Home/Federal/Federal Register/2023-09918

Proposed Rule2023-09918

Pipeline Safety: Gas Pipeline Leak Detection and Repair

Primary source

Metadata and text below are from the Federal Register, a public-domain U.S. government work. Always verify the official published version before relying on it for any legal matter.

Published

May 18, 2023

Issuing agencies

Transportation DepartmentPipeline and Hazardous Materials Safety Administration

Abstract

PHMSA proposes regulatory amendments that implement congressional mandates in the Protecting our Infrastructure of Pipelines and Enhancing Safety Act of 2020 to reduce methane emissions from new and existing gas transmission pipelines, distribution pipelines, regulated (Types A, B, C and offshore) gas gathering pipelines, underground natural gas storage facilities, and liquefied natural gas facilities. Among the proposed amendments for part 192- regulated gas pipelines are strengthened leakage survey and patrolling requirements; performance standards for advanced leak detection programs; leak grading and repair criteria with mandatory repair timelines; requirements for mitigation of emissions from blowdowns; pressure relief device design, configuration, and maintenance requirements; and clarified requirements for investigating failures. Finally, PHMSA proposes expanded reporting requirements for operators of all gas pipeline facilities within DOT's jurisdiction, including underground natural gas storage facilities and liquefied natural gas facilities.

Full Text

<html>
<head>
<title>Federal Register, Volume 88 Issue 96 (Thursday, May 18, 2023)</title>
</head>
<body><pre>
[Federal Register Volume 88, Number 96 (Thursday, May 18, 2023)]
[Proposed Rules]
[Pages 31890-31979]
From the Federal Register Online via the Government Publishing Office [<a href="http://www.gpo.gov">www.gpo.gov</a>]
[FR Doc No: 2023-09918]

[[Page 31889]]

Vol. 88

Thursday,

No. 96

May 18, 2023

Part III

Department of Transportation

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

Pipeline and Hazardous Materials Safety Administration

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

49 CFR Parts 191, 192, and 193

Pipeline Safety: Gas Pipeline Leak Detection and Repair; Proposed Rule

Federal Register / Vol. 88, No. 96 / Thursday, May 18, 2023 /
Proposed Rules

[[Page 31890]]

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

DEPARTMENT OF TRANSPORTATION

Pipeline and Hazardous Materials Safety Administration

49 CFR Parts 191, 192, and 193

[Docket No. PHMSA-2021-0039]
RIN 2137-AF51

Pipeline Safety: Gas Pipeline Leak Detection and Repair

AGENCY: Pipeline and Hazardous Materials Safety Administration (PHMSA),
Department of Transportation (DOT).

ACTION: Notice of proposed rulemaking (NPRM).

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

SUMMARY: PHMSA proposes regulatory amendments that implement
congressional mandates in the Protecting our Infrastructure of
Pipelines and Enhancing Safety Act of 2020 to reduce methane emissions
from new and existing gas transmission pipelines, distribution
pipelines, regulated (Types A, B, C and offshore) gas gathering
pipelines, underground natural gas storage facilities, and liquefied
natural gas facilities. Among the proposed amendments for part 192-
regulated gas pipelines are strengthened leakage survey and patrolling
requirements; performance standards for advanced leak detection
programs; leak grading and repair criteria with mandatory repair
timelines; requirements for mitigation of emissions from blowdowns;
pressure relief device design, configuration, and maintenance
requirements; and clarified requirements for investigating failures.
Finally, PHMSA proposes expanded reporting requirements for operators
of all gas pipeline facilities within DOT's jurisdiction, including
underground natural gas storage facilities and liquefied natural gas
facilities.

DATES: Written comments on this NPRM must be submitted by July 17,
2023. The agency will, consistent with 49 CFR 190.323, consider late-
filed comments to the extent practicable.

ADDRESSES: You may submit comments identified by the docket number
PHMSA-2021-0039 by any of the following methods:
E-Gov Web: <a href="https://www.regulations.gov">https://www.regulations.gov</a>. This site allows the public
to enter comments on any Federal Register notice issued by any agency.
Follow the online instructions for submitting comments.
Mail: Docket Management System: U.S. Department of Transportation,
1200 New Jersey Avenue SE, West Building Ground Floor, Room W12-140,
Washington, DC 20590-0001.
Hand Delivery: U.S. DOT Docket Management System, West Building
Ground Floor, Room W12-140, 1200 New Jersey Avenue SE, Washington, DC
20590-0001 between 9 a.m. and 5 p.m., Monday through Friday, except
Federal holidays.
Fax: 1-202-493-2251.
Instructions: Please include the docket number PHMSA-2021-0039 at
the beginning of your comments. If you submit your comments by mail,
submit two copies. If you wish to receive confirmation that PHMSA has
received your comments, include a self-addressed stamped postcard.
Internet users may submit comments at <a href="https://www.regulations.gov/">https://www.regulations.gov/</a>.
Note: Comments are posted without changes or edits to <a href="https://www.regulations.gov">https://www.regulations.gov</a>, including any personal information provided. There
is a privacy statement published on <a href="https://www.regulations.gov">https://www.regulations.gov</a>.
Privacy Act: In accordance with 5 U.S.C. 553(c), DOT solicits
comments from the public to better inform its rulemaking process. DOT
posts these comments, without edit, including any personal information
the commenter provides, to <a href="http://www.regulations.gov">www.regulations.gov</a>, as described in the
system of records notice (DOT/ALL-14 FDMS), that can be reviewed at
<a href="http://www.dot.gov/privacy">www.dot.gov/privacy</a>.
Confidential Business Information: Confidential Business
Information (CBI) is commercial or financial information that is both
customarily and actually treated as private by its owner. Under the
Freedom of Information Act (FOIA, 5 U.S.C. 552), CBI is exempt from
public disclosure. If your comments responsive to this document contain
commercial or financial information that is customarily treated as
private, that you actually treat as private, and that is relevant or
responsive to this notice, it is important that you clearly designate
the submitted comments as CBI. Pursuant to 49 CFR 190.343, you may ask
PHMSA to give confidential treatment to information you give to the
agency by taking the following steps: (1) mark each page of the
original document submission containing CBI as ``Confidential''; (2)
send PHMSA, along with the original document, a second copy of the
original document with the CBI deleted; and (3) explain why the
information you are submitting is CBI. Submissions containing CBI
should be sent to Sayler Palabrica, Office of Pipeline Safety (PHP-30),
Pipeline and Hazardous Materials Safety Administration (PHMSA), 2nd
Floor, 1200 New Jersey Avenue SE, Washington, DC 20590-0001, or by
email at <a href="/cdn-cgi/l/email-protection#88fbe9f1e4edfaa6f8e9e4e9eafae1ebe9c8ece7fca6efe7fe">[email&#160;protected]</a>. Any commentary PHMSA receives that
is not specifically designated as CBI will be placed in the public
docket.
Docket: For access to the docket to read background documents or
comments received, go to <a href="http://www.regulations.gov">http://www.regulations.gov</a>. Follow the online
instructions for accessing the docket. Alternatively, you may review
the documents in person at the street address listed above.

FOR FURTHER INFORMATION CONTACT: Sayler Palabrica, Transportation
Specialist, by telephone at 202-744-0825 or by email at
<a href="/cdn-cgi/l/email-protection#85f6e4fce9e0f7abf5e4e9e4e7f7ece6e4c5e1eaf1abe2eaf3">[email&#160;protected]</a>.

SUPPLEMENTARY INFORMATION:
I. Executive Summary
A. Purpose of Regulatory Action
B. Summary of the Major Regulatory Provisions
C. Costs and Benefits
II. Background
A. The Urgency of Methane Emissions Reductions in Confronting
the Climate Crisis
B. Dimensions of the Climate Crisis
C. Methane Emissions From Gas Pipeline Facilities
D. The Need for Updating PHMSA Regulations To Incorporate
Advanced Leak Detection Programs To Reduce Unintentional Releases
From Gas Pipelines
E. The Limits of PHMSA Regulation and State and Operator
Initiatives in Reducing Intentional Methane Releases From Gas
Pipeline Facilities
III. Federal Efforts To Address Climate Change by Reducing Methane
Emissions
A. The PIPES Act of 2020
B. Administration Efforts Confronting the Climate Crisis
C. PHMSA Implementation of the PIPES Act of 2020
IV. Summary of Proposals
A. Leakage Survey and Patrol Frequencies and Methodologies
B. Advanced Leak Detection Programs
C. Leak Grading and Repair
D. Qualification of Leakage Survey, Investigation, and Repair
Personnel
E. Reporting and National Pipeline Mapping System
F. Mitigating Vented and Emissions From Gas Pipeline Facilities
G. Design, Configuration, and Maintenance of Pressure Relief
Devices
H. Investigation of Failures
I. Type B and Type C Gathering Pipelines
J. Miscellaneous Changes in Parts 191 and 192 to Reflect
Codification in Federal Regulation of the Congressional Mandate To
Address Environmental Hazards of Leaks From Gas Pipelines
V. Section-by-Section Analysis
VI. Regulatory Analyses and Notices

I. Executive Summary

A. Purpose of Regulatory Action

This notice of proposed rulemaking (NPRM) proposes a series of
regulatory

[[Page 31891]]

amendments to the Federal pipeline safety regulations (49 CFR parts 190
through 199) in response to a bipartisan congressional mandate in the
Protecting our Infrastructure of Pipelines and Enhancing Safety Act of
2020 (PIPES Act of 2020, Pub. L. 116-260) and in support of the Biden-
Harris Administration's U.S. Methane Emissions Reduction Action Plan.
The amendments would reduce both ``fugitive emissions'' (meaning
unintentional emissions resulting from leaks and equipment failures)
and ``vented emissions'' (meaning those emissions resulting from
blowdowns, equipment design features, and other intentional releases,
also called ``intentional emissions'') from over 2.7 million miles of
gas transmission, distribution, and gathering pipelines and other gas
pipeline facilities as well as 403 underground natural gas storage
facilities (UNGSFs) and 165 liquefied natural gas (LNG) facilities,
thereby improving public safety, promoting environmental justice, and
addressing the climate crisis.
The Federal pipeline safety regulations currently covering leak
detection and repair reflect a regulatory approach focused on public
safety risks posed by incidents on gas pipeline facilities. The
regulations do not sufficiently capture environmental costs, align with
the importance attached to environmental protection in PHMSA's enabling
statutes,\1\ or reflect the scientific consensus that prompt reductions
in methane emissions from natural gas infrastructure are critical to
limiting the impacts of climate change. This current approach also
foregoes opportunities to ensure timely identification and repair of
leaks that can degrade into catastrophic failures and incidents
threatening to public safety. The Federal leak detection and repair
standards for gas pipelines have remained largely unchanged since the
1970s despite significant improvements in leak detection technology and
operator practices and the increasingly urgent and tangible threats
from climate change. The current pipeline safety regulations do not
include any meaningful performance standards for leak detection
equipment, nor requirements that leverage the significant advancements
in the sensitivity, efficiency, and variety of leak detection
technologies in the last five decades. Further, the current pipeline
safety regulations do not explicitly require repair of all--or even
most--leaks on gas pipeline facilities. Leaks that an operator
determines do not to present an existing or probable public safety
hazard do not need to be repaired at all regardless of the resulting
environmental harms posed by that release. Current regulations also do
not prescribe specific timeframes for the timely repair of hazardous or
any other leaks, other than leaks associated with certain metal loss,
cracking, and denting defects that are discovered on gas transmission
piping during an integrity assessment in accordance with gas
transmission integrity management in subpart O of 49 CFR part 192 or
Sec. 192.714. Additionally, despite a new self-executing section of
the PIPES Act of 2020, described below, current regulations tolerate
significant intentional emissions of methane and other gases, even in
non-emergency situations, by allowing venting, blowdowns, and other
large-volume releases of gas from all PHMSA-jurisdictional pipeline
facilities without restriction. Consistent with the pipeline safety
regulations' historical lack of emphasis on the environmental
consequences of gas releases, PHMSA's minimum incident reporting
threshold was established principally to better reflect the economic
consequence of lost gas \2\ and was set at 3 million standard cubic
feet (MMCF), which leaves many large-volume gas releases unreported.
And PHMSA has no reporting requirements for intentional releases of gas
at all.
---------------------------------------------------------------------------

\1\ 49 U.S.C. 60102(b)(1)(B)(ii), 60102(b)(2)(A)(iii),
60102(b)(5), 60102(q)(1)(B), 60102(q)(2)(B)(i).
\2\ Prior to the adoption of the volumetric incident criterion,
the cost of lost gas was included in the property damage
calculation. In the NPRM that proposed the adoption of a volumetric
threshold, PHMSA described both a petition from the Interstate
Natural Gas Association of America noting that more incidents were
reportable due to changes in the cost of gas, as well as a GAO
recommendation (GAO-06-946) to adjust the incident reporting
criteria to account for the cost of lost gas. That NPRM did not
identify environmental considerations among the motivations for that
change in incident reporting requirements. See 74 FR 31675, 31677
(July 2, 2009).
---------------------------------------------------------------------------

Congress targeted these regulatory shortcomings in the bipartisan
PIPES Act of 2020. Section 113 mandated that PHMSA establish
performance standards for leak detection and repair programs for
certain part 192-regulated \3\ gas gathering, transmission, and
distribution operators reflecting commercially available advanced
technology and practices for the identification, location,
categorization, and repair of all leaks that are hazardous to public
safety or the environment. Section 114 of the PIPES Act of 2020,
moreover, requires operators of all pipeline facilities with
maintenance and inspection procedures to update pertinent manuals to
address the elimination of hazardous leaks and minimize releases of
natural gas--whether fugitive emissions from leaks or intentional
releases due to venting from maintenance and other activities--and
repair or remediate pipelines known to leak. And section 118 of the
PIPES Act of 2020 clarified that PHMSA must consider environmental
benefits equally with public safety benefits. The mandates in the PIPES
Act of 2020 align with the importance of addressing climate change by
reducing methane emissions.
---------------------------------------------------------------------------

\3\ Throughout this NPRM, PHMSA uses the phrase ``part 192-
regulated gas gathering pipelines'' to refer to offshore gas
gathering pipelines, as well as Types A, B, and C ``regulated
onshore gas gathering'' pipelines--all of which are subject to
certain part 192 requirements under Sec. Sec. 192.8 and 192.9. Such
``part 192-regulated gas gathering pipelines'' does not include
``reporting-regulated'' or ``Type R'' gas gathering pipelines as
defined in Sec. Sec. 191.3 and 192.8(c)(3), which are not subject
to part 192 safety requirements. Similarly, PHMSA also refers to
``part 192-regulated gas pipelines'' to collectively refer to gas
transmission, distribution, offshore gathering, and Types A, B, and
C onshore gathering pipelines subject to part 192 requirements.
``Gas pipeline facilities'' is defined as ``a pipeline, a right of
way, a facility, a building, or equipment used in transporting gas
or treating gas during its transportation''--this broader definition
applies to all part 192-regulated gas pipelines, UNGSFs, and part
193-regulated LNG facilities. See 49 U.S.C. 60101(a)(3).
---------------------------------------------------------------------------

PHMSA proposes a number of regulatory revisions to minimize
emissions of methane and other (flammable, toxic, or corrosive) gases
from, and improve public safety of, new and existing offshore gas
gathering, regulated onshore gas gathering, transmission and
distribution pipelines, UNGSFs and LNG facilities. PHMSA expects that
the proposed regulatory amendments would yield prompt and meaningful
reduction of methane emissions, a key contributor to climate change;
improve public safety; and mitigate the disproportionate burden of
those environmental and safety risks historically placed on minority,
low-income, or other underserved and disadvantaged populations and
communities.

B. Summary of the Regulatory Provisions

This NPRM contains the following proposed changes to the
regulations: (1) strengthen leakage survey and patrolling requirements
at Sec. Sec. 192.9, 192.705, 192.706, 192.723 for all part 192-
regulated gas pipelines, as well as introduce periodic methane leakage
survey requirements for part 193-regulated LNG facilities; (2)
introduce for all part 192-regulated gas pipelines an Advanced Leak
Detection Program (ALDP) performance standard at a new Sec. 192.763
reflecting the capabilities of

[[Page 31892]]

commercially available advanced technologies and practices; (3) amend
Sec. 192.703 to require operators of all part 192-regulated gas
pipelines to grade and repair all leaks, and not merely those that pose
public safety risks; (4) establish for all part 192-regulated gas
pipelines minimum criteria for leak grades and associated repair
schedules prioritized by safety and environmental hazard at a new Sec.
192.760; (5) require reductions in intentional sources of methane
emissions by minimizing releases associated with blowdowns and other
vented emissions from gas transmission, offshore gas gathering, and
Type A gas gathering pipelines (at Sec. 192.770) and LNG facilities
(at Sec. 193.2523); (6) require operators of certain part 192-
regulated gas pipelines to reduce emissions associated with the design,
configuration, and maintenance of pressure relief devices (Sec. Sec.
192.199 and 192.773); (7) codify in Federal regulations a congressional
requirement for operators of gas pipeline facilities to implement
written procedures to eliminate hazardous leaks, minimize releases of
natural gas, and remediate or replace pipelines known to leak
(Sec. Sec. 192.9, 192.12, 192.605, 193.2503, and 193.2605); (8) expand
reporting requirements (at Sec. Sec. 191.3 and 191.19) and
recordkeeping requirements (at Sec. Sec. 192.760 and 192.773) to
provide higher-quality information on unintentional and intentional gas
releases from gas pipeline facilities; (9) require that Types A, B, and
C gathering pipeline operators submit geospatial pipeline location data
to the National Pipeline Mapping System (NPMS) pursuant to Sec.
191.29; (10) incorporate explicit reference to environmental harm among
the ``hazards'' addressed in certain parts 191 and 192 requirements;
and (11) introduce, for certain components and equipment within part
193-regulated LNG facilities, at a new Sec. 193.2624, requirements for
periodic methane leakage surveys using leak detection equipment and
repair of identified leaks pursuant to operators' written maintenance
or abnormal operations procedures. PHMSA proposes an effective date for
this rulemaking of 6 months following publication of a final rule in
the Federal Register. The eleven proposed requirements are described in
the paragraphs immediately below, and further detail is provided in
sections IV and V.
First, PHMSA proposes increased leakage survey frequencies for
distribution pipelines outside of business districts,\4\ annual leakage
surveys for distribution pipelines that lack cathodic protection or
which are known to leak based on their material (cast-iron,
cathodically unprotected steel, wrought-iron, and certain plastic
pipelines), design, or operational and maintenance history; and for gas
transmission, offshore gathering, and Types A, B, and C gathering
pipelines in high consequence areas (HCAs), with the most frequent
leakage surveys to be performed on gas transmission and Types A and B
gathering pipelines located in HCAs within Class 4 locations. PHMSA
also proposes to increase minimum patrolling frequencies for gas
transmission, offshore gathering, and Type A gathering pipelines and to
introduce requirements for annual patrolling of Type B and Type C
gathering pipelines. Finally, PHMSA proposes to establish methane
leakage survey requirements for LNG facilities other than tanks.
---------------------------------------------------------------------------

\4\ The term ``business district'' is not defined in part 192.
However, in a letter of interpretation PHMSA stated that the term
normally refers to an area ``associated with the assembly of people
in shops, offices and the like,'' marked by the conduct of ``buying
and selling commodities and services, and related transactions.''
See PHMSA, Interpretation Response Letter No. PI-72-038 (Aug. 16,
1972).
---------------------------------------------------------------------------

Second, PHMSA proposes to introduce an ALDP performance standard
that would require operators of part 192-regulated gas pipelines to
demonstrate, by conducting engineering tests and analyses, that their
suite of leak detection equipment, procedures, and analytics are
capable of detecting all leaks above a minimum concentration threshold
when measured in close proximity to the pipeline. PHMSA proposes to
require that leakage surveys be performed using commercially available
advanced technology and practices consistent with the proposed ALDP
performance standard. PHMSA also proposes to require a minimum
sensitivity for leak detection equipment used in leakage surveys and
leak investigations. PHMSA proposes to limit the use of human or animal
senses for leakage surveys to offshore, submerged gas transmission and
gathering pipelines. Human senses may also be used for gas transmission
and regulated gas gathering lines in Class 1 and Class 2 locations
outside of HCAs, but only with prior notification to and no objection
from PHMSA in accordance with Sec. 192.18.
Third, PHMSA proposes to require operators of gas transmission,
distribution, and part 192-regulated gathering pipelines to identify,
locate, classify, and repair in a timely manner all leaks. Part 192
provisions governing the repair of leaks are narrowly focused on public
safety risks associated with ignition of large-volume, instantaneous
releases and accumulated gas; they are unclear regarding when, if at
all, most leaks must be repaired. Although some--not all--part 192-
regulated pipelines are subject to a general maintenance requirement in
Sec. 192.703(c) to ``promptly repair hazardous leaks,'' part 192
maintenance requirements neither define ``hazardous leak'' in terms of
risks to the environment nor establish meaningful timelines for repair
of hazardous or any other leaks. These proposed amendments would
address the section 113 mandate of the PIPES Act of 2020 requiring
identification, location, classification, and repair of leaks hazardous
to either public safety or the environment.
Fourth, this NPRM proposes that operators of gas transmission,
distribution, and part 192-regulated gathering pipelines must classify
and repair all identified leaks on a schedule that depends on the
severity of public safety and environmental risks. PHMSA's proposed
requirements build on the tiered framework of the Gas Piping Technology
Committee (GPTC) ``Guide for Gas Transmission and Distribution Piping
Systems'' \5\ leak grading and repair criteria. PHMSA's proposed
framework would require the classification of every leak (as either
grade 1, grade 2, or grade 3) and to prioritize remediation of leaks
posing the most significant risks to public safety or the environment.
---------------------------------------------------------------------------

