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Rule2024-08988

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

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Published

May 14, 2024

Effective

January 1, 2025

Issuing agencies

Environmental Protection Agency

Abstract

The Environmental Protection Agency (EPA) is amending requirements that apply to the petroleum and natural gas systems source category of the Greenhouse Gas Reporting Rule to ensure that reporting is based on empirical data, accurately reflects total methane emissions and waste emissions from applicable facilities, and allows owners and operators of applicable facilities to submit empirical emissions data that appropriately demonstrate the extent to which a charge is owed under the Waste Emissions Charge. The EPA is also amending certain requirements that apply to the general provisions, general stationary fuel combustion, and petroleum and natural gas systems source categories of the Greenhouse Gas Reporting Rule to improve calculation, monitoring, and reporting of greenhouse gas data for petroleum and natural gas systems facilities. This action also establishes and amends confidentiality determinations for the reporting of certain data elements to be added or substantially revised in these amendments.

Full Text

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[Federal Register Volume 89, Number 94 (Tuesday, May 14, 2024)]
[Rules and Regulations]
[Pages 42062-42327]
From the Federal Register Online via the Government Publishing Office [<a href="http://www.gpo.gov">www.gpo.gov</a>]
[FR Doc No: 2024-08988]

[[Page 42061]]

Vol. 89

Tuesday,

No. 94

May 14, 2024

Part II

Environmental Protection Agency

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40 CFR Part 98

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

Federal Register / Vol. 89 , No. 94 / Tuesday, May 14, 2024 / Rules
and Regulations

[[Page 42062]]

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ENVIRONMENTAL PROTECTION AGENCY

40 CFR Part 98

[EPA-HQ-OAR-2023-0234; FRL-10246-02-OAR]
RIN 2060-AV83

Greenhouse Gas Reporting Rule: 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 amending
requirements that apply to the petroleum and natural gas systems source
category of the Greenhouse Gas Reporting Rule to ensure that reporting
is based on empirical data, accurately reflects total methane emissions
and waste emissions from applicable facilities, and allows owners and
operators of applicable facilities to submit empirical emissions data
that appropriately demonstrate the extent to which a charge is owed
under the Waste Emissions Charge. The EPA is also amending certain
requirements that apply to the general provisions, general stationary
fuel combustion, and petroleum and natural gas systems source
categories of the Greenhouse Gas Reporting Rule to improve calculation,
monitoring, and reporting of greenhouse gas data for petroleum and
natural gas systems facilities. This action also establishes and amends
confidentiality determinations for the reporting of certain data
elements to be added or substantially revised in these amendments.

DATES: This rule is effective January 1, 2025, except for Sec. 98.233
(amendatory instruction 12), Sec. 98.236 (amendatory instruction 16),
and Sec. 98.238 (amendatory instruction 19) which are effective July
15, 2024. The incorporation by reference of certain material listed in
this final rule is approved by the Director of the Federal Register as
of January 1, 2025.

ADDRESSES: The EPA has established a docket for this action under
Docket ID. No. EPA-HQ-OAR-2023-0234. All documents in the docket are
listed in the <a href="https://www.regulations.gov">https://www.regulations.gov</a> index. 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. Publicly available docket materials are available
either electronically in <a href="https://www.regulations.gov">https://www.regulations.gov</a> or in hard copy at
the EPA Docket Center, WJC West Building, Room 3334, 1301 Constitution
Ave. NW, Washington, DC. This Docket Facility is open from 8:30 a.m. to
4:30 p.m., Monday through Friday, excluding legal holidays. The
telephone number for the Public Reading Room is (202) 566-1744 and the
telephone number for the Air Docket is (202) 566-1742.

FOR FURTHER INFORMATION CONTACT: Jennifer Bohman, Climate Change
Division, Office of Atmospheric Programs (MC-6207A), Environmental
Protection Agency, 1200 Pennsylvania Ave. NW, Washington, DC 20460;
telephone number: (202) 343-9548; email address: <a href="/cdn-cgi/l/email-protection#692e212e3b0c19061b1d00070e290c1908470e061f">[email&#160;protected]</a>.
For technical information, please go to the Greenhouse Gas Reporting
Program (GHGRP) website, <a href="https://www.epa.gov/ghgreporting">https://www.epa.gov/ghgreporting</a>. To submit a
question, select Help Center, followed by ``Contact Us.''
World Wide 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 final
rule will be posted on the EPA's GHGRP website at <a href="https://www.epa.gov/ghgreporting">https://www.epa.gov/ghgreporting</a>.

SUPPLEMENTARY INFORMATION:
Regulated entities. These final revisions affect certain entities
that must submit annual greenhouse gas (GHG) reports under the GHGRP
(40 CFR part 98). These are amendments to existing regulations and will
affect owners or operators of petroleum and natural gas systems that
directly emit GHGs. Regulated categories and entities include, but are
not limited to, those listed in table 1 of this preamble:
[GRAPHIC] [TIFF OMITTED] TR14MY24.000

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. This table lists the types of facilities that
the EPA is now aware could potentially be affected by this action.
Other types of facilities than those listed in the table could also be
subject to reporting requirements. To determine whether you will be
affected by this action, you should carefully examine the applicability
criteria found in 40 CFR part 98, subpart A (General Provisions) and 40
CFR part 98, subpart W (Petroleum and Natural Gas Systems). If you have
questions regarding the applicability of this action to a particular
facility, consult the person listed in the FOR FURTHER INFORMATION
CONTACT section.
Acronyms and Abbreviations. The following acronyms and
abbreviations are used in this document.

AGR acid gas removal unit
AMLD Advanced Mobile Leak Detection
API American Petroleum Institute

[[Page 42063]]

ASTM American Society for Testing and Materials
AVO audio, visual, and olfactory
BOEM U.S. Bureau of Ocean Energy Management
BRE Bryan Research & Engineering
BSER best system of emissions reduction
Btu/scf British thermal units per standard cubic foot
CAA Clean Air Act
CBI confidential business information
CE combustion efficiency
CEMS continuous emissions monitoring system
CenSARA Central States Air Resources Agency
CFR Code of Federal Regulations
CH<INF>4</INF> methane
CO<INF>2</INF> carbon dioxide
CO<INF>2</INF>e carbon dioxide equivalent
CRR cost-to-revenue ratio
DE destruction efficiency
DI&M directed inspection and maintenance
DOE Department of Energy (DOE)
DRE destruction and removal efficiency
e-GGRT electronic Greenhouse Gas Reporting Tool
EG emission guidelines
EIA U.S. Energy Information Administration
EOR enhanced oil recovery
EPA U.S. Environmental Protection Agency
FAQ frequently asked question
FLIGHT Facility Level Information on Greenhouse gases Tool
FR Federal Register
FTIR Fourier transform infrared
GHG greenhouse gas
GHGRP Greenhouse Gas Reporting Program
GOR gas to oil ratio
gpm gallons per minute
GRI Gas Research Institute
GT gas turbines
HHV higher heating value
ICR information collection request
ID identification
IRA Inflation Reduction Act of 2022
IVT Inputs Verification Tool
kg/hr kilograms per hour
LDAR leak detection and repair
LDC local distribution company
LNG liquefied natural gas
m meters
MDEA methyl diethanolamine
MEA monoethanolamine
MMBtu/hr million British thermal units per hour
MMscf million standard cubic feet
mt metric tons
mtCO<INF>2</INF>e metric tons carbon dioxide equivalent
N<INF>2</INF>O nitrous oxide
NAICS North American Industry Classification System
NGLs natural gas liquids
NRU nitrogen recovery unit
NSPS new source performance standards
NYSERDA New York State Energy Research and Development Authority
O&M operation and maintenance
OCS AQS Outer Continental Shelf Air Quality System
OEL open-ended line
OEM original equipment manufacturer
OGI optical gas imaging
OMB Office of Management and Budget
OTM other test method
PBI proprietary business information
PHMSA U.S. Pipeline and Hazardous Materials Safety Administration
ppm parts per million
ppmv parts per million by volume
PRA Paperwork Reduction Act
PRD pressure relief device
psig pounds per square inch gauge
PTE potential to emit
RFA Regulatory Flexibility Act
RFI Request for Information
RICE reciprocating internal combustion engines
RY reporting year
SCADA supervisory control and data acquisition
scf standard cubic feet
scf/hr/device standard cubic feet per hour per device
TCEQ Texas Commission on Environmental Quality
THC total hydrocarbon
TOC total organic carbon
TSD technical support document
U.S. United States
UMRA Unfunded Mandates Reform Act of 1995
VISR Video Imaging Spectro-Radiometry
VOC volatile organic compound(s)
WEC waste emissions charge
WWW World Wide Web

Table of Contents

I. Background
A. How is this preamble organized?
B. Executive Summary
C. Background on This Final Rule
D. Legal Authority
E. Relationship to Other Clean Air Act Section 136 Actions
F. Relationship to Clean Air Act Section 111
II. Overview and Rationale for Final Amendments to 40 CFR Part 98,
Subpart W
A. Revisions To Address Potential Gaps in Reporting of Emissions
Data for Specific Sectors
B. Revisions To Add New Emissions Calculation Methodologies or
Improve Existing Emissions Calculation Methodologies
C. Revisions to Reporting Requirements To Improve Verification
and Transparency of the Data Collected
D. Technical Amendments, Clarifications, and Corrections
III. Final Amendments to Part 98 and Summary of Comments and
Responses
A. General and Applicability Amendments
B. Other Large Release Events
C. New and Additional Emission Sources
D. Reporting for the Onshore Petroleum and Natural Gas
Production and Onshore Petroleum and Natural Gas Gathering and
Boosting Industry Segments
E. Natural Gas Pneumatic Device Venting and Natural Gas Driven
Pneumatic Pump Venting
F. Acid Gas Removal Unit Vents
G. Dehydrator Vents
H. Liquids Unloading
I. Gas Well Completions and Workovers With Hydraulic Fracturing
J. Blowdown Vent Stacks
K. Atmospheric Storage Tanks
L. Flared Transmission Storage Tank Vent Emissions
M. Associated Gas Venting and Flaring
N. Flare Stack Emissions
O. Compressors
P. Equipment Leak Surveys
Q. Equipment Leaks by Population Count
R. Offshore Production
S. Combustion Equipment
T. Leak Detection and Measurement Methods
U. Industry Segment-Specific Throughput Quantity Reporting
V. Other Final Minor Revisions or Clarifications
IV. Effective Date of the Final Amendments
A. Amendments That Are Effective on January 1, 2025
B. Amendments That Are Effective July 15, 2024
V. Final Confidentiality and Reporting Determinations for Certain
Data Reporting Elements
A. EPA's Approach To Assess Data Elements
B. Final Confidentiality Determinations and Emissions Data
Designations
C. Final Reporting Determinations for Inputs to Emission
Equations
VI. Impacts of the Final Amendments
A. Cost Analysis
B. Cost-to-Revenue Ratio Analysis
VII. 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 (PRA)
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 That Significantly Affect
Energy Supply, Distribution, or Use
I. National Technology Transfer and Advancement Act and 1 CFR
part 51
J. Executive Order 12898: Federal Actions To Address
Environmental Justice in Minority Populations and Low-Income
Populations
K. Congressional Review Act (CRA)
L. Judicial Review
M. Determination Under CAA Section 307(d)
N. Severability

I. Background

A. How is this preamble organized?

The first section of this preamble contains background information
on the August 1, 2023 proposed amendments (88 FR 50282, hereafter
referred to as ``2023 Subpart W Proposal'') and on this final rule, as
well as a summary of the final revisions. This section also discusses
the EPA's legal authority under the Clean Air Act (CAA) to

[[Page 42064]]

promulgate (including subsequent amendments to) the Greenhouse Gas
Reporting Rule, codified at 40 CFR part 98 (hereafter referred to as
``part 98''), generally and 40 CFR part 98, subpart W (hereafter
referred to as ``subpart W'') in particular. This section also
discusses the EPA's legal authority to make confidentiality
determinations for new or revised data elements corresponding to these
amendments or for existing data elements for which the EPA is
finalizing a new determination. Section II. of this preamble describes
the types of amendments included in this final rulemaking and includes
the rationale for each type of change. Section III. of this preamble
contains detailed information on the revisions to 40 CFR part 98,
subpart A (General Provisions), subpart C (General Stationary Fuel
Combustion Sources) and subpart W. Section IV. of this preamble
explains the effective date of the final revisions and how the
revisions are required to be implemented in reporting year (RY) 2024
and RY2025 reports. Section V. of this preamble discusses the final
confidentiality determinations for new or substantially revised (i.e.,
requiring additional or different data to be reported) data reporting
elements, as well as for certain existing data elements for which the
EPA is finalizing a new determination. Section VI. of this preamble
discusses the impacts of the amendments. Finally, section VII. of this
preamble describes the statutory and Executive Order requirements
applicable to this action.

B. Executive Summary

In August 2022, Congress passed, and President Biden signed, the
Inflation Reduction Act of 2022 (IRA) into law. Section 60113 of the
IRA amended the CAA by adding section 136, ``Methane Emissions and
Waste Reduction Incentive Program for Petroleum and Natural Gas
Systems.'' CAA section 136(c), ``Waste Emissions Charge,'' directs the
Administrator to impose and collect a charge on methane
(CH<INF>4</INF>) emissions that exceed statutorily specified waste
emissions thresholds from owners or operators of applicable facilities
that report more than 25,000 metric tons carbon dioxide equivalent
(mtCO<INF>2</INF>e) pursuant to the Greenhouse Gas Reporting Rule's
requirements for the petroleum and natural gas systems source category
(codified as subpart W in the EPA's Greenhouse Gas Reporting Rule
regulations). Further, CAA section 136(h) requires that the EPA shall,
within two years after the date of enactment of section 60113 of the
IRA, revise the requirements of subpart W to ensure the reporting under
subpart W (and corresponding waste emissions charges under CAA section
136) is based on empirical data, accurately reflects the total
CH<INF>4</INF> emissions (and waste emissions) from the applicable
facilities, and allow owners and operators of applicable facilities to
submit empirical emissions data, in a manner to be prescribed by the
Administrator, to demonstrate the extent to which a charge is owed
under CAA section 136.
On August 1, 2023, the EPA proposed revisions to subpart W
consistent with the authority and directives set forth in CAA section
136(h) as well as the EPA's authority under CAA section 114 in the 2023
Subpart W Proposal. The EPA proposed revisions to include reporting of
additional emissions or emissions sources to address potential gaps in
the total CH<INF>4</INF> emissions reported by facilities to subpart W.
The EPA also proposed several revisions to add new or revise existing
calculation methodologies to improve the accuracy of reported
emissions, incorporate additional empirical data and to allow owners
and operators of applicable facilities to submit empirical emissions
data that could appropriately demonstrate the extent to which a charge
is owed in future implementation of CAA section 136, as directed by CAA
section 136(h). For example, the EPA proposed new calculation
methodologies for equipment leaks and natural gas pneumatic devices to
allow for the use of direct measurement. The EPA also proposed several
revisions to existing reporting requirements to collect data that would
improve verification of reported data, ensure accurate reporting of
emissions, and improve the transparency of reported data. For example,
the EPA proposed to disaggregate reporting requirements within the
Onshore Petroleum and Natural Gas Production and Onshore Petroleum and
Natural Gas Gathering and Boosting industry segments, with most
emissions and activity data for Onshore Petroleum and Natural Gas
Production and Onshore Petroleum and Natural Gas Gathering and Boosting
being disaggregated to at least the well-pad site and gathering and
boosting site level, respectively. The EPA also proposed other
technical amendments, corrections, and clarifications that would
improve understanding of the rule. These revisions primarily included
revisions of requirements to better reflect the EPA's intent or
editorial changes. The 2023 Subpart W Proposal also indicated that the
EPA would be undertaking one or more separate actions in the future to
implement the remainder of CAA section 136.
The EPA is finalizing revisions to part 98 included in the 2023
Subpart W Proposal, with some changes made after consideration of
public comments. The final amendments include new reporting
requirements with some revisions from what was proposed for other large
release events, produced water storage tanks, nitrogen removal units,
drilling mud degassing, and crankcase venting. The final amendments
expand the applicability of certain emission sources to new industry
segments as proposed. The final amendments also include new calculation
methods, with some revisions to those proposed, that provide
measurement or monitoring survey options, including for the calculation
of emissions from equipment leaks, combustion slip, crankcase venting,
associated gas, compressors, natural gas pneumatic devices, and
equipment leaks from components at transmission company interconnect
metering and regulating stations, to allow reporters to use appropriate
empirical data for these emission sources as an alternative to
population emission factors. We are also revising calculation methods,
with some revisions based on comments received, to improve the accuracy
or clarity of the existing calculation methods. This action also
finalizes confidentiality determinations for the reporting of data
elements added or substantially revised in these final amendments, and
for certain existing data elements for which no confidentiality
determination has been made previously or for which the EPA proposed to
revise the existing determination.
In some cases, and as further described in section III. of this
preamble, the EPA is not taking final action in this final rule on
certain proposed revisions included in the 2023 Subpart W Proposal. For
example, after review of comments received in response to the proposed
requirements for reporters in the Onshore Petroleum and Natural Gas
Production, Natural Gas Distribution, Onshore Petroleum and Natural Gas
Gathering and Boosting, and Onshore Natural Gas Transmission Pipeline
industry segments that have ownership changes in subpart A, the EPA is
not taking action at this time on the revisions to subpart A regarding
responsibilities for revisions to reports submitted in the years before
the ownership transactions. In consideration of the relationship
between revisions to annual reports for prior years and implementation
requirements for CAA section 136(c)

[[Page 42065]]

proposed on January 26, 2024 (89 FR 5318) (hereafter referred to as the
``2024 WEC Proposal''), the EPA intends to consider those proposed
revisions in coordination with the development of the WEC final rule
and take action, if finalized, on these requirements at the same time.
In some cases, we are not taking final action at this time on certain
revisions to the calculation or monitoring methodologies that would
have revised how data are collected. For example, after review and
consideration of the comments received in response to the proposed
requirements for flares, we are not finalizing requirements to use
continuous flow monitors or continuous parametric monitoring and
continuous composition analyzers or quarterly sampling to determine
flow and composition, respectively, of gas routed to flares. In several
cases, we are also not taking final action at this time on proposed
revisions to add reporting requirements. For example, we are not
finalizing certain proposed reporting requirements for other large
release events when the reporter receives a third-party notification
because all Super-Emitter Program notifications will come from the EPA
and the EPA will already have the information proposed to be reported.
Some of the final amendments, particularly those that allow
reporters to choose from additional calculation methodologies and
submit empirical emissions data will be effective immediately as
optional methodologies. These amendments will apply to reports
submitted by current reporters that are submitted in calendar year 2025
and subsequent years (i.e., starting with reports submitted for RY2024
by March 31, 2025). The remaining final amendments will become
effective on January 1, 2025. Those final revisions, which apply to
both existing and new reporters, will be first implemented for reports
prepared for RY2025 and submitted by March 31, 2026. Reporters who are
newly subject to the rule will be required to implement all
requirements to collect data, including any required monitoring and
recordkeeping, on January 1, 2025.
These final amendments are anticipated to result in an overall
increase in burden for part 98 reporters in cases where the amendments
expand current applicability, add or revise reporting requirements, or
require additional emissions data to be reported. The final revisions
will affect approximately 567 new reporters and 2,510 existing
reporters. The incremental implementation labor costs are $169.4
million per year over the next three years (RY2025 through RY2027), for
a total of $508.3 million for the three years. There is an additional
incremental annualized burden of $14.1 million for operation and
maintenance (O&M) costs in RY2025 and in each subsequent year (RY2026
and RY2027), which reflects changes to monitoring for 2,510 existing
reporters and the 567 additional reporters.
Labor costs increased from $41.4 million per year at proposal to
$169.4 million per year at final, based in part on consideration of
comments received on the estimated labor hours needed to comply with
these amendments at proposal. As detailed in section VI.A. of this
preamble and the Summary of Public Comments and Responses for 2024
Final Revisions and Confidentiality Determinations for Petroleum and
Natural Gas Systems under the Greenhouse Gas Reporting Rule, those
labor hour estimates have been revised, leading to higher labor costs.

