have a continuous gas 
composition analyzer for produced natural gas, you must use an annual 
average of these values for determining the mole fraction. If you do 
not have a continuous gas composition analyzer, then you must use an 
annual average gas composition based on your most recent available 
analysis of the sub-basin category or facility, as applicable to the 
emission source.
* * * * *
    (iii) GHG mole fraction in transmission pipeline natural gas that 
passes through the facility for the onshore natural gas transmission 
compression industry segment and the onshore natural gas transmission 
pipeline industry segment. You may use either a default 95 percent 
methane and 1 percent carbon dioxide fraction for GHG mole fraction in 
natural gas or site specific engineering estimates based on best 
available data.
* * * * *
    (z) Onshore petroleum and natural gas production, onshore petroleum 
and natural gas gathering and boosting, and natural gas distribution 
combustion emissions. Calculate CO2, CH4, and 
N2O combustion-related emissions from stationary or portable 
equipment, except as specified in paragraphs (z)(3) and (4) of this 
section, as follows:
    (1) * * *
    (ii) Emissions from fuel combusted in stationary or portable 
equipment at onshore petroleum and natural gas production facilities, 
at onshore petroleum and natural gas gathering and boosting facilities, 
and at natural gas distribution facilities will be reported according 
to the requirements specified in Sec.  98.236(z) and not according to 
the reporting requirements specified in subpart C of this part.
* * * * *

0
6. Section 98.234 is amended by adding paragraph (g) to read as 
follows:


Sec.  98.234  Monitoring and QA/QC requirements.

* * * * *
    (g) Special reporting provisions for best available monitoring 
methods in reporting year 2016--(1) Best available monitoring methods. 
From January 1, 2016, to December 31, 2016, you must use the 
calculation methodologies and equations in Sec.  98.233 but you may use 
the best available monitoring method as described in paragraph (g)(2) 
of this section for any parameter specified in paragraphs (g)(3) 
through (6) of this section for which it is not reasonably feasible to 
acquire, install, and operate a required piece of monitoring equipment 
by January 1, 2016. Starting no later than January 1, 2017, you must 
discontinue using best available methods and begin following all 
applicable monitoring and QA/QC requirements of this part. For onshore 
petroleum and natural gas production, this paragraph (g)(1) only 
applies if emissions from well completions and workovers of oil wells 
with hydraulic fracturing cause your facility to exceed the reporting 
threshold in Sec.  98.231(a)(1).
    (2) Best available monitoring methods means any of the following 
methods:
    (i) Monitoring methods currently used by the facility that do not 
meet the specifications of this subpart.
    (ii) Supplier data.
    (iii) Engineering calculations.
    (iv) Other company records.
    (3) Best available monitoring methods for well-related measurement 
data for oil wells with hydraulic fracturing. You may use best 
available monitoring methods for any well-related measurement data that 
cannot reasonably be measured according to the monitoring and QA/QC 
requirements of this subpart for venting during well completions and 
workovers of oil wells with hydraulic fracturing.
    (4) Best available monitoring methods for measurement data for 
onshore petroleum and natural gas gathering and boosting facilities. 
You may use best available monitoring methods for any leak detection 
and/or measurement data that cannot reasonably be measured according to 
the monitoring and QA/QC requirements of this subpart for acid gas 
removal vents as specified in Sec.  98.233(d).
    (5) Best available monitoring methods for measurement data for 
natural gas transmission pipelines. You may use best available 
monitoring methods for any measurement data for natural gas 
transmission pipelines that cannot reasonably be obtained according to 
the monitoring and QA/QC requirements of this subpart for blowdown vent 
stacks.
    (6) Best available monitoring methods for specified activity data. 
You may use best available monitoring methods for activity data as 
listed in paragraphs (g)(6)(i) through (iii) of this section that 
cannot reasonably be obtained according to the monitoring and QA/QC 
requirements of this subpart for well completions and workovers of oil 
wells with hydraulic fracturing, onshore petroleum and natural gas 
gathering and boosting facilities, or natural gas transmission 
pipelines.
    (i) Cumulative hours of venting, days, or times of operation in 
Sec.  98.233(e), (g), (o), (p), and (r).
    (ii) Number of blowdowns, completions, workovers, or other events 
in Sec.  98.233(g) and (i).
    (iii) Cumulative volume produced, volume input or output, or volume 
of fuel used in paragraphs Sec.  98.233(d), (e), (j), (n), and (z).
* * * * *

0
7. Section 98.236 is amended by:
0
a. Revising paragraph (a) introductory text;
0
b. Adding paragraphs (a)(9) and (10);
0
c. Revising paragraphs (d)(1)(i) and (vi);
0
d. Revising paragraphs (e)(1)(i) and (xviii);
0
e. Revising paragraphs (f)(1)(ii), (f)(1)(xi)(A), (f)(1)(xii)(A), and 
(f)(2)(i);
0
f. Revising paragraphs (g) introductory text, (g)(1), (g)(2), (g)(5), 
and (g)(6);
0
g. Revising paragraphs (h)(1)(i) and (iv), (h)(2)(i) and (iv), 
(h)(3)(i), and (h)(4)(i);
0
h. Revising paragraphs (i) introductory text and (i)(1) introductory 
text;
0
i. Adding paragraph (i)(3);
0
j. Revising paragraphs (j) introductory text and (j)(1) introductory 
text;
0
k. Revising paragraphs (j)(1)(i), (iii), (iv) (v), (vii), and (viii);
0
l. Revising paragraphs (j)(2)(i) introductory text, (j)(2)(i)(A) 
through (C), (j)(2)(ii), (j)(2)(iii) introductory text, (j)(2)(iii)(A) 
and (B), and (j)(3) introductory text;
0
m. Revising paragraph (l)(1) introductory text;
0
n. Redesignating paragraphs (l)(1)(ii) through (vi) as paragraphs 
(l)(1)(iii) through (vii), respectively;
0
o. Adding paragraph (l)(1)(ii);
0
p. Revising newly designated paragraph (l)(1)(v);
0
q. Revising paragraph (l)(2) introductory text;
0
r. Redesignating paragraphs (l)(2)(ii) through (vii) as paragraphs 
(l)(2)(iii) through (viii), respectively;
0
s. Adding paragraph (l)(2)(ii);
0
t. Revising newly designated paragraph (l)(2)(v);
0
u. Revising paragraph (l)(3) introductory text;
0
v. Redesignating paragraphs (l)(3)(ii) through (v) as paragraphs 
(l)(3)(iii) through (vi), respectively;
0
w. Adding paragraph (l)(3)(ii);
0
x. Revising newly designated paragraph (l)(3)(iv);