\5\ Gas Piping Technology Committee Z380, ANSI GPTC Z380.1-2022,
``The Guide for Gas Transmission, Distribution, and Gathering Piping
Systems'' Including Addenda 1 and 2 (2022).
---------------------------------------------------------------------------

Fifth, PHMSA proposes requirements for the mitigation of
intentional emissions such as blowdowns on gas transmission, offshore
gas gathering, and Type A gas gathering pipelines and LNG facilities.
This proposal requires an operator to choose from among prescribed,
proven, cost-effective mitigation measures when performing blowdowns
related to operations, maintenance, or construction.
Sixth, PHMSA proposes requirements for operators of gas
transmission, distribution, offshore gathering, and Types A, B, and C
gathering pipelines to design and configure all new and modified
pressure relief and limiting devices to minimize unnecessary releases
and to assess and remediate any relief devices that operate outside of
the tolerances established in the operator's procedures. These proposed

[[Page 31893]]

requirements would minimize unintended and unnecessary releases of gas
to the atmosphere, better protecting against environmental and public
safety hazards posed by malfunctioning or poorly designed and
configured pressure relief devices.
Seventh, PHMSA proposes to codify in regulation self-executing
requirements from section 114 of the PIPES Act of 2020, which obliges
operators of gas pipeline facilities to have written procedures that
address the elimination of hazardous leaks, minimize releases of
natural gas, and provide for repair or replacement of pipelines known
to leak based on material, design, or past operating and maintenance
histories. These changes would support PHMSA's cooperation with states
undertaking inspection and enforcement activity in connection with
those requirements.
Eighth, this NPRM proposes a series of changes to part 191
reporting requirements. PHMSA proposes to introduce requirements for
reporting large-volume releases of gas from all gas pipeline
facilities, including intentional releases, that are not currently
captured by the definition of an incident in part 191. Specifically,
this NPRM proposes to create a report for both unintentional releases
and, for the first time, intentional releases of 1 MMCF or more of gas
from any gas pipeline facility. PHMSA also proposes revisions to annual
reporting requirements for gas transmission, distribution, offshore
gathering, and Types A, B, and C gathering pipelines to convey
information regarding the number and grade of all leaks detected and
repaired each calendar year as well as estimated emissions from those
leaks.
Ninth, this NPRM further proposes to extend NPMS reporting
requirements at Sec. 191.29 to offshore gas gathering pipelines as
well as Types A, B, and C onshore gas gathering pipelines.
Tenth, this NPRM proposes incorporation of explicit reference to
environmental harm among the ``hazards'' addressed in certain part 191
and 192 requirements, consistent with section 118 of the PIPES Act of
2020. PHMSA's proposed expansion of the concept of ``hazards'' to
encompass environmental harms would not extend to integrity management
(IM) regulations in part 192, subparts O (gas distribution pipelines)
and P (gas transmission pipelines), which would remain focused on
safety, and certain other existing requirements directed at hazards to
public safety in particular (described in detail in section IV.J).
Finally, this NPRM proposes a new Sec. 193.2624 that would oblige
operators of part 193-regulated LNG facilities to perform quarterly
methane leakage surveys of non-tank equipment and components within an
LNG facility using leak detection equipment satisfying the minimum 5
parts per million (ppm) sensitivity proposed elsewhere within this
NPRM. Operators would also need to repair any leaks identified in a
manner and on a schedule consistent with their maintenance or abnormal
operations procedures. PHMSA also proposes conforming changes to annual
report forms for LNG facilities to ensure meaningful reporting of
methane leaks discovered and repaired pursuant to the proposed Sec.
193.2624.

C. Costs and Benefits

Consistent with Executive Order (E.O.) 12866 and the requirements
of the Federal Pipeline Safety Laws,\6\ PHMSA has prepared an
assessment of the benefits and costs (to include pertinent commercial
benefits, public safety benefits, environmental benefits, equity
benefits, compliance costs, and other risks) of this proposed rule, as
well as reasonable alternatives. PHMSA estimates that emission
reductions under the proposed rule correspond to approximately 72
percent of unintentional emissions from regulated gathering pipelines,
17 percent of unintentional emissions from transmission pipelines, and
44 to 62 percent of unintentional emissions from distribution
pipelines. These shares are relative to modeled baseline emissions
projected over the period of analysis based on the pipeline mileage,
empirical emission factors, and existing survey and repair practices.
Further, PHMSA estimates that the total avoided blowdown emissions
under the proposed rule correspond to approximately 43 percent of
baseline blowdown emissions. PHMSA estimates that the proposed rule
would result in monetized net benefits between $341 to $1,440 million
per year using a 3 percent discount rate. PHMSA also anticipates
additional unquantified benefits to public safety and the environment,
each discussed throughout this NPRM and its supporting documents
(including the Preliminary Regulatory Impact Analysis (RIA) and draft
Environmental Assessment (EA), each available in the docket for this
NPRM).
---------------------------------------------------------------------------

\6\ 49 U.S.C. 60101 et seq. (Federal Pipeline Safety Laws). The
specific provision referenced in the above discussion is 49 U.S.C.
60102(b)(5).
---------------------------------------------------------------------------

The regulatory amendments proposed in this NPRM are expected to
improve public safety, reduce threats to the environment (including,
but not limited to, reduction of methane emissions contributing to the
climate crisis), and promote environmental justice for minority
populations, low-income populations, and other underserved and
disadvantaged communities. Additionally, reducing product losses
results in cost savings for natural gas shippers and consumers and
improves the efficiency and reliability of U.S. energy infrastructure.
PHMSA expects that each of the elements of this rulemaking as proposed
in this NPRM would be technically feasible, reasonable, cost-effective,
and practicable because of the public safety, environmental, and equity
benefits of the proposed regulatory amendments described in this NPRM
and its supporting documents (including the Preliminary RIA and draft
EA) which justify any associated costs. PHMSA has preliminarily
determined that the proposed rule is superior to alternatives
considered in the Preliminary RIA.

II. Background

A. The Urgency of Methane Emissions Reductions in Confronting the
Climate Crisis

The primary component of natural gas is methane (CH<INF>4</INF>).
Methane is a greenhouse gas, or GHG, which means that its concentration
in the atmosphere affects the climate and temperature of the Earth by
trapping heat in the atmosphere. Methane is released from both natural
and anthropogenic sources, the latter of which includes leaks and other
releases from natural gas pipeline systems. Methane is the second most
abundant anthropogenic GHG in the Earth's atmosphere, after carbon
dioxide (CO<INF>2</INF>), by concentration and accounts for the second-
greatest contribution to total radiative forcing (warming effect).\7\
The Environmental Protection Agency (EPA) calculated that methane made
up approximately 11 percent (by mass of CO<INF>2</INF> equivalents) of
the annual GHG emissions in 2019 within the United States, whereas
carbon dioxide made up 79 percent of the total GHG emissions over the
same period.\8\ According to the 2021 installment of the Sixth
Assessment Report (2021 IPCC Report) from Working Group I of the
Intergovernmental Panel on Climate Change (IPCC), the atmospheric
concentration of methane gas was

[[Page 31894]]

measured at 1,866 parts per billion (ppb), compared with 410 ppm of
carbon dioxide.\9\
---------------------------------------------------------------------------

\7\ National Oceanic and Atmospheric Administration (NOAA),
``Annual Greenhouse Gas Index'' at Figure 3 & Table 2 (Spring 2022),
<a href="https://gml.noaa.gov/aggi/aggi.html">https://gml.noaa.gov/aggi/aggi.html</a>.
\8\ EPA, ``Overview of Greenhouse Gases,'' <a href="https://www.epa.gov/ghgemissions/overview-greenhouse-gases#methane">https://www.epa.gov/ghgemissions/overview-greenhouse-gases#methane</a> (last accessed
December 5, 2022).
\9\ IPCC, Climate Change 2021: The Physical Science Basis.
Contribution of Working Group I to the Sixth Assessment Report of
the Intergovernmental Panel on Climate Change, Summary for
Policymakers (SPM)-5 (2021). In the 2021 IPCC Report, atmospheric
concentration of CH<INF>4</INF> since 1984 (1980 for CO<INF>2</INF>)
is based on merging observed gas concentration in the lower
troposphere from the NOAA Global Monitoring Laboratory and the
Advanced Global Atmospheric Gases Experiment monitoring networks.
Emissions in 1850 and earlier are estimated based on assessments of
multiple ice cores. 2021 IPCC Report, Table 2.2 and Table AIII.1a.
---------------------------------------------------------------------------

However, this comparatively small concentration of methane in the
atmosphere makes an outsized contribution to climate change. The 2021
IPCC Report notes that anthropogenic methane emissions account for
approximately one-third of warming of global average surface
temperatures attributed to well-mixed GHG \10\ emissions since
1850.\11\ The IPCC also noted that in 2019, atmospheric CH<INF>4</INF>
concentrations were higher than at any time in 800,000 years, and that
``strong, rapid and sustained reductions in CH<INF>4</INF> emissions''
would be needed to offset short-term warming effects.\12\
---------------------------------------------------------------------------

\10\ According to the IPCC, well-mixed GHGs include
CO<INF>2</INF>, N<INF>2</INF>O, and CH<INF>4.</INF> 2021 IPCC
Report, 2.2. These gases ``generally have lifetimes of more than
several years'' and therefore are relatively uniformly distributed
within the troposphere (lower-atmosphere). 2021 IPCC Report, 2.2.3.
\11\ 2021 IPCC Report, SPM-8.
\12\ 2021 IPCC Report, SPM-9, SPM-36.
---------------------------------------------------------------------------

Once emitted into the atmosphere, some GHGs can persist in the
atmosphere for a long time. Carbon dioxide, for instance, remains in
the atmosphere for 300 to 1000 years.\13\ Methane, on the other hand,
is more short-lived than CO<INF>2</INF> but is much more potent in
trapping heat in the atmosphere. Methane only lasts in the atmosphere
for approximately 12 years once released; however, it traps
approximately 25 times more energy than an equal mass of carbon dioxide
over a 100-year period.\14\ Because methane is a more potent, but more
short-lived, GHG compared to carbon dioxide, reducing methane emissions
would have a more rapid and significant effect on reducing heat-
trapping potential of the atmosphere than an equivalent reduction in
carbon dioxide and would therefore result in a greater effect on
climate change mitigation in the short term.\15\
---------------------------------------------------------------------------

\13\ Buis, ``The Atmosphere: Getting a Handle on Carbon
Dioxide'' (Oct. 9, 2019).
\14\ EPA, ``Overview of Greenhouse Gases,'' <a href="https://www.epa.gov/ghgemissions/overview-greenhouse-gases">https://www.epa.gov/ghgemissions/overview-greenhouse-gases</a> (last accessed July 20,
2022).
\15\ EPA, ``Importance of Methane,'' <a href="https://www.epa.gov/gmi/importance-methane">https://www.epa.gov/gmi/importance-methane</a> (last accessed July 20, 2022).
---------------------------------------------------------------------------

Authoritative scientific projections underscore the need for
achieving a prompt reduction in methane emissions. The 2021 IPCC Report
concluded that urgent action to reduce emissions across all GHG
categories is necessary to minimize global warming and avoid the most
destructive effects of climate change.\16\ The report details five
possible future emissions and warming scenarios: two high emissions
scenarios (SSP3-7.0 and SSP5-8.5), an intermediate scenario with
emissions similar to the status quo through mid-century (SSP2-4.5), and
two relatively low-emissions scenarios (SSP1-1.9 and SSP1-2.6). Of
these, only the two low-emissions scenarios are likely to hold
temperature increases below the Paris Agreement's target of limiting
the increase in global average surface temperature to 2.0 [deg]C above
1850 levels by the end of the century,\17\ and only the very low-
emissions scenario (SSP1-1.9) is likely to limit warming to 1.5 [deg]C
by the end of the century (specifically, between 1.0 [deg] to 1.8
[deg]C above 1850 levels, consistent with the Paris Agreement). Both of
those low-emissions scenarios require cutting methane emissions by
approximately half of 2015 levels before 2050.\18\ Rapid and full-scale
efforts to reduce methane and other GHG emissions are needed to achieve
the very low-emissions scenario (SSP1-1.9).\19\ In contrast, the
intermediate scenario (SSP2-4.5) results in potentially dangerous
warming of 2.0 [deg]C by midcentury, rising to between 2.1 [deg] to 3.5
[deg]C by 2100.
---------------------------------------------------------------------------

\16\ PHMSA acknowledges much of the discussion in section II and
elsewhere in this NPRM is focused on methane emissions from natural
gas pipeline facilities, as those facilities constitute the great
majority of gas pipeline facilities subject to parts 191 and 192.
However, PHMSA parts 191 and 192 requirements are not limited to
natural gas pipelines; rather, they also apply to pipeline
facilities transporting other gases which are flammable, toxic, or
corrosive--releases of which may entail significant public safety or
environmental consequences (including potential contributions to
climate change) in their own right. See Sec. Sec. 191.3 and 192.3
(definitions of ``gas'' for the purposes of parts 191 and 192,
respectively).
\17\ 2021 IPCC Report, 1.2.
\18\ 2021 IPCC Report, SPM-16, Table SPM.1.
\19\ 2021 IPCC Report, Table SPM.1.
---------------------------------------------------------------------------

B. Dimensions of the Climate Crisis

Near-term methane emissions reductions are especially compelling
because global climate change is already causing observable, damaging
effects on the environment. The 2021 IPCC Report shows that the
environmental and social consequences of climate change are no longer
abstract, distant problems: scientists note increased surface
temperature, extreme weather events, rising sea levels, and other
consequences are being felt today and predict those effects will
intensify in the coming decades without immediate action to control GHG
emissions to avoid or stave off the worst effects of climate change.
Higher average surface temperatures will result in sea level rise,
severe heat waves, and more intense extreme weather events (hurricanes,
storms, droughts, and floods), in turn altering water supplies,
damaging habitats, and promoting wildfires. According to the findings
from the 3rd and 4th National Climate Assessment Reports released by
the U.S. Global Change Research Program,\20\ these dimensions of
climate change will have severe consequences for the human population
throughout the United States including alteration of population
distributions; widespread property damage; compromised local economies;
disrupted agriculture, fisheries, and other ecosystems; and degraded
public health.
---------------------------------------------------------------------------

\20\ See U.S. Global Change Research Program, Climate Science
Special Report: Fourth National Climate Assessment, Volume I (2017);
U.S. Global Change Research Program, Climate Change Impacts in the
United States: The Third National Climate Assessment (2014).
---------------------------------------------------------------------------

The most immediate impact of climate change worldwide has been, and
will continue to be, an increase in average surface temperatures. The
average global surface temperature during 2021 was 1.51 degrees
Fahrenheit (0.84 degrees Celsius) warmer than the average temperature
in the 20th century (57.0 degrees Fahrenheit) and was 1.87 degrees
Fahrenheit (1.04 degrees Celsius) warmer than the average temperature
between 1880-1900, which NOAA describes as a ``reasonable surrogate for
pre-industrial conditions.'' \21\ That observed surface temperature
increase has resulted in cascading consequences for the natural world
already; as more GHGs are added to the atmosphere, the rate of warming
is expected to continue to accelerate.
---------------------------------------------------------------------------

\21\ See NOAA National Centers for Environmental Information,
Monthly Global Climate Report for Annual 2021 (Jan. 2022), <a href="https://www.ncei.noaa.gov/news/global-climate-202112">https://www.ncei.noaa.gov/news/global-climate-202112</a>.
---------------------------------------------------------------------------

Increasing the average surface temperature of the Earth changes the
frequency and intensity of extreme temperature events. Higher average
surface temperatures means that heat waves everywhere will become more
frequent and more intense.\22\ The IPCC estimates that current levels
of warming

[[Page 31895]]

have made 10-year extreme heat events \23\ approximately 1.2 degrees
Fahrenheit more intense and 2.8 times more frequent. Likewise, the IPCC
estimates that 50-year extreme heat events have become 4.8 times more
frequent. The estimated frequency and intensity of extreme heat events
will increase further with additional warming, especially in warmer
summer months.\24\
---------------------------------------------------------------------------

\22\ 2021 IPCC Report, SPM-8, SPM-18.
\23\ Defined by the IPCC as ``daily maximum temperatures over
land that were exceeded on average once in a decade (10-year event)
or once every 50 years (50-year event) during the 1850-1900
reference period.'' See 2021 IPCC Report, SPM-24.
\24\ 2021 IPCC Report, SPM-23.
---------------------------------------------------------------------------

A well-known consequence of elevated (average and instantaneous)
surface temperatures is rising sea levels. The global sea level has
risen by about 5.9-9.8 inches (0.15-0.25 meters) between 1901 and 2018
and the rate of increase and degree to which sea level rise can be
attributed with confidence to anthropogenic climate change have both
increased since 1971.\25\ The IPCC has determined that it is
``virtually certain'' that the global sea level will rise further by
2100, as land ice continues to melt and seawater expands as it warms,
with greater sea level rise resulting from higher GHG emissions
scenarios.\26\ An expected contributor to global sea level rise is the
loss of virtually all summer ice from the Arctic Ocean before 2050.\27\
Global average sea levels are projected to rise an additional 1.0-4.3
feet by 2100 under intermediate emissions scenarios, with a global sea
level rise in excess of 8 feet possible by 2100 under higher emissions
scenarios.\28\
---------------------------------------------------------------------------

\25\ 2021 IPCC Report, SPM-6.
\26\ 2021 IPCC Report, SPM-28.
\27\ European Space Agency (ESA), ``Simulations Suggest Ice-Free
Arctic Summers by 2050'' (May 13, 2020), <a href="https://climate.esa.int/en/projects/sea-ice/news-and-events/news/simulations-suggest-ice-free-arctic-summers-2050/">https://climate.esa.int/en/projects/sea-ice/news-and-events/news/simulations-suggest-ice-free-arctic-summers-2050/</a>.
\28\ U.S. Global Change Research Program, Impacts, Risks, and
Adaptation in the United States: Fourth National Climate Assessment,
Volume II--Southeast at 758. (2018).
---------------------------------------------------------------------------

Rising average surface temperatures also alter water cycles and
weather patterns such as precipitation and hurricanes. As noted above,
higher average and instantaneous surface temperatures will result in
loss of soil moisture in most regions. Meanwhile, some areas are
increasingly likely to experience heavy downpours, while other areas
will likely receive far less precipitation than in years past.\29\
Areas that are projected to have less total precipitation and higher
temperatures will likely become more susceptible to drought and
wildfires as a result; as described below, the United States has
already seen the acreage affected by wildfires trend upwards in recent
decades. Scientists also project that the recent trend toward more
frequent heavy precipitation events will continue, even in areas where
the total precipitation is expected to decrease, which could lead to
increased flooding risks, erosion, and land subsidence. As further
noted below, earth and water movement are also threats to pipeline
integrity that can lead to pipeline incidents and accidents that
threaten public safety and the environment.\30\ Similarly, scientists
have observed that it is likely that hurricanes have become stronger
and more intense and determined that it is likely that anthropogenic
climate change has increased rainfall rates associated with hurricanes
and other tropical cyclones.\31\
---------------------------------------------------------------------------

\29\ 2021 IPCC Report, SPM-15.
\30\ PHMSA, ``Pipeline Safety: Potential for Damage to Pipeline
Facilities Caused by Earth Movement and Other Geological Hazards,''
87 FR 33576 (June 2, 2019) (Advisory Bulletin ADB-2022-01).
\31\ 2021 IPCC Report, SPM-9.
---------------------------------------------------------------------------

The United States has a front-row seat to the effects of climate
change. Already, many areas of the United States are seeing increases
in the duration and frequency of heat waves and altered precipitation
patterns. The 2021 IPCC Report describes observed increases in extreme
heat and drought events occurring around the world, including western
North America.\32\ The Colorado River in the Southwest United States is
facing its first-ever water shortage, a phenomenon that is directly
linked to warming temperatures. Due to this historic shortage, in 2022,
the U.S. Department of the Interior`s Bureau of Reclamation proposed
significant cuts to water allocations from the Colorado River to
Arizona, Nevada, and Mexico in order to ensure continued operation of
hydroelectric generation facilities.\33\ In late June and early July of
2021, the Western part of the United States and Canada suffered a heat
wave that was likely exacerbated by climate change, with consequences
ranging as far north as the Yukon territory in Canada, and as far
inland as the State of Montana. Much of the Pacific Northwest reached
temperatures that were 20 to 35 degrees Fahrenheit above normal during
this heat wave, with several daily high temperature records being
broken. Temperatures grew so hot that nighttime low temperatures in
many areas were higher than historical average daytime high
temperatures.
---------------------------------------------------------------------------