C. Background on This Final Rule

This final action builds on previous part 98 rulemakings. The
Greenhouse Gas Reporting Rule was published in the Federal Register
(FR) on October 30, 2009 (74 FR 56260) (hereafter referred to as the
2009 Final Rule). The 2009 Final Rule became effective on December 29,
2009, and requires reporting of GHGs from various facilities and
suppliers, consistent with the 2008 Consolidated Appropriations Act.\1\
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 rulemaking 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 (75 FR 18608; April 12, 2010), and a
subsequent final rulemaking 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 ``2010 Final Rule''). Following promulgation, the EPA
finalized several technical and clarifying amendments to subpart W (76
FR 22825, April 25, 2011; 76 FR 53057, August 25, 2011; 76 FR 59533,
September 27, 2011; 76 FR 73866, November 29, 2011; 76 FR 80554,
December 23, 2011; 77 FR 48072, August 13, 2012; 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; 80 FR
64262, October 22, 2015; and 81 FR 86490, November 30, 2016). These
amendments generally added or revised requirements in subpart W,
including revisions that were intended to improve quality, clarity, and
consistency across the calculation, monitoring, and data reporting
requirements, and to finalize confidentiality and reporting
determinations for data elements reported under the subpart.
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\1\ Consolidated Appropriations Act, 2008, Public Law 110-161,
121 Stat. 1844, 2128.
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More recently, the EPA proposed amendments to subpart W on June 21,
2022 (87 FR 36920) (hereafter referred to as the ``2022 Proposed
Rule''), including technical amendments to improve the quality and
consistency of the data collected under the rule and resolve data gaps,
amendments to streamline and improve implementation, and revisions to
provide additional flexibility in the calculation methods and
monitoring requirements for some emission sources. The 2022 Proposed
Rule was developed prior to the enactment of the Inflation Reduction
Act, which was signed into law on August 16, 2022, and its direction in
CAA section 136(h) to revise subpart W. Consequently, in developing the
2023 Subpart W Proposal, the EPA considered the proposed amendments to
subpart W from the 2022 Proposed Rule as well as the concerns and
information submitted by commenters in response to that proposal. In
the 2023 Subpart W Proposal, the EPA proposed to revise the subpart W
provisions, including both (1) updates to the proposed revisions to
subpart W that were in the 2022 Proposed Rule as well as (2) additional
proposed revisions to comply with CAA section 136(h). The preamble to
the 2023 Subpart W Proposal explained that the EPA did not intend to
finalize the revisions to subpart W that were proposed in the 2022
Proposed Rule and that the final amendments to subpart W would include
consideration of public comments on the 2023 Subpart W Proposal.
Additionally, the EPA opened a non-regulatory docket on November 4,
2022, and issued a Request for Information (RFI) seeking public input
to inform program design related to CAA section 136.\2\ As part of this
request, the EPA sought input on revisions that should be considered
related to subpart W. The comment period closed on January 18, 2023.
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\2\ Docket ID No. EPA-HQ-OAR-2022-0875.
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The EPA is finalizing amendments and confidentiality determinations
in this action, with certain changes from

[[Page 42066]]

the 2023 Subpart W Proposal following consideration of comments
submitted and based on the EPA's updated assessment. The revisions
reflect the EPA's efforts to improve calculation, monitoring, and
reporting of greenhouse gas data for petroleum and natural gas systems
facilities and to ensure that reporting is based on empirical data,
accurately reflects total methane emissions and waste emissions from
applicable facilities, and allows owners and operators of applicable
facilities to submit empirical emissions data that appropriately
demonstrate the extent to which a charge is owed under the Waste
Emissions Charge. Responses to major comments submitted on the proposed
amendments from the 2023 Subpart W Proposal considered in the
development of this final rule can be found in section III. of this
preamble. Documentation of all comments received as well as the EPA's
responses can be found in the document Summary of Public Comments and
Responses for 2024 Final Revisions and Confidentiality Determinations
for Petroleum and Natural Gas Systems under the Greenhouse Gas
Reporting Rule, available in the docket to this rulemaking (Docket ID.
No. EPA-HQ-OAR-2023-0234).
While this final rule complies with and is consistent with
directives in CAA section 136(h), this final rule does not address
implementation of other portions of CAA section 136 (section 60113 of
the Inflation Reduction Act), ``Methane Emissions and Waste Reduction
Incentive Program for Petroleum and Natural Gas Systems.'' The EPA
noted in the preamble to the 2023 Subpart W Proposal that we intend to
issue one or more separate actions to implement other requirements of
CAA section 136, which could include revisions to certain requirements
of subpart W for implementation purposes. Subsequently, the EPA
published the 2024 WEC Proposal to implement CAA section 136(c),
``Waste Emissions Charge,'' or ``WEC,'' on January 26, 2024 (89 FR
5318).\3\
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\3\ CAA section 136(c), ``Waste Emissions Charge,'' directs the
Administrator to impose and collect a charge on methane
(CH<INF>4</INF>) emissions that exceed statutorily specified waste
emissions thresholds from an owner or operator of an applicable
facility that reports more than 25,000 metric tons carbon dioxide
equivalent pursuant to the Greenhouse Gas Reporting Rule's
requirements for the petroleum and natural gas systems source
category (codified as subpart W in the EPA's Greenhouse Gas
Reporting Rule regulations).
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D. Legal Authority

The EPA is finalizing these rule amendments under its existing CAA
authority provided in CAA section 114 and under its newly established
authority provided in CAA section 136, as applicable. As noted in the
preamble to the proposed rule for this rulemaking and in the preamble
to the 2009 Final Rule (74 FR 56264, October 30, 2009), the EPA has
consistently applied its authority under CAA section 114(a)(1) for over
a decade to require the information proposed to be gathered by this
rule because such data would inform and are relevant to the EPA's
carrying out of a variety of CAA provisions. Thus, when promulgating
amendments to the Greenhouse Gas Reporting Rule (40 CFR part 98), the
EPA has assessed the reasonableness of requiring the information to be
provided and explained how the data are relevant to the EPA's ability
to carry out the provisions of the CAA. See the preambles to the
proposed Greenhouse Gas Reporting Rule (74 FR 16448, April 10, 2009)
and the 2009 Final Rule for further information. Additionally, in
enacting CAA section 136, Congress implicitly recognized the EPA's
appropriate use of CAA authority in promulgating the GHGRP. As noted in
section I.B. of this preamble, the provisions of CAA section 136
reference and are in part based on the Greenhouse Gas Reporting Rule
requirements under subpart W for the petroleum and natural gas systems
source category and require further revisions to subpart W for purposes
of supporting implementation of section 136. Under CAA section 136(h),
Congress directed the Administrator to revise the requirements of
subpart W to ensure that reporting of CH<INF>4</INF> emissions under
subpart W (and corresponding waste emissions charges under CAA section
136) is based on empirical data, accurately reflects the total
CH<INF>4</INF> emissions (and waste emissions) from applicable
facilities, and allows owners and operators to submit empirical
emissions data, in a manner prescribed by the Administrator, to
demonstrate the extent to which a charge is owed under CAA section 136.
Under CAA section 136, an ``applicable facility'' is a facility within
nine of the ten industry segments subject to subpart W, as currently
defined in 40 CFR 98.230 (excluding natural gas distribution). The
revisions being finalized are consistent with these directives,
ensuring that (1) reporting of methane emissions under subpart W are
based on empirical data, (2) accurately reflect total methane emissions
(and waste emissions) and (3) allow owners and operators to submit
appropriate empirical data. The EPA appropriately applied its authority
in this rulemaking in a manner consistent with CAA section 114 and the
directives under CAA section 136. See section II. of this preamble for
discussion of the rationale for these revisions, which includes that
they can be used to support carrying out a range of future climate
change policies and regulations under the CAA, including but not
limited to information relevant to carrying out CAA section 136,
provisions involving research, evaluating and setting standards,
endangerment determinations, or informing EPA non-regulatory programs
under the CAA, and see also section III. of this preamble and the
document Summary of Public Comments and Responses for 2024 Final
Revisions and Confidentiality Determinations for Petroleum and Natural
Gas Systems under the Greenhouse Gas Reporting Rule, available in the
docket to this rulemaking (Docket ID. No. EPA-HQ-OAR-2023-0234), for
further detail on the revisions and their supporting rationale.
The Administrator has determined that this action is subject to the
provisions of section 307(d) of the CAA (see also section VII.M. of
this preamble). Section 307(d) contains a set of procedures relating to
the issuance and review of certain CAA rules.
In addition, pursuant to sections 114, 301, and 307 of the CAA, the
EPA is publishing final confidentiality determinations for the new or
substantially revised 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 (excluding
emission data) that qualifies for confidential treatment.

E. Relationship to Other Clean Air Act Section 136 Actions

The IRA adds authorities under CAA section 136 to reduce
CH<INF>4</INF> emissions from the oil and gas sector. It accomplishes
this in multiple ways. First, it provides incentives for CH<INF>4</INF>
mitigation and monitoring. Second, it establishes a waste emissions
charge for applicable facilities that exceed statutorily specified
thresholds that vary by industry segment and are determined by the
amount of natural gas or oil sent to sale. Third, CAA section 136(h)
requires the EPA to revise subpart W. The first and second listed
aspects of CAA section 136 are outside the scope of this rulemaking.
CAA section 136 provides $1.55 billion in incentives for
CH<INF>4</INF> mitigation and monitoring, including through grants,
rebates, contracts, loans, and other activities. Of these funds, at
least $700 million is allocated to activities at

[[Page 42067]]

marginal conventional wells. There are several potential uses of funds.
Use of funds can include financial and technical assistance to owners
and operators of applicable facilities to prepare and submit GHG
reports under subpart W. Financial assistance can also be provided for
CH<INF>4</INF> emissions monitoring authorized under CAA section 103
subsections (a) through (c). Additionally, financial and technical
assistance can be provided to: reduce CH<INF>4</INF> and other GHG
emissions from petroleum and natural gas systems, including to mitigate
legacy air pollution from petroleum and natural gas systems; improve
climate resilience of communities and petroleum and natural gas
systems; improve and deploy industrial equipment and processes that
reduce CH<INF>4</INF> and other GHG emissions and waste; support
innovation in reducing CH<INF>4</INF> and other GHG emissions and waste
from petroleum and natural gas systems; permanently shut in and plug
wells on non-Federal land; and mitigate health effects of
CH<INF>4</INF> and other GHG emissions and legacy air pollution from
petroleum and natural gas systems in low-income and disadvantaged
communities, and support environmental restoration.
The EPA has partnered with the Department of Energy (DOE) to
administer financial assistance under the Methane Emission Reduction
Program. In 2023, DOE announced and conditionally awarded $350 million
in funds to fourteen states to measure and reduce methane emissions
from low-producing conventional wells.\4\ In February 2024, the EPA and
DOE announced intent to open a competitive funding opportunity to a
broader range of applicants to reduce and monitor emissions from the
oil and gas industry.\5\
---------------------------------------------------------------------------

\4\ U.S. Environmental Protection Agency. (2023, December 15).
Biden-Harris Administration Announces $350 Million to 14 States to
Reduce Methane Emissions from Oil and Gas Sector as Part of
Investing in America Agenda [Press Release]. <a href="https://www.epa.gov/newsreleases/biden-harris-administration-announces-350-million-14-states-reduce-methane-emissions">https://www.epa.gov/newsreleases/biden-harris-administration-announces-350-million-14-states-reduce-methane-emissions</a>. Available in the docket for this
rulemaking, Docket ID. No. EPA-HQ-OAR-2023-0234.
\5\ U.S. Environmental Protection Agency. (2024, February 9).
EPA and DOE announce intent to fund projects to reduce methane
emissions from the oil and natural gas sectors as part of President
Biden's Investing in America agenda [Press Release]. <a href="https://www.epa.gov/newsreleases/epa-and-doe-announce-intent-fund-projects-reduce-methane-emissions-oil-and-natural-gas">https://www.epa.gov/newsreleases/epa-and-doe-announce-intent-fund-projects-reduce-methane-emissions-oil-and-natural-gas</a>. Available in the
docket for this rulemaking, Docket ID. No. EPA-HQ-OAR-2023-0234.
---------------------------------------------------------------------------

The EPA and DOE are moving expeditiously to implement the
incentives for CH<INF>4</INF> mitigation and monitoring and anticipate
making announcements regarding next steps; however, as noted, those
steps are outside the scope of this rulemaking. As relevant data become
available from the funded activities, the EPA will consider how they
can be used to improve reporting under subpart W.
CAA section 136(c) provides that the Administrator shall impose and
collect a charge on CH<INF>4</INF> emissions that exceed an applicable
waste emissions threshold under CAA section 136(f) from an owner or
operator of an applicable facility that reports more than 25,000
mtCO<INF>2</INF>e per year pursuant to subpart W. CAA section 136
provides various flexibilities and exemptions relating to the waste
emissions charge. The EPA proposed to add 40 CFR part 99 to implement
the WEC in the 2024 WEC Proposal and has provided an opportunity for
public comment on that proposal; therefore, as noted, implementation of
the WEC is outside the scope of this rulemaking.
As noted earlier, CAA section 136(h) requires revisions to subpart
W. The purpose of this final action is to meet directives set forth in
CAA section 136(h) and to amend certain requirements that apply to the
general provisions, general stationary fuel combustion, and petroleum
and natural gas systems source categories of the Greenhouse Gas
Reporting Rule to improve the calculation, monitoring, and reporting of
greenhouse gas data for petroleum and natural gas systems facilities
consistent with the EPA's authority.

F. Relationship to Clean Air Act Section 111

The EPA had also identified areas where additional revisions to
part 98 would better align subpart W requirements with recently
promulgated requirements in 40 CFR part 60 and part 62, allow
facilities to use a consistent method to demonstrate compliance with
multiple EPA programs (and thereby limit burden), and improve the
emission calculations reported under subpart W. On November 15, 2021
(86 FR 63110), the EPA proposed under CAA section 111(b) standards of
performance for certain new, reconstructed, and modified oil and
natural gas sources (40 CFR part 60, subpart OOOOb) (hereafter referred
to as ``NSPS OOOOb''), as well as emissions guidelines under CAA
section 111(d) for certain existing oil and natural gas sources (40 CFR
part 60, subpart OOOOc) (hereafter referred to as ``EG OOOOc'') (the
sources affected by these two proposed subparts are collectively
referred to in this preamble as ``affected sources''). On December 6,
2022, the EPA issued a supplemental proposal to update, strengthen and
expand the standards proposed on November 15, 2021 (87 FR 74702). On
March 8, 2024, the final NSPS OOOOb and EG OOOOc rule published in the
Federal Register (89 FR 16820). While the standards in NSPS OOOOb will
directly apply to new, reconstructed, and modified sources, the final
EG OOOOc does not impose binding requirements directly on sources;
rather it contains guidelines, including presumptive standards, for
states to follow in developing, submitting, and implementing plans to
establish standards of performance to limit GHGs (in the form of
CH<INF>4</INF> limitations) from existing oil and gas sources within
their own states. If a state does not submit a plan to the EPA for
approval in response to the final emission guidelines, or if the EPA
disapproves a state's plan, then the EPA must establish a Federal plan.
In addition, a Federal plan could apply to sources located on Tribal
lands where the tribe does not request approval to develop a tribal
implementation plan similar to a state plan. Once the Administrator
approves a state plan under CAA section 111(d), the plan is codified in
40 CFR part 62 (Approval and Promulgation of State Plans for Designated
Facilities and Pollutants) within the relevant subpart for that state.
40 CFR part 62 also includes all Federal plans promulgated pursuant to
CAA section 111(d). Therefore, rather than referencing the presumptive
standards in EG OOOOc, which do not directly apply to sources, the
final amendments to subpart W reference 40 CFR part 62.
We are finalizing revisions to certain requirements in subpart W
relative to the requirements finalized for NSPS OOOOb and the
presumptive standards in EG OOOOc (which will inform the standards to
be developed and codified at 40 CFR part 62). The final amendments in
this rule will allow facilities to use a consistent method to
demonstrate compliance with multiple EPA programs. These final
standards will limit burden for subpart W facilities with affected
sources that are also required to comply with the NSPS OOOOb or a state
or Federal plan in 40 CFR part 62 implementing EG OOOOc by allowing
them to use data derived from the implementation of the NSPS OOOOb to
calculate emissions for the GHGRP rather than requiring the use of
different monitoring methods.