[[Page 64292]]

0
y. Revising paragraph (l)(4) introductory text;
0
a. Redesignating paragraphs (l)(4)(ii) through (vi) as paragraphs 
(l)(4)(iii) through (vii), respectively;
0
aa. Adding paragraph (l)(4)(ii);
0
bb. Revising newly designated paragraph (l)(4)(iv);
0
cc. Revising paragraphs (m)(1), (m)(5), (m)(6), (m)(7)(i), (m)(8)(i);
0
dd. Revising paragraph (n)(1);
0
ee. Revising paragraphs (o) introductory text and (o)(5) introductory 
text;
0
ff. Revising paragraphs (p) introductory text and (p)(5) introductory 
text;
0
gg. Revising paragraphs (r)(1) introductory text, (r)(1)(i), (r)(3) 
introductory text, and (r)(3)(ii) introductory text;
0
hh. Revising paragraph (z) introductory text;
0
ii. Revising paragraphs (aa) introductory text and (aa)(1)(ii)(D) 
through (H);
0
jj. Adding paragraphs (aa)(10) and (11); and
0
kk. Revising paragraph (cc).
    The revisions and additions read as follows:


Sec.  98.236  Data reporting requirements.

* * * * *
    (a) The annual report must include the information specified in 
paragraphs (a)(1) through (10) of this section for each applicable 
industry segment. The annual report must also include annual emissions 
totals, in metric tons of each GHG, for each applicable industry 
segment listed in paragraphs (a)(1) through (10), and each applicable 
emission source listed in paragraphs (b) through (z) of this section.
* * * * *
    (9) Onshore petroleum and natural gas gathering and boosting. For 
the equipment/activities specified in paragraphs (a)(9)(i) through (xi) 
of this section, report the information specified in the applicable 
paragraphs of this section.
    (i) Natural gas pneumatic devices. Report the information specified 
in paragraph (b) of this section.
    (ii) Natural gas driven pneumatic pumps. Report the information 
specified in paragraph (c) of this section.
    (iii) Acid gas removal units. Report the information specified in 
paragraph (d) of this section.
    (iv) Dehydrators. Report the information specified in paragraph (e) 
of this section.
    (v) Blowdown vent stacks. Report the information specified in 
paragraph (i) of this section.
    (vi) Storage tanks. Report the information specified in paragraph 
(j) of this section.
    (vii) Flare stacks. Report the information specified in paragraph 
(n) of this section.
    (viii) Centrifugal compressors. Report the information specified in 
paragraph (o) of this section.
    (ix) Reciprocating compressors. Report the information specified in 
paragraph (p) of this section.
    (x) Equipment leaks by population count. Report the information 
specified in paragraph (r) of this section.
    (xi) Combustion equipment. Report the information specified in 
paragraph (z) of this section.
    (10) Onshore natural gas transmission pipeline. For blowdown vent 
stacks, report the information specified in paragraph (i) of this 
section.
* * * * *
    (d) * * *
    (1) * * *
    (i) A unique name or ID number for the acid gas removal unit. For 
the onshore petroleum and natural gas production and the onshore 
petroleum and natural gas gathering and boosting industry segments, a 
different name or ID may be used for a single acid gas removal unit for 
each location it operates at in a given year.
* * * * *
    (vi) Sub-basin ID that best represents the wells supplying gas to 
the unit (for the onshore petroleum and natural gas production industry 
segment only) or name of the county that best represents the equipment 
supplying gas to the unit (for the onshore petroleum and natural gas 
gathering and boosting industry segment only).
* * * * *
    (e) * * *
    (1) * * *
    (i) A unique name or ID number for the dehydrator. For the onshore 
petroleum and natural gas production and the onshore petroleum and 
natural gas gathering and boosting industry segments, a different name 
or ID may be used for a single dehydrator for each location it operates 
at in a given year.
* * * * *
    (xviii) Sub-basin ID that best represents the wells supplying gas 
to the dehydrator (for the onshore petroleum and natural gas production 
industry segment only) or name of the county that best represents the 
equipment supplying gas to the dehydrator (for the onshore petroleum 
and natural gas gathering and boosting industry segment only).
* * * * *
    (f) * * *
    (1) * * *
    (ii) Well tubing diameter and pressure group ID and a list of the 
well ID numbers associated with each sub-basin and well tubing diameter 
and pressure group ID.
* * * * *
    (xi) * * *
    (A) Well ID number of tested well.
* * * * *
    (xii) * * *
    (A) Well ID number.
* * * * *
    (2) * * *
    (i) Sub-basin ID and a list of the well ID numbers associated with 
each sub-basin.
* * * * *
    (g) Completions and workovers with hydraulic fracturing. You must 
indicate whether your facility had any well completions or workovers 
with hydraulic fracturing during the calendar year. If your facility 
had well completions or workovers with hydraulic fracturing during the 
calendar year, then you must report information specified in paragraphs 
(g)(1) through (10) of this section, for each sub-basin and well type 
combination. Report information separately for completions and 
workovers.
    (1) Sub-basin ID and a list of the well ID numbers associated with 
each sub-basin that had completions or workovers with hydraulic 
fracturing during the calendar year.
    (2) Well type combination (horizontal or vertical, gas well or oil 
well).
* * * * *
    (5) If you used Equation W-10A of Sec.  98.233 to calculate annual 
volumetric total gas emissions, then you must report the information 
specified in paragraphs (g)(5)(i) through (iii) of this section.
    (i) Cumulative gas flowback time, in hours, from when gas is first 
detected until sufficient quantities are present to enable separation, 
and the cumulative flowback time, in hours, after sufficient quantities 
of gas are present to enable separation (sum of ``Tp,i'' and 
sum of ``Tp,s'' values used in Equation W-10A of Sec.  
98.233). You may delay the reporting of this data element if you 
indicate in the annual report that wildcat wells and/or delineation 
wells are the only wells included in this number. If you elect to delay 
reporting of this data element, you must report by the date specified 
in Sec.  98.236(cc) the total number of hours of flowback from all 
wells during completions or workovers and the well ID number(s) for the 
well(s) included in the number.
    (ii) For the measured well(s), the flowback rate, in standard cubic 
feet per