\32\ 2021 IPCC Report, SPM-12.
\33\ Yanchin, ``Interior Threatens Colorado River Cuts,'' E&E
News (Oct. 28, 2022), <a href="https://www.eenews.net/articles/interior-threatens-colorado-river-cuts/">https://www.eenews.net/articles/interior-threatens-colorado-river-cuts/</a>.
---------------------------------------------------------------------------

Higher average surface temperatures and extreme instantaneous
temperatures have also exacerbated wildfires in the United States.
Prolonged heat has led to dry vegetation, and the heat and dry
vegetation have contributed to the severity of several wildfires.
According to the research compiled in the 4th National Climate
Assessment, drought in California and the Colorado River Basin have
made forests ``more susceptible to burning'' and caused ``spring-like
temperatures to occur earlier in the year,'' extending the western fire
season \34\ and doubling the cumulative forest area burned by wildfires
between 1984 and 2015.\35\ Wildfires pose serious health risks,
including illnesses from smoke inhalation and contaminated drinking
water, and cause significant property damage ($3.1 billion in the Los
Angeles area alone from 1990 to 2009, or approximately $4 billion in
2021 dollars).\36\ The 4th National Climate Assessment cautions that
the frequency and intensity of wildfires in the Western United States
will increase with further warming, with higher emissions scenarios
estimating a 25% increase in wildfires in the Southwest region and
three times as many wildfires that exceed 5,000 hectares in size.\37\
Researchers at the University of California, Los Angeles and Columbia
University have determined that the 22-year period from 2000-2021 was
the driest such period in the Southwestern United States since the year
800, due in large part to climate change.\38\ Climate change poses a
significant threat of extending the drought even further. In fact, the
Southwestern drought is expected to persist through at least the end of
2022 and become the longest megadrought on record in the Southwestern
United States, further endangering sources of water, and the

[[Page 31896]]

communities that rely on them, throughout the region.\39\
---------------------------------------------------------------------------

\34\ U.S. Global Change Research Program, Impacts, Risks, and
Adaptation in the United States: Fourth National Climate Assessment,
Volume II--Southwest at 1115, 1116 (2018).
\35\ U.S. Global Change Research Program, Impacts, Risks, and
Adaptation in the United States: Fourth National Climate Assessment,
Volume II--Southwest at 1115, 1135 & Figure 25.4 (2018).
\36\ U.S. Global Change Research Program, Impacts, Risks, and
Adaptation in the United States: Fourth National Climate Assessment,
Volume II--Southwest at 1116 (2018); Inflation adjustment via
Consumer Price Index inflation from December 2009 to December 2021.
\37\ U.S. Global Change Research Program, Impacts, Risks, and
Adaptation in the United States: Fourth National Climate Assessment,
Volume II--Southwest at 1116 (2018).
\38\ Williams et al., ``Rapid Intensification of the Emerging
Southwestern North American Megadrought in 2020-2021,'' 12 Nature
Climate Change (Mar. 1, 2022).
\39\ Williams et al., ``Rapid Intensification of the Emerging
Southwestern North American Megadrought in 2020-2021,'' 12 Nature
Climate Change (Mar. 1, 2022).
---------------------------------------------------------------------------

The United States will also experience dramatically altered
precipitation and weather patterns from climate change. Increases in
GHG concentrations in the atmosphere have already led to increased
Atlantic hurricane activity, and a warming climate is projected to
cause extreme rainfall and significant regional flooding from
hurricanes, nor'easters, and other severe storms, in addition to
exacerbating the intensity of hurricanes in the Atlantic and eastern
North Pacific.\40\ While projections are difficult to make for
infrequent, smaller weather events like tornadoes and severe
thunderstorms, these events have also been recently exhibiting changes
that may be caused by climate change.\41\ Moreover, tornadoes can be
generated by hurricanes (such as the 25 tornadoes produced by Hurricane
Irma in 2017, mostly along the east coast of Florida), and more intense
hurricanes could generate more tornadoes.
---------------------------------------------------------------------------

\40\ U.S. Global Change Research Program, Impacts, Risks, and
Adaptation in the United States: Fourth National Climate Assessment,
Volume II--Our Changing Climate at 74, 95 (2018) (noting the
heaviest rainfall amounts from recent storms have been estimated to
be 6-7% greater than the most intense storms of the early 1900s).
\41\ U.S. Global Change Research Program, Impacts, Risks, and
Adaptation in the United States: Fourth National Climate Assessment,
Volume II--Our Changing Climate at 97 (2018).
---------------------------------------------------------------------------

Climate change-induced sea level rise is and will continue to be
experienced in the United States. Sea level rise has already led to
more frequent high tide flooding. One study of flooding in 27
communities cited in the Fourth National Climate Assessment found that
the frequency of high tide flooding in several communities has
increased by a factor of 5 or more, and that such flooding increased by
a factor of 10 or more in Atlantic City (NJ), Baltimore (MD), Annapolis
(MD), Wilmington (DE), Port Isabel (TX), and Honolulu (HI).\42\ In the
Southeast, tidal data from the National Oceanic and Atmospheric
Administration shows sea level rise of 1-3 feet has already occurred
over the past 100 years. The effects of sea level rise are not
distributed equally across the world, nor along the U.S. coastline;
instead, the Northeast United States, eastern coast of Florida, and
western Gulf Coast regions will likely experience the worst impacts
from rising sea levels and coastal flooding due to ocean circulation,
land subsidence, and uneven ice melt. The 4th National Climate
Assessment identifies an average of 2 to 4.5 feet as the most probable
sea level rise in the Northeast United States before 2100 with worst-
case estimates projecting sea level rise of more than 11 feet over the
same period.\43\ Under higher emission projections, the 4th National
Climate Assessment found it likely that all U.S. coastlines, other than
Alaska, will experience sea level rise greater than the global averages
due to Antarctic ice loss. By 2100, sea level rise is likely to
submerge real estate worth between $238-507 billion across the United
States and force the migration of substantial elements of the U.S.
population.\44\ Average sea level rise of 6 feet by 2100 could displace
an estimated 13.1 million people along the U.S. coasts.\45\
---------------------------------------------------------------------------

\42\ Sweet & Park, ``From the Extreme to the Mean: Acceleration
and Tipping Points of Coastal Inundation from Sea Level Rise,
Earth's Future 2 at 579-600 (2014).
\43\ U.S. Global Change Research Program, Impacts, Risks, and
Adaptation in the United States: Fourth National Climate Assessment,
Volume II--Northeast at 692 (2018).
\44\ U.S. Global Change Research Program, Impacts, Risks, and
Adaptation in the United States: Fourth National Climate Assessment,
Volume II--Coastal Effects at 330, 335 (2018).
\45\ U.S. Global Change Research Program, Impacts, Risks, and
Adaptation in the United States: Fourth National Climate Assessment,
Volume II--Coastal Effects at 335 (2018).
---------------------------------------------------------------------------

These and other dimensions of the climate crisis also have
disastrous near and long-term consequences for human health. The EPA
Administrator, as early as 2009 \46\ (and again in 2016),\47\
determined that methane along with 5 other ``well-mixed greenhouse
gases'' together constituted a harmful air pollutant that endangered
public health and welfare of persons. According to the 2016 assessment
of human health impacts of climate change from the U.S. Global Change
Research Program (2016 Assessment), climate change will likely
contribute to ``thousands to tens of thousands of premature heat-
related deaths in the summer'' in the United States in the years
ahead.\48\ Indeed, the heat wave in summer 2021 discussed above
resulted in excess heat-related deaths of 143 in Washington, 119 in
Oregon, 13 in California, and 619 in British Columbia according to
public health authorities.\49\ The 2016 Assessment also notes climate
change is likely to result in ``meteorological conditions increasingly
conducive to forming ozone over most of the United States,'' which is
likely to result in ``premature deaths, hospital visits, lost school
days, and acute respiratory symptoms.'' \50\ The 4th National Climate
Assessment also notes that, in addition to the immediate hazard to life
and property, climate change-induced wildfires will result in direct
hazards to human health in the form of burns, smoke inhalation,
exacerbation of particulate and ozone pollution, and negative impacts
on water quality.\51\
---------------------------------------------------------------------------

\46\ 74 FR 66495 (Dec. 15, 2009).
\47\ 81 FR 54422 (Aug. 15, 2016).
\48\ U.S. Global Change Research Program, The Impacts of Climate
Change on Human Health in the United States: A Scientific
Assessment--Executive Summary at 6 (2016).
\49\ U.S. Department of Health and Human Services, Office of
Climate Change and Health Equity, Climate and Health Outlook:
Extreme Heat (June 2022), <a href="https://www.hhs.gov/sites/default/files/climate-health-outlook-june-2022.pdf">https://www.hhs.gov/sites/default/files/climate-health-outlook-june-2022.pdf</a>; British Columbia, ``Minister's
Statement on 619 Lives Lost During 2021 Heat Dome'' (June 7, 2022).
<a href="https://news.gov.bc.ca/26965">https://news.gov.bc.ca/26965</a>.
\50\ Methane also directly contributes to adverse air quality
because it is a chemical precursor to ozone.
\51\ U.S. Global Change Research Program, Impacts, Risks, and
Adaptation in the United States: Fourth National Climate Assessment,
Volume II--Water at 154 (2018); U.S. Global Change Research Program,
Impacts, Risks, and Adaptation in the United States: Fourth National
Climate Assessment, Volume II--Air Quality at 514, 519 (2018); U.S.
Global Change Research Program, Impacts, Risks, and Adaptation in
the United States: Fourth National Climate Assessment, Volume I--
Southeast at 755 (2018).
---------------------------------------------------------------------------

Increased intensity and frequency of extreme weather events (such
as hurricanes and floods) from climate change also threaten human life
and property. In the Northeast, high-tide flooding will impact low-
lying areas with increased frequencies and could result in an
additional $6--9 billion in damages per year by 2100 in high emissions
scenarios.\52\ In 2017, Hurricane Irma caused, in the United States,
the deaths of 84 people and costs of approximately $50 billion (with
Florida suffering most of these costs). In the Midwest, the Fourth
National Climate Assessment found precipitation has increased by
between 5% to 15% since the 1901-1960 period; the Fourth National
Climate Assessment projects that seasonal precipitation during winter
and spring associated with flood risk could increase by ``by up to 33%
by the end of the century.'' \53\ Extreme precipitation events and
river flooding could damage private property and transportation
infrastructure and overwhelm stormwater treatment facilities, resulting
in water quality impacts, especially in communities with combined sewer
overflows. In the Southern Great Plains States, increased frequency and
severity of severe floods was also projected for the southern

[[Page 31897]]

Great Plains states, potentially resulting in significant costs from
flood damage and adaptation costs.\54\ The Fourth National Climate
Assessment also found climate change-induced degradation of natural
habitats, agricultural resources, water resources, and other ecological
resources threaten the viability of subsistence and commercial
activities that Federally recognized Indian Tribes depend on, such as
``agriculture, hunting and gathering, fisheries, forestry, energy,
recreation, and tourism,'' and threaten Tribal water allocations in the
Western United States.\55\
---------------------------------------------------------------------------

\52\ U.S. Global Change Research Program, Impacts, Risks, and
Adaptation in the United States: Fourth National Climate Assessment,
Volume II--Northeast at 695 (2018).
\53\ U.S. Global Change Research Program, Impacts, Risks, and
Adaptation in the United States: Fourth National Climate Assessment,
Volume II--Midwest at 914-16 (2018).
\54\ U.S. Global Change Research Program, Impacts, Risks, and
Adaptation in the United States: Fourth National Climate Assessment,
Volume II--Southern Great Plains at 1003-06 (2018).
\55\ U.S. Global Change Research Program, Impacts, Risks, and
Adaptation in the United States: Fourth National Climate Assessment,
Volume II--Tribes and Indigenous Peoples at 579 (2018).
---------------------------------------------------------------------------

Increased severe whether phenomena caused by climate change further
threaten human health by wreaking havoc on public services and
infrastructure. Hurricane Nicholas in the Gulf of Mexico in September
2021 caused widespread flooding and weeks of blackouts on the U.S. Gulf
Coast, much as the increasingly long wildfire season in California is
now routinely accompanied by threats of rolling blackouts. The summer
2021 heat wave that blanketed the Western United States damaged
transportation infrastructure, closing multiple lanes on Interstate 5
and causing trains to operate at reduced speeds as a precaution against
the potential deformation of rail tracks. Earlier, the 2017 Atlantic
hurricane season produced the second and third costliest hurricanes in
U.S. history, hurricane Harvey and Hurricane Maria. Hurricane Harvey
caused more than 60 inches of rainfall over the Texas Gulf Coast,
including the Houston metro area, and resulted in at least 68 direct
casualties and approximately $125 billion in storm-related damage.\56\
Hurricane Maria caused widespread devastation in Puerto Rico, resulting
in approximately $90 billion dollars in damage and the near total loss
of electric, water, and telecommunication infrastructure across the
island, and electrical outages persisted for months across much of the
island.\57\
---------------------------------------------------------------------------

\56\ Eric S. Blake and David A. Zelinsky. NOAA National
Hurricane Center. `National Hurricane Center Tropical Cyclone
Report.'' May 9, 2018. <a href="https://www.nhc.noaa.gov/data/tcr/AL092017_Harvey.pdf">https://www.nhc.noaa.gov/data/tcr/AL092017_Harvey.pdf</a>.
\57\ Richard J. Pasch, Andrew B. Penny, and Robbie Berg. NOAA
National Hurricane Center. ``National Hurricane Center Tropical
Cyclone Report: Hurricane Maria.'' February 14, 2019. At page 7.
<a href="https://www.nhc.noaa.gov/data/tcr/AL152017_Maria.pdf">https://www.nhc.noaa.gov/data/tcr/AL152017_Maria.pdf</a>.
---------------------------------------------------------------------------

Pipeline infrastructure is similarly vulnerable to the impacts of
climate change. For example, well-documented threats to pipeline
infrastructure from natural force damage (which includes incidents
caused by acts of nature such as flooding, land movement, and
lightning) are likely to be exacerbated by climate change. On April 11,
2019, PHMSA published an advisory bulletin on the threat that severe
flooding can have on pipeline integrity, especially at water
crossings.\58\ As described in further detail in the advisory bulletin,
flooding and related earth movements can cause damage to pipelines in
and around water crossings from direct water force, impacts from
debris, added strain on pipeline structures through changes in loading
conditions, and other means. Flooding can also threaten pipeline
integrity by causing damage to aboveground, safety-critical components
such as valves, pressure regulators, relief devices, and pressure
sensors. A weather-induced failure of a gas pipeline can result in
releases that threaten public safety and further contribute to climate
change. On May 2, 2019, PHMSA issued another advisory bulletin to
remind operators of the risks to pipeline facilities from large earth
movement, including subsidence and erosion events that can be
intensified due to climate change.\59\ PHMSA issued an update to this
advisory bulletin on June 2, 2022, noting recent incidents and
accidents underscoring the risks described in Advisory Bulletin ADB-
2019-02.\60\ This most recent bulletin notes that changing weather
patterns due to climate change can weaken soil stability, increasing
the likelihood of earth movement damage to pipeline facilities.
---------------------------------------------------------------------------

\58\ PHMSA, ``Pipeline Safety: Potential for Damage to Pipeline
Facilities Caused by Flooding, River Scour, and River Channel
Migration,'' 84 FR 14715 (Apr. 11, 2019) (Advisory Bulletin ADB-
2019-01).
\59\ PHMSA, ``Pipeline Safety: Potential for Damage to Pipeline
Facilities Caused by Earth Movement and Other Geological Hazards,''
84 FR 18919 (May 2, 2019) (Advisory Bulletin ADB-2019-02).
\60\ PHMSA, ``Pipeline Safety: Potential for Damage to Pipeline
Facilities Caused by Earth Movement and Other Geological Hazards,''
87 FR 22576 (June 2, 2022) (Advisory Bulletin ADB-2022-01).
---------------------------------------------------------------------------

PHMSA has also documented serious pipeline integrity threats from
hurricanes in an advisory bulletin published on September 1, 2011,
titled ``Pipeline Safety: Potential for Damage to Pipeline Facilities
Caused by the Passage of Hurricanes.'' \61\ This advisory bulletin
notes that hurricanes can directly damage pipelines, cause submerged
pipelines to become exposed, or otherwise cause pipeline facilities to
become a hazard to navigation. The advisory bulletin also noted that in
2005, Hurricane Katrina and Hurricane Rita caused extensive damage to
onshore and offshore oil and gas production and transportation
infrastructure in the Gulf of Mexico, which took substantial time and
resources to contain and remediate. PHMSA expects more severe and
frequent hurricanes will amplify the risk of damage to pipeline
facilities, to the detriment of coastal communities, environments, and
the reliability of the U.S. oil and gas industry.
---------------------------------------------------------------------------

\61\ PHMSA, ``Pipeline Safety: Potential for Damage to Pipeline
Facilities Caused by the Passage of Hurricanes,'' 76 FR 54531 (Sept.
1, 2011) (Advisory Bulletin ADB-11-050).
---------------------------------------------------------------------------

Finally, these and other consequences of climate change have been,
and are expected to continue to be, disproportionately borne by
vulnerable populations in the United States--in particular by minority
and low-income populations, outdoor laborers, children, and the
elderly.\62\ Some communities of color may be uniquely vulnerable to
climate change health impacts in the United States because they live in
areas where the impacts of climate change (e.g., extreme temperatures
and flooding) are likely to be the most significant, and because these
communities tend to have limited adaptive opportunities due to a
greater dependence on climate-sensitive resources (such as local water
and food supplies), economic opportunities (e.g., seasonal labor), and
limited access to social and information resources. The 2016 scientific
assessment on the Impacts of Climate Change on Human Health similarly
found that social determinants of health (e.g., access to healthcare,
economic stability) are highly likely to contribute to climate change-
related health impacts.\63\ And insofar as gas transmission and gas
gathering pipeline infrastructure is often located in the vicinity of
socially vulnerable populations,\64\ those populations would face the
greatest risks in the event of a release from a gas pipeline damaged by
climate change-induced extreme weather events.
---------------------------------------------------------------------------

\62\ U.S. Global Change Research Program, The Impacts of Climate
Change on Human Health in the United States: A Scientific
Assessment--Executive Summary at 6 (2016).
\63\ U.S. Global Change Research Program, The Impacts of Climate
Change on Human Health in the United States: A Scientific Assessment
at 21 (2016).
\64\ See Emanuel et al., ``Natural Gas Gathering and
Transmission Pipelines and Social Vulnerability in the United
States,'' 5 GeoHealth (June 2021).
---------------------------------------------------------------------------

C. Methane Emissions From Gas Pipeline Facilities

Most gas produced or consumed in the United States is transported
by a gas

[[Page 31898]]

pipeline at some stage of its lifecycle. PHMSA is, by statute (49
U.S.C. 60101 et seq.), responsible for regulating the interstate
transportation of gas by pipeline facilities, which can include the
gathering, transmission, and distribution of natural gas as well as
other gases regulated under parts 191 and 192.\65\ Federal law,
however, provides that the certified State agencies have jurisdiction
to regulate purely intrastate gas pipeline facilities. Certain
certified State programs may also inspect interstate pipelines, such as
interstate distribution systems. Both Federal and State regulation of
gas pipeline facilities has historically been directed toward the
immediate, direct risks to public safety (and indirect risks to the
environment) associated with the ignition of natural gas releases--less
so on the direct threat to environmental risks, including those risks
posed by un-ignited, released methane, that invariably contribute to
climate change.\66\
---------------------------------------------------------------------------

\65\ Parts 191 and 192 govern not only natural gas, but also any
``flammable gas, or gas which is toxic or corrosive.'' See
Sec. Sec. 191.3 and 192.3 (definitions of ``gas''). Consequently,
the proposed revisions to parts 191 and 192 within this NPRM would
apply not only to natural gas pipelines but also to other gas
pipeline governed by parts 191 and 192.
\66\ PHMSA acknowledges that in revising its Pipeline Safety
Regulations over the years, it has identified environmental benefits
of those efforts in much the same way that it has identified other
benefits (e.g., reduced compliance cost for operators, equity, etc.)
of those rulemakings. However, PHMSA submits those non-safety
benefits were generally presented as secondary benefits of safety-
focused regulatory amendments.
---------------------------------------------------------------------------

1. Gas Pipeline Facilities
PHMSA regulations cover several types of gas pipeline facilities,
including gas gathering pipelines, gas transmission pipelines, gas
distribution pipelines, LNG facilities, and UNGSFs.
Gathering Pipelines
A gas gathering pipeline is defined in Federal regulations at Sec.
192.3 as a pipeline that transports gas from a production facility to a
transmission pipeline or main. More generally, these pipelines
``gather'' gas from production facilities for transport to a gas
processing plant for further transportation across transmission
pipelines. The precise points where a gathering pipeline begins and
ends are defined in Sec. Sec. 192.8 and 192.9 and the first edition of
American Petroleum Institute (API) Recommended Practice 80,
``Guidelines for the Definition of Onshore Gas Gathering Lines.'' \67\
---------------------------------------------------------------------------