II. Overview and Rationale for Final Amendments to 40 CFR Part 98,
Subpart W

As discussed in section I. of this preamble, in August 2022,
Congress

[[Page 42068]]

passed, and President Biden signed, the IRA into law. Section 60113 of
the IRA amended the CAA by adding section 136, ``Methane Emissions and
Waste Reduction Incentive Program for Petroleum and Natural Gas
Systems.'' CAA section 136(h) requires that the EPA shall, within two
years of the enactment of that section of the IRA, revise the
requirements of subpart W to ensure the reporting under that subpart
and calculation of charges under CAA section 136(e) and (f) are based
on empirical data, accurately reflect the total CH<INF>4</INF>
emissions and waste emissions from the applicable facilities, and allow
owners and operators of applicable facilities to submit empirical
emissions data, in a manner prescribed by the Administrator, to
demonstrate the extent to which a charge is owed. CAA section 136(d)
defines the term ``applicable facility'' as a facility within the
following industry segments as defined in subpart W: offshore petroleum
and natural gas production, onshore petroleum and natural gas
production, onshore natural gas processing, onshore gas transmission
compression, underground natural gas storage, liquefied natural gas
storage, liquefied natural gas import and export equipment, onshore
petroleum and natural gas gathering and boosting, and onshore natural
gas transmission pipeline.
Empirical data can be defined as data that are collected by
observation and experiment. There are many forms of empirical data that
can be used to quantify GHG emissions. For purposes of this action, the
EPA interprets empirical data to mean data that are collected by
conducting observations and experiments that could be used to
accurately calculate emissions at a facility, including direct
emissions measurements, monitoring of CH<INF>4</INF> emissions (e.g.,
leak surveys) or measurement of associated parameters (e.g., flow rate,
pressure), and published data. The EPA reviewed available empirical
data methods for accuracy and appropriateness for calculating annual
unit or facility-level GHG emissions. The review included both the
evaluation of technologies and methodologies already incorporated in
subpart W for measuring and reporting annual source- and facility-level
GHG emissions and the evaluation of the accuracy of potential
alternative technologies and methodologies, with a focus on
CH<INF>4</INF> emissions due to the directive in CAA section 136(h).
The EPA also reviewed technologies and methodologies suggested by
commenters during the public comment period for the 2023 Subpart W
Proposal.
Currently, subpart W specifies emission source types to be reported
for each industry segment and provides methodologies to calculate
emissions from each source type, which are then summed to generate the
total subpart W emissions for the facility. Current calculation methods
can be grouped into five categories: (1) direct emissions measurement;
(2) combination of measurement and engineering calculations; (3)
engineering calculations; (4) leak detection and use of a leaker
emission factor; and (5) population count and population emission
factors. Subpart W emission factors (both population and leaker
emission factors) include both those developed from published empirical
data and those developed from site-specific data collected by the
reporting facility. The EPA developed the current subpart W monitoring
and reporting requirements to use the most appropriate monitoring and
calculation methods, considering both the accuracy of the emissions
calculated by the proposed method and the size of the emission source
based on the methods and data available at the time of the applicable
rule promulgation. Considering the directives set forth in CAA section
136, the EPA re-evaluated the existing methodologies to determine if
they are likely to accurately reflect CH<INF>4</INF> and waste
emissions at an individual facility, whether the existing methodologies
used empirical data, and whether the existing methodologies should be
modified or replaced or if additional optional calculation methods were
available and appropriate and should be added to meet CAA section 136
directives. Even in cases where the EPA determined that an existing
method that is not based on direct measurement or emission monitoring
provides a reasonably accurate calculation of emissions for a facility,
we also reviewed whether an appropriate direct emission measurement or
emission monitoring method could be added to subpart W, if one was not
already available, to give owners and operators the opportunity to
submit empirical data. For example, intermittent bleed pneumatic
devices are designed to vent during actuation only, but these devices
are known to often malfunction and operate incorrectly, which causes
them to release gas to the atmosphere when idle, leading to high degree
of variance in emissions from pneumatic devices between facilities (see
the technical support document Greenhouse Gas Reporting Rule: Technical
Support for Revisions and Confidentiality Determinations for Data
Elements Under the Greenhouse Gas Reporting Rule; Final Rule--Petroleum
and Natural Gas Systems, hereafter referred to as the ``final subpart W
TSD,'' available in the docket for this rulemaking, Docket ID. No. EPA-
HQ-OAR-2023-0234, for more information). For this example, the final
amendments add several new optional calculation methods to allow
reporters to account for the variability. The EPA also evaluated
whether there were gaps in the emission source types reporting
CH<INF>4</INF> emissions under subpart W and whether there were
methodologies available to calculate those emissions.
The final amendments include:
<bullet> Revisions to expand reporting to include new emission
sources, in order to accurately reflect total CH<INF>4</INF> emissions
reported to the GHGRP.
<bullet> Revisions to add emissions calculation methodologies to
expand options to allow owners and operators to submit empirical
emissions data and improve the accuracy of reported emission data,
including to expand options to allow owners and operators to submit
empirical emissions data where the EPA determined appropriate methods
were available.
<bullet> Revisions to refine existing emissions calculation
methodologies to reflect an improved understanding of emissions, to
incorporate additional empirical data or to incorporate more recent
research on GHG emissions to improve the accuracy of reported emission
data.
The EPA has also identified additional areas where revisions to
part 98 will improve the EPA's ability to verify the accuracy of
reported emissions and improve data transparency and alignment with
other EPA programs and regulations. The EPA also identified areas where
additional data or revised data elements may be necessary for future
implementation of the Waste Emissions Charge under CAA section 136. The
final revisions include:
<bullet> Revisions to report emissions and certain associated data
from emission sources at facilities in the Onshore Petroleum and
Natural Gas Production and Onshore Petroleum and Natural Gas Gathering
and Boosting industry segments at the site level or well level instead
of at the basin level, sub-basin level, or county level.
<bullet> Addition of data elements related to emissions from
plugged wells.
<bullet> Addition or clarification of throughput-related data
elements for subpart W industry segments.
<bullet> Revisions to data elements or recordkeeping where the
current

[[Page 42069]]

requirements are redundant or alternative data are more appropriate for
verification of emission data.
<bullet> Revisions that provide additional information for
reporters to better or more fully understand their compliance
obligations, revisions that emphasize the EPA's intent for requirements
that reporters appear to have previously misinterpreted to ensure that
accurate data are being collected, and editorial corrections or
harmonizing changes that will improve the public's understanding of the
rule.
Sections II.A. through II.D. of this preamble describe the above
changes in more detail and provide the EPA's rationale for the changes
included in each category. Additional details for the specific
amendments for each subpart are included in section III. of this
preamble.

A. Revisions To Address Potential Gaps in Reporting of Emissions Data
for Specific Sectors

We are finalizing several amendments to include reporting of
additional emissions or emissions sources to address potential gaps in
the total CH<INF>4</INF> emissions reported per facility to subpart W.
These final amendments ensure that the reporting under subpart W
accurately reflects the total CH<INF>4</INF> emissions and waste
emissions from applicable facilities, as directed by CAA section
136(h). In particular, based on recent analyses such as those conducted
for the annual Inventory of U.S. Greenhouse Gas Emissions and Sinks
(U.S. GHG Inventory), and data newly available from atmospheric
observations, we have become aware of potentially significant sources
of emissions for which there are no current emission estimation methods
or reporting requirements within part 98. For subpart W, we are
finalizing the addition of calculation methodologies and requirements
to report GHG emissions for several additional sources. We are adding a
new emissions source, referred to as ``other large release events,'' to
capture abnormal emission events that are not accurately accounted for
using existing methods in subpart W. This additional source covers
events such as storage wellhead leaks, well blowouts,\6\ and other
large, atypical release events and will apply to all types of
facilities subject to subpart W. Reporters will calculate GHG emissions
using measurement data or engineering estimates of the amount of gas
released and using measurement data, if available, or process knowledge
(best available data) to estimate the composition of the released gas.
We are also finalizing the addition of calculation methodologies and
requirements to report GHG emissions for several other new emission
sources, including nitrogen removal units, produced water tanks, mud
degassing, and crankcase venting. None of these sources are currently
accounted for in subpart W, and the EPA is adding them because they are
likely to have a meaningful impact on reported total facility
CH<INF>4</INF> emissions. We are also finalizing revisions to the
existing methodologies and adding new measurement-based methodologies,
consistent with section II.B. of this preamble, for determining
combustion emissions from RICE and GT to account for combustion slip,
which is not currently accounted for under the existing calculation
methodologies for combustion emissions. We are also finalizing
requirements to report existing emission sources for certain subpart W
industry segments under additional industry segments. For example, we
are requiring liquefied natural gas (LNG) import/export facilities to
begin calculating and reporting emissions from acid gas removal unit
(AGR) vents. Additional details of these types of final changes may be
found in section III. of this preamble.
---------------------------------------------------------------------------

\6\ We are finalizing as proposed the provision to define a well
blowout in 40 CFR 98.238 as a complete loss of well control for a
long duration of time resulting in an emissions release.
---------------------------------------------------------------------------

B. Revisions To Add New Emissions Calculation Methodologies or Improve
Existing Emissions Calculation Methodologies

We are finalizing several revisions to add new or revise existing
calculation methodologies to improve the accuracy of emissions data
reported to the GHGRP, incorporate additional empirical data, and to
allow owners and operators of applicable facilities to submit empirical
emissions data that appropriately demonstrate the extent to which a
charge is owed in future implementation of CAA section 136, as directed
by CAA section 136(h). Subpart W specifies emission source types to be
reported for each industry segment and provides methodologies to
calculate emissions from each source type, which are then summed to
generate the total subpart W emissions for the facility. Considering
the directives set forth in CAA section 136, the EPA re-evaluated the
existing methodologies for each source to determine if they are likely
to accurately reflect CH<INF>4</INF> and waste emissions at an
individual facility, whether the existing methodologies used empirical
data (e.g., direct emissions measurements or monitoring of
CH<INF>4</INF> emissions; measurement of associated parameters), and
whether the existing methodologies should be modified or replaced or if
new optional calculation methodologies should be added to meet CAA
section 136 directives. A summary list of the final emissions sources
to be reported with the corresponding monitoring and emissions
calculation methods is available in the final subpart W TSD, available
in the docket for this rulemaking, Docket ID. No. EPA-HQ-OAR-2023-0234.
Many sources in subpart W already have or require calculation
methodologies that use direct emission measurement, including AGR
vents, large reciprocating compressor rod packing vents, large
compressor blowdown vent valve leaks, and large compressor blowdown
vent (unit isolation valve leaks), the latter three when leakage is
detected via screening. In these final amendments, the EPA is
finalizing the addition of new calculation methodologies to allow for
the use of direct measurement, including for the calculation of
emissions from equipment leaks, combustion slip, crankcase venting,
associated gas, compressors, natural gas pneumatic devices, and
equipment leaks from components at transmission company interconnect
metering and regulating stations. The EPA is also finalizing new
calculation methodologies to allow for the development of facility-
specific emission factors for equipment leaks based on data collected
from direct measurement at the facility. The EPA is also finalizing the
option to use advanced technologies to measure data that are inputs to
emissions calculations for flares and completions and workovers with
hydraulic fracturing. These final amendments will provide owners and
operators the opportunity to submit appropriate empirical data in their
subpart W annual reports. We also reviewed whether some optional
calculation methodologies would be appropriate to allow in RY2024, so
that owners and operators would have the opportunity to submit
appropriate empirical data in line with existing subpart W. As
discussed in section IV. of this preamble, we are finalizing the
addition of a number of new optional calculation methodologies that are
relevant to existing subpart W sources effective July 15, 2024.
Similar to the 2016 amendments to align subpart W requirements with
certain requirements in 40 CFR part 60, subpart OOOOa (hereafter
referred to as ``NSPS OOOOa'') (81 FR 86500,

[[Page 42070]]

November 30, 2016), we are also finalizing revisions to certain
requirements in subpart W relative to the requirements finalized for
NSPS OOOOb and the presumptive standards in EG OOOOc (which will inform
the standards to be developed and codified at 40 CFR part 62). As in
the 2016 rule, the final amendments also allow facilities to use a
consistent method to demonstrate compliance with multiple EPA programs.
These final standards will limit burden for subpart W facilities with
affected sources that are also required to comply with the NSPS OOOOb
or a state or Federal plan in 40 CFR part 62 implementing EG OOOOc by
allowing them to use data derived from the implementation of the NSPS
OOOOb to calculate emissions for the GHGRP rather than requiring the
use of different monitoring methods. Consistent with that goal, the
final amendments to subpart W reference the final version of the
method(s) in the NSPS OOOOb and EG OOOOc. These amendments also improve
the emission calculations reported under the GHGRP by requiring the use
of facility-collected measurement or survey data to calculate emissions
where available and appropriate. Specifically, we are finalizing
amendments to the subpart W calculation methodologies for atmospheric
pressure storage tanks, flares, centrifugal and reciprocating
compressors, and equipment leak surveys related to the final NSPS OOOOb
and presumptive standards in EG OOOOc, and we are finalizing new
reporting requirements for ``other large release events'' as defined in
subpart W that reference the NSPS OOOOb and approved state plans or
applicable Federal plan in 40 CFR part 62. These final amendments are
described in sections III.B., N., O., and P. of this preamble; the
effective dates of these final amendments are discussed in section IV.
of this preamble. As reflected in section IV. of this preamble, the
provisions of these final amendments that reference the NSPS OOOOb and
approved state plans or applicable Federal plan in 40 CFR part 62 do
not apply to individual reporters unless and until their emission
sources are required to comply with either the final NSPS OOOOb or an
approved state plan or applicable Federal plan in 40 CFR part 62. In
the meantime, reporters have the option to comply with the calculation
methodologies that are required for sources subject to NSPS OOOOb or 40
CFR part 62, or they may comply instead with the applicable provisions
of subpart W that apply to sources not subject to NSPS OOOOb or 40 CFR
part 62. For example, for flare sources, subpart W facilities have the
option to comply with the flare monitoring requirements in NSPS OOOOb
even if the source is not yet subject to or will not be subject to
those provisions. For the ``other large release events'' source
category, emissions from other large release events are required to be
calculated and reported starting in Reporting Year (RY) 2025; the
requirements to calculate and report these emissions are not dependent
on whether a source is subject to NSPS OOOOb or 40 CFR part 62. The
specific changes that we are finalizing, as described in this section,
are described in detail in section III. of this preamble.
We are also finalizing several revisions to modify calculation
equations to incorporate refinements to methodologies based on an
improved understanding of emission sources. In some cases, we have
become aware of discrepancies between assumptions in the current
emission estimation methods and the processes or activities conducted
at specific facilities, where the revisions will reduce reporter
errors. In other cases, we are revising the emissions estimation
methodologies to incorporate recent studies on GHG emissions or
formation that reflect updates to scientific understanding of GHG
emissions sources. The final amendments will improve the quality and
accuracy of the data collected under the GHGRP.
We are also finalizing revisions to several existing calculation
methodologies to incorporate empirical data obtained at the facility.
Emissions can be reliably calculated for sources such as atmospheric
storage tanks and glycol dehydrators using standard engineering first
principle methods such as those available in API 4697 E&P Tanks \7\ and
GRI-GLYCalcTM \8\ when based on actual operating conditions.
Using such software also addresses safety concerns that are associated
with direct emissions measurement from these sources in certain
circumstances. For example, sometimes the temperature of the emissions
stream for glycol dehydrator vent stacks is too high for operators to
safely measure emissions. Currently these methods in subpart W allow
for use of best available data for all inputs to the model. However,
the EPA has noted that in some cases, such as with reporting of
emissions from some dehydrators, the data used to calculate emissions
are not based on actual operating conditions but instead based on
``worst-case scenarios'' or other estimates. In these final amendments,
for large glycol dehydrators and AGRs, we are requiring that certain
input parameters be based on actual measurements at the unit level in
order to ensure that emissions calculations are based on actual
operating conditions and to improve the accuracy of the reported
emissions for these sources.
---------------------------------------------------------------------------

\7\ E&P Tanks v3.0 software and the user guide (Publication
4697) formerly available from the American Petroleum Institute (API)
website.
\8\ GRI-GLYCalcTM software available from Gas
Technology Institute website (<a href="https://sales.gastechnology.org/">https://sales.gastechnology.org/</a>)
---------------------------------------------------------------------------

In order to improve the accuracy of the data collected under the
GHGRP, we are finalizing revisions to emission factors where improved
measurement data has become available or we have received additional
information from stakeholders. Some of the calculation methodologies
provided in the GHGRP rely on the use of emission factors that are
based on published empirical data. Default emission factors based on
representative empirical data can provide a reasonably accurate
estimate of facility-level emissions. The final rule includes revisions
to emission factors for a number of emission source types where we have
received or identified updated, representative measurement data.
We are finalizing updated emission factors for natural gas
pneumatic devices, equipment leaks from natural gas distribution
sources (including pipeline mains and services, below grade
transmission-distribution transfer stations, and below grade metering-
regulating stations) and equipment at onshore petroleum and natural gas
production and onshore petroleum and natural gas gathering and boosting
facilities, and compressors at onshore petroleum and natural gas
production and onshore petroleum and natural gas gathering and boosting
facilities in subpart W. The revised emission factors are more
representative of GHG emissions sources and will improve the overall
accuracy of the emission data collected under the GHGRP. Additional
details of these types of final revisions may be found in section III.
of this preamble.
As noted in section II.A. of this preamble, we are adding a new
emissions source, referred to as ``other large release events,'' to
capture abnormal emission events that are not accurately accounted for
using existing methods in subpart W. Under these provisions in this
final rule, the EPA is also finalizing the inclusion of emissions from
other large emissions events and super-emitters in the subpart W
reporting program. This addition will directly address the concerns
identified by a multitude of studies about the

[[Page 42071]]