[[Page 64293]]

hour (average of ``FRs,p'' values used in Equation W-12A of 
Sec.  98.233), and the well ID numbers of the wells for which it is 
measured. You may delay the reporting of this data element if you 
indicate in the annual report that wildcat wells and/or delineation 
wells are the only wells that can be used for the measurement. If you 
elect to delay reporting of this data element, you must report by the 
date specified in Sec.  98.236(cc) the measured flowback rate during 
well completion or workover and the well ID number(s) for the well(s) 
included in the measurement.
    (iii) If you used Equation W-12C of Sec.  98.233 to calculate the 
average gas production rate for an oil well, then you must report the 
information specified in paragraphs (g)(5)(iii)(A) and (B) of this 
section.
    (A) Gas to oil ratio for the well in standard cubic feet of gas per 
barrel of oil (``GORp'' in Equation W-12C of Sec.  98.233). 
You may delay the reporting of this data element if you indicate in the 
annual report that wildcat wells and/or delineation wells are the only 
wells that can be used for the measurement. If you elect to delay 
reporting of this data element, you must report by the date specified 
in Sec.  98.236(cc) the gas to oil ratio for the well and the well ID 
number for the well.
    (B) Volume of oil produced during the first 30 days of production 
after completions of each newly drilled well or well workover using 
hydraulic fracturing, in barrels (``Vp'' in Equation W-12C 
of Sec.  98.233). You may delay the reporting of this data element if 
you indicate in the annual report that wildcat wells and/or delineation 
wells are the only wells that can be used for the measurement. If you 
elect to delay reporting of this data element, you must report by the 
date specified in Sec.  98.236(cc) the volume of oil produced during 
the first 30 days of production after well completion or workover and 
the well ID number for the well.
    (6) If you used Equation W-10B of Sec.  98.233 to calculate annual 
volumetric total gas emissions, then you must report the information 
specified in paragraphs (g)(6)(i) through (iii) of this section.
    (i) Vented natural gas volume, in standard cubic feet, for each 
well in the sub-basin (``FVs,p'' in Equation W-10B of Sec.  
98.233).
    (ii) Flow rate at the beginning of the period of time when 
sufficient quantities of gas are present to enable separation, in 
standard cubic feet per hour, for each well in the sub-basin 
(``FRp,i'' in Equation W-10B of Sec.  98.233).
    (iii) The well ID number for which vented natural gas volume was 
measured.
* * * * *
    (h) * * *
    (1) * * *
    (i) Sub-basin ID and a list of the well ID numbers associated with 
each sub-basin for gas well completions without hydraulic fracturing 
and without flaring.
* * * * *
    (iv) Average daily gas production rate for all completions without 
hydraulic fracturing in the sub-basin without flaring, in standard 
cubic feet per hour (average of all ``Vp'' used in Equation 
W-13B of Sec.  98.233). You may delay reporting of this data element if 
you indicate in the annual report that wildcat wells and/or delineation 
wells are the only wells that can be used for the measurement. If you 
elect to delay reporting of this data element, you must report by the 
date specified in Sec.  98.236(cc) the measured average daily gas 
production rate for all wells during completions and the well ID 
number(s) for the well(s) included in the measurement.
* * * * *
    (2) * * *
    (i) Sub-basin ID and a list of the well ID numbers associated with 
each sub-basin for gas well completions without hydraulic fracturing 
and with flaring.
* * * * *
    (iv) Average daily gas production rate for all completions without 
hydraulic fracturing in the sub-basin with flaring, in standard cubic 
feet per hour (the average of all ``Vp'' from Equation W-13B 
of Sec.  98.233). You may delay reporting of this data element if you 
indicate in the annual report that wildcat wells and/or delineation 
wells are the only wells that can be used for the measurement. If you 
elect to delay reporting of this data element, you must report by the 
date specified in Sec.  98.236(cc) the measured average daily gas 
production rate for all wells during completions and the well ID 
number(s) for the well(s) included in the measurement.
* * * * *
    (3) * * *
    (i) Sub-basin ID and a list of the well ID numbers associated with 
each sub-basin for gas well workovers without hydraulic fracturing and 
without flaring.
* * * * *
    (4) * * *
    (i) Sub-basin ID and a list of well ID numbers associated with each 
sub-basin for gas well workovers without hydraulic fracturing and with 
flaring.
* * * * *
    (i) Blowdown vent stacks. You must indicate whether your facility 
has blowdown vent stacks. If your facility has blowdown vent stacks, 
then you must report whether emissions were calculated by equipment or 
event type or by using flow meters or a combination of both. If you 
calculated emissions by equipment or event type for any blowdown vent 
stacks, then you must report the information specified in paragraph 
(i)(1) of this section considering, in aggregate, all blowdown vent 
stacks for which emissions were calculated by equipment or event type. 
If you calculated emissions using flow meters for any blowdown vent 
stacks, then you must report the information specified in paragraph 
(i)(2) of this section considering, in aggregate, all blowdown vent 
stacks for which emissions were calculated using flow meters. For the 
onshore natural gas transmission pipeline segment, you must also report 
the information in paragraph (i)(3) of this section.
    (1) Report by equipment or event type. If you calculated emissions 
from blowdown vent stacks by the seven categories listed in Sec.  
98.233(i)(2) for industry segments other than the onshore natural gas 
transmission pipeline segment, then you must report the equipment or 
event types and the information specified in paragraphs (i)(1)(i) 
through (iii) of this section for each equipment or event type. If a 
blowdown event resulted in emissions from multiple equipment types, and 
the emissions cannot be apportioned to the different equipment types, 
then you may report the information in paragraphs (i)(1)(i) through 
(iii) of this section for the equipment type that represented the 
largest portion of the emissions for the blowdown event. If you 
calculated emissions from blowdown vent stacks by the eight categories 
listed in Sec.  98.233(i)(2) for the onshore natural gas transmission 
pipeline segment, then you must report the pipeline segments or event 
types and the information specified in paragraphs (i)(1)(i) through 
(iii) of this section for each ``equipment or event type'' (i.e., 
category). If a blowdown event resulted in emissions from multiple 
categories, and the emissions cannot be apportioned to the different 
categories, then you may report the information in paragraphs (i)(1)(i) 
through (iii) of this section for the ``equipment or event type'' 
(i.e., category) that represented the largest portion of the emissions 
for the blowdown event.
* * * * *