\67\ API, Recommended Practice 80: Guidelines for the Definition
of Onshore Gas Gathering Lines (Apr. 2000) (API RP 80).
---------------------------------------------------------------------------

Section 192.9(b) provides that offshore gas gathering pipelines are
generally subject to the same part 192 requirements as gas transmission
pipelines. Section 192.8 also defines three types of regulated onshore
gas gathering pipelines subject to part 192 requirements: Type A, Type
B, and Type C gathering pipelines. Operators reported 8,290 miles of
Type A pipelines, 3,078 miles of Type B pipelines, and 5,706 miles of
offshore gathering lines in their 2021 annual reports. Type C gathering
line operators will be required to submit their first annual report for
calendar year 2022 in 2023; PHMSA estimates that there are
approximately 90,000 miles of Type C gathering lines.\68\ Type A and
Type B gathering pipelines are located in Class 2, Class 3, or Class 4
locations. Type A gathering pipelines are higher-pressure pipelines and
subject to most part 192 safety requirements applicable to gas
transmission pipelines, while Type B gathering pipelines are lower
pressure pipelines subject to a smaller subset of specific part 192
safety requirements listed in Sec. 192.9(d). The Type C gathering
pipeline designation was established in a final rule titled ``Pipeline
Safety: Safety of Gas Gathering Pipelines: Extension of Reporting
Requirements, Regulation or Large, High-Pressure Lines, and Other
Related Amendments'' published on Nov. 15, 2021.\69\ Type C gathering
pipelines are located in Class 1 locations, have an outside diameter
greater than or equal to 8.625 inches, and operate at high
pressure.\70\ These pipelines are subject to scaled safety requirements
in Sec. 192.9(e), with more part 192 safety requirements applicable as
a function of the risk posed to public safety based on the diameter of
the Type C segment (which affects the potential energy of a pipeline
rupture and explosion) and its proximity to nearby populated
structures. For example, Sec. 192.9(e) provides that while all Type C
lines are required to carry out a damage prevention program, leakage
survey requirements only attach to either the largest (outside diameter
greater than 16 inches) Type C lines, or those Type C lines with
smaller diameters (8.625 inches through 16 inches) near buildings
intended for human occupancy.
---------------------------------------------------------------------------

\68\ See PHMSA, Doc. No. PHMSA-2011-0023, ``Regulatory Impact
Analysis: Pipeline Safety: Expansion of Gas Gathering Regulation
Final Rule'' at 11, 15 (Nov. 2021) (Gas Gathering RIA).
\69\ 86 FR 63266 (Gas Gathering Final Rule). Certain smaller-
diameter Type C gas gathering pipelines are the subject of a
temporary enforcement discretion whereby PHMSA has committed not to
pursue enforcement action against those pipelines for alleged
violations of certain part 192 safety requirements before May 17,
2024. See PHMSA, ``Notice of Limited Enforcement Discretion for
Particular Type C Gas Gathering Pipelines'' (July 8, 2022), <a href="https://www.phmsa.dot.gov/news/notice-limited-enforcement-discretion-particular-type-c-gas-gathering-pipelines">https://www.phmsa.dot.gov/news/notice-limited-enforcement-discretion-particular-type-c-gas-gathering-pipelines</a>.
\70\ See the pressure criteria in the second column of table 1
in Sec. 192.8(c)(2).
---------------------------------------------------------------------------

Type A, Type B, and certain Type C gathering pipelines (namely,
those Type C gathering pipelines that are installed, replaced,
relocated, or otherwise changed after May 16, 2023) must comply with
the design, construction, initial inspection, and initial testing
requirements applicable to gas transmission lines, and must therefore
be constructed from similar materials. According to annual reports
submitted to PHMSA, gas transmission pipelines and Type A and Type B
regulated onshore gathering lines are generally made from steel and, to
a lesser extent, polyethylene plastic. An operator may also use two
polyamide compounds, PA-11 and PA-12. Composite materials \71\ may be
used with notification to PHMSA on a Type C gathering pipeline. PHMSA
expects that most Type C gathering pipelines, which have operational
characteristics similar to gas transmission and Type A regulated gas
gathering pipelines, are made of steel, but Type C pipelines existing
prior to May 16, 2023, may have been constructed with non-standard
materials.
---------------------------------------------------------------------------

\71\ ``Composite materials'' are defined in Sec. 192.3 as
materials used to make pipe or components manufactured with a
combination of either steel and/or plastic and with a reinforcing
material to maintain its circumferential or longitudinal strength.
---------------------------------------------------------------------------

Transmission Pipelines
A gas transmission pipeline is defined in Sec. 192.3 to include
any pipeline, other than a gathering pipeline, that transports gas from
a gathering pipeline or storage facility to a distribution center,
storage facility, or large-volume customer such as a gas power station
or an LNG facility. In 2021, operators reported 301,524 miles of gas
transmission pipelines on their annual reports. Additionally, a
pipeline other than a gathering pipeline that operates at a hoop stress
of 20% or more of the specified minimum yield strength (SMYS),\72\ or
that transports gas within a storage field, is also classified as a gas
transmission pipeline. An operator may also voluntarily designate a
pipeline as a gas transmission pipeline that would otherwise meet the
definition of a gas gathering pipeline or gas distribution

[[Page 31899]]

pipeline. Gas transmission pipelines are typically steel, larger
diameter (6 to 48 inches), high-pressure lines (operating pressures
generally between 200 and 1500 pounds per square inch) transporting
large volumes of gas long distances.
---------------------------------------------------------------------------

\72\ SMYS is defined in 49 CFR 192.3 to mean specified minimum
yield strength, which is a measure of tensile strength. As an
example, Trade B pipe made to API 5L specification has a specified
minimum yield strength (SMYS) of 35,000 pounds per square inch (psi)
40 percent of SMYS (35,000 x 0.40) is 14,000 psi.
---------------------------------------------------------------------------

Distribution Pipelines
A gas distribution pipeline is defined at Sec. 192.3 as a pipeline
other than a gas transmission pipeline or gathering pipeline.
Distribution pipelines are typically a part of a distribution system
that transports gas received from a transmission pipeline by a
distribution center (often located at the so-called ``city gate''), and
then to homes and businesses through a network of gas mains and service
pipelines.\73\ A gas distribution service pipeline feeds gas to one or
two customers, while a distribution main is the common source of supply
for two or more service pipelines. In 2021, distribution operators
reported 2,300,793 miles of gas distribution mains and service lines on
their annual reports. While virtually all gas transmission piping is
fabricated from steel, gas distribution pipeline materials vary
depending on the vintage and usage. Modern systems are predominately
polyethylene plastic and protected steel (i.e., coated with corrosion-
resistant materials and/or equipped with cathodic protection); older
systems may contain cast-iron or bare (not protected) steel piping.
Distribution pipelines made of copper, wrought iron, and non-
polyethylene plastic also exist but are less common.
---------------------------------------------------------------------------

\73\ Under 49 U.S.C. 60105 and 60106, States may assume safety
authority over intrastate gas pipelines through certifications and
agreements with PHMSA. Currently, the District of Columbia, Puerto
Rico, and all States except Alaska and Hawaii exercise safety
oversight authority over all intrastate gas distribution pipelines
within State lines. These State programs conduct regular inspections
and enforce State safety regulations over intrastate distribution
pipelines. See PHMSA's State Programs website for more information:
<a href="https://www.phmsa.dot.gov/working-phmsa/state-programs/state-programs-overview">https://www.phmsa.dot.gov/working-phmsa/state-programs/state-programs-overview</a> (last accessed Dec. 20, 2022).
---------------------------------------------------------------------------

LNG Facilities
An LNG facility is defined in Federal regulations at 49 CFR part
193 \74\ as a gas pipeline facility that is used for liquefying natural
gas or synthetic gas or transferring, storing, or vaporizing LNG. LNG
means natural gas or synthetic gas having methane as its principal
constituent, and which has been changed to a liquid, thereby reducing
the volume of the gas to facilitate storage and long-distance
transportation. LNG facilities are subject to the safety requirements
in part 193. LNG facilities include gas pipeline facilities that either
change gas into LNG (liquefaction) or that change LNG back into a vapor
or gaseous state (vaporization). LNG facilities also include transfer
piping systems that transfer LNG between any of the following:
liquefaction process facilities, storage tanks, vaporizers,
compressors, cargo transfer systems, and facilities other than gas
pipeline facilities. In 2021, operators reported 168 in-service LNG
facilities on their annual reports.
---------------------------------------------------------------------------

\74\ Part 193 requirements may change as a result of regulatory
amendments proposed in a forthcoming notice of proposed rulemaking
issued under RIN 2137-AF45. PHMSA's references to part 193 within
this NPRM--including the proposed amended regulatory text at its
conclusion--reflect current regulatory text and organization.
---------------------------------------------------------------------------

Underground Natural Gas Storage Facilities
Finally, an UNGSF is defined at Sec. 192.3 as a gas pipeline
facility that stores natural gas underground incidental to the
transportation of natural gas, including: (1) a depleted hydrocarbon
reservoir; (2) an aquifer reservoir; or (3) a solution-mined salt
cavern. In addition to the storage reservoir or cavern itself, an UNGSF
includes: injection, withdrawal, monitoring, and observation wells;
wellbores and downhole components; wellheads and associated wellhead
piping; wing-valve assemblies that isolate the wellhead from connected
piping beyond the wing-valve assemblies; and any other equipment,
facility, right-of-way, or building used in the underground storage of
natural gas. Most underground natural gas storage occurs in depleted
natural gas reservoirs. UNGSFs are subject to specific safety
requirements set forth in Sec. 192.12.
2. Sources of Emissions From Gas Pipeline Facilities
Emissions of methane and other gases subject to PHMSA's regulations
under part 192 occur in all sectors of the natural gas industry--from
production/extraction facilities, gathering pipelines, processing
facilities (where the gas is made suitable for transportation and use),
transmission pipelines, distribution pipelines, and end user
facilities.\75\ Emissions occur during normal operation, routine
maintenance, and abnormal conditions (such as incidents). Gas pipeline
facilities emit methane and other gases from ``fugitive emissions''
from system upsets (incidents and abnormal operations that result in
the release of gas); unintentional leaks from line pipe, flanges,
valves, meter sets, and other equipment; and intentional releases (such
as when a gas pipeline facility is blown down for repairs or
maintenance or through pressure relief device operation as designed or
configured). Older pipelines and pipelines known to leak based on their
material (e.g., legacy materials such as cast iron, wrought iron,
unprotected steel, and certain historic plastics), design, or past
operating and maintenance history are generally more susceptible to
leaks.
---------------------------------------------------------------------------

\75\ Although the evaluation of release data discussed in this
section II.C.2 and subsequent sections is focused on the location,
frequency, and severity of leaks on natural gas pipeline facilities,
that analysis is largely applicable to leaks on other part 192-
regulated gas pipeline facilities. Indeed, certain part 192-
regulated gas pipeline facilities (e.g., gas pipeline facilities
transporting hydrogen gas) may be particularly susceptible to leaks
because of (inter alia) the smaller size of hydrogen gas molecules
compared to methane molecules of which natural gas is mostly
composed.
---------------------------------------------------------------------------

The EPA compiles and publishes data on the magnitude and sources of
methane emissions from gas gathering, transmission, and distribution
pipelines and other gas pipeline facilities. The EPA has two
complementary programs for characterizing GHG emissions such as
methane: the Inventory of Greenhouse Gas Emissions and Sinks
(Greenhouse Gas Inventory, or GHGI), and the Greenhouse Gas Reporting
Program (GHGRP).
<bullet> The 2022 GHGI estimates a time series of total annual
national-level GHG emissions across sectors of the economy using a
large number of data inputs including GHGRP, research studies, and
national and subnational activity data sets. The most recent final GHGI
(2022 GHGI) includes estimates from 1990 through 2020.\76\ The GHGI
includes estimates of GHG emissions from sources including fossil fuel
combustion, industrial processes, agriculture, and transportation. The
GHGI is updated annually.
---------------------------------------------------------------------------

\76\ EPA, Inventory of U.S. Greenhouse Gas Emissions and Sinks:
1990-2020 (Apr. 15, 2022) (2022 GHGI).
---------------------------------------------------------------------------

<bullet> The Greenhouse Gas Reporting Program (GHGRP) has, since
2010, collected facility-level emissions data from certain large GHG
emission sources, fuel and industrial gas suppliers, and CO<INF>2</INF>
injection sites in the United States including large suppliers or
facilities that emit more than 25,000 metric tons of CO<INF>2</INF>
equivalent per year.\77\
---------------------------------------------------------------------------

\77\ In the GHGI, the EPA estimates that the global warming
potential of 1 metric ton of CH<INF>4</INF> is equivalent to 25
metric tons of CO<INF>2</INF> over a 100-year time horizon. (40 CFR
98, Table A-1 to Subpart A of Part 98).
---------------------------------------------------------------------------

For the 2020 reporting year, subpart W facilities in the GHGRP
included 164 reports from distribution operators and 45 reports from
gas transmission pipeline operators. However, GHGRP

[[Page 31900]]

data is not congruent with the pipelines subject to PHMSA regulations.
For example, the 45 gas transmission pipeline operators submitting
reports under GHGRP for the 2020 reporting year correspond only to
approximately \2/3\ of gas transmission pipeline mileage
nationwide.\78\ Additionally, certain entire sectors, such as the
agricultural sector, are not required to report to the GHGRP. The
creation of the GHGRP was provided for by Congress in the fiscal year
2008 Consolidated Appropriations Act (Pub. L. 110-161) and promulgated
under section 114 of the Clean Air Act.\79\ Data must be reported to
EPA by March 31 of each year. Petroleum and natural gas industries,
including natural gas distribution facilities, onshore natural gas
gathering and boosting, onshore natural gas transmission pipelines
(including compression), and LNG storage/terminal facilities are
covered under 40 CFR part 98, subpart W.
---------------------------------------------------------------------------

\78\ One operator may submit multiple GHGRP reports if they
operate multiple systems or in multiple states.
\79\ 42 U.S.C. 7414.
---------------------------------------------------------------------------

The GHGI estimates for methane emissions are generally developed by
multiplying an emissions factor by an activity factor. For example, for
distribution main leaks, an emission factor in kg CH<INF>4</INF> per
mile by material type is multiplied by mileage data by material type
(an activity factor) from PHMSA annual reports. Each itemized emissions
segment or source in the GHGI has its own emissions factor, in many
cases derived from GHGRP data. EPA annually updates the methodology in
the GHGI to improve accuracy and completeness.\80\ The current GHGI
quantifies emissions from leaks in pipelines using the following
approaches and data:
---------------------------------------------------------------------------

\80\ Refer to tables 3.6-2, 3.6-6, and 3.6-17 of Annex 36 of the
2022 GHGI for more information on the methodologies or data sources
used by EPA to develop each emissions factor.
---------------------------------------------------------------------------

<bullet> Gathering pipeline leaks. Emission factors are developed
using year specific GHGRP data. GHGRP data are used as the activity
factor as well. GHGRP data are reported by material type.
<bullet> Transmission pipeline leaks. Data from EPA/GRI 1996 were
used to develop the emission factor. PHMSA mileage data are used as the
national activity factor.
<bullet> Distribution pipeline leaks. Data from Lamb et al. 2015
were combined with EPA/GRI 1996 to develop the material-specific
emission factors. PHMSA main mileage and service line count data are
used as the national activity factor, by material type.
Recent research using modern leak detection equipment indicates
that overall fugitive methane emissions from gas pipeline facilities
may be significantly underestimated in current methane emissions
estimates. The methodology of multiplying an activity factor (such as
pipeline mileage) by an emissions factor to extrapolate an estimate of
overall emissions for a given source is considered a ``bottom-up''
approach that can be contrasted with a ``top-down'' approach taking
total emissions measured at larger (e.g., national) scales and
attributing emissions to specific sources through modeling. Top-down
approaches regularly estimate higher total emissions in the atmosphere
than have been estimated by bottom-up approaches (sometimes referred to
as the ``top-down/bottom-up gap''). For example, recent analysis using
top-down methods from the International Energy Agency (IEA) released in
early 2022 found that global methane emissions from the energy sector
are about 70% greater than the official statistics reported by national
governments.\81\ IEA used satellite-based sensor technologies,
atmospheric methane measurements, and data processing techniques to
capture total emissions over large areas and attribute those emissions
to facility-level sources, rather than by simply multiplying activity
factors by bottom-up emissions factors. Other studies comparing the two
approaches have consistently shown that bottom-up approaches may
underestimate total U.S. methane emissions by 50% or more.\82\ One
explanation suggested for the significant discrepancy in estimated
emissions is that bottom-up methods under-sample large but infrequent
emissions events such as malfunctions and venting, possibly due to the
difficulty and risks associated with taking samples during such
events.\83\ Furthermore, as discussed below, recent research also
indicates that potential under-estimation of pipeline facility
emissions could be particularly pronounced in connection with
distribution and gathering pipelines. EPA has recently proposed
adjustments to its GHGRP data collection for reporting 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 for reporting emissions
from equipment at onshore petroleum and natural gas production and
onshore petroleum and natural gas gathering and boosting
facilities.\84\ Additional discussion of emissions factors for gas
pipelines is available in the Preliminary RIA for this NPRM available
in the rulemaking docket.
---------------------------------------------------------------------------

\81\ IEA, Press Release, ``Methane emissions from the energy
sector are 70% higher than official figures'' (Feb. 23, 2022),
<a href="https://www.iea.org/news/methane-emissions-from-the-energy-sector-are-70-higher-than-official-figures">https://www.iea.org/news/methane-emissions-from-the-energy-sector-are-70-higher-than-official-figures</a>. IEA's analysis may
underestimate the full extent of methane emissions as satellite data
used by the organization do not provide complete coverage of all
global oil and gas operations.
\82\ Zavala-Araiza et al., ``Reconciling Divergent Estimates of
Oil and Gas Methane Emissions,'' 112 Proceedings of the National
Academy of Sciences of the United States of America 11597-98 (Dec.
22, 2015); Lyon et al., ``Constructing a Spatially Resolved Methane
Emission Inventory for the Barnett Shale Region,'' 49 Environmental
Science & Technology at 8147, 8154 (July 7, 2015); Alvarez et al.,
``Assessment of Methane Emissions from the U.S. Oil and Gas Supply
Chain,'' Science 186 (June 21, 2018).
\83\ Brandt et al., ``Methane Leakage from North American
Natural Gas Systems,'' Science 343, 345 (Feb. 13, 2014); Zavala-
Araiza et al., 2015, at 15598; Lyon, at al., 2015, at 8147, 8155;
Alvarez et al., 2018, at 183. The authors of the Brandt, Zavala-
Araiza, and Lyon studies also suggest that this underestimation of
emissions could be due to (or exacerbated by) incomplete activity
factors that omit certain emissions source activities (such as
inaccurate component counts or even the omission of entire
facilities). Further, the authors of the Brandt study point to
limited sample sizes and changing technologies as other potential
sources of error in bottom-up emissions estimates.
\84\ EPA, ``Revisions and Confidentiality Determinations for
Data Elements under the Greenhouse Gas Reporting Rule--Notice of
Proposed Rulemaking'' 87 FR 36920, 36927 (June 21, 2022).
---------------------------------------------------------------------------

Methane Emissions Data--All Natural Gas Pipeline Facilities
The 2022 GHGI estimated annual net methane emissions from U.S.
natural gas systems in 2020 to be 6,6,137 thousand metric tons
(kt).\85\ Gas transmission, gas distribution, transportation-related
gas and LNG storage, and regulated gas gathering lines as determined in
Sec. 192.8 are regulated by PHMSA. On the other hand, exploration,
production, gas processing plants, and Type R unregulated gas gathering
lines are not regulated by PHMSA.). Assuming approximately one third of
gathering and boosting emissions are attributable to regulated gas
gathering lines, approximately half of net methane emissions from
natural gas systems are from PHMSA-regulated pipeline facilities. The
sector classifications used in the GHGI may not correspond precisely
with the regulatory definitions of different types of pipeline
facilities in the Federal Pipeline Safety Regulations. In EPA's GHGI,
the gathering and

[[Page 31901]]

boosting sources include gathering and boosting stations (with multiple
sources on site) and gathering pipelines. Those sources include PHMSA-
regulated gas gathering lines, Type R gathering lines, and some
pipelines and activities that are better described as production and
not transportation.\86\ The GHGI data cited in this section is for
natural gas systems, and therefore would be covered under the
regulatory classifications in part 192. The EPA definition is similar
in principle to the definition of a gas ``gathering line'' in part 192,
although it references some gas treatment processes that could be
classified as a ``production operation'' rather than as a gathering
pipeline under Sec. 192.9 and the first edition of API RP 80, and
therefore not under PHMSA's jurisdiction. However, for the purposes of
estimating emissions from leaks and incidents on PHMSA-regulated gas
gathering pipelines, PHMSA believes that the emissions rate associated
with ``pipeline leaks'' from ``gathering and boosting'' piping as
defined by EPA would not be significantly different than the emissions
rate for gas gathering pipelines as defined by PHMSA.
---------------------------------------------------------------------------

\85\ Natural gas systems include exploration, production,
gathering, processing, transmission, storage, and distribution of
gas. The 2022 GHGI inventory introduced estimates of post-meter
emissions. Emissions from power generation are estimated elsewhere
in the GHGI.
\86\ 2022 GHGI. Pg. 3-90.
---------------------------------------------------------------------------

While natural gas exploration and production (i.e., the upstream
sector) is the single largest source category, approximately one-third
of total methane emissions are attributed to transmission, storage, and
distribution systems, and an additional one-fourth of total methane
emissions is attributed to natural gas gathering and boosting systems.
A summary of these high-level emissions estimates is shown in the table
below and represent the net methane emissions \87\ for 2020 from
section 3.7 and annex 3.6 of the 2022 GHGI. These figures represent
only methane emissions and do not include, for example, CO<INF>2</INF>
emissions from compressor station engines.
---------------------------------------------------------------------------

\87\ Net emissions estimates include estimated emissions
reductions from reported implementation of EPA Methane Challenge and
Gas STAR best practices by operators in the production, transmission
and storage and distribution sectors and estimated reductions from
EPA regulatory requirements.