contribution of super-emitters to total emissions and help to ensure
the completeness and accuracy of emissions reporting data. Advanced
measurement approaches that have demonstrated their ability to detect,
attribute the source at least to site-level, and accurately quantify
emission rates of such events are a central feature of the finalized
changes. Some advanced measurement approaches have a demonstrated
ability to provide data useful for quantifying emissions from very
large, distinct emission events, such as production well blowouts. In
the U.S. GHG Inventory, the EPA has already incorporated emissions
estimates developed from such approaches to calculate emissions from
well blowouts.\9\ In this final rule, we are requiring facilities to
consider notifications of super-emitter emissions event under the
super-emitter provisions of NSPS OOOO/OOOOa/OOOOb at 40 CFR 60.5371,
60.5371a, and 60.5371b or the applicable approved state plan or
applicable Federal plan and calculate the associated emissions when
they exceed the final threshold of 100 kg/hr CH4 if they are not
already appropriately accounted for under another source category in
subpart W. We expect that under the final methodology for other large
release events, data from some advanced measurement approaches,
including data derived from equipment leak and fugitive emissions
monitoring using advanced screening methods conducted under NSPS OOOOb
or the applicable approved state plan or applicable Federal plan in 40
CFR part 62, in combination with other empirical data, could be used by
reporters to calculate the total emissions from these events and/or
estimate duration of such an event.
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\9\ U.S. EPA. Inventory of U.S. Greenhouse Gas Emissions and
Sinks 1990-2020: Updates for Anomalous Events including Well Blowout
and Well Release Emissions. April 2022. Available at <a href="https://www.epa.gov/system/files/documents/2022-04/2022_ghgi_update_-_blowouts.pdf">https://www.epa.gov/system/files/documents/2022-04/2022_ghgi_update_-_blowouts.pdf</a> and in the docket for this rulemaking, Docket ID. No.
EPA-HQ-OAR-2023-0234.
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The EPA received numerous comments requesting that the EPA allow
for the use of advanced technologies to quantify emissions from other
emission sources in subpart W beyond ``other large release events.'' In
response, we reviewed advanced measurement approaches that utilize
information from satellite, aerial, drone, vehicle, and stationary
platforms to detect and/or quantify methane emissions from petroleum
and natural gas systems at different spatial and temporal scales for
their potential use in estimating emissions of specific sources for the
purposes of subpart W reporting. Advanced technologies have been a
focus for research and emission monitoring strategies, and several
technologies have progressed in recent years to provide valuable CH4
emission data. The spatial and temporal resolution of emission
estimates varies widely, however, depending on the technology and
platform.
Two general categories of advanced technologies were evaluated for
their potential use in subpart W: remote sensing (e.g., satellite,
aerial) and continuous monitoring systems, which typically use gas
sensors and/or imaging coupled with proprietary algorithms to detect
emissions and/or provide emission rates. Remote sensing approaches
typically use aerial or satellite-deployed infrared spectroscopy to
survey areas for methane emission plumes. For remote sensing
technologies, the size of the area monitored is typically inversely
related to the detection levels. Satellite remote sensing technologies
are deployed at altitudes of 400 to 800 kilometers and currently have
CH4 detection limits of approximately 50 to 25,000 kilograms per hour
(kg/hr),\10\ and high altitude remote sensing (by airplane) measure at
altitudes of 168 to 12,000 meters (m) with current CH4 detection limits
of approximately 1 to 50 kg/hr.\11\ We find that existing remote
sensing approaches are suitable to supplement the other requirements
for periodic measurement and calculation of annual emissions for large
discrete events, as they are capable of having suitable detection
limits for the identification of the presence of large anomalous
events. However, our assessment at this time is that existing remote
sensing approaches currently are not able to appropriately estimate
annual emissions from other sources under subpart W. Most remote
sensing measurements are taken over limited durations (a few minutes to
a few hours) typically during the daylight hours and limited to times
when specific meteorological conditions exist (e.g., no cloud cover for
satellites; specific atmospheric stability and wind speed ranges for
aerial measurements). These direct measurement data taken at a
particular moment in time may not be representative of the annual CH4
emissions from the facility, given that many emissions are episodic. If
emissions are found during a limited duration sampling, that does not
necessarily mean they are present for the entire year. And if emissions
are not found during a limited duration sampling, that does not
necessarily mean significant emissions are not occurring at other
times. Extrapolating from limited measurements to an entire year
therefore creates risk of either over or under counting actual
emissions.
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\10\ See GHGSat. GHGSat Media Kit. (2021). Available at <a href="https://www.ghgsat.com/upload/misc/GHGSAT_MEDIAKIT_2021.pdf">https://www.ghgsat.com/upload/misc/GHGSAT_MEDIAKIT_2021.pdf</a>; Pandey, S., et
al. ``Satellite observations reveal extreme methane leakage from a
natural gas well blowout.'' Proceedings of the National Academy of
Sciences, Vol. 116, no. 52. Pp. 26376-26381, December 16, 2019,
available at <a href="https://doi.org/10.1073/pnas.1908712116">https://doi.org/10.1073/pnas.1908712116</a>; Jacob, D.J.,
et al. ``Quantifying methane emissions from the global scale down to
point sources using satellite observations of atmospheric methane.''
Atmospheric Chemistry and Physics, Vol. 22, Issue 14, pp. 9617-9646,
July 29, 2022, available at <a href="https://doi.org/10.5194/acp-22-9617-2022">https://doi.org/10.5194/acp-22-9617-2022</a>; Anderson, V., et al. ``Technological opportunities for sensing
of the health effects of weather and climate change: a state-of-the-
art-review.'' International Journal of Biometeorology, Vol. 65,
Issue 6, pp. 779-803, January 11, 2021, available at <a href="https://doi.org/10.1007/s00484-020-02063-z">https://doi.org/10.1007/s00484-020-02063-z</a>. The documents are also available
in the docket for this rulemaking, Docket ID. No. EPA-HQ-OAR-2023-
0234.
\11\ See Conrad, B.M., Tyner, D.R. & Johnson, M.R. ``Robust
probabilities of detection and quantification uncertainty for aerial
methane detection: Examples for three airborne technologies.''
Remote Sensing of Environment, Vol. 288, p. 113499, available at
<a href="https://doi.org/10.1016/j.rse.2023.113499">https://doi.org/10.1016/j.rse.2023.113499</a>. 2023; Duren, R.M., et al.
``California's methane super-emitters.'' Nature, Vol. 575, Issue
7781, pp. 180-184, available at <a href="https://doi.org/10.1038/s41586-019-1720-3">https://doi.org/10.1038/s41586-019-1720-3</a>. 2019; Thorpe, A.K., et al. ``Airborne DOAS retrievals of
methane, carbon dioxide, and water vapor concentrations at high
spatial resolution: application to AVIRIS-NG.'' Atmos. Meas. Tech.,
10, 3833-3850, available at <a href="https://doi.org/10.5194/amt-10-3833-2017">https://doi.org/10.5194/amt-10-3833-2017</a>. 2017; Staebell, C., et al. ``Spectral calibration of the
MethaneAIR instrument.'' Atmospheric Measurement Techniques, Vol.
14, Issue 5, pp. 3737-3753, available at <a href="https://doi.org/10.5194/amt-14-3737-2021">https://doi.org/10.5194/amt-14-3737-2021</a>. 2021. The documents are also available in the
docket for this rulemaking, Docket ID. No. EPA-HQ-OAR-2023-0234.
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Additionally, while advanced measurement methods based on remote
sensing, including satellite and aerial methods, have proven their
ability to identify and measure large emissions events, their detection
limits may be too high to detect emissions from sources with relatively
low emission rates.\12\ The data provided by some of these technologies
are at large spatial scales, with limited ability to disaggregate to
the facility- or emission source-level and have high minimum detection
limits. So while these technologies can provide very useful information
about emissions during snapshots in time, and thus help to greatly
improve the completeness and accuracy of emission reporting, with the
current state of these technologies they generally cannot by themselves
estimate annual emissions.

[[Page 42072]]

Therefore, this rule finalizes allowing the use of these advanced
measurement methods based on remote sensing to supplement the other
requirements for periodic measurement and calculation of annual
emissions for other large release events, as described in section
III.B. of this preamble.
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\12\ Duren, et al. ``California's methane super-emitters.''
Nature, Vol. 575, Issue 7781, pp. 180-184, 2019. Available at
<a href="https://doi.org/10.1038/s41586-019-1720-3">https://doi.org/10.1038/s41586-019-1720-3</a> and in the docket for this
rulemaking, Docket ID. No. EPA-HQ-OAR-2023-0234.
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Continuous monitoring systems, which typically use one or more
stationary sensors and/or imagers located on or near sites to
frequently detect and/or quantify anomalous emissions, can have
significant value for detecting anomalous emissions but are less
suitable for the annual quantification that is required for purposes of
the Greenhouse Gas Reporting Program and satisfying Congress's
directive in the Inflation Reduction Act. Although these systems may
continuously collect methane concentration data, emissions data from
monitored sites are not typically continuous because methane emission
plumes may not reach sensors or visual images may not detect plumes
under certain meteorological and operational conditions. Recent studies
evaluating the performance of several continuous monitors have reported
that these systems can provide valuable data for detecting anomalous
emissions (and generally faster than survey methods) and determining
event duration, but typically have high uncertainty in quantifying
total emissions.\13\ Therefore, we determined that continuous
monitoring systems currently are not suitable for quantifying emissions
for subpart W reporting on their own but may provide data on the
duration of large release events. Further discussion of our review of
advanced technologies is available in the final subpart W TSD,
available in the docket for this rulemaking.
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\13\ See, e.g., Bell, C., et al. ``Performance of Continuous
Emission Monitoring Solutions under a Single-Blind Controlled
Testing Protocol.'' Environ. Sci. Technol. 2023, 57, 14, 5794-5805.
Published March 28, 2023. <a href="https://doi.org/10.1021/acs.est.2c09235">https://doi.org/10.1021/acs.est.2c09235</a>.
Available in the docket for this rulemaking, Docket ID. No. EPA-HQ-
OAR-2023-0234.
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Based on our review, we are finalizing the use of advanced
measurement data, including both remote sensing technologies and
continuous monitoring systems, to help identify and quantify super-
emitter and other large emissions events. Commenters also requested
that the EPA allow for the adoption of advanced technologies without
having to go through a new rulemaking process, similar to the
technology verification programs developed under the NSPS OOOOb and EG
OOOOc even though many commenters acknowledged that with the current
state of advanced technologies, it is not possible to accurately
quantify annual emissions at the individual source level, particularly
at low emission rates as would be needed to accurately quantify many
subpart W sources. However, for reasons discussed below, this final
rule does not include a general provision to incorporate the use of
advanced measurement approaches at this time except in certain cases,
such as large release events. It is worth noting that the NSPS OOOOb
and EG OOOOc (and the technologies that are verified under that
program), are focused on detecting leaks or identifying anomalous
emissions that exceed certain action levels, which is more
straightforward than accurately quantifying source emission rates over
annual time periods. Furthermore, the EPA is not aware of a
standardized protocol to accurately extrapolate from either continuous
or discrete remote sensing measurement data to an annual, facility-
level emission total. At this point in time, there are still many
outstanding research questions associated with how best to combine
advanced measurement data (sometimes called ``top-down'' methods) with
bottom-up methods in a way that avoids double counting of emissions,
including how frequently measurements would need to be conducted to be
considered reliable or representative of annual emissions for reporting
purposes, and what emissions simulation modeling would be necessary to
accurately estimate annual emissions. As described previously in this
section, the different types of measurement data have a wide range of
detection limits and spatial resolution, which makes converting point
estimates to an annual emission estimate as required by and necessary
for the purposes of the GHGRP subpart W difficult. Therefore, this
final rule does not include a general provision to incorporate the use
of advanced measurement approaches for sources at this time and instead
specifically allows its use in certain appropriate cases, including for
other large release events, due to the limitations described earlier in
this section.
The EPA notes that advanced measurement approaches are rapidly
evolving, and expects that these approaches will continue to improve
over time. Advanced measurement approaches are currently being used to
generate a range of valuable information on emissions sources in the
oil and natural gas sector and have great promise for playing a greater
role in subpart W emissions reporting as experience with using them to
quantify emissions grows. We will continue to closely monitor
developments in advanced monitoring technologies and measurement
approaches and engage with experts and stakeholders on how they can be
used in subpart W reporting.
As these measurement approaches continue to develop, the EPA will,
as appropriate, undertake notice-and-comment rulemaking to determine
under what circumstances these approaches can be used for subpart W
reporting of methane emissions, and how subpart W reporters can use
these approaches to quantify annual emissions based on advanced
technologies and the rapid evolution of such technologies. Given the
wide variety of advanced measurement approaches and the methodological
challenges described above, the EPA believes it is necessary to provide
adequate notice and opportunity for comment on the use of advanced
measurement approaches in order to incorporate such technologies into
subpart W. We believe that such an approach is consistent with the
historic implementation of the Greenhouse Gas Reporting Rule which has
been revised over time to incorporate the latest data, updated
scientific knowledge and additional measurement methods. In advance of
such a rulemaking, the EPA intends to solicit input on the use of
advanced measurement data and methods in subpart W through a request
for information, workshop or white paper. We further intend to evaluate
for potential future subpart W updates whether there are measurement
approaches that could be used to estimate annual emissions for any
source categories under subpart W or for facility-level emissions, what
level of accuracy should be required for such use, and whether the
development of standard protocols for estimating emissions from
advanced measurement (either by the EPA or third-party organizations)
could help inform this determination. We also intend to evaluate
whether there are other appropriate uses of this data for the purposes
of reporting under subpart W of the GHGRP, including for what types of
emission sources and emission events and what specific measurement
approaches use may be appropriate, especially in terms of spatial scale
and minimum detection limits. We will also continue to evaluate how
frequently measurements would need to be conducted to be considered
reliable or representative of annual emissions for reporting purposes.

[[Page 42073]]

C. Revisions to Reporting Requirements To Improve Verification and
Transparency of the Data Collected

The EPA is finalizing several revisions to existing reporting
requirements to collect data that will improve verification of reported
data and improve the transparency of the data collected. Data reported
under the GHGRP undergo comprehensive verification review. This process
identifies errors that result in the over- or under- statement of
emissions that are reported from individual facilities and leads to
their correction. As such, amendments that improve the verification
process are supportive of the directive under CAA section 136(h) to
ensure that reporting under subpart W accurately reflects total methane
emissions. Additionally, such revisions will better enable the EPA to
obtain data that is of sufficient quality and granularity that it can
be used to support a range of future climate change policies and
regulations under the CAA, including but not limited to information
relevant to carrying out CAA section 136, provisions involving
research, evaluating and setting standards, endangerment
determinations, or informing EPA non-regulatory programs under the CAA.
The final revisions include changes to the level of reporting of
aggregated emissions and activity data that will improve the process of
emissions verification and the transparency and granularity of the
data. For example, we are finalizing requirements for Onshore Petroleum
and Natural Gas Production and Onshore Petroleum and Natural Gas
Gathering and Boosting industry segment reporters to report emissions
and associated activity data at the site level or well level instead of
at the basin level, sub-basin level, or county level.
We are also finalizing additions or revisions to reporting
requirements to better characterize the emissions for several emission
sources. For example, we are collecting additional information from
facilities with liquids unloadings to differentiate between manual and
automated unloadings.
Other final revisions to the rule include changes that will better
align reporting with the calculation methods in the rule. For example,
we are finalizing revisions to reporting requirements related to
atmospheric pressure fixed roof storage tanks receiving hydrocarbon
liquids that follow the methodology specified in 40 CFR 98.233(j)(3)
and equation W-15. The current calculation methodology uses population
emission factors and the count of applicable separators, wells, or non-
separator equipment to determine the annual total volumetric GHG
emissions at standard conditions. The associated reporting requirements
in existing 40 CFR 98.236(j)(2)(i)(E) and (F) require reporters to
delineate the counts used in equation W-15. The current reporting
requirements are inadvertently inconsistent with the language used in
the calculation methodology and are seemingly not inclusive of all
equipment to be included. Therefore, we are revising the reporting
requirements to better align the requirement with the calculation
methodology and streamline the requirements for all facilities
reporting atmospheric storage tanks emissions using the methodology in
40 CFR 98.233(j)(3).
In some cases, we are finalizing the removal of duplicative
reporting elements within or across GHGRP subparts to reduce data
inconsistencies and reporting errors. For example, we are eliminating
duplicative reporting between subpart NN (Suppliers of Natural Gas and
Natural Gas Liquids) and subpart W where both subparts require similar
data elements to be reported to the electronic Greenhouse Gas Reporting
Tool (e-GGRT). For fractionators of natural gas liquids (NGLs), both
subpart W (under the Onshore Natural Gas Processing segment) and
subpart NN require reporting of the volume of natural gas received and
the volume of NGLs received. For Local Distribution Companies (LDCs),
both subpart W (under the Natural Gas Distribution segment) and subpart
NN require reporting of the volume of natural gas received, volume
placed into and out of storage each year, and volume transferred to
other LDCs or to a pipeline as well as some other duplicative data. The
final amendments limit the reporting of these data elements to
facilities that do not report under subpart NN, thus removing the
duplicative requirements from subpart W for facilities that report to
both subparts. These data elements are not the throughputs that are
proposed to be used for WEC calculations; see section III.U. of this
preamble and the 2024 WEC Proposal for more information on those
throughputs. This revision will improve the EPA's ability to verify the
reported data across subparts.

D. Technical Amendments, Clarifications, and Corrections

We are finalizing other technical amendments, corrections, and
clarifications that will improve understanding of the rule. These
revisions primarily include revisions of requirements to better reflect
the EPA's intent or editorial changes. Some of these changes result
from consideration of questions raised by reporters through the GHGRP
Help Desk or e-GGRT. In particular, we are finalizing amendments for
several source types that will emphasize the original intent of certain
rule requirements, such as reported data elements that have been
misinterpreted by reporters. In several cases, the misinterpretation of
these provisions may have resulted in reporting that is inconsistent
with the rule requirements. The final clarifications will increase the
likelihood that reporters will submit accurate reports the first time.
For example, the EPA is finalizing revisions to the definition of
variable ``Tt'' in existing equation W-1 (final equation W-1B) in 40
CFR 98.233 and the corresponding reporting requirements in final 40 CFR
98.236(b)(4)(ii)(D)(4), (b)(5)(i)(C)(2), and (b)(6)(ii) to use the term
``in service (i.e., supplied with natural gas)'' rather than
``operational'' or ``operating.'' This revision emphasizes the EPA's
intent that the average number of hours used in equation W-1 (final
equation W-1B) should be the number of hours that the devices of a
particular type are in service (i.e., the devices are receiving a
measurement signal and connected to a natural gas supply that is
capable of actuating a valve or other device as needed). These final
clarifications and corrections will also reduce the burden associated
with reporting, data verification, and EPA review. Additional details
of these types of final changes are discussed in section III. of this
preamble.
We are also finalizing revisions to applicability provisions for
certain industry segments and applicable calculation methods. For
example, we are revising the definition of the Onshore Natural Gas
Processing industry segment to remove the gas throughput threshold so
that the applicable industry segment and calculation methods are
defined from the beginning of the year. The current definition of the
Onshore Natural Gas Processing industry segment includes processing
plants that fractionate gas liquids and processing plants that do not
fractionate gas liquids but have an annual average throughput of 25
million standard cubic feet (MMscf) per day or greater. Processing
plants that do not fractionate gas liquids and have an annual average
throughput of less than 25 MMscf per day may be part of a facility in
the Onshore Petroleum and Natural Gas Gathering and Boosting

[[Page 42074]]

industry segment. Processing plants that do not fractionate gas liquids
and generally operate close to the 25 MMscf per day threshold do not
know until the end of the year whether they will be above or below the
threshold, so they must be prepared to report under whichever industry
segment is ultimately applicable. Therefore, as discussed in greater
detail in section III.A.3. of this preamble, we are revising the
Onshore Natural Gas Processing industry segment definition in 40 CFR
98.230(a)(3) to remove the 25 MMscf per day threshold and more closely
align subpart W with the definitions of natural gas processing in other
rules (e.g., NSPS OOOOa). This revision to the Onshore Natural Gas
Processing industry segment definition will better define whether a
processing plant is classified as an Onshore Natural Gas Processing
facility or as part of an Onshore Petroleum and Natural Gas Gathering
and Boosting facility, and the applicable segment will no longer have
the potential to change from one year to the next simply based on the
facility throughput.
Additional details of these types of final changes may be found in
section III. of this preamble.
Other minor changes being finalized include correction edits to fix
typos, minor clarifications such as adding a missing word, harmonizing
changes to match other final revisions, reordering of paragraphs so
that a larger number of paragraphs need not be renumbered, and others
as reflected in the redline regulatory text in the docket for this
rulemaking (Docket ID. No. EPA-HQ-OAR-2023-0234).

III. Final Amendments to Part 98 and Summary of Comments and Responses

This section summarizes the specific substantive final amendments
for subpart W (as well as subparts A and C), as generally described in
section II. of this preamble. Major changes to the final rule as
compared to the proposed revisions are identified in this section. The
summary of the amendments in each section is followed by a summary of
the major comments on those amendments and the EPA's responses to those
comments. The document Summary of Public Comments and Responses for
2024 Final Revisions and Confidentiality Determinations for Petroleum
and Natural Gas Systems under the Greenhouse Gas Reporting Rule,
available in the docket to this rulemaking (Docket ID. No. EPA-HQ-OAR-
2023-0234), contains the full text of all the comments on the 2023
Subpart W Proposal, including the major comments responded to in this
preamble. All final amendments, including minor corrections and
clarifications, are also reflected in the final redline regulatory text
in the docket for this rulemaking (Docket ID. No. EPA-HQ-OAR-2023-
0234).
Section III.A of this preamble describes amendments that affect
reporting responsibility or applicability. Sections III.B through III.U
of this preamble describe technical amendments that affect specific
source types or industry segments. Section III.V of this preamble lists
miscellaneous technical corrections and clarifications.