[[Page 64294]]

    (3) Onshore natural gas transmission pipeline segment. Report the 
information in paragraphs (i)(3)(i) through (iii) of this section for 
each state.
    (i) Annual CO2 emissions in metric tons CO2.
    (ii) Annual CH4 emissions in metric tons CH4.
    (iii) Annual number of blowdown events.
    (j) Onshore production and onshore petroleum and natural gas 
gathering and boosting storage tanks. You must indicate whether your 
facility sends produced oil to atmospheric tanks. If your facility 
sends produced oil to atmospheric tanks, then you must indicate which 
Calculation Method(s) you used to calculate GHG emissions, and you must 
report the information specified in paragraphs (j)(1) and (2) of this 
section as applicable. If you used Calculation Method 1 or Calculation 
Method 2 of Sec.  98.233(j), and any atmospheric tanks were observed to 
have malfunctioning dump valves during the calendar year, then you must 
indicate that dump valves were malfunctioning and you must report the 
information specified in paragraph (j)(3) of this section.
    (1) If you used Calculation Method 1 or Calculation Method 2 of 
Sec.  98.233(j) to calculate GHG emissions, then you must report the 
information specified in paragraphs (j)(1)(i) through (xvi) of this 
section for each sub-basin (for onshore production) or county (for 
onshore petroleum and natural gas gathering and boosting) and by 
calculation method. Onshore petroleum and natural gas gathering and 
boosting facilities do not report the information specified in 
paragraphs (j)(1)(ix) and (xi) of this section.
    (i) Sub-basin ID (for onshore production) or county name (for 
onshore petroleum and natural gas gathering and boosting).
* * * * *
    (iii) The total annual oil volume from gas-liquid separators and 
direct from wells or non-separator equipment that is sent to applicable 
onshore production and onshore petroleum and natural gas gathering and 
boosting storage tanks, in barrels. You may delay reporting of this 
data element for onshore production if you indicate in the annual 
report that wildcat wells and delineation wells are the only wells in 
the sub-basin with oil production greater than or equal to 10 barrels 
per day and flowing to gas-liquid separators or direct to storage 
tanks. If you elect to delay reporting of this data element, you must 
report by the date specified in Sec.  98.236(cc) the total volume of 
oil from all wells and the well ID number(s) for the well(s) included 
in this volume.
    (iv) The average gas-liquid separator or non-separator equipment 
temperature, in degrees Fahrenheit.
    (v) The average gas-liquid separator or non-separator equipment 
pressure, in pounds per square inch gauge.
* * * * *
    (vii) The minimum and maximum concentration (mole fraction) of 
CO2 in flash gas from onshore production and onshore natural 
gas gathering and boosting storage tanks.
    (viii) The minimum and maximum concentration (mole fraction) of 
CH4 in flash gas from onshore production and onshore natural 
gas gathering and boosting storage tanks.
* * * * *
    (2) * * *
    (i) Report the information specified in paragraphs (j)(2)(i)(A) 
through (F) of this section, at the basin level, for atmospheric tanks 
where emissions were calculated using Calculation Method 3 of Sec.  
98.233(j). Onshore gathering and boosting facilities do not report the 
information specified in paragraphs (j)(2)(i)(E) and (F) of this 
section.
    (A) The total annual oil/condensate throughput that is sent to all 
atmospheric tanks in the basin, in barrels. You may delay reporting of 
this data element for onshore production if you indicate in the annual 
report that wildcat wells and delineation wells are the only wells in 
the sub-basin with oil/condensate production less than 10 barrels per 
day and that send oil/condensate to atmospheric tanks. If you elect to 
delay reporting of this data element, you must report by the date 
specified in Sec.  98.236(cc) the total annual oil/condensate 
throughput from all wells and the well ID number(s) for the well(s) 
included in this volume.
    (B) An estimate of the fraction of oil/condensate throughput 
reported in paragraph (j)(2)(i)(A) of this section sent to atmospheric 
tanks in the basin that controlled emissions with flares.
    (C) An estimate of the fraction of oil/condensate throughput 
reported in paragraph (j)(2)(i)(A) of this section sent to atmospheric 
tanks in the basin that controlled emissions with vapor recovery 
systems.
* * * * *
    (ii) Report the information specified in paragraphs (j)(2)(ii)(A) 
through (D) of this section for each sub-basin (for onshore production) 
or county (for onshore petroleum and natural gas gathering and 
boosting) with atmospheric tanks whose emissions were calculated using 
Calculation Method 3 of Sec.  98.233(j) and that did not control 
emissions with flares.
    (A) Sub-basin ID (for onshore production) or county name (for 
onshore petroleum and natural gas gathering and boosting).
    (B) The number of atmospheric tanks in the sub-basin (for onshore 
production) or county (for onshore petroleum and natural gas gathering 
and boosting) that did not control emissions with flares.
    (C) Annual CO2 emissions, in metric tons CO2, 
from atmospheric tanks in the sub-basin (for onshore production) or 
county (for onshore petroleum and natural gas gathering and boosting) 
that did not control emissions with flares, calculated using Equation 
W-15 of Sec.  98.233(j) and adjusted for vapor recovery, if applicable.
    (D) Annual CH4 emissions, in metric tons CH4, 
from atmospheric tanks in the sub-basin (for onshore production) or 
county (for onshore petroleum and natural gas gathering and boosting) 
that did not control emissions with flares, calculated using Equation 
W-15 of Sec.  98.233(j) and adjusted for vapor recovery, if applicable.
    (iii) Report the information specified in paragraphs (j)(2)(iii)(A) 
through (E) of this section for each sub-basin (for onshore production) 
or county (for onshore petroleum and natural gas gathering and 
boosting) with atmospheric tanks whose emissions were calculated using 
Calculation Method 3 of Sec.  98.233(j) and that controlled emissions 
with flares.
    (A) Sub-basin ID (for onshore production) or county name (for 
onshore petroleum and natural gas gathering and boosting).
    (B) The number of atmospheric tanks in the sub-basin (for onshore 
production) or county (for onshore petroleum and natural gas gathering 
and boosting) that controlled emissions with flares.
* * * * *
    (3) If you used Calculation Method 1 or Calculation Method 2 of 
Sec.  98.233(j), and any gas-liquid separator liquid dump values did 
not close properly during the calendar year, then you must report the 
information specified in paragraphs (j)(3)(i) through (iv) of this 
section for each sub-basin (for onshore production) or county (for 
onshore petroleum and natural gas gathering and boosting).
* * * * *
    (l) * * *
    (1) If you used Equation W-17A of Sec.  98.233 to calculate annual 
volumetric natural gas emissions at actual