2022 GHGI: 2020 Natural Gas Systems Net Methane Emissions
------------------------------------------------------------------------
Source Kt CH4 Percent
------------------------------------------------------------------------
Exploration and Production (excluding 1,964 32
gathering).............................
Gathering and Boosting.................. 1,500 24
Processing Plants....................... 494 8
Transmission, Storage, and LNG.......... 1,625 26
Distribution............................ 554 9
-------------------------------
Total............................... 6,137 100
------------------------------------------------------------------------

Methane Emissions Data--Natural Gas Distribution Pipelines
The GHGI estimates that in 2020, approximately half of methane
emissions from natural gas distribution systems was caused by leaks
from and incidents on gas distribution line pipe. Leaks from customer
meters, meter stations, and regulator stations comprise most of the
remaining emissions. Recent studies indicate, however, that current
methane emissions data likely significantly under-estimates methane
emissions from gas distribution pipelines. For example, a national
study focusing on the natural gas distribution sector estimated
emissions from mains that were five times larger than those in the GHGI
estimate for 2017 estimates (0.69 million metric tons of methane vs.
0.14 million metric tons) \88\ and by extension the GHGI estimate for
2020 as well (0.69 million metric tons of methane vs. 0.13 million
metric tons).\89\ The current methodology for calculating the emissions
factors from natural gas distribution main and service pipelines in the
GHGI was most recently updated in 2016 \90\ and relies on a 1996 report
by the U.S. EPA and the Gas Research Institute (GRI) \91\ and a 2015
study by Lamb et. al.\92\ The 2020 study by Weller et.al. attributed
the differences to a larger number of leaks than previously estimated
and better quantification of the largest leaks from the distribution
sector (so-called ``super-emitter'' leaks), which contribute
significantly to overall emissions.\93\
---------------------------------------------------------------------------

\88\ Weller et al., ``A National Estimate of Methane Leakage
from Pipeline Mains in Natural Gas Local Distribution Systems,'' 54
Environmental Science & Technology 8958, 8966 (June 10, 2020).
\89\ EPA, Inventory of U.S. Greenhouse Gas Emissions and Sinks:
1990-2020, Annex 3.6-1 (Apr. 15, 2022).
\90\ U.S. EPA. ``Inventory of U.S. Greenhouse Gas Emissions and
Sinks 1990-2014: Revisions to Natural Gas Distribution Emissions''.
Pgs. 10-13. (April 2016). <a href="https://www.epa.gov/sites/default/files/2016-08/documents/final_revision_ng_distribution_emissions_2016-04-14.pdf">https://www.epa.gov/sites/default/files/2016-08/documents/final_revision_ng_distribution_emissions_2016-04-14.pdf</a>.
\91\ EPA & Gas Research Institute, Methane Emissions from the
Natural Gas Industry (June 1996) (the 1996 GRI/EPA Report).
\92\ Lamb et al., ``Direct Measurements Show Decreasing Methane
Emissions from Natural Gas Local Distribution Systems in the United
States,'' 49 Environmental Science & Technology 5161 (Mar. 31,
2015).
\93\ Weller et al., 2020, at 8958-59.

2022 GHGI: 2020 Natural Gas Distribution Systems Emissions by Category
------------------------------------------------------------------------
Source Kt CH4 Percent
------------------------------------------------------------------------
Main Pipeline Leaks..................... 132.0 23.8
Service Pipeline Leaks.................. 70.8 12.8
Mishaps (e.g., Incidents)............... 68.6 12.4
Meter/Regulator Stations................ 44.4 8.0
Customer Meters......................... 235.4 42.5
Pipeline Blowdown....................... 2.1 0.4
Relief Device Venting................... 1.2 0.2
-------------------------------
Total............................... 554.5 100
------------------------------------------------------------------------
Note the PHMSA definition of a service pipeline in Sec. 192.3 includes
the customer meter in most configurations.

[[Page 31902]]

Unlike natural gas transmission systems, the GHGI separately
estimates emissions from natural gas distribution mains and service
pipelines by construction material.\94\ PHMSA has monitored trends in
legacy pipe materials for years, as these materials pose safety
risks.\95\ The GHGI data demonstrates that replacing leak-prone pipe,
such as aging cast iron, can have a significant effect in reducing
methane emissions from gas distribution systems. Despite dramatically
increased natural gas production and consumption between 1990 and 2019,
methane emissions from natural gas distribution systems have fallen
steadily from 1,819 kt CH<INF>4</INF> in 1990 to 554.5 kt
CH<INF>4</INF> in 2020 (as quantified by GHGI). This reduction in
methane emissions corresponds to a decline in cast-iron and
cathodically unprotected steel pipe mileage over the same period. And
while cast iron mains currently represent less than 1 percent of total
distribution main miles--approximately 18,000 miles of cast iron or
wrought iron distribution main remain in place as of 2021--leaks on
such facilities account for approximately one-fifth of GHGI's estimated
total fugitive emissions from all natural gas distribution mains in
2020. Additionally, PHMSA incident report data shows that cast iron
mains are vulnerable to integrity failures resulting in incidents;
around 8 percent of the incidents that occurred on gas distribution
mains between 2010 and 2021 occurred on cast iron mains. GHGI and PHMSA
data, therefore, demonstrates that replacing leak-prone materials on
gas distribution pipelines can reduce fugitive emissions and incidents
and suggest that similar environmental and public safety benefits could
be achieved by upgrading gas transmission and gas gathering pipelines
made from materials known to leak. PHMSA and its predecessor agency,
the Research and Special Programs Administration (RSPA), have
identified replacement of cast iron and bare steel pipe as a policy
priority for reducing gas distribution leaks and incidents for over two
decades. Further, on November 15, 2021, the Bipartisan Infrastructure
Law (Pub. L. 117-57) appropriated $200 million per year for PHMSA's
Natural Gas Distribution Infrastructure Safety and Modernization Grants
program, which provides grant funding to municipally or community-owned
gas distribution pipeline facilities for the purposes of replacing
legacy pipeline facilities.\96\
---------------------------------------------------------------------------

\94\ 2022 GHGI, Annex 3.6.
\95\ PHMSA, ``Pipe Replacement Background'' (Apr. 26, 2021),
<a href="https://www.phmsa.dot.gov/data-and-statistics/pipeline-replacement/pipeline-replacement-background">https://www.phmsa.dot.gov/data-and-statistics/pipeline-replacement/pipeline-replacement-background</a> (last accessed Dec. 20, 2022).
\96\ See PHMSA. ``Natural Gas Distribution Infrastructure Safety
and Modernization Grants'' (Aug. 2, 2022), <a href="https://www.phmsa.dot.gov/grants/pipeline/natural-gas-distribution-infrastructure-safety-and-modernization-grants">https://www.phmsa.dot.gov/grants/pipeline/natural-gas-distribution-infrastructure-safety-and-modernization-grants</a> (last accessed Dec.
20, 2022).
---------------------------------------------------------------------------

Methane Emissions Data--Natural Gas Transmission and Storage
The GHGI estimates natural gas transmission pipelines in 2020
emitted 1,300 kt of methane emissions, excluding storage; however, the
causes are very different than distribution. Leaks from natural gas
transmission line pipe represent a small share of emissions estimated
in the GHGI: only 3.3 kt of a total 1,504 kt of net methane emissions
from the transmission and storage sector. As shown in the table below,
vented and fugitive emissions (i.e., leaks) from natural gas
transmission compressor stations, compressors, and regulating and
metering stations comprise a significant portion of total methane
emissions from pipeline facilities. GHGI data on the natural gas
transmission and storage segment reflects both onshore and offshore
sources.

2022 GHG Inventory: 2020 Natural Gas Transmission Methane Emissions
------------------------------------------------------------------------
Source Kt CH4 Percent
------------------------------------------------------------------------
Pipeline Leaks.......................... 3.3 0.3
Pipeline Venting (including blowdowns 221.3 17.0
and upset venting).....................
Station Venting (including blowdowns)... 168.9 13.0
Dehydrator Venting...................... 2.6 0.2
Flaring................................. 0.6 0.0
Pneumatic Devices....................... 36.3 2.8
Compressor Station Fugitive Emissions... 702.8 54.1
Compressor Exhaust...................... 164.1 12.6
-------------------------------
Total............................... 1,300.0 100.0
------------------------------------------------------------------------
Note: Pipeline venting includes releases from ruptures and other
incidents.

The table below shows emissions from compressor stations on natural
gas transmission pipelines in additional detail. Emissions from
generators includes emissions from natural gas storage facilities
dedicated to a compressor station.

2022 GHG Inventory: 2020 Natural Gas Transmission Compressor Station
Methane Emissions
------------------------------------------------------------------------
Source Kt CH4 Percent
------------------------------------------------------------------------
Fugitive Emissions...................... 145.1 14.0
Reciprocating Compressor................ 419.5 40.5
Centrifugal Compressor (Wet Seals)...... 57.0 5.5
Centrifugal Compressor (Dry Seals)...... 81.3 7.8
Engine Exhaust.......................... 148.8 14.4
Turbine Exhaust......................... 1.6 0.2
Generator Engines (inc. Storage)........ 13.8 1.3
Generator Turbine (inc. Storage)........ 0.004 0.0
Station Venting......................... 168.9 16.3
-------------------------------

[[Page 31903]]

Total............................... 1,035.8 100.0
------------------------------------------------------------------------

Additionally, the table below shows emissions from natural gas
storage facilities.\97\
---------------------------------------------------------------------------

\97\ The nature and use of tankage as storage incidental to the
movement of gas by pipeline dictates whether storage facilities are
pipeline facilities subject to the jurisdiction of 49 U.S.C. 60101,
et seq.

2022 GHG Inventory: 2020 Natural Gas Storage Methane Emissions
------------------------------------------------------------------------
Source Kt CH4 Percent
------------------------------------------------------------------------
Station and Compressor Fugitive 24.5 7.6
Emissions..............................
Reciprocating Compressors............... 102.9 32.2
Storage Wells........................... 11.3 3.5
Metering and Regulating (Transmission 75.3 23.5
Interconnect)..........................
Metering and Regulating (Farm Taps & 17.5 5.5
Direct Sales)..........................
Dehydrator Venting...................... 4.5 1.4
Flaring................................. 1.1 0.4
Engine Exhaust.......................... 22.7 7.1
Turbine Exhaust......................... 0.2 0.1
Generators (inc. Transmission).......... 13.8 4.3
Pneumatic Devices....................... 17.3 5.4
Station Venting......................... 28.9 9.0
-------------------------------
Total............................... 319.9 100.0
------------------------------------------------------------------------

Though the 2022 GHGI does not track relief and control device
releases as a separate emissions source for natural gas transmission
and storage facilities, PHMSA incident report data indicates that such
releases are a significant contributor to methane emissions. A pressure
relief device is designed to allow gas to escape from a pressurized
system to protect the system from overpressurization. Relief devices
and other pressure control devices are critical to the safe operation
of a pipeline system when they function as intended. However, a poorly
designed or poorly configured pressure relief device can result in
releases of gas to the atmosphere larger than strictly necessary to
protect pipeline integrity. Conversely, a relief device or control
device that fails to release gas as designed or configured will not
provide adequate protection from overpressurization and may rupture,
presenting a hazard to public safety and the environment. Between 2010
and 2021, PHMSA incident report data yields that ``malfunction of
control/relief equipment,'' including control valves, relief valves,
pressure regulators, and emergency shutdown device system failures,\98\
was listed as the cause for 30% of incidents and 21% of unintentional
gas emissions from reportable incidents on gas transmission pipelines.
Approximately 95% of these incidents are reportable due to reported
unintentional emissions exceeding 3 MMCF, although these incidents are
occasionally reportable because repair costs or other monetary damages
exceed the property damage criterion in Sec. 191.3. Out of these 480
incidents, 114 involved the failure of a relief valve. The next most
commonly involved component in these failures were emergency shutdown
devices, which resulted in 54 incidents over this time period.
---------------------------------------------------------------------------

\98\ See PHMSA, Form F 7100.2, ``Incident Report -Gas
Transmission and Gathering System'' at section G6 (May 2022).
---------------------------------------------------------------------------

Recent studies also suggest that current methane emissions data
likely underestimates emissions from natural gas transmission and
storage facilities. The emission factor for transmission pipeline leaks
in the GHGI is based on volume 9 of the 1996 GRI/EPA Report. The
emissions factor is derived from the frequency of leak repairs reported
on operators' annual reports to RSPA and self-reported leak
measurements from distribution mains, both collected in 1991.\99\ The
authors of one study noted that the difficulty in accurately measuring
abnormal ``super-emitter'' events from natural gas transmission and
storage facilities using on-site measurements suggests that bottom-up
methodologies underestimate emissions from ``super-emitter'' events,
and consequently total emissions.\100\ For example, the 1996 GRI/EPA
Report relied on limited RSPA incident report data which did not even
include a volumetric incident definition criterion as used under
current PHMSA reporting requirements.\101\ The RSPA incident report
form in 1991 similarly did not require operators to provide an estimate
of release volume. While current methane emissions data attempts to
address this concern by factoring in ``super-emitter'' estimates, this
remains a source of uncertainty for any type of point-in-time
measurement.\102\ Further, certain infrequent but significant incidents
at UNGSFs such as the release of 86 billion cubic feet (BCF) of natural
gas from the Aliso Canyon facility

[[Page 31904]]

failure in 2015, the release of 6 BCF of natural gas from the Moss
Bluff facility in 2004, and the release of 143 BCF of natural gas from
the Yaggy storage field in 2001 demonstrate both the uncertainty in
estimating methane emissions from UNGSFs and the potential for
substantial methane emissions (which in turn result in public safety
harms) from such facilities.\103\
---------------------------------------------------------------------------

\99\ EPA & Gas Research Institute, Methane Emissions from the
Natural Gas Industry, Volume 9: Underground Pipelines. (June 1996).
Pgs. 38 and 46.
\100\ Zimmerle et al., ``Methane Emissions from the Natural Gas
Transmission and Storage System in the United States,'' 49
Environmental Science & Technology 9374 (July 21, 2015).
\101\ See, e.g., RSPA Form F7100.2 (Rev. 3--1984), ``PHMSA Gas
Transmission & Gathering Incident Data--mid 1984 to 2001'',
available at <a href="https://www.phmsa.dot.gov/data-and-statistics/pipeline/distribution-transmission-gathering-lng-and-liquid-accident-and-incident-data">https://www.phmsa.dot.gov/data-and-statistics/pipeline/distribution-transmission-gathering-lng-and-liquid-accident-and-incident-data</a> (last accessed Jan. 4, 2023).
\102\ See Alvarez et al., ``Assessment of Methane Emissions from
the U.S. Oil and Gas Supply Chain,'' Science 186, Table 1 (June 21,
2018) (finding that bottom-up quantifications of methane emissions
may underestimate natural gas transmission and storage emissions by
nearly 30% when compared with top-down quantifications).
\103\ PHMSA, ``Pipeline Safety: Safe Operations of Underground
Storage Facilities for Natural Gas,'' 81 FR 6334 (Feb. 5, 2016)
(Advisory Bulletin ADB-2016-02).
---------------------------------------------------------------------------

Methane Emissions Data--Gathering Pipelines
The GHGI estimates for ``natural gas gathering and boosting''
systems have estimated fugitive emissions from line pipe leaks that are
much higher than for natural gas transmission systems. As shown in the
table below, the GHGI estimates 126.7 kt of methane emissions from
pipeline leaks in natural gas gathering and boosting systems (estimated
at 381,909 miles in the GHGI) \104\ compared with 3.3 kt for natural
gas transmission systems (302,252 miles). In the RIA for the 2021 Gas
Gathering Final Rule, PHMSA estimated that there were approximately
426,000 miles of unregulated rural gas gathering pipelines,\105\ in
addition to the 17,064 miles of regulated offshore and onshore Type A
and Type B regulated gas gathering pipelines reported by operators in
2021. Additionally, the EPA mileage estimate may include mileage that
could be considered under Sec. 192.8 to be production pipelines rather
than gathering pipelines. The EPA mileage therefore provides an
estimate of gathering pipeline mileage and resulting total emissions
estimates from such facilities that may not accurately represent
emissions from the subset of PHMSA-regulated gathering pipeline
sources.
---------------------------------------------------------------------------

\104\ 2022 GHGI, Annex 36 Table 3.6-7.
\105\ Gas Gathering RIA at 15; PHMSA, ``Annual Report Mileage
for Natural Gas Transmission and Gathering Systems.'' (Aug. 1,
2022), <a href="https://www.phmsa.dot.gov/data-and-statistics/pipeline/annual-report-mileage-natural-gas-transmission-gathering-systems">https://www.phmsa.dot.gov/data-and-statistics/pipeline/annual-report-mileage-natural-gas-transmission-gathering-systems</a>
(last accessed Aug. 19, 2022).

2022 GHG Inventory: Natural Gas Gathering and Boosting Methane Emissions
------------------------------------------------------------------------
Source Kt CH4 Percent
------------------------------------------------------------------------
Station Combustion Slip................. 407.1 27
Station Compressors..................... 306.9 20
Station Tanks........................... 244.3 16
Station Pneumatic Devices............... 202.0 13
Pipeline Leaks.......................... 126.7 8
Station Yard Piping..................... 93.3 6
Station Blowdowns....................... 44.9 3
Station Dehydrator Vents and Leaks...... 25.7 2
Station Pneumatic Pumps................. 27.2 2
Pipeline Blowdowns...................... 9.4 1
Station Flare Stacks.................... 11.1 1
Station Separators...................... 1.4 0
Station Acid Gas Removal Units.......... 0.1 0
-------------------------------
Total............................... 1500.0 100
------------------------------------------------------------------------
Note: Total includes Type R gas gathering pipelines and production
operations not regulated under part 192.

Recent research also suggests that, as in the case of other gas
pipeline facilities, current methane emissions data likely understates
emissions from natural gas gathering pipelines. One study conducted in
the New Mexico Permian Basin in 2022 estimated emissions from natural
gas production and gathering facilities in that region that were 6.5
times larger than GHGI estimates.\106\ In the study, methane emissions
were estimated using a comprehensive aerial survey spanning 35,923
square kilometers (including over 15,000 kilometers of natural gas
pipelines) over 115 flight days. This large sample size was intended to
better capture infrequent ``super-emitter'' events, and the study found
that 50% of observed emissions were attributable to large emissions
sources with average methane emissions rates greater than 308 kilograms
per hour. Even as studies in the past few years have increasingly
sounded the alarm that leaks from gathering pipelines and boosting
stations are significant contributors to climate change, GHGI emissions
factors for those facilities have decreased over the same time period
due to changes in GHGRP inputs.\107\ Moreover, studies aiming to
improve gas gathering pipeline emissions factors with more accurate
data (like one conducted on the Utica Shale in 2020) \108\ suggest that
self-reported emissions information from GHGRP reporting on which GHGI
emissions data for gathering pipelines is based may underestimate
actual emissions rates. Any point-in-time measurement of methane
emissions can miss large but infrequent events (particularly
methodologies that use smaller sample areas such as ground-based
approaches), thus underestimating total emissions when used to
extrapolate beyond the sample area to an entire region.\109\
---------------------------------------------------------------------------

\106\ Chen et al., ``Quantifying Regional Methane Emissions in
the New Mexico Permian Basin with a Comprehensive Aerial Survey,''
56 Environmental Science & Technology 4317 (Mar. 23, 2022) (finding
that ``[m]idstream assets were also a significant source [of
emissions], with 29 <plus-minus> 20 t/h [(metric tonnes per hour)]
emitted from pipelines (including underground gas gathering
pipelines) and 26 <plus-minus> 16 t/h emitted from compressor
stations without a well on site'').
\107\ GHGI emissions factors for gathering pipeline leaks were
identified as 354.7 CH<INF>4</INF>/mile in 2017 but decreased to
288.5 in the 2022 GHGI. See 2022 GHGI, Annex 36 Table 3.6-2. See
also Li et al., ``Gathering Pipeline Methane Emissions in Utica
Shale Using an Unmanned Aerial Vehicle and Ground-Based Mobile
Sampling,'' Atmosphere (July 5, 2020) (calling for improved gas
gathering pipeline methane emissions factors for the Utica Shale
region based on data from both aerial surveys and ground-based
vehicle sampling); Chen et al., 2022, at 4317-18 (observing that,
while ``uncertainty remains about the emissions rates in the Permian
Basin'', recent studies conducted in that region ``consistently find
emissions significantly in excess of government estimates'').
\108\ Li et al., ``Gathering Pipeline Methane Emissions in Utica
Shale Using an Unmanned Aerial Vehicle and Ground-Based Mobile
Sampling,'' Atmosphere (July 5, 2020).
\109\ Chen et al., 2022, at 4321-22 (``[T]he clear impact of
large emissions found by this study suggests that estimates from
ground-based methane surveys may be underestimating total emissions
by missing low-frequency, high-impact large emissions.'').