A. General and Applicability Amendments

1. Ownership Transfer
a. Summary of Final Amendments
We are finalizing amendments to specific provisions to subpart A
that will apply in lieu of existing 40 CFR 98.4(h) for changes in the
owner or operator of a facility in the four industry segments in
subpart W (Petroleum and Natural Gas Systems) that have unique
definitions of facility.\14\ The final provisions specify which owner
or operator is responsible for current and future reporting years'
reports following a change in owner or operator for specific industry
segments in subpart W, beginning with RY2025 reports. As described in
more detail in this section, the provisions vary based upon whether the
selling owner or operator will retain any emission sources, the number
of purchasing owner(s) or operator(s), and whether the purchasing
owner(s) or operator(s) already report to the GHGRP in the same
industry segment and basin or state (as applicable). These final
revisions are expected to improve data quality as described in section
II.C of this preamble by ensuring that the EPA receives a more complete
data set, and they are also expected to improve understanding of the
rule, as described in section II.D. of this preamble.
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\14\ Specifically the Onshore Petroleum and Natural Gas
Production, Natural Gas Distribution, Onshore Petroleum and Natural
Gas Gathering and Boosting, and Onshore Natural Gas Transmission
Pipeline industry segments.
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In this final rule, the EPA is not taking final action at this time
on the proposed amendments related to responsibility for revisions to
annual reports for reporting years prior to owner or operator changes
for specific industry segments in subpart W. In consideration of the
relationship between revisions to annual reports for prior years and
proposed implementation requirements in the 2024 WEC Proposal, the EPA
intends to consider those proposed revisions in coordination with the
2024 WEC rulemaking and take action, if finalized, on these
requirements at the same time.
As discussed in the 2023 Subpart W proposal, we expect that
transactions fall into one of four general categories, and we are
finalizing provisions that specify the current and future reporting
years' responsibilities for reporting for each of those general
categories. First, to address transactions where an entire facility is
sold to a single purchaser and the purchasing owner or operator does
not already report to the GHGRP in that industry segment (and basin or
state, as applicable), we are finalizing as proposed that the
facility's certificate of representation must be updated within 90 days
of the transaction to reflect the new owner or operator. We are
finalizing as proposed the requirement that the purchasing owner or
operator will be responsible for submitting the facility's annual
report for the entire reporting year in which the acquisition occurred
(i.e., the owner or operator as of December 31 will be responsible for
the report for that entire reporting year) and each reporting year
thereafter. In addition, because the definitions of facility for each
of these segments encompass all of the emission sources in a particular
geographic area (i.e., basin, state, or nation), the purchasing owner
or operator must include any other applicable emission sources already
owned by that purchasing owner or operator in the same geographic area
as part of the purchased facility beginning with the reporting year in
which the acquisition occurred. We proposed, but are not taking final
action at this time on, a requirement that the purchasing owner or
operator would also become responsible for responding to EPA questions
and making any necessary revisions to annual GHG reports for reporting
years prior to the reporting year in which the acquisition occurred. As
noted above, we intend to consider those proposed revisions in
coordination with the 2024 WEC rulemaking and take action on these
requirements, if finalized, at the same time.
Second, to address transactions where the entire facility is sold
to a single purchaser and the purchasing owner or operator already
reports to the GHGRP in that industry segment (and basin or state, as
applicable), we are finalizing as proposed that the purchasing owner or
operator will merge the acquired facility with their existing facility
for purposes of reporting under the GHGRP. In other words, the acquired
emission sources will become part of the purchaser's existing facility
under the GHGRP and emissions for the combined facility will

[[Page 42075]]

be reported under the e-GGRT identifier for the purchaser's existing
facility. We are finalizing as proposed a requirement that the
purchaser will then follow the provisions of 40 CFR 98.2(i)(6) to
notify the EPA that the purchased facility has merged with their
existing facility and will provide the e-GGRT identifier for the
merged, or reconstituted, facility. Finally, the purchaser will be
responsible for submitting the merged facility's annual report for the
entire reporting year in which the acquisition occurred (i.e., the
owner or operator as of December 31 will be responsible for the report
for that entire reporting year) and each reporting year thereafter. We
proposed, but are not taking final action at this time on, a
requirement that the purchasing owner or operator would also become
responsible for responding to EPA questions and making any necessary
revisions to annual GHG reports for the purchased facility for
reporting years prior to the reporting year in which the acquisition
occurred. Similarly, we are not taking final action at this time on a
requirement that the acquired facility's certificate of representation
be updated within 90 days of the transaction to reflect the new owner
or operator. As noted above, we intend to consider those proposed
revisions in coordination with the 2024 WEC rulemaking and take action
on these requirements, if finalized, at the same time.
Third, to address transactions where the selling owner or operator
retains some of the emission sources and sells the other emission
sources of the seller's facility to one or more purchasing owners or
operators, we are finalizing as proposed that the selling owner or
operator will continue to report under subpart W for the retained
emission sources unless and until that facility meets one of the
criteria in 40 CFR 98.2(i) and complies with those provisions. Each
purchasing owner or operator that does not already report to the GHGRP
in that industry segment (and basin or state, as applicable) will begin
reporting as a new facility for the entire reporting year beginning
with the reporting year in which the acquisition occurred. The new
facility will include the acquired applicable emission sources as well
as any previously owned applicable emission sources. We note that,
under the provisions that are being finalized as proposed, because the
new facility will contain acquired emission sources that were part of a
facility that was subject to the requirements of part 98 and already
reporting to the GHGRP, the purchasing owner or operator will follow
the provisions of 40 CFR 98.2(i) and continue to report unless and
until one of the criteria in 40 CFR 98.2(i) are met, instead of
comparing the facility's emissions to the reporting threshold in 40 CFR
98.231(a) to determine if they should begin reporting. Each purchasing
owner or operator that already reports to the GHGRP in that industry
segment (and basin or state, as applicable) will add the acquired
applicable emission sources to their existing facility for purposes of
reporting under subpart W and will be responsible for submitting the
annual report for their entire facility, including the acquired
emission sources, for the entire reporting year beginning with the
reporting year in which the acquisition occurred.
Fourth, to address transactions where the selling owner or operator
does not retain any of the emission sources and sells all of the
facility's emission sources to more than one purchasing owner or
operator, we are finalizing as proposed that the selling owner or
operator for the existing facility will notify the EPA within 90 days
of the transaction that all of the facility's emission sources were
acquired by multiple purchasers. After consideration of comment, we are
revising from proposal use of the term ``current owner or operator'' to
instead read ``prior owner or operator'' in the final amendments. The
purchasing owners or operators will begin submitting annual reports for
the acquired emission sources for the reporting year in which the
acquisition occurred following the same provisions as in the third
scenario. In other words, each owner or operator will either begin
reporting their acquired applicable emission sources as a new facility
or add the acquired applicable emission sources to their existing
facility.
Finally, for the third and fourth types of transactions, we
proposed but are not taking final action at this time on a set of
provisions to clarify responsibility for annual GHG reports for
reporting years prior to the reporting year in which the acquisition
occurred. As noted above, we intend to consider those proposed
revisions in coordination with the 2024 WEC rulemaking and take action
on these requirements, if finalized, at the same time.
We proposed that as part of the third and fourth types of ownership
change described previously in this section, the selling owner or
operator and each purchasing owner or operator would be required to
select by an agreement binding on the owners and operators (following
the procedures specified in 40 CFR 98.4(b)) a ``historic reporting
representative'' that would be responsible for revisions to annual GHG
reports for previous reporting years within 90 days of the transaction.
The proposed historic reporting representative for each facility would
respond to any EPA questions regarding GHG reports for previous
reporting years and would submit corrected versions of GHG reports for
previous reporting years as needed. As noted above, we are not taking
final action at this time on the proposed provisions for past reporting
years after a transaction, including the proposed historic reporting
representative provisions, and intend to consider those proposed
revisions in coordination with the 2024 WEC rulemaking and take action
on these requirements, if finalized, at the same time.
We are finalizing as proposed amendments to 40 CFR 98.2(i)(3), the
current provision that allows an owner or operator to discontinue
reporting to the GHGRP when all applicable processes and operations
cease to operate. Through correspondence with reporters via e-GGRT, we
are aware that there have been times that an owner or operator divested
a facility and was therefore no longer required to report the emissions
from that facility, but even though the facility changed owners and did
not cease operating, the selling owner or operator chose the provisions
of existing 40 CFR 98.2(i)(3) as the reason they were ceasing to report
because none of the other options fit the situation. The EPA's intent
is that this reason for no longer reporting to the GHGRP should only be
used in cases in which all the applicable sources permanently ceased
operation. Therefore, we are finalizing as proposed amendments to
clarify that 40 CFR 98.2(i)(3) will not apply when there is a change in
the owner or operator for facilities in these four industry segments,
unless the changes result in permanent cessation of all applicable
processes and operations. We are finalizing a new paragraph at 40 CFR
98.2(i)(7) to specify that a selling owner or operator that completes
the fourth transaction type discussed above (i.e., all the emission
sources from the reporting facility are sold to multiple owners or
operators within the same reporting year) may discontinue reporting for
the facility for the reporting years following the year in which the
transactions occurred provided that notification is provided to the
Administrator. Prior to the addition of this new paragraph, there was
not a reason provided in the regulations to discontinue reporting under
40 CFR 98.2(i) that applied to this situation.

[[Page 42076]]

b. Summary of Comments and Responses
This section summarizes the major comments and responses related to
the proposed amendments to ownership transfers.
Comment: Multiple commenters suggested that the EPA amend the
reporting and ownership transfer provisions such that owners and
operators would only be responsible for reporting emissions that
occurred during their period of ownership or operation and that new
owners should not be responsible for methane taxes generated by the
prior owner. Commenters identified the WEC as a reason to reconsider
reporting responsibilities. Under the structure suggested by
commenters, in the case of transfer of a facility during a reporting
year there would be a separate report submitted by each owner or
operator. One commenter asserted that multiple reports from multiple
reporters would be necessary to ensure accurate reporting as required
by CAA section 136(h). The commenter further stated the proposed
requirements for consolidated reporting by one owner would constitute a
deviation from the IRA and increase the possibility of inaccurate
reporting. Commenters further stated that new owners or operators
should not be responsible for revisions to reports prior to their
effective date of acquisition.
Response: The EPA is not taking action in this final rule on the
existing subpart W requirement that the owner or operator of a facility
as of December 31 is responsible for submitting a report including the
entire calendar year's emissions by March 31 of the following calendar
year.
The EPA disagrees with the assertion that multiple reports and
reporters will be necessary to ensure accurate emissions reporting. The
amendments affecting ownership transfers do not impact the existing
requirement that the owner or operator of a facility as of December 31
is responsible for submitting a report by March 31 of the following
calendar year. The commenter did not identify specific issues with this
current structure leading to the inaccurate reporting of emissions
data. Rather than ensure accurate reporting as the commenter claimed,
the EPA believes that preparation and submission of multiple reports by
different entities related to the same emission sources would lead to
duplicative burden and raise the potential for inconsistencies in
reported data. The EPA therefore believes it would be neither practical
nor supportive of the CAA section 136(h) directive to ensure the
accuracy of reported data for the reporting responsibility for a single
facility to be duplicated in multiple reports among multiple owners and
operators. For these same reasons, the EPA disagrees with commenters
that this implementation deviates from the IRA.
With respect to the assertion that the existing reporting structure
makes the new owner or operator responsible for the methane taxes
generated by the prior owner, the EPA notes that the comment concerns
the timing of ownership changes and the impact upon WEC obligations and
that the EPA considers these to be outside the scope of this subpart W
rulemaking and they are addressed in the 2024 WEC Proposal. With
respect to the assertion that retaining this reporting structure would
constitute ``deviating from the IRA,'' the EPA notes that full calendar
year reporting under subpart W was required for the facility as of
December 31 at the time of signature of the IRA. The EPA finds no
indication in the text of CAA section 136 suggesting that revision to
this structure was mandated or intended.
Comment: Multiple commenters opposed the proposed implementation of
a historic reporting representative. Some commenters suggested that a
historic reporting representative was unnecessary as owners and
operators should only be responsible for emissions that occurred during
their time of ownership or operation, although one commenter stated
that the historic reporting representative was preferable to placing
the responsibility for historic reporting on the new owner or operator.
Some commenters stated that there is no certainty that a historic
reporting representative would have access to the data and information
needed to accurately respond to questions regarding prior year reports.
One commenter suggested that in place of a historic reporting
representative, the EPA implement a data freeze after one year from the
original submittal date of a report.
One commenter supported the proposed use of a contractually
determined reporting representative but asserted that some transactions
may be too complicated to fit within the four categories of
transactions that were proposed.
Response: The EPA is not finalizing the proposed requirements
related to designation of a historic reporting representation at this
time. To better facilitate implementation of the WEC under CAA section
136(c) and alignment with the final WEC rule, the EPA intends to
finalize requirements related to the responsibility for historic
reporting as part of a future rulemaking.
The EPA acknowledges that commenters expressed concern regarding
whether the individual responsible for historic reporting would have
access to data and information needed to accurately respond to
questions regarding GHG reporting, including potentially confidential
or sensitive information and correspondence. Similarly, in past
correspondence regarding the GHGRP, facility representatives have
expressed concern that providing an individual access to the data and
information needed for historic reporting would also provide that
individual access to potentially confidential or sensitive information
and correspondence submitted to e-GGRT in future year reporting. The
EPA notes that the EPA is considering updating e-GGRT to implement
these proposed provisions if finalized in a future rulemaking. For
example, one potential update could be that the individual that an
owner or operator selects to be responsible for historic reporting
would be provided access to a facility's reports and correspondence
limited to the reporting years for which that owner or operator was
responsible for reporting for the facility. This potential
implementation would prevent the individual responsible for historic
reporting from accessing potentially confidential or sensitive
information and correspondence for reporting years following an
ownership transaction.
The EPA is not implementing a data freeze for subpart W reporting
as part of this final rulemaking. The EPA recognizes that resubmissions
for historic reporting years have the potential to be complex due to
changes in facility owners or operators, and further, that because
assessment of the WEC is based upon subpart W reporting these revisions
may carry financial obligations under the WEC program (compared to the
GHGRP). In recognition of this potential complexity, in the 2024 WEC
Proposal a deadline of November 1 was proposed for resubmission of WEC
filings that would otherwise be required due to resubmission of a
report under subpart W. While not at issue in this subpart W
rulemaking, we note that as part of the 2024 WEC Proposal, we proposed
that the EPA would retain the right to reevaluate WEC obligations in
WEC filings after November 1 (e.g., as part of an EPA audit of facility
data). Similarly, the proposed November 1 deadline would not apply to
adjustments to WEC obligations resulting from the process to

[[Page 42077]]

resolve unverified data, proposed at 40 CFR 99.8, should that
resolution occur after November 1. The EPA's proposed approaches for
WEC filing requirements and data verification are intended to
incentivize complete and accurate WEC filings under part 99, and thus
corresponding reporting of complete and accurate data under part 98 to
the extent it is relevant for purposes of WEC, by March 31 of each
year. The EPA anticipates that there may be situations requiring
resubmissions of subpart W reports after the proposed November 1
deadline for purposes of the GHGRP, but notes that these situations
would not necessarily require resubmissions or trigger a change in WEC
obligation under the proposed WEC rule. The EPA is not taking final
action on the requested implementation of a data freeze for subpart W
reporting under this final rule and considers the comment insofar as it
relates to WEC timeframes under the proposed 40 CFR part 99 to be
outside the scope of this subpart W rulemaking.
The EPA acknowledges the existence of complex asset transfers
within the oil and gas industry but is not aware of, and the commenter
did not provide an example of, a transfer that would not fit within the
four categories proposed. The four categories have been finalized as
proposed.
Comment: Multiple commenters stated that a new owner or operator
should not be responsible for correcting or resubmitting reporters that
were submitted and certified prior to their acquisition of a facility.
Response: The EPA is not taking final action on the proposed
requirements related to designation of a historic reporting
representation at this time. To better facilitate implementation of the
WEC under CAA section 136(c) and align with the final WEC rule, the EPA
intends to finalize requirements related to the responsibility for
historic reporting as part of a future rulemaking.
Comment: One commenter noted that in the proposed 40 CFR 98.4(n)(1)
and (2) it is not directly stated which party is responsible for filing
the certificate of representation following the transfer of a facility.
The commenter suggested clarifying amendment to specify this is the
responsibility of the new owner or operator. Another commenter stated
it is unclear what is meant by the term certificate of representation.
Response: The EPA is finalizing 40 CFR 98.4(n)(1) and (2) as
proposed. The language referenced by the commenter is consistent with
the existing language at 40 CFR 98.4(h) related to updates to the
certificate of representation following a change in owner or operator
in the general case (i.e., for all facilities other than those
specified in the final introductory paragraph at 40 CFR 98.4) and is
consistent with the EPA's interpretation of that language (that such
updates are the responsibility of the new owner or operator). As
previously noted, the EPA plans to finalize amendments to historic
reporting responsibilities in a future rulemaking. The EPA intends to
consider any associated amendments related to the responsibility for
updates to the certificate of representation at such time. Regarding
the last comment, we note that the contents of a complete certificate
of representation are listed at 40 CFR 98.4(i), which is not being
amended as part of this rulemaking.
Comment: Multiple commenters addressed the impact of the proposed
amendments on reporting and notification requirements for partial
facility sales. One commenter opposed the proposed language at 40 CFR
98.4(n)(3) that would require both the existing and purchasing owner
and operator to report for their respective emission sources until the
criteria in 40 CFR 98.2(i) are met. The commenter requested that the
EPA instead finalize a provision allowing the existing and purchasing
owners and operators to compare their respective facility emissions to
the reporting threshold in 40 CFR 98.231(a).
One commenter expressed general support for the proposed revisions
but stated that the proposed language for reporting requirements under
the scenarios addressed at 40 CFR 98.4(n)(3) and (4) are ambiguous. The
commenter recommended that the EPA clarify that in scenarios of partial
facility sales the criteria of 40 CFR 98.2(i) would apply. The
commenter further recommended that the EPA finalize a requirement
requiring notification when any type of transaction occurs.
Response: The EPA is finalizing as proposed the provisions related
to continued reporting obligations following the sale of a portion of a
facility's emission sources. The EPA believes the language of 40 CFR
98.4(n)(3) is clear regarding continued reporting obligations for both
the existing and the purchasing owner or operator involved in a
transaction. 40 CFR 98.4(n)(3) requires that the existing owner or
operator continue to report for their retained emission sources unless
and until the criteria of 40 CFR 98.2(i) are met. Similarly, 40 CFR
98.4(n)(3)(i) requires that a purchasing owner or operator that does
not already have a reporting facility in the same industry segment
continue to report for the new facility until one of the criteria in 40
CFR 98.2(i) are met. For a purchasing owner or operator that already
has a reporting facility in the same industry segment, 40 CFR
98.4(n)(3)(ii) directs that the acquired emission sources must be
included in their annual report. The EPA disagrees that the reporting
threshold in 40 CFR 98.231(a) should be used in place of the provisions
of 40 CFR 98.2(i) to determine continued reporting obligations. The
commenter that expressed general support for the provisions stated that
40 CFR 98.2(i) contemplates continued reporting for operators whose
facilities no longer meet the original definition of a applicable
facility under subpart A--including after they have sold assets. The
final amendments ensure that the applicable requirements to cease
reporting for facilities involved in the transactions to which 40 CFR
98.4(n)(3) applies are the same as the applicable requirements to cease
reporting for existing facilities.
The EPA did not propose, and is not finalizing, a requirement that
notification is provided when any type of transaction occurs. As
discussed above, the EPA believes this final rule establishes clear
requirements regarding continued reporting for transferred assets.
Further, the disaggregated reporting provisions finalized for the
Onshore Petroleum and Natural Gas Production and Onshore Petroleum and
Natural Gas Gathering and Boosting industry segments are expected to
provide the EPA the ability to track the movement of assets without
requiring specific notification of each asset transfer.
Comment: One commenter stated that the use of the word ``current''
in the proposed language of 40 CFR 98.4(n)(4) was ambiguous in the
context of a transfer of ownership or operation and recommended that
the EPA clarify that the new owner or operator should be required to
notify the EPA of the acquisition of emission sources.
Response: The EPA acknowledges the potential for confusion with the
term ``current owner or operator'' in the proposed 40 CFR 98.4(n)(4)
and has instead finalized the term ``prior owner or operator'' in this
context. The EPA has not adopted the commenter's suggestion that this
requirement should instead be the responsibility of the new owner or
operator. The intent of this notification is to inform the EPA that
reporting will discontinue for the prior facility due to the sale of
all emission sources to multiple purchasers. The EPA does not believe
any single purchaser will necessarily know that all of the assets from
the prior facility had