[[Page 64295]]

conditions from oil wells and the emissions are not vented to a flare, 
then you must report the information specified in paragraphs (l)(1)(i) 
through (vii) of this section.
* * * * *
    (ii) Well ID numbers for the wells tested in the calendar year.
* * * * *
    (v) Average flow rate for well(s) tested, in barrels of oil per 
day. You may delay reporting of this data element if you indicate in 
the annual report that wildcat wells and/or delineation wells are the 
only wells that are tested. If you elect to delay reporting of this 
data element, you must report by the date specified in Sec.  98.236(cc) 
the measured average flow rate for well(s) tested and the well ID 
number(s) for the well(s) included in the measurement.
* * * * *
    (2) If you used Equation W-17A of Sec.  98.233 to calculate annual 
volumetric natural gas emissions at actual conditions from oil wells 
and the emissions are vented to a flare, then you must report the 
information specified in paragraphs (l)(2)(i) through (viii) of this 
section.
* * * * *
    (ii) Well ID numbers for the wells tested in the calendar year.
* * * * *
    (v) Average flow rate for well(s) tested, in barrels of oil per 
day. You may delay reporting of this data element if you indicate in 
the annual report that wildcat wells and/or delineation wells are the 
only wells that are tested. If you elect to delay reporting of this 
data element, you must report by the date specified in Sec.  98.236(cc) 
the measured average flow rate for well(s) tested and the well ID 
number(s) for the well(s) included in the measurement.
* * * * *
    (3) If you used Equation W-17B of Sec.  98.233 to calculate annual 
volumetric natural gas emissions at actual conditions from gas wells 
and the emissions were not vented to a flare, then you must report the 
information specified in paragraphs (l)(3)(i) through (vi) of this 
section.
* * * * *
    (ii) Well ID numbers for the wells tested in the calendar year.
* * * * *
    (iv) Average annual production rate for well(s) tested, in actual 
cubic feet per day. You may delay reporting of this data element if you 
indicate in the annual report that wildcat wells and/or delineation 
wells are the only wells that are tested. If you elect to delay 
reporting of this data element, you must report by the date specified 
in Sec.  98.236(cc) the measured average annual production rate for 
well(s) tested and the well ID number(s) for the well(s) included in 
the measurement.
* * * * *
    (4) If you used Equation W-17B of Sec.  98.233 to calculate annual 
volumetric natural gas emissions at actual conditions from gas wells 
and the emissions were vented to a flare, then you must report the 
information specified in paragraphs (l)(4)(i) through (vii) of this 
section.
* * * * *
    (ii) Well ID numbers for the wells tested in the calendar year.
* * * * *
    (iv) Average annual production rate for well(s) tested, in actual 
cubic feet per day. You may delay reporting of this data element if you 
indicate in the annual report that wildcat wells and/or delineation 
wells are the only wells that are tested. If you elect to delay 
reporting of this data element, you must report by the date specified 
in Sec.  98.236(cc) the measured average annual production rate for 
well(s) tested and the well ID number(s) for the well(s) included in 
the measurement.
* * * * *
    (m) * * *
    (1) Sub-basin ID and a list of well ID numbers for wells for which 
associated gas was vented or flared.
* * * * *
    (5) Volume of oil produced, in barrels, in the calendar year during 
the time periods in which associated gas was vented or flared (the sum 
of ``Vp,q'' used in Equation W-18 of Sec.  98.233). You may 
delay reporting of this data element if you indicate in the annual 
report that wildcat wells and/or delineation wells are the only wells 
from which associated gas was vented or flared. If you elect to delay 
reporting of this data element, you must report by the date specified 
in Sec.  98.236(cc) the volume of oil produced for well(s) with 
associated gas venting and flaring and the well ID number(s) for the 
well(s) included in the measurement.
    (6) Total volume of associated gas sent to sales, in standard cubic 
feet, in the calendar year during time periods in which associated gas 
was vented or flared (the sum of ``SG'' values used in Equation W-18 of 
Sec.  98.233(m)). You may delay reporting of this data element if you 
indicate in the annual report that wildcat wells and/or delineation 
wells from which associated gas was vented or flared. If you elect to 
delay reporting of this data element, you must report by the date 
specified in Sec.  98.236(cc) the measured total volume of associated 
gas sent to sales for well(s) with associated gas venting and flaring 
and the well ID number(s) for the well(s) included in the measurement.
    (7) * * *
    (i) Total number of wells for which associated gas was vented 
directly to the atmosphere without flaring and a list of their well ID 
numbers.
* * * * *
    (8) * * *
    (i) Total number of wells for which associated gas was flared and a 
list of their well ID numbers.
* * * * *
    (n) * * *
    (1) Unique name or ID for the flare stack. For the onshore 
petroleum and natural gas production and onshore petroleum and natural 
gas gathering and boosting industry segments, a different name or ID 
may be used for a single flare stack for each location where it 
operates at in a given calendar year.
* * * * *
    (o) Centrifugal compressors. You must indicate whether your 
facility has centrifugal compressors. You must report the information 
specified in paragraphs (o)(1) and (2) of this section for all 
centrifugal compressors at your facility. For each compressor source or 
manifolded group of compressor sources that you conduct as found leak 
measurements as specified in Sec.  98.233(o)(2) or (4), you must report 
the information specified in paragraph (o)(3) of this section. For each 
compressor source or manifolded group of compressor sources that you 
conduct continuous monitoring as specified in Sec.  98.233(o)(3) or 
(5), you must report the information specified in paragraph (o)(4) of 
this section. Centrifugal compressors in onshore petroleum and natural 
gas production and onshore petroleum and natural gas gathering and 
boosting are not required to report information in paragraphs (o)(1) 
through (4) of this section and instead must report the information 
specified in paragraph (o)(5) of this section.
* * * * *
    (5) Onshore petroleum and natural gas production and onshore 
petroleum and natural gas gathering and boosting. Centrifugal 
compressors with wet seal degassing vents in onshore petroleum and 
natural gas production and onshore petroleum and natural gas gathering 
and boosting must report the information specified in paragraphs 
(o)(5)(i) through (iii) of this section.
* * * * *
    (p) Reciprocating compressors. You must indicate whether your 
facility has reciprocating compressors. You must report the information 
specified in