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

[[Page 31905]]

Methane Emissions Data--LNG Facilities
As shown in the tables below, the GHGI estimates that blowdowns
account for 80 percent of estimated methane emissions from LNG storage
facilities, and nearly half of methane emissions from all LNG
facilities.

2022 GHG Inventory: LNG Storage Facility 2020 Methane Emissions
------------------------------------------------------------------------
Source Kt CH4 Percent
------------------------------------------------------------------------
Equipment Leaks, Compressors, Flares, 1.4 13
etc....................................
Blowdowns............................... 8.4 80
Engine Exhaust.......................... 0.6 5
Turbine Exhaust......................... 0.1 1
------------------------------------------------------------------------

2022 GHG Inventory: LNG Import Terminal 2020 Methane Emissions
------------------------------------------------------------------------
Source Kt CH4 Percent
------------------------------------------------------------------------
Equipment Leaks, Compressors, Flares, 0.1 22
etc....................................
Blowdowns............................... 0.2 33
Engine Exhaust.......................... 0.2 45
Turbine Exhaust......................... 0.0 <1
------------------------------------------------------------------------

2022 GHG Inventory: LNG Export Terminal 2020 Methane Emissions
------------------------------------------------------------------------
Source Kt CH4 Percent
------------------------------------------------------------------------
Equipment Leaks, Compressors, Flares, 4.0 53
etc....................................
Blowdowns............................... 0.3 4
Engine Exhaust.......................... 1.4 18
Turbine Exhaust......................... 2.0 26
------------------------------------------------------------------------

Fugitive emissions represent the majority of estimated methane
emissions from LNG import and export terminals. While LNG facilities
are often designed with boil-off gas recovery systems to avoid routine
continuous venting of natural gas during operations, methane regularly
escapes from LNG facilities through compressor rod packing and valve
leakage, incomplete combustion during flaring, and other various
process venting sources.\110\ Similar to gas transmission facilities,
additional emissions are attributable to releases from relief devices
and O&M related venting. Likewise, fugitive emissions from gas
treatment equipment at liquefaction plants are likely similar to those
from comparable equipment on other pipeline or gas processing
facilities.\111\ Methane may also be lost to the atmosphere during pipe
transfers of LNG to or from an LNG facility, whether through loading
for transport or off-loading for storage or vaporization. Even if
initially captured, boil-off gas and other fugitive emissions from LNG
facilities may still be vented directly to the atmosphere without
combustion during normal operation.\112\ And, as with any pipe
transporting natural gas, the pressurized piping that runs throughout
LNG facilities is susceptible to integrity failures and other
incidents,\113\ including pipeline leaks that can precipitate
explosions.\114\ For example, Cheniere reported that the Sabine Pass
LNG terminal constituted approximately 40 miles of plant piping for its
import facilities and an additional 285 miles of plant piping for its
first four of six liquefaction trains,\115\ and the operator of the
Cameron LNG terminal reported approximately 255 miles of piping in
their liquefaction project consisting of three liquefaction
trains.\116\ In addition, Freeport LNG similarly reported its
liquefaction project's pretreatment and three liquefaction trains
included approximately 192 miles of plant piping, providing ample
opportunities for methane to escape during normal and emergency
operations.
---------------------------------------------------------------------------

\110\ API, Compendium of Greenhouse Gas Emissions Methodologies
for the Natural Gas and Oil Industry at 6-121 through 6-126 (Nov.
2021).
\111\ API, Compendium of Greenhouse Gas Emissions Methodologies
for the Natural Gas and Oil Industry at 6-121 through 6-122 (Nov.
2021).
\112\ API, Compendium of Greenhouse Gas Emissions Methodologies
for the Natural Gas and Oil Industry at 6-123 (Nov. 2021). For
example, boil-off gas may be vented if the vapor generation rate
exceeds the capacity of the boil-off gas compressors or the re-
liquefaction unit. API's compendium estimates typical losses at
0.05% of total tank volume per day when boil-off gas is vented from
an LNG storage vessel. See also Soraghan & Lee, ``LNG explosion
shines light on 42-year-old gas rules'' EnergyWire. (June 28, 2022),
<a href="https://www.eenews.net/articles/lng-explosion-shines-light-on-42-year-old-gas-rules/">https://www.eenews.net/articles/lng-explosion-shines-light-on-42-year-old-gas-rules/</a> (noting that an LNG terminal had reported
several natural gas releases to the state Department of
Environmental Quality, including one release of 180,000 pounds of
methane in January 2022).
\113\ See, e.g., PHMSA, CPF No. 4-2022-051-NOPSO, ``In the
Matter of Freeport LNG Development LP: Notice of Proposed Safety
Order'' at 3 (June 30, 2022), (describing the LNG release and
natural gas vapor cloud that resulted from the June 8, 2022 incident
at the Quintana Island LNG facility, which may have been caused by
the overpressure and rupture of a segment of LNG transfer line
between the facility's LNG storage tank area and its dock
facilities).
\114\ See, e.g., ``Algerian LNG Complex Explosion Caused by Gas
Pipeline Leak,'' Oil & Gas Journal (Feb. 18, 2004). A gas pipeline
leak was ultimately determined to be the cause of the Skikda,
Algeria LNG terminal explosion on January 20, 2004, that killed 27
people, injured 74 others, and resulted in an estimated $800
million-$1 billion in damages to the Skikda port facilities,
including the destruction of three of the LNG terminal's six
liquefaction trains. See also Romero, ``Algerian Explosion Stirs
Foes of U.S. Gas Projects,'' New York Times (Feb. 14, 2004).
\115\ Cheniere. ``Cheniere Energy Analyst/Investor Day.'' (Apr.
2014). Pgs. 12-13.
\116\ Cameron LNG. <a href="https://cameronlng.com/lng-facility/economic-impact/">https://cameronlng.com/lng-facility/economic-impact/</a>.
---------------------------------------------------------------------------

However, emissions for LNG facilities have proven difficult to
estimate due to the limited availability of accurate, complete
emissions data, with insufficient differentiation between intentional
and fugitive emissions.\117\

[[Page 31906]]

Bottom-up methodologies for estimating LNG emissions typically use
generalized emissions factors averaged across the entire sector despite
significant differences between suppliers and each step of the supply
chain.\118\ Emissions estimates using this approach may apply a single
emissions factor to all types of LNG facilities, even though the wave
of recently built LNG export terminals could have little in common with
an LNG peak shaver or storage facility. Developing accurate emissions
estimates is also hampered by selection bias. Specifically, EPA
currently uses data reported in accordance with 40 CFR part 98, subpart
W (i.e., GHGRP) to develop GHGI emissions factors for LNG facilities
(with the exception of LNG storage facility blowdowns). However,
operators of LNG facilities need only report emissions under subpart W
if total emissions reach the reporting threshold of 25,000 metric tons
of CO<INF>2</INF> equivalent per year. Many LNG storage facilities fall
under that threshold, introducing uncertainty into aggregate emissions
calculated using only a subset of LNG storage facilities.\119\
---------------------------------------------------------------------------

\117\ Oxford Institute for Energy Studies, Measurement,
Reporting, and Verification of Methane Emissions from Natural Gas
and LNG Trade: Creating Transparent and Credible Frameworks at 51
(Jan. 2022).
\118\ See Roman-White et al., ``LNG Supply Chains: A Supplier-
Specific Life-Cycle Assessment for Improved Emission Accounting,''
ACS Sustainable Chemistry & Engineering at 10857, 10861 (2021).
\119\ EPA, Memorandum, ``Inventory of U.S. Greenhouse Gas
Emissions and Sinks 1990-2017: Updates to Liquefied Natural Gas
Segment'' at 2-3 (Apr. 2019). While EPA identified between 94-98 LNG
storage facilities as active each year from 2011-2017, only 8 such
facilities reported emissions under Subpart W during that timeframe.
---------------------------------------------------------------------------

Further, even among those LNG facilities that report their
emissions to EPA, there is a potential for great variation in emissions
reported within and across reporting years due to small sample sizes:
the small number of LNG facilities reporting emissions to EPA (only 5
storage facilities and 11 import and export facilities as of August
2022 \120\) make resulting methane emissions estimates susceptible to
substantial year-to-year fluctuation and limit the predictive value of
such estimates for subsequent years.\121\ Lastly, operators of LNG
storage facilities are not required to report LNG storage blowdown
emissions under GHGRP--instead, GHGI estimates for LNG storage blowdown
emissions consist of generalized data based on a 1996 study of blowdown
emissions on gas transmission compressor stations and UNGSFs.\122\
---------------------------------------------------------------------------

\120\ See EPA, ``GHGRP Petroleum and Natural Gas Systems,''
<a href="https://www.epa.gov/ghgreporting/ghgrp-petroleum-and-natural-gas-systems#emissions-table">https://www.epa.gov/ghgreporting/ghgrp-petroleum-and-natural-gas-systems#emissions-table</a> (last accessed March 16, 2023).
\121\ For example, in 2016, one LNG storage facility was
responsible for more than 82% of all LNG storage facility methane
emissions and one LNG import terminal was responsible for more than
95% of all LNG terminal methane emissions reported to EPA under
Subpart W. EPA, Memorandum, ``Inventory of U.S. Greenhouse Gas
Emissions and Sinks 1990-2017: Updates to Liquefied Natural Gas
Segment'' at 3-8 & Tables 5, 8 (April 2019).
\122\ EPA, Memorandum, ``Inventory of U.S. Greenhouse Gas
Emissions and Sinks 1990-2017: Updates to Liquefied Natural Gas
Segment'' at 1 (April 2019).
---------------------------------------------------------------------------

D. The Need for Updating PHMSA Regulations To Incorporate Advanced Leak
Detection Programs To Reduce Unintentional Releases From Gas Pipelines

PHMSA's regulations have historically prioritized addressing public
safety risks posed by ignition of instantaneous, large-volume releases
or accumulated gas. This focus on public safety is vital and can
support PHMSA's renewed and expanded commitment to addressing
environmental risks as well. However, current regulations can allow
leaks of methane and other gases from gas gathering, transmission, and
distribution pipeline facilities to continue undetected and unrepaired
for extended periods of time.\123\ This approach therefore foregoes the
emissions reduction potential of commercially available, advanced leak
detection technologies and practices within integrated ALDPs. This
historical approach also forgoes opportunities for timely
identification and remediation of leaks from gas pipelines that can
develop into catastrophic incidents. State and voluntary industry
efforts to improve leak detection and repair on gas pipelines are
emerging, but are insufficient to reduce unintentional emissions of
methane and other gases without PHMSA regulations that support and
backstop those efforts.
---------------------------------------------------------------------------

\123\ PHMSA notes that the limitations of current part 191 and
192 regulations for meaningful and timely identification, repair,
and reporting of leaks discussed in this section II.D. may be
particularly acute in connection with the pipeline transportation of
gaseous hydrogen, which is a much smaller molecule (with potentially
greater leakage potential) than methane.
---------------------------------------------------------------------------

1. PHMSA Regulations Pertinent to Unintentional Releases of Methane and
Other Gases
PHMSA's current regulatory requirements pertaining to gas pipeline
leak detection, repair, maintenance, and reporting reflect a focus on
public safety risks from ignition of instantaneous, large-volume
releases or accumulated gas while treating risks to the environment as
less important. PHMSA maintenance requirements at part 192, subpart M
explicitly require only a subset of unintentional releases from gas
pipelines--namely those unintentional releases thought to create an
actual or probable harm to public safety--need be identified, repaired,
or reported. Nor do those maintenance requirements in the subpart M
regulations include explicit requirements for the replacement or
remediation of pipes known to leak based on material, design, or past
operating and maintenance history.\124\ And PHMSA IM regulations at
part 192 subparts O (gas transmission pipelines) and P (gas
distribution pipelines) allow considerable operator discretion in
determining which leaks merit repairs and the timing of those repairs.
PHMSA reporting requirements at part 191 similarly are calibrated to
provide information regarding instantaneous, large-volume releases
rather than granular data on operator leak detection and repair
efforts, or the releases of gas from those leaks.
---------------------------------------------------------------------------

\124\ An exception is that part 192, subpart M acknowledges
cast-iron piping's susceptibility to leakage and contains provisions
focused on a single mechanism (graphitization-derived corrosion) for
development of leaks, and then only after indicia of that mechanism
have emerged. Specifically, Sec. 192.489(a) requires replacement of
each segment of cast iron or ductile iron pipe with general
graphitization (a type of corrosion) that could cause a fracture or
leak. Section 192.489(b) similarly requires replacement, repair, or
internal sealing for localized graphitization on cast and ductile
iron pipeline segments that could result in leakage.
---------------------------------------------------------------------------

Gas Pipelines Generally
Part 192, subpart M contains minimum maintenance requirements for
gas gathering, transmission, and distribution pipelines.\125\ Gas
transmission (Sec. 192.706), distribution (Sec. 192.723), offshore
gas gathering, and Type A, Type B, and certain Type C gathering
(Sec. Sec. 192.9 and 192.706) pipeline operators must perform periodic
leakage surveys. When leaks are discovered, both their severity and the
operating conditions of the pipeline are used to determine whether and
when a repair is performed. PHMSA's subpart M requirements contain
broad language at Sec. 192.703(c) mandating repair of all ``hazardous
leaks . . . promptly.'' However, subpart M neither

[[Page 31907]]

defines a ``hazardous'' leak nor provides guidance on what exactly
constitutes a ``prompt'' repair of such leaks. Although Sec. 192.1001
describes a ``hazardous leak'' only in terms of an existing or probable
hazard to persons or property (and not the environment), that
regulatory definition applies only to the gas distribution system IM
requirements in part 192, subpart P. The Sec. 192.703(c) repair
mandate is also inapplicable to most Type C gas gathering
pipelines.\126\
---------------------------------------------------------------------------

\125\ Certain part 192 regulations will be revised on
codification of a recent PHMSA rulemaking that will become effective
on May 24, 2023. See PHMSA, ``Safety of Gas Transmission Pipelines:
Repair Criteria, Integrity Management Improvements, Cathodic
Protection, Management of Change, and Other Related Amendments--
Final Rule,'' 87 FR 52224 (Aug. 24, 2022) (RIN2 Final Rule). PHMSA's
references to part 192 within this NPRM--including the proposed
amended regulatory text at its conclusion--reflect the regulatory
text and organization as amended by the RIN2 Final Rule unless
otherwise noted. The RIN2 Final Rule contains enhanced repair
criteria that can affect leak repairs, but the requirements are
generally directed toward phenomena (cracking, corrosion-induced
metal loss, dents) distinct from the detection, grading, and repair
of all leaks as proposed in this NPRM.
\126\ Only ca. 20,000 miles of the ca. 91,000 miles of Type C
gas gathering pipelines are subject to Sec. 192.703(c). PHMSA, Doc.
No. PHMSA-2011-0023-0488, ``Regulatory Impact Analysis for Gas
Gathering Final Rule'' at 11, 15 (Nov. 2021).
---------------------------------------------------------------------------

Part 191 reporting requirements similarly reflect PHMSA's
historical focus on public safety risks from ignition of instantaneous,
large-volume releases or accumulated gas.\127\ Incident reports for gas
distribution (Form F7100.1), transmission and part-192 regulated
gathering (Form F7100.2), and Type R gathering pipelines (Form
F7100.2.2) provide limited information regarding unintentional
releases, as only unintentional releases of at least 3 MMCF need be
reported. And while annual reports for gas distribution (Form F7100.1-
1), transmission and part-192 regulated gathering (Form F7100.2-1), and
Type R gathering pipelines (Form F7100.2-3) include information on the
number of leaks repaired in the preceding calendar year, the
instructions for those annual report forms expressly exclude reporting
of repairs on a broad category of leaks: releases that can be corrected
by ``lubrication, adjustment, or tightening'' are not considered
``leaks'' for annual reporting of repairs.\128\ The instructions for
annual reports other than for gas distribution pipelines also do not
require reporting of repairs of any leaks other than leaks that are
hazardous; and the instructions for all annual report forms
characterize leaks as ``hazardous'' with respect to public safety,
omitting mention of hazards to the environment. Further, none of
PHMSA's annual reports require operators to submit information on
either the total number of leaks detected in the reporting period, the
rolling tally of all unrepaired leaks, or estimated emissions
associated with leaks during the reporting period.
---------------------------------------------------------------------------

\127\ PHMSA annual and incident forms and instructions discussed
in this paragraph can be found on PHMSA's website at <a href="https://www.phmsa.dot.gov/forms/operator-reports-submitted-phmsa-forms-and-instructions">https://www.phmsa.dot.gov/forms/operator-reports-submitted-phmsa-forms-and-instructions</a>. <a href="https://www.phmsa.dot.gov/forms/operator-reports-submitted-phmsa-forms-and-instructions">https://www.phmsa.dot.gov/forms/operator-reports-submitted-phmsa-forms-and-instructions</a>.
\128\ PHMSA annual reporting requirements for part 193-regulated
LNG facilities contain a similar exception from leak reporting
requirements. See PHMSA, Form 7300.1-3, ``Annual Report Form for
Liquefied Natural Gas Facilities (Oct. 2014); PHMSA, Instructions
for Form 7300.1-3 at 4 (Oct. 2014) (stating that ``a non-hazardous
release that can be eliminated by lubrication, adjustment, or
tightening is not a leak'').
---------------------------------------------------------------------------

Lastly, only gas transmission pipelines are required to provide
geospatial data on their pipeline systems in accordance with the NPMS
requirements at 49 U.S.C. 60132 and 49 CFR 191.29. Gas distribution and
gathering pipelines have no requirement to provide geospatial data for
NPMS.
Part 192--Regulated Gas Gathering Pipelines
Operators of offshore gas gathering, Type A, Type B, and certain
Type C gathering pipelines must comply with the leakage survey
requirements (at Sec. 192.706) applicable to gas transmission
pipelines and repair any hazardous leaks detected (per Sec. 192.703).
However, most Type C gathering pipelines--specifically, those with an
outer diameter between 8.625'' and 16'' not near an occupied building--
are, pursuant to Sec. 192.9(f)(1), not subject to any part 192 leakage
survey and repair requirements, whether for ``hazardous'' leaks or any
other leaks. Additionally, only offshore gas gathering and Type A
gathering pipelines are subject to other subpart M maintenance
requirements, including right-of-way patrols (Sec. 192.705), general
transmission pipeline requirements for making permanent or temporary
repairs (Sec. 192.711), and recordkeeping (Sec. 192.709). Type B and
Type C gathering pipelines need only comply with the specific
requirements listed in Sec. 192.9(d) and (e), which do not include
patrol, repair, and recordkeeping requirements.
Gas Transmission Pipelines
All gas transmission pipelines are subject to maintenance
requirements at part 192, subpart M. Section 192.706 requires gas
transmission operators to perform leakage surveys on most gas
transmission pipelines at least once every calendar year. However, that
provision does not require the use of leak detection equipment for
those leakage surveys. Leak detection equipment is only required if a
gas transmission pipeline is not odorized in accordance with Sec.
192.625 and the pipeline is located in a Class 3 or Class 4 location;
otherwise, leak detection can be by human senses only, such as visual
observation of dead vegetation or blowing debris. Operators required to
conduct a leakage survey with leak detection equipment must do so at
least twice each year in Class 3 locations, and at least four times
each calendar year in Class 4 locations.
In addition to leakage surveys, Sec. 192.705 requires operators of
gas transmission pipelines to have a patrolling program to monitor
conditions on and adjacent to pipeline rights-of-way. These patrols are
visual surveys, commonly performed using aircraft, and are intended to
find leaks and other conditions affecting the safety and operation of
the pipeline. Patrols commonly identify potential or current pipeline
integrity threats caused by external changes, including construction,
excavation, blasting, earth movements, and flooding. Information
gathered from these patrols can prevent further damage to the pipeline
or target leakage surveys or integrity assessments to locations that
may have been damaged. This can prevent leaks, potentially fatal
incidents, or damage that could result in shutdowns and maintenance-
related releases of methane and other gases to the atmosphere. For
example, if an operator spots construction activity along the line,
they can dispatch personnel to observe construction to minimize the
risk of excavation-related damage to the pipeline. According to
incidents reports submitted to PHMSA, such excavation damage is a
leading cause of incidents that result in injuries and fatalities and
pipeline breaks with very high emissions rates. The patrol frequency
depends on the class location of the pipeline, the pipeline's diameter,
operating pressure, terrain, weather, and other relevant factors. Gas
transmission pipeline operators must perform patrols at least four
times each calendar year in Class 4 locations, at least twice each
calendar year in Class 3 locations, and at least once each calendar
year in Class 1 and Class 2 locations. If the pipeline is located at a
highway or railroad crossing in a Class 1 or Class 2 location, the
minimum patrol frequency is increased to at least twice each calendar
year. In Class 3 locations, the minimum patrol frequency at highway and
railroad crossings is four times each calendar year.
As explained above, Sec. 192.703(c) requires all transmission
operators to repair leaks that are ``hazardous'' to public safety
``promptly''--but PHMSA regulations contain few guardrails as to what
``promptly'' means. Repair requirements at Sec. 192.711 require that
operators take immediate temporary measures for leaks that impair the
serviceability of a steel transmission pipeline operating above 40
percent of SMYS if a permanent repair is not feasible.
Section 192.711(b) requires that permanent repair be made as soon
as feasible or as specified under the