[[Page 42078]]

been sold or the identity of other purchasers.
2. Definition of ``Owner'' and ``Operator''
Consistent with section II.D. of this preamble, the EPA is
finalizing the proposal to amend 40 CFR 98.1(c) to clarify that the
terms ``owner'' and ``operator'' used in subpart A have the same
meaning as the terms ``gathering and boosting system owner or
operator'' and ``onshore natural gas transmission pipeline owner or
operator'' for the Onshore Petroleum and Natural Gas Gathering and
Boosting and Onshore Natural Gas Transmission Pipeline industry
segments of subpart W, respectively. The EPA received only supportive
comments on this clarification.
3. Onshore Natural Gas Processing Industry Segment Definition
The EPA is finalizing several amendments to 40 CFR 98.230(a)(3) as
described in this section. The EPA received only minor comments on the
proposed requirements related to the definition of ``onshore natural
gas processing'' in 40 CFR 98.230(a)(3). See the document Summary of
Public Comments and Responses for 2024 Final Revisions and
Confidentiality Determinations for Petroleum and Natural Gas Systems
under the Greenhouse Gas Reporting Rule in Docket ID. No. EPA-HQ-OAR-
2023-0234 for these comments and the EPA's responses.
According to existing 40 CFR 98.230(a)(3), the Onshore Natural Gas
Processing industry segment currently includes all facilities that
fractionate NGLs. The industry segment also includes all facilities
that separate NGLs from natural gas or remove sulfur and carbon dioxide
(CO2) from natural gas, provided the annual average throughput at the
facility is 25 MMscf per day or greater. The industry segment also
currently includes all residue gas compression equipment owned or
operated by natural gas processing facilities that is not located
within the facility boundaries.
The EPA is finalizing as proposed an amendment to revise the
definition of ``onshore natural gas processing'' in 40 CFR 98.230(a)(3)
to specify that it includes forced extraction of natural gas liquids
(NGLs) from field gas, fractionation of mixed NGLs to natural gas
products, or both, similar to the definition of ``natural gas
processing plant'' in NSPS OOOOa. The revised definition for natural
gas processing also does not include the 25 MMscf per day threshold for
facilities that separate NGLs from natural gas using forced extraction
but do not fractionate NGLs. We are also finalizing the revisions to
the term ``forced extraction of natural gas liquids'' in 40 CFR 98.238
as proposed to specify that forced extraction does not include ``a
Joule-Thomson valve, a dewpoint depression valve, or an isolated or
standalone Joule-Thomson skid.'' These amendments will improve the
verification and transparency of the data, particularly across
reporting years, consistent with section II.C. of this preamble, and it
will provide reporters with certainty about the applicable industry
segment for the reporting year, consistent with section II.D. of this
preamble, allowing them to focus their efforts on collecting accurate
monitoring data and emissions information needed for one applicable
industry segment. As explained in the 2023 Subpart W Proposal, while we
expect that the final revisions will result in some processing plants
that have been reporting as part of onshore petroleum and natural gas
gathering and boosting facilities to begin report as onshore natural
gas processing facilities, and some onshore natural gas processing
facilities beginning to report as part of onshore petroleum and natural
gas gathering and boosting facilities, we do not expect that the
overall coverage of the GHGRP will decrease.
4. Applicability of Proposed Subpart B to Subpart W Facilities
The EPA is not taking final action on the proposed addition of 40
CFR 98.232(n), which would have referred to subpart B of part 98
(Energy Consumption) that was proposed in the May 22, 2023, GHGRP
supplemental proposed rule (88 FR 32852). For the reasons explained in
section III.B. of the preamble to the GHGRP amendments that were signed
by the EPA Administrator on April 3, 2024,\15\ the EPA did not take
final action on the proposed addition of subpart B of part 98.
Therefore, we are not taking final action on proposed amendments to
subpart W to clarify the intent for subpart W reporters to also report
under subpart B. See the document Summary of Public Comments and
Responses for 2024 Final Revisions and Confidentiality Determinations
for Petroleum and Natural Gas Systems under the Greenhouse Gas
Reporting Rule in Docket ID. No. EPA-HQ-OAR-2023-0234 for a complete
listing of all comments and responses related to subpart B.
---------------------------------------------------------------------------

\15\A copy of the final preamble and rule is available at
<a href="https://www.epa.gov/ghgreporting/rulemaking-notices-ghg-reporting">https://www.epa.gov/ghgreporting/rulemaking-notices-ghg-reporting</a>.
---------------------------------------------------------------------------

B. Other Large Release Events

1. Summary of Final Amendments
We are finalizing the inclusion of an additional emissions source,
referred to as ``other large release events,'' to capture maintenance
or abnormal emission events that are not fully accounted for using
existing methods in subpart W, consistent with section II.A. of this
preamble. We proposed to include calculation and reporting requirements
for other large release events in the 2022 Proposed Rule and in the
2023 Subpart W Proposal. We are finalizing the definition of other
large release event to include planned releases, such as those
associated with maintenance activities, for which there are not
emission calculation procedures in subpart W as proposed in the 2023
Subpart W Proposal, except that we are specifically excluding blowdowns
for which emissions are calculated according to the provisions in 40
CFR 98.233(i) from the definition of other large release events, for
reasons described later in this section. We are also finalizing the
language in 40 CFR 98.233(y)(1)(ii), with modifications from proposal
for clarity, that instructs the reporter to exclude emissions that
would have been calculated for the source(s) of the other large release
event during the timespan of the other large release event from source-
specific emissions calculated under paragraphs 40 CFR 98.233(a) through
(h), (j) through (s), (w), (x), (dd), or (ee), as applicable, to avoid
double counting.
One primary difference in the requirements we are finalizing for
other large release events and those in the 2023 Subpart W Proposal is
we are limiting the threshold for other large release events to include
only events under this source category with an instantaneous
CH<INF>4</INF> emission rate of 100 kg/hr or higher or events with
instantaneous CH<INF>4</INF> emission rates of 100 kg/hr greater than
the emissions estimated using other subpart W methods (the latter of
which is applicable for events associated with calculation methods
elsewhere in subpart W), which aligns with the threshold for events
under the Super-Emitter Program in NSPS OOOOb and EG OOOOc, rather than
having both an aggregate 250 mtCO<INF>2</INF>e threshold and a 100 kg/
hr methane instantaneous threshold with reporting required if either
threshold was exceeded. We are also finalizing an additional clarifying
sentence at 40 CFR 98.233(y)(1) to clearly state that emissions for the
entire

[[Page 42079]]

duration of the event must be reported as an other large release event,
not just those time periods of the event in which emissions exceed the
100 kg/hr instantaneous rate threshold to ensure that the total
emissions for the duration of the event are appropriately accounted for
in subpart W. This clarification to the proposed provision was added to
ensure that the emissions from the entire event are reported; on
further review the EPA wants to ensure the requirement to calculate and
report emissions from the event could not be misinterpreted, given the
use of the 100 kg/hr instantaneous threshold in the final rule, as
applying to only those periods when the emissions rate exceeded the 100
kg/hr emission rate threshold. Under the final provisions, we are also
clarifying that events that meet or exceed the 100 kg/hr emission rate
threshold when simultaneous emissions from multiple release points that
have a common root cause are aggregated must be reported as a single
other large release event. This approach aligns subpart W's other large
release event provisions with the Super-Emitter Program, which uses
remote sensing technologies that typically detect and measure the
cumulative emissions from the site or facility. Even when more
geospatially accurate methods are used, the measurements may still
reflect the cumulative emissions from an aggregate plume created by
several nearby sources within the site or facility.
We are not finalizing the proposed separately applicable 250
mtCO<INF>2</INF>e per event threshold. After consideration of comments
and further consideration of available scientific literature, we
determined that the single threshold is more straightforward to
implement and more consistent with the emission events we sought to
include than the 250 mtCO<INF>2</INF>e threshold, which could include
emission events with relatively small emission rates that occur for
prolonged periods of time. Our literature review reveals that tanks,
unlit flares, and reciprocating compressors have been the majority of
emission sources with emissions that may exceed 250 mtCO<INF>2</INF>e
over the duration of the emissions event but are generally below 100
kg/hr. We already have calculation methods appropriate for these
sources so the vast majority of these lower rate emission events would
continue to be reported under the source-specific methods and would not
be reported as an other large release event, even if the 250
mtCO<INF>2</INF>e threshold was retained. Thus, removing the 250
mtCO<INF>2</INF>e threshold should not meaningfully reduce the
emissions that would have to be reported under the other large release
event provisions.
Additionally, we are changing the requirements related to assessing
incremental emission differences from the source-specific methodologies
for blowdowns from what was proposed. Specifically, we are excluding
blowdowns from the list of subpart W sources for which facilities must
assess whether the incremental emissions threshold for an other large
release event has been met or exceeded. Blowdowns can often have high,
but short-lived, release rates that might otherwise be identified as
other large release events; however, we are excluding such events from
the other large release event source because our assessment is that the
calculation methods for blowdown events under 40 CFR 98.233(i) are more
accurate for this emission source, which has highly transient
emissions. Specifically, the calculation methodology for blowdown vent
stacks under 40 CFR 98.233(i) determines the total volume of between
closed isolation valves and uses the pressure of the system at the
start and end of the blowdown to calculate the amount of gas released,
which we consider to be accurate even for large events. During a
blowdown event, the emission rate will be highest at the start of the
event (highest pressure) and consistently decline during the blowdown.
Many remote measurements only determine the emission rate during a
minute or two of observations, so projecting this instantaneous
emission rate to estimate event emissions for blowdowns can be highly
inaccurate. For these reasons, blowdowns will continue to be reported
under blowdown vent stacks and not under other large release events,
even for large emission rate events. We note that accidental ruptures
of transmission pipelines at onshore natural gas transmission pipeline
facilities and gathering pipelines at onshore petroleum and natural gas
gathering and boosting facilities are not considered blowdowns if the
isolation valves are not closed at the time of the incident because the
volume of the gas released is not limited to the volume between the
isolation valves that are subsequently closed to isolate the leak for
repair. Considering the high pressures at which transmission pipelines
operate, we expect these incidents are likely to have emissions
exceeding 100 kg/hr and are most accurately assessed under the other
large release event provisions.
Consistent with the 2023 Subpart W Proposal, for other large
release events, we are finalizing calculation requirements that rely on
measurement data, if available, or a combination of engineering
estimates, process knowledge, and best available data, when measurement
data are not available. The final calculation procedure consists of
estimating the amount of gas released and the composition of the
released gas. The amount of gas released would generally be calculated
based on a measured or estimated emission rate(s) and an event
duration. We are finalizing provisions as proposed that the start time
of the duration must be determined based on monitored process
parameters, when available, such as pressure or temperature, for which
sudden changes in the monitored parameter signals the start of the
event. If the monitored process parameters cannot identify the start of
the event, we are finalizing the requirement that reporters must assume
the release started on the date of the most recent monitoring or
measurement survey, including advanced technology surveys or voluntary
surveys, that confirms the source was not emitting at the rates above
the other large release event reporting threshold or assume a start
date of 91 days prior to the date of identification, whichever start
date is the most recent. We are also finalizing provisions that for the
purpose of estimating the total volume of the release during the event,
monitoring or measurement survey includes any monitoring or measurement
method in 40 CFR 98.234(a) through (d) as well as advanced screening
methods such as monitoring systems mounted on vehicles, drones,
helicopters, airplanes, or satellites capable of identifying
CH<INF>4</INF> emissions at 100 kg/hr, with a modification from
proposal to add language specifying the screening method must be
capable of identifying events at this threshold at a 90 percent
probability of detection as demonstrated by controlled release tests.
This revision in the final provision will ensure that appropriate
advanced screening methods are used. We recognize that some release
events may be identified using audio, visual, and olfactory (AVO)
inspections. Therefore, we are finalizing additional provisions that
specify that, when an event is identified using AVO methods, previous
AVO inspections are considered monitoring surveys and can be used to
limit the start date of an event.
One change from proposal in this final rule is to the default
assumptions associated with the start date of an other large release
event. If no monitoring data or measurement survey data are available,
we are finalizing that reporters must assume that the event

[[Page 42080]]

start date occurred 91 days (three months) prior to the event
identification date. We proposed a 182-day default maximum duration and
requested comment on a 91-day default duration. The available data
suggest that the duration of emission events exceeding 100 kg/hr is
highly variable, commonly lasting several hours to several weeks but
occasionally lasting 182 days or longer, as noted by one commenter.\16\
After reviewing the available information, we determined that a 91-day
default more accurately reflects an average duration than the proposed
182-day default. We note that, consistent with the directives in CAA
section 136(h), we provide default durations for other sources in the
GHGRP, such as equipment leaks, where leaks identified are assumed to
leak all year long (when annual surveys are conducted) or since the
previous survey (with the option for reporters to conduct additional
surveys). For other large release events, we similarly include several
provisions that allow reporters to determine the start date based on
their facility's specific data, including consideration of other
monitoring conducted by the facility; however, we maintain that, in the
absence of other facility-specific information, a default value is
needed and that default should be appropriate based on available data
of other large release events at this time so as to result in
reasonably accurate reporting of total emissions for the facility, as
discussed in the preamble of the 2023 Subpart W Proposal and in the
document Summary of Public Comments and Responses for 2024 Final
Revisions and Confidentiality Determinations for Petroleum and Natural
Gas Systems under the Greenhouse Gas Reporting Rule, available in the
docket to this rulemaking (Docket ID. No. EPA-HQ-OAR-2023-0234). Based
on consideration of the comments received and for reasons discussed in
section III.B.2. of this preamble, we are finalizing the default start
date of the event, when other information is not available to support a
shorter duration, would be 91 days from the time the event was first
identified. We are aware that many events may be shorter than 91 days;
under the final provisions operators may choose to gather and use other
specified information to determine the actual duration, to avoid the
potential need to apply a default start date for such events. As new
data on event duration becomes available, we intend to evaluate if the
default event should be updated in the future through a future
rulemaking process. We are revising from proposal the language
regarding this 91-day default start date to more clearly specify that
it is used to establish the start date of the event. The 91-day default
start date prior to the date of detection does not limit the cumulative
duration of an event in cases where the repair or cessation of the
emissions is delayed after the date of event detection. For example, if
an event is immediately identified but takes 120 days to repair, the
full duration of the event (120 days) must be used. The 91-day default
only applies to the determination of the start date and not the
cumulative duration. We are finalizing, as proposed, that the end time
of the release event must be the date of the confirmed repair or
confirmed cessation of emissions. There may be events that span across
two separate reporting years. In such cases, we are finalizing as
proposed that the volume of gas released specific to each reporting
year would be calculated and reported for that reporting year starting
with RY2025.
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\16\ Kairos Aerospace comments on the Greenhouse Gas Reporting
Rule: Revisions and Confidentiality Determinations for Petroleum and
Natural Gas Systems. Letter from Ryan Streams, Kairos Aerospace, to
Jennifer Bohman and Mark DeFigueiredo, U.S. EPA, September 29, 2023.
EPA Docket Id No. EPA-HQ-OAR-2023-0234-0240. ``However, Kairos has
also noted instances where emissions that would qualify as ``Other
Large Release Events'' do appear to be highly persistent in nature.
Kairos analyzed our emission detections during 2022 across the
Anadarko, Barnett, DJ, Eagle Ford, Haynesville, Permian, San
Joaquin, San Juan, and Uinta Basins and observed 714 upstream sites
that had emissions that persisted for at least 182 days. This does
not represent a majority of Kairos detections--Kairos observes
thousands of emissions per year, the majority of which persist for
less than 182 days--but it does appear that long duration events can
happen.''
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For explosions or fires where some of the gas may be combusted or
partially combusted, we are finalizing that reporters must estimate the
portion of the total volume of natural gas released that was combusted
in the explosion or fire in order to determine the composition of GHG
released to the atmosphere during the event. For the portion of natural
gas released via combustion in an explosion or fire, we are finalizing
as proposed that a maximum combustion efficiency of 92 percent be
assumed. Because these releases are not through engineered nozzles that
can be designed to promote mixing and combustion efficiency, the
combustion efficiency of these releases can be highly variable and are
expected to be less efficient than a flare designed to destroy methane.
Since facilities must first estimate the fraction of the gas released
via combustion, we expect that the total combustion efficiency,
considering all gas released over the length of the event, will be much
lower than 92 percent.
We are finalizing requirements for facilities to evaluate releases
when there is monitoring or measurement data completed by the EPA or
the facility. We are also finalizing requirements for facilities to
evaluate releases when there is a notification from the EPA Super-
Emitter Program in NSPS OOOO/OOOOa/OOOOb at 40 CFR 60.5371, 60.5371a,
60.5371b or an applicable approved state plan or applicable Federal
plan in 40 CFR part 62. After consideration of comments received, as
discussed in section III.B.2. of this preamble, and in alignment with
the final provisions of the Super-Emitter Program in NSPS OOOO/OOOOa/
OOOOb and EG OOOOc, we are not finalizing the proposed provision that
subpart W reporters must consider other third-party information (i.e.,
information from parties other than the EPA's or facility's sponsored
monitoring events or notifications of large potential super-emitter
events under the Super-Emitter Program in NSPS OOOO/OOOOa/OOOOb and EG
OOOOc received by the facility from the EPA), and are accordingly not
finalizing the use of the term ``credible information.'' Other third-
party notifications are not assured of having the credibility and
defined requirements that notifications from the EPA under the Super-
Emitter Program, or data from monitoring or measurement conducted by
the EPA or the facility, will have and the EPA has concluded that it is
not appropriate to place a potentially large burden on subpart W
reporters to respond to such information. The final provisions of the
Super-Emitter Program in NSPS OOOO/OOOOa/OOOOb have robust assurances
of credibility, reliability and transparency. The entities doing the
super-emitter monitoring under NSPS OOOO/OOOOa/OOOOb must have the
remote-sensing technology they are using (e.g., satellites) certified
by the EPA under the EPA's advanced methane detection technology
program, including rigorous accuracy checks, where the EPA is
certifying that the technology used is capable of providing accurate
and reliable data within the requirements of the Super-Emitter Program.
The entity filing the super-emitter report must also be certified by
the EPA, to demonstrate that the third party has the training and
expertise to interpret the data and identify a super-emitter event and
has appropriate and reliable methods for identifying the owner or
operator of the sites where the super-emitter event occurred. The
third-party reports must be filed with the EPA