[[Page 64296]]

paragraphs (p)(1) and (2) of this section for all reciprocating 
compressors at your facility. For each compressor source or manifolded 
group of compressor sources that you conduct as found leak measurements 
as specified in Sec.  98.233(p)(2) or (4), you must report the 
information specified in paragraph (p)(3) of this section. For each 
compressor source or manifolded group of compressor sources that you 
conduct continuous monitoring as specified in Sec.  98.233(p)(3) or 
(5), you must report the information specified in paragraph (p)(4) of 
this section. Reciprocating compressors in onshore petroleum and 
natural gas production and onshore petroleum and natural gas gathering 
and boosting are not required to report information in paragraphs 
(p)(1) through (4) of this section and instead must report the 
information specified in paragraph (p)(5) of this section.
* * * * *
    (5) Onshore petroleum and natural gas production and onshore 
petroleum and natural gas gathering and boosting. Reciprocating 
compressors in onshore petroleum and natural gas production and onshore 
petroleum and natural gas gathering and boosting must report the 
information specified in paragraphs (p)(5)(i) through (iii) of this 
section.
* * * * *
    (r) * * *
    (1) You must indicate whether your facility contains any of the 
emission source types required to use Equation W-32A of Sec.  98.233. 
You must report the information specified in paragraphs (r)(1)(i) 
through (v) of this section separately for each emission source type 
required to use Equation W-32A that is located at your facility. 
Onshore petroleum and natural gas production facilities and onshore 
petroleum and natural gas gathering and boosting facilities must report 
the information specified in paragraphs (r)(1)(i) through (v) 
separately by component type, service type, and geographic location 
(i.e., Eastern U.S. or Western U.S.).
    (i) Emission source type. Onshore petroleum and natural gas 
production facilities and onshore petroleum and natural gas gathering 
and boosting facilities must report the component type, service type 
and geographic location.
* * * * *
    (3) Onshore petroleum and natural gas production facilities and 
onshore petroleum and natural gas gathering and boosting facilities 
must also report the information specified in paragraphs (r)(3)(i) and 
(ii) of this section.
* * * * *
    (ii) Onshore petroleum and natural gas production facilities and 
onshore petroleum and natural gas gathering and boosting facilities 
must report the information specified in paragraphs (r)(3)(ii)(A) and 
(B) of this section, for each major equipment type, production type 
(i.e., natural gas or crude oil), and geographic location combination 
in Tables W-1B and W-1C of this subpart.
* * * * *
    (z) Combustion equipment at onshore petroleum and natural gas 
production facilities, onshore petroleum and natural gas gathering and 
boosting facilities, and natural gas distribution facilities. If your 
facility is required by Sec.  98.232(c)(22), (i)(7), or (j)(12) to 
report emissions from combustion equipment, then you must indicate 
whether your facility has any combustion units subject to reporting 
according to paragraph (a)(1)(xvii), (a)(8)(i), or (a)(9)(xi) of this 
section. If your facility contains any combustion units subject to 
reporting according to paragraph (a)(1)(xvii), (a)(8)(i), or (a)(9)(xi) 
of this section, then you must report the information specified in 
paragraphs (z)(1) and (2) of this section, as applicable.
* * * * *
    (aa) Each facility must report the information specified in 
paragraphs (aa)(1) through (11) of this section, for each applicable 
industry segment, by using best available data. If a quantity required 
to be reported is zero, you must report zero as the value.
    (1) * * *
    (ii) * * *
    (D) The number of producing wells at the end of the calendar year 
and a list of the well ID numbers (exclude only those wells permanently 
taken out of production, i.e., plugged and abandoned).
    (E) The number of producing wells acquired during the calendar year 
and a list of the well ID numbers.
    (F) The number of producing wells divested during the calendar year 
and a list of the well ID numbers.
    (G) The number of wells completed during the calendar year and a 
list of the well ID numbers.
    (H) The number of wells permanently taken out of production (i.e., 
plugged and abandoned) during the calendar year and a list of the well 
ID numbers.
* * * * *
    (10) For onshore petroleum and natural gas gathering and boosting 
facilities, report the quantities specified in paragraphs (aa)(10)(i) 
through (iv) of this section.
    (i) The quantity of gas received by the gathering and boosting 
facility in the calendar year, in thousand standard cubic feet.
    (ii) The quantity of gas transported to a natural gas processing 
facility, a natural gas transmission pipeline, a natural gas 
distribution pipeline, or another gathering and boosting facility in 
the calendar year, in thousand standard cubic feet.
    (iii) The quantity of all hydrocarbon liquids received by the 
gathering and boosting facility in the calendar year, in barrels.
    (iv) The quantity of all hydrocarbon liquids transported to a 
natural gas processing facility, a natural gas transmission pipeline, a 
natural gas distribution pipeline, or another gathering and boosting 
facility in the calendar year, in barrels.
    (11) For onshore natural gas transmission pipeline facilities, 
report the quantities specified in paragraphs (aa)(11)(i) through (vi) 
of this section.
    (i) The quantity of natural gas received at all custody transfer 