[[Page 31908]]

operators' IM program under subpart O but does not specify when
permanent repairs are necessary.\129\ Like the general repair
requirement in Sec. 192.703, these requirements frame leak repair
obligations in terms of public safety risks and use ambiguous language
(``as soon as feasible'') to describe the timing of any repair
obligations. In recognition of this regulatory gap, PHMSA has
referenced the GPTC Guide in guidance and letters of interpretation on
how operators should comply with these provisions of part 192.\130\
---------------------------------------------------------------------------

\129\ The RIN2 Final Rule will amend Sec. 192.711(b) by
replacing the existing requirement that permanent repairs of safety-
adverse conditions on certain onshore gas transmission pipelines
must be made ``as soon as feasible'' with a cross-reference to a new
Sec. 192.714 prescribing repair schedules set forth in an industry
standard. See 87 FR at 52271 (introducing a new Sec. 192.714
referencing ASME/ANSI B31.8S-2004, Supplement to B31.8 on Managing
System Integrity of Gas Pipelines at section 7, Figure 4 (Jan. 14,
2005)). However, those repair schedules--which are intended for
``anomalies and defects'' consisting of dents, corrosion metal loss,
and cracking rather than leaks--contemplate that some repairs may
not be required for years. The RIN2 Final Rule does not disturb the
existing requirement to effectuate permanent repairs ``as soon as
feasible'' for other part 192-regulated gas pipelines not subject to
subpart O IM requirements.
\130\ See, e.g., PHMSA, ``Distribution Integrity Management:
Guidance for Master Meter and Small Liquefied Petroleum Gas Pipeline
Operators'' (2013) at 2 (directing larger distribution pipeline
operators to refer to GPTC guidelines); PHMSA, Interpretation
Response Letter No. PI-93-009 (February 11, 1993) (recommending
public stakeholder consult the GPTC Guide for further determination
of instruments and techniques to be used in certain leak detection
activities); see also PHMSA, Interpretation Response Letter No. PI-
99-0105 (December 1, 1999) (stating that the GPTC Guide ``is a
document endorsed by us which contains information and some methods
to assist the gas pipeline operator in complying with the
regulations contained in 49 CFR part 192'').
---------------------------------------------------------------------------

Subpart O requirements similarly provide little direction on how
gas transmission pipelines that are located in HCAs \131\ must manage
leak detection and repair, instead giving operators considerable
discretion to determine when and how they address leaks on their
pipelines. Subpart O requires operators to identify, prioritize,
assess, evaluate, repair, and validate the integrity of their pipelines
that have the potential to cause injury or death in the event of a
failure. In addition, operators must measure IM plan performance to
support continual improvement of their programs. Operators of gas
transmission pipelines subject to the IM regulations may develop IM
plans reflecting idiosyncratic choices regarding identification of
specific integrity risks to their pipelines, selection of proper
assessment tools; periodic assessment of the pipe for anomalies, and
procedures for taking prompt action to address and repair anomalous
conditions discovered through pipeline integrity assessments.
Additionally, the subpart O regulations do not explicitly require
operators to repair all leaks; operators can determine the precise
timing of ``prompt'' repairs based on the operator's evaluation of risk
to public safety. Further, Sec. 192.93 provides operators up to 6
months from the date that an integrity assessment was performed to
confirm discovery of an anomalous condition. Repair criteria at Sec.
192.933 require that anomalous conditions posing the greatest risks to
public safety be repaired immediately, but other anomalies that an
operator determines pose less significant public safety risks need to
be repaired within a year of discovery, or only monitored during
subsequent risk assessments and integrity assessments for any change
that may require remediation. Section 192.935 directs operators to take
additional measures beyond those required elsewhere in part 192 to
prevent, and mitigate the consequences of, pipeline failures in HCAs,
but that provision identifies enhanced leak detection and monitoring
programs as merely one potential item on a menu from which operators
may choose in order to meet this requirement.\132\
---------------------------------------------------------------------------

\131\ Subpart O contains IM requirements for transmission
pipelines in HCAs. Annual reports submitted by operators in 2020
yields that only 7% (ca. 21,000 miles) of the 301,000 miles of gas
transmission pipelines are subject to IM requirements at subpart O.
\132\ Amendments to subpart O requirements pursuant to the RIN2
Final Rule will not disturb the pertinent requirements of that
subpart described above.
---------------------------------------------------------------------------

Gas Distribution Pipelines
Distribution pipelines are subject to select part 192, subpart M
maintenance requirements. Section 192.721 requires operators to patrol
distribution mains at frequencies that consider the severity of the
conditions that would cause failure or leakage, and the consequent
hazard to public safety. Distribution mains subject to physical
movement or external loading that could fail or leak must be patrolled
at least twice each calendar year if located outside of business
districts, and at least four times every calendar year if located
within business districts. Distribution leakage survey requirements are
defined in Sec. 192.723. In business districts, operators must conduct
leakage surveys of distribution pipelines with leak detection equipment
at least once every calendar year. These surveys must include testing
the atmosphere in utility manholes, at cracks in the pavement and
sidewalks, and at other locations, providing opportunities to find
leaks. Outside of business districts, operators must perform leakage
surveys using leak detection equipment as frequently as necessary, but
not less than once every 5 calendar years. Gas distribution operators
are subject to repair requirements for hazardous leaks at Sec.
192.703, but that requirement provides no specific guidance on repair
timelines and fails to mention environmental risks.
The distribution IM program (DIMP) regulations in subpart P require
distribution pipeline operators to identify, prioritize, assess,
evaluate, repair, and validate the integrity of gas distribution
pipelines that have the potential to cause injury or death in the event
of a leak or failure. Section 192.1007 requires operators to
demonstrate an understanding of their gas distribution systems based on
reasonably available information. Operators then must apply the
knowledge acquired through reasonably available information to identify
threats to the integrity of their gas distribution systems. Threats can
include a variety of phenomena: corrosion, excavation damage, vehicular
strikes, poorly fitting connections, and other threats. Operators must
evaluate and rank the risk to their systems from those threats, and
then identify and implement measures to address those risks. DIMP
regulations require operators to periodically (at least once every 5
years) evaluate the threats, risks, and results of the performance
measures to gauge the effectiveness of their DIMPs in controlling each
threat. And Sec. 192.1007(d) explicitly requires distribution pipeline
operators to either repair all leaks when found or have an ``effective
leak management program.'' However, subpart P prescribes few specific
requirements for those leak management programs or criteria for
determining their effectiveness, requiring a distribution pipeline
operator only to monitor (as a performance measure for evaluating a
DIMP), the number of leaks it eliminates or repairs; to categorize such
leaks by cause, material; to determine whether they are ``hazardous'';
and to report such measures annually to PHMSA. Indeed, the preamble to
the 2009 final rule codifying subpart P merely suggested that each
operator ``should develop a program based on their knowledge of their
pipeline system'' with the GPTC Guide identified as an aid in
developing such a program.\133\
---------------------------------------------------------------------------

\133\ PHMSA, ``Pipeline Safety: Integrity Management for Gas
Distribution Pipelines--Final Rule,'' 74 FR 63905, 63917 (Dec 4,
2009). PHMSA is undertaking a complementary rulemaking under RIN
2137-AF53 (``Pipeline Safety: Safety of Gas Distribution Pipelines
and Other Pipeline Safety Initiatives'') responding to congressional
mandates in title II of The PIPES Act of 2020 directing PHMSA to,
among other things, amend its subpart P distribution IM program
requirements. PHMSA expects that the leak detection, grading, and
repair requirements for gas distribution pipelines proposed herein
would reinforce any changes to subpart P proposed in that
rulemaking.

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

[[Page 31909]]

2. Shortcomings of Current PHMSA Regulations in Addressing
Unintentional Releases From Gas Pipelines
PHMSA regulations pertinent to leaks from gas pipelines focus on
risks to public safety posed by ignition of instantaneous, large-volume
releases or accumulated gas from gas pipeline facilities--an approach
that is vital for protecting public safety but that foregoes
opportunities to address environmental harms, including methane
emissions' contribution to climate change. This approach has proven
unsuccessful in timely identification and remediation of leaks that can
have a substantial impact on the environment or even evolve into
incidents posing catastrophic risks to public safety.
As explained above, part 192 subpart M maintenance requirements
contain only a single repair requirement specific to leaks, which is
applicable only to some part 192-regulated gas gathering, transmission,
and distribution pipelines: Sec. 192.703(c)'s requirement that
``hazardous leaks'' be repaired ``promptly.'' However, the term
``hazardous leak'' is nowhere defined in subpart M. Rather, what other
limited evidence there is in PHMSA regulations elaborating on the
meaning of ``hazardous leak'' pertains either to entirely different
elements of part 192 (specifically, the Sec. 192.1001 definition of
``hazardous leak'' within DIMP requirements in subpart P) or part 191
reporting requirements.\134\ These regulatory provisions both describe
``hazardous leak'' with respect to potential or present risks to public
safety; they are silent regarding risks to the environment.
---------------------------------------------------------------------------

\134\ See, e.g., PHMSA, Form F7100.1-1 Instructions (May 2021)
(defining hazardous leaks as those representing an ``existing or
probable hazard to persons or property and requires immediate repair
or continuous action until the conditions are no longer
hazardous''). The instructions for annual report forms for other gas
pipeline facilities contain similar language.
---------------------------------------------------------------------------

Similarly, subpart M does not elaborate on the requirement that all
hazardous leaks be repaired ``promptly.'' Section 192.711 allows
operators to repair hazardous leaks and other conditions as soon as
feasible for non-IM repairs, and as prescribed by Sec. 192.933(d) for
IM repairs. If a permanent repair is infeasible, Sec. 192.711 merely
requires that any temporary measure addresses public safety, again
excluding the environment from explicit consideration.
Part 192 nowhere specifies remote or continuous monitoring for
pipeline leaks apart from a recent limited requirement pertaining to
detection of ruptures (rather than leaks) on certain new gas
transmission pipelines with rupture mitigation valves.\135\ Frequencies
of leakage survey (Sec. 192.706) and patrol (Sec. 192.705)
requirements are generally keyed to location and the likelihood of
nearby people--proxies for risks to public safety but not the
environment. Consequently, the majority of part 192-regulated gas
transmission and some part 192-regulated, onshore gathering mileage in
the United States (in particular, Types A and B gathering pipelines in
more populated areas, and a minority of Type C lines \136\) need only
have annual leakage surveys, with as long as 15 months between surveys.
The default leak detection survey periodicity for gas distribution
pipelines outside of business districts is only once every 5 years.
Similarly, PHMSA regulations at subpart M allow gas transmission and
select part 192-regulated gathering pipeline mileage to have right-of-
way patrols only once a year, if at all. Finally, patrols on gas
distribution pipelines inside business districts are required twice a
year.
---------------------------------------------------------------------------

\135\ PHMSA, ``Pipeline Safety: Requirement of Valve
Installation and Minimum Rupture Detection Standards--Final Rule,''
87 FR 20940, 20985 (Apr. 8, 2022) (introducing a new Sec. 192.636).
\136\ Only ca. 20,000 miles of the ca. 91,000 miles of Type C
gas gathering pipelines are subject to Sec. 192.706 leakage survey
requirements. PHMSA, Doc. No. PHMSA-2011-0023-0488, ``Regulatory
Impact Analysis for Gas Gathering Final Rule'' at 11, 15 (Nov.
2021).
---------------------------------------------------------------------------

Subpart M maintenance requirements governing the use of leak
detection equipment also reflect the same historical focus on acute
public safety risks. Subpart M regulations are silent on specific
technologies or equipment operators should employ in their leak
detection surveys. For example, leakage surveys on gas distribution
lines, certain regulated gathering lines, and un-odorized transmission
pipelines in Class 3 and Class 4 locations must be performed with leak
detection equipment--but part 192 neither requires particular
technologies, nor establishes performance standards for leak detection
equipment. Leakage surveys on other gas transmission pipelines (e.g.,
odorized lines and all pipelines in Class 1 and Class 2 locations) and
patrols of pipeline rights-of-way can rely entirely on human senses
such as smell or sight, which are imprecise and substantially limited
in their effectiveness. Evidence of a leak detectible by human senses
includes dead vegetation caused by natural gas displacing oxygen in the
soil, blowing soil, bubbling water, or noise. However, it may take a
long time for evidence of a gas leak on vegetation to appear visibly
from the air. Further, the reliability of vegetation surveys is
inconsistent and depends heavily on soil and climate conditions, the
characteristics of the vegetation, the time of year, and other factors.
For example, the impacts of gas leaks on vegetation may not be visible
during seasonal or climate conditions that produce dead vegetation, and
in some soil conditions gas can temporarily increase vegetation growth.
Finally, vegetation surveys are ineffective in areas with no or sparse
vegetation, such as paved areas, particularly rocky areas, or deserts.
PHMSA is not aware of research on the effectiveness of vegetation
surveys versus instrumented surveys in general, however operators who
begin performing instrumented surveys (such as the aerial survey
examples described in section II.D.4) generally report more leaks
discovered using instrumented surveys.
Additionally, PHMSA's IM regulations do not require identification
and remediation of all leaks. PHMSA's IM regulations apply to about 7
percent of gas transmission pipelines.\137\ And no part 192-regulated
gathering pipelines (even Types A and C pipelines with operating
characteristics and threats to public safety and the environment
comparable to transmission lines) \138\ are subject to any IM
requirements. IM requirements also reflect a historical focus on
identifying, preventing, and remediating risks to public safety from
large-volume, instantaneous releases or accumulated gas rather than
environmental harms. While the gas transmission IM regulations at
subpart O oblige some transmission operators to find and eliminate
pipeline anomalies posing risks to public safety, those regulations do
not require repair of all leaks discovered and allow for substantial
delay in the evaluation and subsequent repair of leaks that operators

[[Page 31910]]

(largely at their discretion) consider not to pose acute public safety
risks. DIMP regulations require gas distribution pipeline operators to
have an ``effective leak management program,'' but those regulations
provide few standards regarding what constitutes an ``effective''
program and can instead give considerable deference to an operator's
discretion regarding which leaks are repaired and when. Further,
neither subparts O nor P require operator IM plans to consider
replacement or remediation as a preventative or mitigative measure for
pipe materials known to leak, despite data demonstrating that cast
iron, wrought iron, unprotected steel, and certain plastic pipelines
are more susceptible to leaks and other losses of pipeline integrity.
PHMSA's IM regulations are also not designed to address leaks with low
release rates that persist for a long period of time, which can make
significant contributions to climate change.
---------------------------------------------------------------------------

\137\ The effectiveness of its IM regulations for gas
transmission pipelines at subpart O relies on operators'
identification that those requirements apply--which is not a given.
See NTSB, Pipeline Accident Brief 13-01, ``Rupture of Florida Gas
Transmission Pipeline and Release of Natural Gas'' (Aug. 13, 2013)
(finding that a gas transmission pipeline operator's exclusion of a
segment from its IM plan due to mischaracterization of a Class 1
location contributed to a subsequent rupture).
\138\ See Gas Gathering Final Rule, 87 FR at 6367-68, 63278-79
and 63282-84.
---------------------------------------------------------------------------

PHMSA part 191 reporting requirements also reflect a narrow focus
on public safety risks rather than environmental harms such as the
contribution of methane leaks to climate change, or environmental
degradation from the release of other flammable, toxic or corrosive
gases. Incident reporting requirements are expressed in terms of
personal injury, commercial harm, property damage, or minimum release
volumes that are far too high (3 MMCF) to capture any but the largest
unintentional leaks from pipeline facilities--corresponding to a
volumetric release rate of 340 cubic feet per hour (CFH) or more over a
one-year period. Although annual reports submitted to PHMSA contain
information on all leaks repaired each year, the instructions for those
annual reports explicitly discourage reporting of leaks that can be
eliminated by ``lubrication, adjustment or tightening'' on the narrow
presumption that such releases were not necessarily hazardous from a
public safety perspective. Operators are also not required to submit in
their annual reports the total number of leaks--of any type--detected
in the reporting period; the number of outstanding unrepaired leaks
from year-to-year; or estimated emission volumes from any category of
detected leaks.
Finally, the exclusion of all gas gathering pipelines from NPMS
reporting requirements inhibits PHMSA, State regulators, operators, and
members of the public from knowing the location and operating
characteristics of pipelines. Such knowledge would help identify and
remediate leaks and avoid excavation damage. Although all part 192-
regulated gathering pipelines are subject to damage prevention
requirements of Sec. 192.614, those requirements are not reinforced by
the NPMS requirements identifying the precise location of pipeline
infrastructure.
3. Real-World Consequences of Delayed Repair and Prolonged Releases
From Leaks on Gas Pipelines
The shortcomings of existing regulations pertaining to leak
detection and repair described above are not abstract risks; operators
currently allow leaks from gas pipelines to continue emitting methane
and other gases for extended periods of time, thereby threatening the
environment as well as public safety and human health.
Infrequent leak detection and patrol periodicities provide extended
time intervals within which leaks can develop and worsen, thereby
resulting in prolonged methane and other emissions to the atmosphere.
Infrequent leak detection and patrol periodicities also entail
increased public safety risks. Specifically, PHMSA's regulations have
long recognized the safety risk associated with potential ignition of
leaks, as evidenced by heightened leak surveying and maintenance
requirements throughout part 192 for pipelines located in areas where
buildings intended for human occupancy are more prevalent (Class 3 or 4
locations) as well as requirements to prevent the accumulation of gas
in confined spaces (see, e.g., Sec. Sec. 192.167(c)(2), 192.353(c),
192.355(b)(2), and 192.361(e)(3)). But leaks on gas pipelines that are
not associated with potential ignition of leaks also entail public
safety risks. Leaks of toxic or corrosive gases from part 192-regulated
pipeline facilities can have serious public safety consequences. And
leaks of any type can degrade into catastrophic failures--sometimes
referred to as the ``leak-before-break'' concept.\139\ Additionally,
the absence of baseline leak detection equipment technology
requirements for conducting leakage surveys can also inhibit timely
opportunities to identify, evaluate, and remediate leaks. The absence
(in subparts M, O, and P) of repair criteria and mandatory repair
schedules for all leaks compounds the delays and methodological
shortcomings in identifying leaks. And PHMSA's limited reporting
requirements for leaks from all types of gas pipeline facilities can
complicate its ability to identify systemic pipeline integrity issues
or support enforcement actions against specific operators. Lastly, the
exemption of all gas gathering pipeline facilities from NPMS reporting
requirements inhibits timely leak detection and introduces heightened
vulnerability to a principal mechanism (excavation damage) for loss of
pipeline integrity.
---------------------------------------------------------------------------

\139\ See, e.g., Wilkowski, ``Leak-Before-Break, What Does It
Really Mean?'' 122 Journal of Pressure Vessel Technology 267 (Aug.
2000); Zhang, et al., ``Paper: Preventive Leak Detection for High
Pressure Gas Transmission Networks,'' AAAI 2017 (2017); see also
GPTC Guide appendix G-192-11 table 3c, recommending that grade 3
leaks be re-evaluated within 15 months or during the next required
leakage survey.
---------------------------------------------------------------------------

PHMSA further estimates that, due to those limitations in its
regulatory regime, thousands of leaks persist across part 192-regulated
gas pipelines. With respect to gas distribution pipelines, PHMSA annual
report data between 2010 and 2021 yields roughly the same per-mile,
nationwide averages of repairs of all leaks (0.225 leaks repaired/mile
in 2010 and 0.230 in 2021) and repairs of hazardous leaks (0.089 in
2010 and 0.086 in 2021). PHMSA assumes that the average per-mile rate
at which new leaks are created (controlled for material type) remains
constant, suggesting either that operators may not be reporting to
PHMSA a significant number of leak repairs on their gas distribution
pipelines; operators are not discovering or repairing a significant
number of leaks on their gas distribution pipelines; or existing
regulatory requirements and operator repair practices have not yielded
improvements in reducing the frequency of leak repairs (and perhaps
have failed to yield improvements in leak identification) on gas
distribution pipelines for nearly a decade. PHMSA incident report data
for gas distribution pipelines shows that distribution system operators
reported only 377 incident reports identified as leaks (rather than
ruptures or mechanical punctures) during the entire period from 2010
through 2020. This represents a miniscule percentage of the 510,224
leak repairs reported on operators' annual reports in 2020 alone, a
figure which does not include leaks that are not scheduled for repair
at all. Forty-five percent of these reported leaks were attributable to
causes that progressed over time (e.g., corrosion failure, equipment
failure, and material failure), which may have been discovered earlier
through more frequent leakage surveys, patrols, and repair practices.
As described later in this section, evidence that leaks that are large
in release volume or hazardous to public safety are not reliably
detected or repaired is further supported by available state-