[[Page 42081]]

within 15 days of detection, increasing the opportunity for the owners
and operators to get timely notice, and must also meet specified
reporting criteria and be filed under attestation that the information
is true and accurate to the best of the notifier's knowledge. Once the
super-emitter report is received by the EPA, the EPA evaluates the
report for completeness and accuracy before sending a super-emitter
notice to the owner or operator. The super-emitter notices, and the
owner or operator's response, will all be posted to a public website.
All of these requirements and the significant oversight role the EPA
assumes in certifying both the technology and the reporter, as well as
the checks performed once the reports are submitted to the EPA,
demonstrate that the data underlying the EPA's notices are credible and
reliable and thus support the EPA's conclusion that the emissions
included in the super-emitter notices from the EPA must be evaluated
for a facility's subpart W report. We note that our judgment regarding
the revisions to requirements for each type of source within each
subpart W industry segments reflects our determinations specific to
considerations for each source in each industry segment, including
other large release events. More specifically here, the revisions for
other large release events are intended to be and are implementable
even absent revisions to the other sources, and vice versa, as they
each independently ensure that the emissions reported under subpart W
for the given source or industry segment at issue are consistent with
the directives in CAA section 136(h) and improve the subpart W
provisions as described in section II. of this preamble. Furthermore,
the other large release event requirements for facilities to evaluate
releases when there is monitoring or measurement data completed by the
EPA or the facility are intended to be and are implementable even
absent the other large release event requirements for facilities to
evaluate releases when there is a notification from the EPA Super-
Emitter Program in NSPS OOOO/OOOOa/OOOOb at 40 CFR 60.5371, 60.5371a,
or 60.5371b or an applicable approved state plan or applicable Federal
plan in 40 CFR part 62. Accordingly, the EPA finds that these other
large release event requirements are severable from each other, and
that at minimum revisions for each source are severable from revisions
to each of the other sources.
Under the Super-Emitter Program, the EPA may receive third-party
notifications and in turn notify owners and operators of potential
super-emitter events that are related to subpart W facilities,
including subpart W facilities that either do or do not have NSPS OOOO/
OOOOa/OOOOb or EG OOOOc affected facilities. Under subpart W, we are
finalizing that owners and operators are required to report whether
emission events identified in those notifications are included in their
annual emissions report and if so, under which source category. We are
clarifying in the final rule that facilities must include in the
facility's annual emissions report emissions events identified in
super-emitter notices received from the EPA unless the owners and
operators can certify that the facility does not own or operate the
equipment at the location identified in the notification or, in
situations where there are multiple facilities that own and operate
equipment within 50 meters of the location identified in the
notification, the owners and operators can certify that their facility
does not own or operate the emitting equipment at the location
identified in the notification or unless the EPA has determined that
the notification contains a demonstrable error. For consideration of
demonstrable error, the facility must submit a statement of
demonstrable error as specified by 40 CFR 60.5371, 60.5371a, or
60.5371b or an applicable approved state plan or applicable Federal
plan in 40 CFR part 62.\17\ We are finalizing additional requirements
for actions the owners and operators must complete in order to be able
to certify that the facility does not own or operate the emitting
equipment at the location identified in the notification in situations
where there are multiple facility owners and operators of equipment at
the location. Specifically, the facility must complete an investigation
of available data as specified in 40 CFR 60.5371b(d)(2)(i) through (iv)
within 5 days of receiving the notification to identify the emission
source related to the event. If this data investigation does not
identify the emission source, the facility must conduct a complete leak
survey of equipment within 50 meters of the location identified in the
notification using any one of the methods provided in Sec.
98.234(a)(1) through (3) within 15 days of receiving the notification.
If the data investigation and the leak survey both fail to identify the
source of the event, then the facility owner or operator can certify
that they do not own the emitting equipment.
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\17\Under the Super-Emitter Program, the owner or operator has
15 days to submit a report, which could include a statement of
demonstrable error challenging the notification. Events occurring
during a calendar year are not reported to the GHGRP until the
following March. We also note that facilities have the ability to
revise their annual reports after submission if errors are
identified.
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Further, we are finalizing as proposed definitions of the terms
``well release'' and ``well blowout'' in 40 CFR 98.238 to assist
reporting facilities with differentiating between these types of
release events that could potentially occur at wells.
Finally, we are finalizing a series of reporting requirements in 40
CFR 98.236(y) related to the type, location, duration, calculations,
and emissions of each ``other large release event'' similar to those
proposed. Specifically, we are finalizing as proposed that reporters
provide the location, a description of the release (from a specified
list that includes an ``other (specify)'' option for releases that are
not otherwise described well with the list provided), a description of
the technology or method used to identify the release, volume of gas
released, volume fractions of CO<INF>2</INF> and CH<INF>4</INF> in the
gas released, and CO<INF>2</INF> and CH<INF>4</INF> emissions for each
``other large release event.'' We are also finalizing that reporters
would provide the start date and time of the release, duration of the
release, and the method used to determine the start date and time
(options would include a pressure monitor, a temperature monitor, other
monitored process parameter, most recent monitoring or measurement
survey showing no large release (and specify the type of monitoring or
survey), or the default assumption that the release started 91 days
prior to the event identification date). As previously explained in
this section, the 91 days start date would be the required assumption
if the facility does not have empirical data, such as monitored process
parameter data or leak inspections or advanced technology monitoring or
measurement surveys, to identify the release start date, a reduction
from the 180 days proposed. These provisions are otherwise being
finalized as proposed except for minor revisions to reflect the
revisions and clarifications pertaining to the default assumption start
date. We are also finalizing as proposed that reporters provide a
general description of the event and indicate whether the ``other large
release event'' was also identified as a potential super-emitter event
under the super-emitter event provisions of NSPS OOOO/OOOOa/OOOOb at 40
CFR 60.5371, 60.5371a, or 60.5371b or an applicable approved state plan
or applicable Federal plan in 40 CFR part 62.
We are finalizing that reporters that received super-emitter event

[[Page 42082]]

notifications from the EPA would be required to report certain
information on each release notification with some revisions from
proposal. We are adding language to limit reporting requirements for
super-emitter event notifications to those for which the EPA does not
determine that the notification contains a demonstratable error. For
consideration of demonstrable error by the EPA, facilities must
describe the demonstrable error in their Super-Emitter Program report
according to the provisions of NSPS OOOO/OOOOa/OOOOb at 40 CFR 60.5371,
60.5371a, or 60.5371b or an applicable approved state plan or
applicable Federal plan in 40 CFR part 62. We are finalizing that for
each EPA notification received via the Super-Emitter Program (for which
the EPA does not subsequently determine that the notification contains
a demonstrable error), facilities would report the type of event
resulting in the emissions as one of the following types of events:
normal operations, a planned maintenance event, leaking equipment,
malfunctioning equipment or device, or undetermined cause. Because all
Super-Emitter Program notifications will come from the EPA, we are not
finalizing certain proposed reporting requirements regarding the
notification since the EPA will already have this information (e.g.,
name of notifier, method used, date of measurement, and emission rate
and uncertainty bounds). We are finalizing that facilities must
indicate whether the emissions identified from the event are included
as an other large release event, as another source required to be
reported under subpart W, or not included. The only exception to the
requirement to include emissions identified via the notification in
emissions reported by the facility under subpart W is if the facility
is able to make a determination, and then certify to the EPA that the
facility does not own or operate the equipment at the location
identified in the Super-Emitter Program notification. We are not
finalizing the proposed requirement that the reporter provide a reason
for not including the emissions from the event in their annual
emissions report, as all emission events identified under the Super-
Emitter Program that are the subject of a notice from the EPA to the
owner/operator must be quantified unless the exception applies and the
owner or operator of the facility certifies that the exception applies.
This information would support EPA verification and ensure accuracy of
the emissions reported under other large release events and the
facility's total reported emissions.
We are not finalizing several of the proposed reporting
requirements under subpart W regarding notifications under the Super-
Emitter Program because all of the Super-Emitter Program notifications
will be issued by the EPA and the EPA will already have records of the
information we had proposed to require be submitted under subpart W.
Specifically, we are not finalizing requirements proposed at 40 CFR
98.236(y)(11)(ii) to report the latitude and longitude of the release
as reported in the notification. Also, we are not finalizing
requirements proposed at 40 CFR 98.236(y)(11)(iv) to report whether the
release was received under the super-emitter event provisions of NSPS
OOOO/OOOOa/OOOOb at 40 CFR 60.5371, 60.5371a, or 60.5371b or an
applicable approved state plan or applicable Federal plan in 40 CFR
part 62 or another notifier, and, if the notification was from another
notifier, the reporter would provide the name of the notifier, the
remote sensing method used, the date and time of the measurement, the
measured emission rate, and uncertainty bounds on the emission rate.
These changes from proposal align with the final requirements in the
Super-Emitter Program under NSPS OOOO/OOOOa/OOOOb and EG OOOOc and
ensure we are not finalizing duplicative reporting requirements.
Finally, we are adding a reporting requirement to provide an
indication if you received a super-emitter release notification from
the EPA after December 31 of the reporting year for which
investigations are on-going such that the annual report that has been
submitted may be revised and resubmitted pending the outcome of the
super-emitter investigation. This reporting element is provided in
recognition of the fact that some super-emitter notifications received
in 2026 may impact the 2025 reporting year annual report and there may
not be sufficient time to revise the 2025 annual report prior to the
March 31 deadline. This reporting element allows the reports to be
certified as accurate for submission while noting the potential need
for revision depending on the outcome of the super-emitter release
notification investigation.
2. Summary of Comments and Responses
This section summarizes the major comments and responses related to
the proposed amendments to add the other large release events source
category.
Comment: We received numerous comments on the proposed thresholds
for defining a reportable other larger release event. Several
commenters supported both of the thresholds included in the 2023
Subpart W Proposal and some commenters recommended smaller reporting
thresholds, specifically reducing the 100 kg/hr to 14 kg/hr. However, a
majority of the comments received opposed one or both of the
thresholds. Commenters opposing the 250 mtCO<INF>2</INF>e threshold
generally considered it to be too small, especially considering the
proposed 182-day default start date. One commenter stated ``. . . it
would take approximately 90 days for a 4.7 kg/hr CH<INF>4</INF> leak to
exceed the proposed 250 mtCO<INF>2</INF>e threshold. . . A `large
release event' should be just that, not a small release over a long
period of time.'' Many of these commenters suggested that the EPA adopt
the Pipeline and Hazardous Materials Safety Administration (PHMSA)
threshold for a reportable incident of 3 MMscf (approximately 6 times
higher that the proposed threshold).
Regarding the 100 kg/hr threshold, a few commenters suggested this
emission rate was too high and that a lower threshold should be adopted
but most of the commenters recommended that a time component was needed
with this threshold because in their view high rate, short duration
events would still have small contributions to a facility's annual
emissions. Many of the commenters making this argument specifically
cited blowdowns as sources with high release rates and short durations
and indicated that these types of events should not be considered under
the other large release event provisions.
Several of the commenters indicated that the EPA should use a
combined threshold (exceed 250 mtCO<INF>2</INF>e AND 100 kg/hr methane)
rather than the two independent thresholds proposed (exceed 250
mtCO<INF>2</INF>e OR 100 kg/hr methane). These commenters noted that
this would address issues with low rate, long duration events being
considered as other large release events as well as setting a minimum
emission quantity for high release events, so short duration, high rate
releases such as blowdowns would not be considered under the other
large release event provisions. A few of the commenters suggesting a
combined threshold also suggested increasing thresholds levels.
Response: After considering comments received, we are finalizing
the 100 kg/hr threshold as proposed, but we are not finalizing the
proposed 250 mtCO<INF>2</INF>e threshold. We determined that the single
threshold will be more straightforward for operators to implement,
aligns more directly with

[[Page 42083]]

the EPA's Super-Emitter Program, and is more consistent with the
emission events we sought to include in the other large release events
source than the 250 mtCO<INF>2</INF>e limit. Furthermore, based on our
literature review of emission sources with emissions below 100 kg/hr,
tanks, unlit flares, and reciprocating compressors were the majority of
these smaller rate emitters. In this final rule, we have calculation
methods appropriate for these sources that accurately estimate
emissions from events with emission rates less than 100 kg/hr and
determined that removing the 250 mtCO<INF>2</INF>e threshold would not
significantly reduce the emissions that would have to be reported under
the other large release event provisions because these sources would
always be reported under the source-specific reporting requirements, as
amended, rather than under other large release event provisions.
We disagree with commenters requesting a smaller 14 kg/hr methane
emission rate threshold. First, this emission rate is at or below the
level of detection for several remote sensing methods. Second, this
would cause a disconnect between the final other large release event
threshold and the NSPS Super-Emitter Program requirements.
Regarding commenters suggesting that the 100 kg/hr threshold alone
is not appropriate because high rate, short events may have low
cumulative emissions and commenters suggestion that the EPA implement
one combined threshold exceeding both the 100 kg/hr and the 250
mtCO<INF>2</INF>e limit, we disagree that these high emission rate
events should not be reported when they are from sources not otherwise
subject to reporting under subpart W or from sources for which the
source-specific method significantly understates the emissions. We also
disagree that the 250 mtCO<INF>2</INF>e threshold should be applied to
limit the number of releases exceeding 100 kg/hr that should be
accounted for within the subpart W other large release event reporting
requirements. CAA section 136(h) directed the EPA to revise subpart W
to accurately reflect total methane (and waste emissions). Combining
the thresholds would cause a disconnect between the Super-Emitter
Program and the GHGRP reporting requirements where some NSPS OOOOb or
EG OOOOc super-emitter events would not be reported under the subpart W
and result in the underreporting of methane emissions to subpart W.
Several of the commenters provided hypothetical calculations of mass
emissions that would occur for events right at the 100 kg/hr rate for 1
to 5 minutes but offer no data to support that such events are
prevalent. We also note that remote detection of high release events
relies on an adequate pathlength concentration being present, which
would not be the case for these hypothetical short duration events.
These methods generally make flux calculations using wind speeds and/or
dispersion models that typically assume a developed plume, but the
plume would not be fully developed for these hypothetical short events.
Even if the emission event can be detected and quantified by the
monitoring technique used, it is highly unlikely that the remote
monitoring measurement would occur precisely at the time of the 1- to
5-minute release. As such, we find the commenter's concern regarding
the need to evaluate numerous very short events is largely unfounded.
Nonetheless, we did evaluate potential release events that may be of
short duration, as described in the following paragraph.
When commenters provided an example of high-rate, short events,
they all pointed to blowdown events. However, blowdowns have their own
calculation method, which we consider to be accurate across the
duration of the event. Specifically, the blowdown methodology
determines the total volume of natural gas between closed isolation
valves and uses the pressure of the system at the start and end of the
blowdown to calculate the amount of gas released. During the blowdown
event, the emission rate will be highest at the start of the event
(highest pressure) and consistently decline during the blowdown. Many
remote measurements only determine the emission rate during a minute or
two of observations. Projecting this instantaneous emission rate to
estimate event emissions for blowdowns can be highly inaccurate.
Therefore, in the final provisions we have removed the proposed cross-
reference to 40 CFR 98.233(i) for blowdowns in the definition of other
large release events so no additional calculations are necessary for
the emissions from blowdown activities. If a facility fails to close an
isolation valve and an intended blowdown event is actually a continuous
venting event, such an event is not a blowdown and would have to be
reported as an other large release event if it exceeds the 100 kg/hr
threshold.
Besides blowdowns, the other likely high rate, short duration
release event is pressure relief device (PRD) openings. Currently, PRDs
are included under equipment leaks to account for periods when there is
a leak past the PRD valve while it is in the closed position, but
pressure relief events (periods when the valve intentionally opens due
to an over-pressuring of the process vessel or equipment) are not
accounted for under most circumstances. For uncontrolled production
storage tanks, the calculation method assumes all dissolved methane in
fluids from the separator are emitted from the tank. For controlled
tanks, we require facilities to assume a zero percent capture/control
efficiency over the time period the thief hatch is open (which commonly
works as a PRD for the storage tank). Because large, direct PRD
releases are not captured elsewhere in subpart W except for storage
tanks, we maintain that these emissions must remain reportable as other
large release events when the applicable threshold is met to accurately
reflect methane emissions from the facility. We note that CAA section
136(h) requires that the EPA revise the requirements of subpart W to
accurately reflect the total methane emissions from applicable
facilities.
We expect that most short duration events will be adequately
captured under source-specific provisions of subpart W, as included in
the final rule. Additionally, with the 100 kg/hr emission rate
threshold and exclusion of blowdowns, we expect that there will be a
limited number of events that qualify under the provisions of other
large release events. However, we maintain that the emissions from
large emission rate events that are currently not required to be
reported or that are not well-characterized under other provisions of
subpart W must be reported as other large release events as directed
under CAA section 136(h).
Comment: Numerous commenters opposed the proposed requirement that
``. . . if you have credible information that demonstrates the release
meets or exceeds one of the thresholds or credible information that the
release may reasonably be anticipated to meet or exceed (or to have met
or exceeded) one of the thresholds in paragraph (y)(1) of this section,
then you must calculate the event emissions and, if the thresholds are
confirmed to be exceeded, report the emissions as an other large
release event.'' Some commenters expressed concern that this
requirement would create a disincentive to voluntary, site-wide
monitoring. The commenters also stated that ``credible information'' is
poorly defined. Additionally, commenters opposed the proposed reporting
requirements that reporters must consider and report on ``third-party
notifications'' because unqualified third-party notifications could
unnecessarily increase the reporting burden while not leading to more
accurate GHG reporting. The