stations in the calendar year, in thousand standard cubic feet. This 
value may include meter corrections, but only for the calendar year 
covered by the annual report.
    (ii) The quantity of natural gas withdrawn from in-system storage 
in the calendar year, in thousand standard cubic feet.
    (iii) The quantity of natural gas added to in-system storage in the 
calendar year, in thousand standard cubic feet.
    (iv) The quantity of natural gas transferred to third parties such 
as LDCs or other transmission pipelines, in thousand standard cubic 
feet.
    (v) The quantity of natural gas consumed by the transmission 
pipeline facility for operational purposes, in thousand standard cubic 
feet.
    (vi) The miles of transmission pipeline for each state in the 
facility.
* * * * *
    (cc) If you elect to delay reporting the information in paragraph 
(g)(5)(i), (g)(5)(ii), (g)(5)(iii)(A), (g)(5)(iii)(B), (h)(1)(iv), 
(h)(2)(iv), (j)(1)(iii), (j)(2)(i)(A), (l)(1)(iv), (l)(2)(iv), 
(l)(3)(iii), (l)(4)(iii), (m)(5), or (m)(6) of this section, you must 
report the information required in that paragraph no later than the 
date 2 years following the date specified in Sec.  98.3(b) introductory 
text.

0
8. Section 98.238 is amended by adding definitions for ``Facility with 
respect to onshore petroleum and natural gas gathering and boosting for 
purposes of reporting under this subpart and for the corresponding 
subpart A requirements,'' ``Facility with respect to the onshore 
natural gas transmission pipeline segment,'' ``Gathering and

[[Page 64297]]

boosting system,'' ``Gathering and boosting system owner or operator,'' 
``Onshore natural gas transmission pipeline owner or operator,'' and 
``Well identification (ID) number'' in alphabetical order to read as 
follows:


Sec.  98.238  Definitions.

* * * * *
    Facility with respect to onshore petroleum and natural gas 
gathering and boosting for purposes of reporting under this subpart and 
for the corresponding subpart A requirements means all gathering 
pipelines and other equipment located along those pipelines that are 
under common ownership or common control by a gathering and boosting 
system owner or operator and that are located in a single hydrocarbon 
basin as defined in this section. Where a person owns or operates more 
than one gathering and boosting system in a basin (for example, 
separate gathering lines that are not connected), then all gathering 
and boosting equipment that the person owns or operates in the basin 
would be considered one facility. Any gathering and boosting equipment 
that is associated with a single gathering and boosting system, 
including leased, rented, or contracted activities, is considered to be 
under common control of the owner or operator of the gathering and 
boosting system that contains the pipeline. The facility does not 
include equipment and pipelines that are part of any other industry 
segment defined in this subpart.
* * * * *
    Facility with respect to the onshore natural gas transmission 
pipeline segment means the total U.S. mileage of natural gas 
transmission pipelines, as defined in this section, owned and operated 
by an onshore natural gas transmission pipeline owner or operator as 
defined in this section. The facility does not include pipelines that 
are part of any other industry segment defined in this subpart.
* * * * *
    Gathering and boosting system means a single network of pipelines, 
compressors and process equipment, including equipment to perform 
natural gas compression, dehydration, and acid gas removal, that has 
one or more connection points to gas and oil production and a 
downstream endpoint, typically a gas processing plant, transmission 
pipeline, LDC pipeline, or other gathering and boosting system.
    Gathering and boosting system owner or operator means any person 
that holds a contract in which they agree to transport petroleum or 
natural gas from one or more onshore petroleum and natural gas 
production wells to a natural gas processing facility, another 
gathering and boosting system, a natural gas transmission pipeline, or 
a distribution pipeline, or any person responsible for custody of the 
petroleum or natural gas transported.
* * * * *
    Onshore natural gas transmission pipeline owner or operator means, 
for interstate pipelines, the person identified as the transmission 
pipeline owner or operator on the Certificate of Public Convenience and 
Necessity issued under 15 U.S.C. 717f, or, for intrastate pipelines, 
the person identified as the owner or operator on the transmission 
pipeline's Statement of Operating Conditions under section 311 of the 
Natural Gas Policy Act, or for pipelines that fall under the ``Hinshaw 
Exemption'' as referenced in section 1(c) of the Natural Gas Act, 15 
U.S.C. 717-717 (w)(1994), the person identified as the owner or 
operator on blanket certificates issued under 18 CFR 284.224. If an 
intrastate pipeline is not subject to section 311 of the Natural Gas 
Policy Act (NGPA), the onshore natural gas transmission pipeline owner 
or operator is the person identified as the owner or operator on 
reports to the state regulatory body regulating rates and charges for 
the sale of natural gas to consumers.
* * * * *
    Well identification (ID) number means the unique and permanent 
identification number assigned to a petroleum or natural gas well. If 
the well has been assigned a US Well Number, the well ID number 
required in this subpart is the US Well Number. If a US Well Number has 
not been assigned to the well, the well ID number is the identifier 
established by the well's permitting authority.
* * * * *