[[Page 31911]]

level information shows persistent backlogs of grade 3 leaks and
research with advanced leak detection methods, which suggests that
operators may not reliably detect releases with large volumes or that
are hazardous to public safety.
Data from States employing the three-tiered GPTC Guide leak grading
framework (discussed in section II.E.) for gas distribution pipeline
facilities demonstrates that most leaks on distribution main and
service pipelines that are identified by operators are not subject to
PHMSA repair requirements as hazardous leaks, and can persist for
extended periods before repair. By way of example, the 2020 Pipeline
Safety Performance Measures Report from New York State reports that out
of 19,683 leaks on main and service pipelines discovered by 11 natural
gas local distribution companies in 2019, 7,403 (37.6%) were grade 1
leaks that approximate to ``hazardous leaks'' under PHMSA repair
requirements in Sec. 192.703(c), while an additional 5,468 (27.8%)
were grade 2 leaks, and 5,768 (29.3%) were grade 3 leaks using New York
State requirements similar to the GPTC Guide criteria.\140\ New York
State has adopted repair deadlines mirroring those in the GPTC Guide
for grade 2 leaks (12 months or 6 months, depending on potential
hazard, see 16 NYCRR 255.813-255.815). However, neither the GPTC Guide
nor New York regulations (as of October 2022) require repair of grade 3
leaks, resulting in a backlog of almost 10,000 outstanding unrepaired
leaks in 2020.\141\ Each of these unrepaired leaks will continue to
release methane (or other gases) to atmosphere until remediated, and
each could increase in size between patrols or leakage surveys.
Minority populations and other disadvantaged communities often bear the
brunt of unrepaired leaks on those gas distribution systems.\142\ The
IM regulations at subpart P have proven insufficient to prevent leaks,
as all the gas distribution pipelines, including those in the New York
data described above, had been subject to DIMP regulations.
---------------------------------------------------------------------------

\140\ State of New York Department of Public Service, Case 21-G-
0165, ``2020 Pipeline Safety Performance Measures Report'' (June 17,
2021), <a href="https://www3.dps.ny.gov/W/PSCWeb.nsf/All/9DBA66C148A1310985257B2600750639?OpenDocument">https://www3.dps.ny.gov/W/PSCWeb.nsf/All/9DBA66C148A1310985257B2600750639?OpenDocument</a>. Note that New York
leak classification requirements use the term ``types'' rather than
``grades,'' however they are conceptually identical.
\141\ State of New York Department of Public Service, Case 21-G-
0165, ``2020 Pipeline Safety Performance Measures Report'' at
Appendix K (June 17, 2021), <a href="https://www3.dps.ny.gov/W/PSCWeb.nsf/All/9DBA66C148A1310985257B2600750639?OpenDocument">https://www3.dps.ny.gov/W/PSCWeb.nsf/All/9DBA66C148A1310985257B2600750639?OpenDocument</a>.
\142\ Luna et al., ``An Environmental Justice Analysis of
Distribution-Level Natural Gas Leaks in Massachusetts, USA,'' 162
Energy Policy 112778 (2022). This study of the distribution of gas
leaks reported to the Massachusetts Department of Public Utilities
found consistently higher densities of unrepaired leaks in the homes
of people of color, lower income persons, renters, adults with lower
levels of education, and limited English-speaking households. These
same groups were more likely to experience slower repair times and
significantly older unrepaired leaks.
---------------------------------------------------------------------------

The number of leaks from gas transmission pipelines are also
significant. A review of PHMSA incident data yields that over 500
(roughly 40%) of the 1,300 incidents reported by gas transmission
operators between 2010 and 2020 involved hazardous leaks.\143\ PHMSA's
IM regulations at subpart O do not ensure that pipeline operators
prevent such leaks. Of the over 500 leaks reported as incidents on gas
transmission pipelines between 2010-2020, nearly a quarter of those
incidents occurred on gas transmission pipelines subject to subpart O
requirements. Further, incident reports on gas transmission pipelines
show that many were either identified during leakage surveys or patrols
or were attributed to causes that could have degraded over time. PHMSA
therefore expects that more frequent patrols and leakage surveys and
prompt remediation would result in earlier detection and potential
avoidance of leak degradation that would lead to incidents.
---------------------------------------------------------------------------

\143\ This calculation is based on a review of gas transmission
pipeline incident reports, excluding incidents attributed to other
causes such as ``mechanical puncture,'' ``rupture'' or ``other.''
---------------------------------------------------------------------------

Annual report data similarly suggests a large number of leaks on
gas transmission pipelines and the potential value of enhanced leak
detection and repair requirements for promptly identifying and
remediating those leaks. In annual reports submitted between 2012-2021,
operators of gas transmission pipelines reported repairing an average
of 13,600 leaks repaired per year across the 302,000 miles of gas
transmission pipelines nationwide. But part 191 requires annual
reporting of only the number of leaks repaired--not all detected leaks
(even hazardous leaks detected but not repaired). In addition, part 192
does not provide clear timelines for ``prompt'' repair of hazardous
leaks, much less any timeline for other leaks. Even if unreported, non-
hazardous leaks occurred on gas transmission pipelines at just a
fraction of the average, per-mile rate of hazardous leak repairs noted
in annual reports over the last decade, there would be a significant
number of additional, unreported leaks on gas transmission pipelines
each year. Those unreported leaks would generally not be subject to
prescribed repair timelines under existing PHMSA regulations. Although
some of those leaks could be identified and corrected in a timely
manner pursuant to PHMSA's IM regulations at subpart O, the limited
application of those requirements (only transmission pipelines in HCAs)
and the significant discretion given to operators in designing and
executing IM plans do not guarantee any such leaks would be identified
and remediated promptly.
PHMSA similarly understands that its existing regulations tolerate
the persistence of numerous leaks on part 192-regulated gas gathering
pipelines. Data from incidents on Types A and B gas gathering pipelines
across 2010-2020 yields an average, per-mile rate of incidents--83
incidents on 11,542 miles of pipeline (0.0072 incidents/mile)--nearly
double that of gas transmission pipelines (0.00435 incidents/mile) over
the same period. Further, leaks are a more frequent cause of incidents
on Types A and B gas gathering pipelines than for gas transmission
pipelines--operators attributed nearly 80% of the incidents reported on
Types A and B gathering pipelines to leaks. And PHMSA understands from
reviewing incident reports for Types A and B gathering pipelines that
many of those incidents could have been avoided or mitigated by more
timely detection and repair. Annual report data for Types A and B
gathering pipelines tells a similar story. In 2020 annual reports,
Types A and B gathering operators reported 1,574 hazardous leak repairs
on 298,795 miles of onshore gas transmission pipelines (5.3 leaks per
1,000 miles) and 153 hazardous leak repairs on 11,542 miles of Type A
and Type B regulated onshore gas gathering pipelines (13.3 leaks per
1,000 miles). If the number of hazardous leak repairs corresponds to
the total number of hazardous leaks identified, Types A and B gathering
pipelines would have an average, per-mile rate of hazardous leaks more
than twice that of gas transmission pipelines. Similar to the
discussion above regarding distribution and transmission lines, the
annual report-derived values understate the total number of leaks on
Types A and B gathering lines. Therefore, the total number of leaks on
Types A and B gathering lines not subject to any meaningful Federal
repair requirements is likely even higher. Furthermore, the number and
persistence of leaks on Type C pipelines are likely to be higher than
on Types A and B gas gathering pipelines because Type C gathering
pipelines have historically avoided any meaningful

[[Page 31912]]

State or Federal reporting or design requirements.\144\
---------------------------------------------------------------------------

\144\ See, e.g., PHMSA, Doc. No. PHMSA-2011-0023-0504,
``Response to Petition for Reconsideration of the Gas Gathering
Final Rule'' at 3 (Apr. 1, 2022).
---------------------------------------------------------------------------

The number and persistence of leaks on gas distribution,
transmission, and gathering pipelines tolerated by PHMSA regulations
entail considerable risks to public safety.\145\ Each of those leaks
discussed above that were or became incidents reported pursuant to part
191 involved significant public safety consequences: specifically, one
or more of death, personal injury necessitating in-patient
hospitalization, property damage of $122,000 or more (excluding the
value of the gas itself), or 3 MMCF or more gas lost. Similarly, each
of the hazardous leaks observed on gas pipelines under existing PHMSA
regulations are a hazard with respect to public safety. Since leaks in
pressurized systems can over time degrade into catastrophic failures,
even those leaks that have not yet been reported as incidents or
otherwise designated as hazardous in that they do not involve an
existing or imminent risk of ignition can nevertheless give rise to
such risk if not repaired.
---------------------------------------------------------------------------

\145\ PHMSA discusses in this section only direct public safety
consequences of leaks; however (as explained in section II.D.3),
leaks and other releases from gas pipelines can also have second-
order public safety impacts resulting from climate change-induced
natural force damage and equipment malfunction.
---------------------------------------------------------------------------

Lastly, any leak from gas gathering pipelines entails unique public
safety risks. Natural gas gathering pipelines are often located in the
vicinity of socially vulnerable populations.\146\ Additionally,
unprocessed natural gas within gathering pipelines typically contains
significant quantities of volatile organic compounds (VOCs) and
hazardous air pollutants (HAPs) such as benzene (a known carcinogen).
As discussed in further detail in the Preliminary RIA, VOCs and HAPs
pose risks from long-term adverse health effects. VOC emissions are
precursors to ozone, and to a lesser extent fine particulate matter
(PM<INF>2.5</INF>). Both ambient ozone and PM<INF>2.5</INF> are
associated with adverse health effects, including respiratory
morbidity, such as asthma attacks, hospital and emergency department
visits, lost school days, and premature respiratory mortality. HAPs
contained in unprocessed natural gas includes several substances that
are known or suspected carcinogens, including but not limited to
benzene, formaldehyde, toluene, xylenes, and ethylbenzene. Benzene and
formaldehyde are known human carcinogens, and ethylbenzene has been
identified as possibly carcinogenic in humans. Chronic (long-term)
inhalation of benzene can result in several adverse noncancer health
effects including arrested development of blood cells, anemia,
leukopenia, thrombocytopenia, and aplastic anemia, and acute (short-
term) exposure to benzene vapors has been reported to cause negative
respiratory effects. Formaldehyde inhalation exposure also causes a
range of noncancer health effects including irritation of the nose,
eyes, and throat, and repeated exposures cause respiratory tract
irritation, chronic bronchitis, and nasal epithelial lesions. There is
evidence that formaldehyde may also increase the risk of asthma and
chronic bronchitis in children. Inhalation of toluene, mixed xylenes,
and ethylbenzene can have neurological, respiratory, and
gastrointestinal effects, among others, with chronic exposure to
toluene potentially leading to developmental effects such as central
nervous system dysfunction, attention deficits, and other anomalies.
Further, corrosives entrained in the unprocessed natural gas can
accelerate corrosion in the vicinity of leaks, thereby increasing the
risk of a catastrophic failure. Recent incident data on Types A and B
gas gathering pipelines similarly underscores the unique risks to
public safety posed by the exemption of any part 192-regulated gas
gathering pipelines from PHMSA's NPMS reporting requirements. The
average, per-mile rate of incidents due to excavation damage reported
to PHMSA between 2010 and 2020 on Types A and B gathering pipelines was
comparable to that on distribution pipelines (0.023 and 0.027 annual
incidents per 1,000 miles, respectively); further, insufficient
locating practices have been reported to PHMSA as a contributing factor
in those incidents.
---------------------------------------------------------------------------

\146\ Emanuel et al., ``Natural Gas Gathering and Transmission
Pipelines and Social Vulnerability in the United States,'' 5
GeoHealth (June 2021) (concluding that natural gas gathering and
transmission infrastructure is disproportionately sited in socially-
vulnerable communities).
---------------------------------------------------------------------------

Aside from the public safety risks discussed above, leaks from gas
distribution, transmission, and gathering pipelines are also a
significant contributor to climate change. As discussed in section
II.C.2 of this NPRM, current methane emissions data identifies leaks
across line pipe alone on U.S. natural gas distribution, transmission,
and gathering as a significant contributor (the GHGI estimates nearly
328.9 kt CH<INF>4</INF> in 2019) to U.S. methane emissions. But current
methane emissions estimates could materially understate actual methane
emissions. GHGRP reporting requirements do not capture all gas pipeline
mileage subject to PHMSA's regulations at parts 191 and 192,
introducing uncertainty into whether national average methane emissions
estimates derived from such reports may accurately be extrapolated to
all PHMSA-regulated gas pipelines. Additionally, recent evidence from
aerial surveys of a small (7,500 square kilometer) swath of the Permian
basin \147\ found leaks from natural gas gathering pipelines in the
Permian basin to be a larger source of methane emissions than would be
calculated using the national average in the GHGI.\148\ A series of
two-week aerial surveys conducted in the fall of 2019, summer of 2021,
and fall of 2021 conducted for the Environmental Defense Fund (EDF)'s
Permian Methane Analysis Project observed between 50 and 350 leaks
attributed to gas gathering line pipe, of which roughly half are likely
attributable to part 192-regulated gathering line pipe. PHMSA made this
assessment by comparing the leak coordinates for gathering line pipe
within the raw data of EDF's Permian Methane Analysis Project \149\ to
geospatial data for specific gathering pipelines downloaded from the
Texas Railroad Commission (TRRC) website.\150\ PHMSA then reviewed the
TRRC's database of attributes of those gathering pipelines to determine
diameter, using that metric to determine whether an observed leak was
on a part-192 regulated gathering pipeline. The leaks identified in
these aerial surveys, moreover, were not de minimis: the average leak
rate observed by EDF was 273 kg CH<INF>4</INF>/hour, correlating to
roughly a metric ton of methane emitted to atmosphere every five days.
Even this limited Permian Basin data could under-report the number and
scale of leaks from methane emissions from gas gathering pipelines if
projected

[[Page 31913]]

nationwide.\151\ Many of the gathering pipelines in the Permian basin
are relatively new pipelines, while older gas gathering infrastructure
in other production regions may leak at higher rates.
---------------------------------------------------------------------------

\147\ The entire Permian basin covers approximately 86,000
square miles--more than 220,000 square kilometers.
\148\ See Yu et al., ``Methane Emissions from Natural Gas
Gathering Pipelines in the Permian Basin,'' Environ. Sci. Technol.
Lett. (Nov. 8, 2022) (Yu Study) (``The EF [(emissions factor)]
derived from each of the four aerial surveys is more than an order
of magnitude higher than the EPA's published values [for national
average emissions].''). The emissions factors calculated from this
study were also ``4-13 times higher than the highest estimate
derived from a published ground-based survey of gathering lines.''
\149\ See EDF, Permian Methane Analysis Project, <a href="https://permianmap.org/">https://permianmap.org/</a> (last accessed July 20, 2022).
\150\ <a href="https://rrc.texas.gov/oil-and-gas/publications-and-notices/maps/">https://rrc.texas.gov/oil-and-gas/publications-and-notices/maps/</a> (last accessed July 25, 2022).
\151\ The Yu Study acknowledged that its data may also be
underestimating emissions from gathering pipelines. The authors
conservatively excluded any emissions sources in areas of co-located
gathering and transmission pipelines where the source could not be
definitively attributed, although the authors noted that it would be
reasonable to assume at least some of those sources were from
gathering pipelines. See Yu et al.
---------------------------------------------------------------------------

4. Regulatory Requirements Lag Commercially Available, Advanced Leak
Detection Technologies
As explained above in section D.1, PHMSA regulations prescribe
requirements for identifying leaks--leakage surveys and rights of way
patrols--directed principally toward risks to public safety (from
ignition of instantaneous, large-volume releases or accumulated gas)
and not toward environmental harm that even small leaks can cause.
Consistent with that historical approach, PHMSA regulations permit
reliance on non-instrumented leak detection methods such as smell or
visual surveys of gas transmission pipeline infrastructure and rights
of way that are more appropriate for discovering ruptures or
accumulated gas than smaller leaks. When leak detection equipment is
required, PHMSA regulations specify neither particular leak detection
technologies nor minimum performance standards for detection of gas
concentration by leak detection equipment.
These shortcomings in PHMSA's regulatory regime allow operators to
rely on inadequate or ineffective leak detection equipment and
practices, rather than encouraging use of commercially available,
advanced leak detection technologies and practices appropriate to
different gases transported by gas pipeline facility subject to part
192. Many of these technologies and practices were discussed by PHMSA,
industry and academic research organizations, and vendors within a
virtual public meeting on advanced methane leak detection technology
and practices hosted by PHMSA on May 5-6, 2021 (2021 Public
Meeting).\152\ PHMSA staff also attended the Methane Detection
Technology Workshop hosted by EPA on August 23-24, 2021 (2021 EPA
Methane Detection Technology Workshop).153 154 155 156
Presenters at these meetings described how innovations in equipment
sensitivity, analytics, automation, and survey speed of leak detection
services could increase the effectiveness and decrease the cost of
detecting gas releases from oil and gas facilities.
---------------------------------------------------------------------------

\152\ Recordings, transcripts, and slides from the 2021 Public
Meeting are available at the meeting web page at <a href="https://primis.phmsa.dot.gov/meetings/MtgHome.mtg?mtg=152">https://primis.phmsa.dot.gov/meetings/MtgHome.mtg?mtg=152</a>. A number of
entities submitted written comments before and after the meeting
that are available in the rulemaking docket at Doc. No. PHMSA-2021-
0039.
\153\ Recordings are available at the EPA meeting web page at:
https://www.epa.gov/controlling-air-pollution-oil-and-natural-gas-
industry/epa-methane-detection-technology-
workshop#:~:text=Natural%20Gas%20Industry-
,EPA%20Methane%20Detection%20Technology%20Workshop%20%2D%2D%20August%
2023%20and%2024,oil%20and%20natural%20gas%20industry (last accessed
July 20, 2022).
\154\ See ``Attachment 1: Summary Report Methane Detection
Technology Workshop'' of ``Background Technical Support Document for
the Proposed New Source Performance Standards (NSPS) and Emissions
Guidelines (EG)'' at <a href="https://www.regulations.gov/">https://www.regulations.gov/</a> Docket ID No. EPA-
HQ-OAR-2021-0317-0166.
\155\ See ``EPA's Methane Detection Technology Virtual Workshop.
August 23-24, 2021. Audio'', ``Transcripts'', and ``Presentations''
at <a href="https://www.regulations.gov/">https://www.regulations.gov/</a> Docket ID No. EPA-HQ-OAR-2021-0317-
0183, EPA-HQ-OAR-2021-0317-0181, and EPA-HQ-OAR-2021-0317-0182
respectively.
\156\ See ``Controlling Air Pollution from the Oil and Natural
Gas industry. EPA Methane Detection Technology Workshop. August 23
and 24, 2021'' <a href="https://www.regulations.gov/">https://www.regulations.gov/</a> Docket ID No. EPA-HQ-
OAR-2021-0317-0183.
---------------------------------------------------------------------------

At the 2021 Public Meeting, EDF presented a set of recommended
elements for an advanced methane leak detection system, including (1)
leak detection equipment with a parts-per-billion level of sensitivity
\157\ and the ability to capture other data for use in an algorithm to
understand the size and location of leaks; (2) a defined deployment
strategy or work practice to ensure that accurate data is being
collected; and (3) comprehensive data collection on topics such as leak
location, estimated leak flow rate or gas emission rate, a coverage map
showing which areas were successfully surveyed and which areas were
not, and a summary or cumulative loss estimate for the total area
surveyed. AGA observed in their remarks at the 2021 Public Meeting and
AGA et al.\158\ in their written comments that most currently available
leak detection technologies are focused on identifying indications of
methane leaks in the air (i.e., gas concentration) rather than
measuring the rate of leakage from a component. AGA et al.
characterized methane concentration as a more appropriate metric for
evaluating the public safety risks from explosion than for estimating
the amount of methane going to atmosphere.
---------------------------------------------------------------------------

\157\ EDF commented that parts-per-billion detection is
important in this effort in light of the potential for hidden
underground leaks, where only a small volume of gas may migrate
through the pavement despite a significant leak buried under the
street.
\158\ The American Gas Association (AGA), API, American Public
Gas Association, GPA Midstream Association (GPA), and Interstate
Natural Gas Association of America submitted joint comments (Doc.
No. PHMSA-2021-0039-0008) to the rulemaking docket after the 2021
Public Meeting. Throughout this NPRM, references to ``AGA et al.''
refer to those joint comments.
-------------------------------------------------------------------------

[…truncated; see source link]

View on FederalRegister.gov →Plain-text source

Indexed from Federal Register on May 18, 2023.

This is legal information, not legal advice. Laws vary by jurisdiction and change frequently. Always verify current law with official sources and consult a licensed attorney in your jurisdiction for advice on your specific situation.