[[Page 42084]]

commenters also challenged the legality of this requirement. According
to the commenters, CAA section 114 authorizes the EPA only to collect
information and it does not authorize the EPA to impose a mandatory
reporting obligation that would be triggered by third-party
observations or assertions. The commenters also state that any third-
party data should be thoroughly vetted by the EPA and should require
assessment of persistence of the observed emissions rather than relying
on a single observation. One commenter expressed concern that without a
robust structure in place, third party notices could be received on
March 30 that require revisions to annual reports due on March 31,
which the commenter considered unreasonable. Other commenters stated
that the EPA must define ``credible evidence,'' allow operators to
account for telemetry malfunctions, and remove requirements for
reporters to respond to third-party notifications.
Response: We agree with commenters that the EPA should have a role
in authorizing third-party measurement systems and collecting and
submitting notifications that trigger a reporting obligation under
subpart W. Under the Super-Emitter Program, third parties must be EPA-
certified entities, who must use EPA-approved remote sensing
technologies and approaches. Under the Super-Emitter Program, the EPA
will play an important oversight role, including notifying owners and
operators after reviewing third-party notifications of events received
under the Super-Emitter Program. It is within our authority for this
subpart W rule to require reporters to assess the information that we
have vetted and sent to them as notifications through the Super-Emitter
Program, as it is data that we will have assessed as robust as part of
that program, is based on empirical data, and is relevant to accurate
calculations of emissions for the facility. Owners and operators
identified through the Super-Emitter Program will also investigate and
report all sources that they suspect may have caused or contributed to
the super-emitter event specified in the EPA notice that they have
received. Regarding our authority for the NSPS Super-Emitter Program
itself, that is outside the scope of this rulemaking; please see the
discussion of our authority in the NSPS OOOOb final rule (see 89 FR
16876-16879, March 8, 2024).
In this final rule, we are not finalizing the proposed term
``credible information'' and simply describing in 40 CFR 98.233(y) the
types of information that must be considered. Specifically, we are
requiring that facilities consider both EPA-verified notifications
provided under the Super-Emitter Program in NSPS OOOOb or federal or
state plans consistent with EG OOOOc and any EPA- or facility-funded
monitoring data that identify high emission events. Facility owners and
operators are required to assess whether those emission events meet the
definition of other large release event or are adequately reported
under other provisions of subpart W. Owners or operators are not
required to consider any other third-party monitoring data besides
those received through a notification from the EPA or funded by EPA or
the facility, but may consider other third-party data at their
discretion. This eliminates the concerns noted by the commenters
regarding unvetted and unsolicited third-party notifications.
If a company-sponsored monitoring event (whether voluntary or
regulatorily required) indicates an other large release event and site
operation staff confirm the release, such emissions should be reported,
particularly given the direction under CAA section 136(h). Commenters
raised concerns that this may discourage facilities from conducting
voluntary site-wide monitoring; however, we consider that the structure
of directives Congress gave the EPA under CAA section 136(h), which the
EPA acted consistent with in this final rule, provides an incentive for
routine monitoring. Routine or continuous monitoring allows a facility
to both reduce waste emissions and identify an accurate number and
duration of other large emission events. The EPA recognizes that the
option for reporters to submit additional empirical data for a given
facility may lead to reporters taking additional voluntary actions for
subpart W reporting, including for the purpose of demonstrating the
extent to which a charge under CAA section 136(c) is owed. To the
extent this approach ``incentivizes'' additional actions by the
reporter, the EPA considers this to be inherent in the directives
Congress gave the EPA in CAA section 136(h). The EPA considers this
approach consistent with the directives Congress specified in CAA
section 136(h), as it ensures that reporting is based on empirical data
and accurately reflects total methane emissions while also allowing
reporters to submit appropriate empirical emissions data. We also note
that facilities must still act on EPA-provided notifications (from the
Super-Emitter Program) about large release events.
With respect to concerns about notifications impacting soon to be
submitted or previously submitted annual reports, we first note that
the 15-day maximum timeframe for third-party notifiers to submit
information to the EPA under the Super-Emitter Program will ensure
facilities will be notified of super-emitter events in a timely manner.
For events for which start times can be determined, which we expect to
be most events, notifications received in late March are unlikely to
require revisions of the annual report due at the end of March because
it is likely that the facility is already aware of the event from data
regularly monitored by the facility. Second, with the revised default
start date being 91 days from event identification rather than 182
days, it is much less likely that notifications received at the end of
March 2026, for example, would impact the emission totals for the 2025
reporting year, which ends 89 days before the report due date. However,
we acknowledge that there may be circumstances that notifications are
received near the March 31 due date and there would not be time to
evaluate the notification prior to the reporting deadline. In this
circumstance, facilities should submit their report to the best of
their knowledge. We added a reporting element at 40 CFR
98.236(y)(11)(v) for reporters to provide an indication of whether they
have received a super-emitter release notification after December 31 of
the reporting year for which an investigation is on-going and might
result in the need to revise and resubmit the annual report pending the
outcome of the super-emitter investigation. If upon determining the
start date and duration of the event, the some of the event's emissions
are reportable for the report already submitted, facilities are able to
amend the previously submitted annual report to include the applicable
event emissions and resubmit that annual report. We note that
facilities have 45 days under 40 CFR 98.3(h)(1) to resubmit and correct
their annual report after identifying a substantive error, which would
afford them additional time to evaluate the event.
While persistence is not specifically included in the Super-Emitter
Program notification requirements, many of the remote sensing
technologies use multiple determinations (e.g., multiple transects at
different heights) to meet required accuracy assessments.
18 19 For

[[Page 42085]]

a super-emitter notification that the EPA determines is complete and
does not contain information that the EPA finds to be inaccurate to a
reasonable degree of certainty, we maintain that it is reasonable to
require facilities to report these emissions, even when they may be
short-lived. Because some remote measurements may identify an aggregate
emission rate from the site or facility that exceeds 100 kg/hr but
would not have the spatial resolution to identify the specific source
or sources, reporters will need to investigate and identify the source
of the emissions. We note that in certain situations, such as a process
unit over-pressuring, there may be multiple release points (such as
several different PRDs opening at the same time). For these types of
releases, we find it reasonable to aggregate the emissions from all
release points that have a common root-cause and consider that a single
``event'' because this would more closely tie reported emissions to the
available monitoring data.
---------------------------------------------------------------------------

\18\Karion, A., et al., ``Aircraft-Based Estimate of Total
Methane Emissions from the Barnett Shale Region.'' Environ. Sci.
Technol. 2015, 49, 8124-8131. <a href="https://pubs.acs.org/doi/10.1021/acs.est.5b00217">https://pubs.acs.org/doi/10.1021/acs.est.5b00217</a>. Available in the docket for this rulemaking, Docket
ID. No. EPA-HQ-OAR-2023-0234.
\19\Schwietzke, S., et al., ``Improved Mechanistic Understanding
of Natural Gas Methane Emissions from Spatially Resolved Aircraft
Measurements.'' Environ. Sci. Technol. 2017, 51, 7286-7294. <a href="https://pubs.acs.org/doi/10.1021/acs.est.7b01810">https://pubs.acs.org/doi/10.1021/acs.est.7b01810</a>. Available in the docket
for this rulemaking, Docket ID. No. EPA-HQ-OAR-2023-0234.
---------------------------------------------------------------------------

Comment: Several commenters supported the 182-day default duration.
One commenter noted that they had observed 714 upstream sites that (1)
had emissions that would qualify as an other large release event under
the subpart W proposal, and (2) persisted for at least 182 days. While
the majority of the site-level emission detected by the commenter
persisted for less than 182 days, the commenter noted that long
duration events can occur. On the other hand, numerous commenters
opposed the 182-day default duration. These commenters argued that the
182-day duration would effectively require facilities to do more
frequent monitoring to avoid having to use the 182-day default
duration. Several of these commenters indicated that the 91-day default
duration that the EPA requested comment on was more appropriate. Other
commenters suggested a default duration of 30 or 45 days may be more
appropriate given the typical duration of large release events. Other
commenters recommended that reporters be permitted to use a wide
variety of methods, including audio, visual and olfactory methods,
optical gas imaging (OGI) surveys, flyovers, process parameters, and
Supervisory Control and Data Acquisition (SCADA) systems, to determine
the start and end time of such events. Some commenters suggested
process knowledge and engineering estimates be allowed to determine
event duration.
Response: After reviewing comments, we have decided to finalize the
default start date of an event to be 91 days prior to event
identification rather than the proposed 182 days. While we also
inadvertently referred to this as a default duration in our 2023
Subpart W Proposal, we intended this to be the default start date (in
the absence of any monitored process data, survey or remote sensing
data suggesting a more recent start date). As further indication of our
intent, we note that the paragraph at 40 CFR 98.233(y)(2)(ii) is
specific to determining the start date of the event and a separate
paragraph--40 CFR 98.233(y)(2)(iii)--provides the provision for the end
time. Nonetheless, based on comments received, it appears some
commenters may have interpreted this to be a maximum event duration;
therefore, we are clarifying in the final provisions in 40 CFR
98.233(y)(2)(ii) that, in the absence of monitored process parameter
data indicating the start date, the event must be assumed to start on
the date of the most recent monitoring or measurement survey that
confirms the source was not emitting at or above the rates specified in
40 CFR 98.233(y)(1) or assumed to have started 91 days prior to the
date the event was first identified, whichever start date is most
recent. Therefore, we are limiting how far back in time the default
start date is from the date the event was first identified, but we are
not limiting the maximum duration of the event. For example, the Aliso
Canyon event was identified soon after it started since the natural gas
contained odorant, but the leak took months to repair and had a total
duration of about 112 days. In a case with these facts under the final
provisions, the duration of the event must still be reported as 112
days based on the identified start date and the confirmed repair date
of the leak.
The literature study data we reviewed, as detailed in the subpart W
TSD for the final rule (included in Docket ID. No. EPA-HQ-OAR-2023-
0234), suggest that the duration of emission events exceeding 100 kg/hr
is typically short and that a 91-day default more accurately reflects
the typical range of observed durations expected to be reported under
this source category than the proposed 182-day default. For example,
well blowouts, which is a source of emissions that will be reported
under other large release events, often persist for an extended period
of time. We disagree with commenters that the default duration should
be reduced further, for example to 30 days, because this could in many
cases result in under-reporting, and will also disincentivize
facilities from trying to pinpoint actual start dates for events that
may have started 30 or more days prior to event detection. We also
expect that most short duration events will be adequately captured
under source-specific provisions of subpart W, as included in the final
rule. We also note that, as discussed above, blowdowns, the often-cited
example of high-rate, short events, have been excluded from the final
provisions for assessment as an other large release events and are
required to be reported under the provisions at 40 CFR 98.233(i) for
blowdown vent stacks. We also have strong evidence that longer duration
events do occur, as noted by one commenter. With the clarification that
this default relates only to the start date of the event, we maintain
that emissions from longer duration events will still be accurately
characterized when using this 91-day default event start date because
this default does not limit the total duration of the event in cases
where it may take days to several months or longer to correct the
issue. While we revised from proposal the default start date, we still
expect that this default start date provisions will not be used often
and that most facilities will be able to identify a start time based on
monitored process parameter data or routine monitoring surveys.
We intentionally provided flexibility for using monitored process
parameters for determining the start time of a release in the proposed
rule without trying to limit the types of parameters that could be
monitored to identify the start date of an event. We note that data
from SCADA systems are considered monitored process parameters. If a
facility has a continuous monitoring network, they can also use that
data to identify the start time. If a facility conducts frequent
advanced technology or remote sensing surveys, these can be used to
more directly assign a start date, provided that the advanced screening
method is capable of identifying events with CH4 emission rates of 100
kg/hr at a 90 percent probability of detection as demonstrated by
controlled release tests. We allow process knowledge and engineering
estimates in the review of the process data to identify the event start
date. However, we maintain that monitored parameters must be used to
make these assessments. The comments received could be construed to
suggest the facility should be able to pick a start date in the absence
of monitored process parameters. This is inconsistent with our intent
when allowing process knowledge or engineering estimates for

[[Page 42086]]

other reporting elements. To ensure clarity on the use of process
knowledge or engineering estimates, we are retaining the proposed
language that the start time must be determined based on monitored
process parameters and adding that ``sound engineering principles'' are
to be used to determine the start time based on the monitored process
parameter.
We note that most of the monitoring methods suggested by commenters
to identify the start date were already proposed at 40 CFR
98.233(y)(2)(iv). At proposal, we did not include AVO monitoring in the
list of monitoring inspections provided in 40 CFR 98.233(y)(2)(iv)
because the ability of AVO to identify a large event is highly
dependent on the height, location, and characteristics of the release.
However, we also recognize that on-site AVO inspections may identify
some other large release events. If the event is identified via AVO
methods, then we think that it logically follows that it is reasonable
to allow the use of previous AVO inspections conducted for that
equipment to limit the default assumed start date that would otherwise
apply (if no monitoring process parameter data or other monitoring or
measurement survey is available). Therefore, we are adding an
additional sentence to final 40 CFR 98.233(y)(2)(iv) that states that
AVO inspections are considered monitoring surveys if and only if the
event was identified via an AVO inspection.
Reporters are allowed under the final rule and may prefer to
undertake more frequent surveys and submit empirical emissions data
because such an approach could shorten the estimated duration of the
event. The EPA recognizes that the option for reporters to submit
additional empirical data for a given facility may lead to reporters
taking additional voluntary actions for subpart W reporting, including
for the purpose of demonstrating the extent to which a charge under CAA
section 136(c) is owed. As previously explained in response to comment
earlier in this section, to the extent this approach ``incentivizes''
additional actions by the reporter, the EPA considers this to be
inherent in the directives Congress gave the EPA in CAA section 136(h).
The EPA also notes that, as discussed in Section I.E of this preamble,
Congress also provided other provisions under CAA section 136, outside
the scope of this rulemaking, that were intended to be and may provide
incentives; for example, CAA section 136 provides $1.55 billion in
incentives for various specified purposes related to CH4 mitigation and
monitoring, including through grants, rebates, contracts, loans, and
other activities.
Comment: One commenter supported the proposed reporting
requirements for other large release events and supported provisions
ensuring that reporters can only exclude from reported emissions those
coming from third-party notifiers when the reporter provides valid,
well-documented reasons for doing so. To do this, according to the
commenter, the reporter should be required to submit evidence of a site
survey occurring shortly after the notification proving that the event
did not occur or come from their site, including time-stamped
parametric data from the site showing that normal operating conditions
existed. If there is imagery that clearly shows an event at the
reporter's site with a quantified, time-stamped emission rate, it
should not be rebuttable by the reporter according to this commenter.
Several commenters stated that the EPA's proposed reporting
requirements for other large release events are nearly identical to the
proposed super-emitter response program reporting requirements in NSPS
OOOOb and EG OOOOc. According to these commenters, reporting elements
such as the unique notification identification number under the Super-
Emitter Program, latitude/longitude of release, a description of the
technology or method used to identify the release, and the total number
of super-emitter release notifications received from a third-party for
the facility have no bearing or impact on the reporting of GHG
emissions. According to these commenters, GHGRP reporters should not
have to bear the burden of retransmitting that information through a
separate reporting program as it is already being provided to the EPA
through the NSPS program.
Response: As noted previously in this section, we are limiting from
proposal the responsibilities of facilities to respond to third-party
notifications, but we are finalizing many of the proposed reporting
requirements in 40 CFR 98.236(y)(11) for other large release event
reporting pertaining to Super-Emitter Program (under the final NSPS
OOOOb and EG OOOOc) notifications that come from the EPA. We are
finalizing reporting requirements under subpart W for reporters to
indicate the results of any assessment or investigation triggered by
the notification, including the type of event and whether the
identified emissions are included in the subpart W report for a
specific source type or as an other large release event. We are
clarifying in the final rule that facilities must quantify and include
in the facility's annual emissions report emissions events identified
in Super-Emitter Program notices received from the EPA (and the EPA has
not determined that the notification contains a demonstrable error)
unless the owners and operators can certify that the facility does not
own or operate the equipment at the location identified in the
notification or, in situations where there are multiple facilities that
own and operate equipment at the location identified in the
notification, the owners and operators can certify that their facility
does not own or operate the emitting equipment at the location
identified in the notification if they complete certain actions. We are
finalizing additional requirements at 40 CFR 98.233(y)(6) for the
actions required by the owners and operators in order for to certify
that their facility does not own or operate the emitting equipment in
cases where there are multiple oil and gas facilities within 50 meters
of the location identified in the notification. Specifically, owners
and operators must conduct investigations of available data as
specified in 40 CFR 60.5371b(d)(2)(i) through (iv) to identify the
emissions source related to the event notification within 5 days of
receiving the notification. If these investigations do not identify the
emissions source, owners and operators must conduct a complete leak
survey of their equipment within 50 meters of the location identified
in the notification using any one of methods provided in 40 CFR
98.234(a)(1) through (3) within 15 days of receiving the notification.
If that survey also fails to identify the emissions source, the
facility may certify that they took these required actions and that
they do not own or operate the emitting equipment at the location
identified in the notification. Note that, if the reporter owns and
operates the equipment at the location identified in the notification
and there are no other owners or operators of equipment at the location
identified in the notification, then that reporter must account for the
emissions from that event within their subpart W report. With respect
to reporting requirements, if the emissions are not included in the
subpart W report, we are finalizing a reporting requirement that the
facility must have determined, and then must certify, that the
emissions identified in the notification were not from assets under
common ownership or control of the facility. In this manner, we are
requiring that the emissions from all notifications be accounted for
within the subpart W report unless the facility can demonstrate that it
does not own or

[[Page 42087]]

operate the equipment or, if applicable, the emitting equipment at the
location identified in the notice from the EPA.
As previously noted in this section, we are also finalizing that
only for each EPA notification received via the Super-Emitter Program
for which the EPA has not determined that the notification contains a
demonstratable error, the facility would be required to report
information related to the notification. We note, however, that because
the EPA will have vetted and sent to the notifications through the
Super-Emitter Program, we expect that demonstrable errors will be rare.
Because all Super-Emitter Program notifications will be coming from
the EPA for the subpart W other large release event reporting
requirements, we have reduced the reporting requirements under 40 CFR
98.236(y)(11) to focus on those details that the EPA would not already
have regarding the super-emitter event. Specifically, we are
eliminating from the final rule proposed reporting requirements for
latitude and longitude in the notification [at 40 CFR
98.236(y)(11)(ii)] and information on the notifier and method used to
detect emissions by the notifier [at 40 CFR 98.236(y)(11)(iv)]. We
maintain that the remaining reporting elements are important for
understanding which releases are reported as other large release events
and which are reported under other provisions of subpart W.

C. New and Additional Emission Sources

Sources of emissions that are required to be reported to subpart W
are listed in 40 CFR 98.232 for each industry segment, with the
methodology and reporting requirements for each source provided in 40
CFR 98.233 and 98.236, respectively. The EPA is finalizing as proposed
the addition of several emission sources that are anticipated to have a
meaningful impact on reported emissions, are commonplace in the oil and
gas industry, and/or have existing emission calculation methodologies
and reporting provisions in the current subpart W regulatory text. For
some of these emission sources, discussed in additional detail in
section III.C.1. of this preamble, reporting is currently required for
some, but not all, industry segments in which they exist. Other
emission sources, discussed in additional detail in sections III.C.2
through 5 of this preamble, are not currently required to be reported
for any industry segments in which they exist. The addition of sources
to subpart W is expected to enhance the overall quality of the data
collected under the GHGRP and improve the accuracy of total emissions
reported from facilities, consistent with section II.A. of this
preamble.
The following sections detail the final additions of emission
sources to subpart W.
1. Current Subpart W Emission Sources Proposed for Additional Industry
Segments
a. Summary of Final Amendments
Upon review of the U.S. GHG Inventory and the 2021 API Compendium,
as well as other publications,\20\ the EPA determined that several of
the emission sources included in at least one industry segment in
subpart W are not currently required to be reported by facilities in
all the industry segments in which those sources exist. As such,
consistent with section II.A. of this preamble, we are finalizing as
proposed the addition of requirements to report CO<INF>2,</INF>
CH<INF>4,</INF> and nitrous oxide (N<INF>2</INF>O) emissions (as
applicable for the source type) from the following sources under 40 CFR
98.232 and 98.236(a): \21\
---------------------------------------------------------------------------

\20\ For example, American Petroleum Institute (API). Liquefied
Natural Gas (LNG) Operations Consistent Methodology for Estimating
Greenhouse Gas Emissions. Prepared for API by The LEVON Group, LLC.
Version 1.0, May 2015. Available in the docket for this rulemaking,
Docket ID. No. EPA-HQ-OAR-2023-0234.
\21\ It should be noted that the EPA did not identify any
subpart W emission sources missing from the Onshore Petroleum and
Natural Gas Gathering and Boosting industry segment.
---------------------------------------------------------------------------

<bullet> Onshore petroleum and natural gas production: Blowdown
vent stacks.
<bullet> Onshore natural gas processing: Natural gas pneumatic
device venting, Hydrocarbon liquids and produced water storage tank
emissions.
<bullet> Onshore natural gas transmission compression: Dehydrator
vents.
<bullet> Underground natural gas storage: Dehydrator vents,
Blowdown vent stacks, Condensate storage tanks.
<bullet> LNG storage: Blowdown vent stacks, Acid gas removal unit
vents.
<bullet> LNG import and export equipment: Acid gas removal unit
vents.
<bullet> Natural gas distribution: Natural gas pneumatic device
venting, Blowdown vent stacks.
<bullet> Onshore natural gas transmission pipeline: Equipment leaks
at transmission company interconnect metering-regulating stations,
Equipment leaks at farm tap and/or direct sale metering-regulating
stations, Transmission pipeline equipment leaks.
We are also finalizing several revisions that would facilitate
implementation of the final provisions that require reporting of these
emission sources from additional industry segments. We are finalizing
revisions as proposed to change the name of the emission source type
``onshore production and onshore petroleum and natural gas gathering
and boosting st

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