0
9. Revise Table W-1A of subpart W of part 98 to read as follows:

 Table W-1A to Subpart W of Part 98--Default Whole Gas Emission Factors
 for Onshore Petroleum and Natural Gas Production Facilities and Onshore
       Petroleum and Natural Gas Gathering and Boosting Facilities
------------------------------------------------------------------------
  Onshore petroleum and natural gas production
and Onshore petroleum and natural gas gathering   Emission factor (scf/
                  and boosting                       hour/component)
------------------------------------------------------------------------
                              Eastern U.S.
------------------------------------------------------------------------
      Population Emission Factors--All Components, Gas Service \1\
------------------------------------------------------------------------
Valve..........................................                    0.027
Connector......................................                    0.003
Open-ended Line................................                    0.061
Pressure Relief Valve..........................                    0.040
Low Continuous Bleed Pneumatic Device Vents \2\                     1.39
High Continuous Bleed Pneumatic Device Vents                        37.3
 \2\...........................................
Intermittent Bleed Pneumatic Device Vents \2\..                     13.5
Pneumatic Pumps \3\............................                     13.3
------------------------------------------------------------------------
  Population Emission Factors--All Components, Light Crude Service \4\
------------------------------------------------------------------------
Valve..........................................                     0.05
Flange.........................................                    0.003
Connector......................................                    0.007
Open-ended Line................................                     0.05
Pump...........................................                     0.01
Other \5\......................................                     0.30
------------------------------------------------------------------------
  Population Emission Factors--All Components, Heavy Crude Service \6\
------------------------------------------------------------------------
Valve..........................................                   0.0005
Flange.........................................                   0.0009
Connector (other)..............................                   0.0003

[[Page 64298]]

 
Open-ended Line................................                    0.006
Other \5\......................................                    0.003
------------------------------------------------------------------------
 Population Emission Factors--Gathering Pipelines, by Material Type \7\
------------------------------------------------------------------------
Protected Steel................................                     0.47
Unprotected Steel..............................                    16.59
Plastic/Composite..............................                     2.50
Cast Iron......................................                    27.60
------------------------------------------------------------------------
                              Western U.S.
------------------------------------------------------------------------
      Population Emission Factors--All Components, Gas Service \1\
------------------------------------------------------------------------
Valve..........................................                    0.121
Connector......................................                    0.017
Open-ended Line................................                    0.031
Pressure Relief Valve..........................                    0.193
Low Continuous Bleed Pneumatic Device Vents \2\                     1.39
High Continuous Bleed Pneumatic Device Vents                        37.3
 \2\...........................................
Intermittent Bleed Pneumatic Device Vents \2\..                     13.5
Pneumatic Pumps \3\............................                     13.3
------------------------------------------------------------------------
  Population Emission Factors--All Components, Light Crude Service \4\
------------------------------------------------------------------------
Valve..........................................                     0.05
Flange.........................................                    0.003
Connector (other)..............................                    0.007
Open-ended Line................................                     0.05
Pump...........................................                     0.01
Other \5\......................................                     0.30
------------------------------------------------------------------------
  Population Emission Factors--All Components, Heavy Crude Service \6\
------------------------------------------------------------------------
Valve..........................................                   0.0005
Flange.........................................                   0.0009
Connector (other)..............................                   0.0003
Open-ended Line................................                    0.006
Other \5\......................................                    0.003
------------------------------------------------------------------------
  Population Emission Factors--Gathering Pipelines by Material Type \7\
------------------------------------------------------------------------
Protected Steel................................                     0.47
Unprotected Steel..............................                    16.59
Plastic/Composite..............................                     2.50
Cast Iron......................................                    27.60
------------------------------------------------------------------------
\1\ For multi-phase flow that includes gas, use the gas service
  emissions factors.
\2\ Emission Factor is in units of ``scf/hour/device.''
\3\ Emission Factor is in units of ``scf/hour/pump.''
\4\ Hydrocarbon liquids greater than or equal to 20[deg]API are
  considered ``light crude.''
\5\ ``Others'' category includes instruments, loading arms, pressure
  relief valves, stuffing boxes, compressor seals, dump lever arms, and
  vents.
\6\ Hydrocarbon liquids less than 20[deg]API are considered ``heavy
  crude.''
\7\ Emission factors are in units of ``scf/hour/mile of pipeline.''


0
10. Amend Table W-1B of subpart W of part 98 by revising the table 
heading to read as follows:

Table W-1B to Subpart W of Part 98--Default Average Component Counts for
Major Onshore Natural Gas Production Equipment and Onshore Petroleum and
              Natural Gas Gathering and Boosting Equipment
 
 
 
 
 

* * * * *
[FR Doc. 2015-25840 Filed 10-21-15; 08:45 am]
 BILLING CODE 6560-50-P