Pipeline Safety: Gas Pipeline Leak Detection and Repair

Federal RegisterMay 18, 2023

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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: https://www.regulations.gov.

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

https://www.regulations.gov/.

Note:

Comments are posted without changes or edits to

https://www.regulations.gov,

including any personal information provided. There is a privacy statement published on

https://www.regulations.gov.

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

www.regulations.gov,

as described in the system of records notice (DOT/ALL-14 FDMS), that can be reviewed at

www.dot.gov/privacy.

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

sayler.palabrica@dot.gov.

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

http://www.regulations.gov.

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

sayler.palabrica@dot.gov.

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

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,

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 § 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

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.

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).

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

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.

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 §§ 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 §§ 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 §§ 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 § 192.763 reflecting the capabilities of

commercially available advanced technologies and practices; (3) amend § 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 § 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 § 192.770) and LNG facilities (at § 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 (§§ 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 (§§ 192.9, 192.12, 192.605, 193.2503, and 193.2605); (8) expand reporting requirements (at §§ 191.3 and 191.19) and recordkeeping requirements (at §§ 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 § 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 § 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,

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.

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 § 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 § 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”

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.

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

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 § 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 § 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 § 193.2624.

C. Costs and Benefits

Consistent with Executive Order (E.O.) 12866 and the requirements of the Federal Pipeline Safety Laws,

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).

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

). 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

), by concentration and accounts for the second-greatest contribution to total radiative forcing (warming effect).

The Environmental Protection Agency (EPA) calculated that methane made up approximately 11 percent (by mass of CO

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.

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

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

National Oceanic and Atmospheric Administration (NOAA), “Annual Greenhouse Gas Index” at Figure 3 & Table 2 (Spring 2022),

https://gml.noaa.gov/aggi/aggi.html.

EPA, “Overview of Greenhouse Gases,”

https://www.epa.gov/ghgemissions/overview-greenhouse-gases#methane

(last accessed December 5, 2022).

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

since 1984 (1980 for CO

) 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

emissions since 1850.

The IPCC also noted that in 2019, atmospheric CH

concentrations were higher than at any time in 800,000 years, and that “strong, rapid and sustained reductions in CH

emissions” would be needed to offset short-term warming effects.

According to the IPCC, well-mixed GHGs include CO

, N

O, and CH

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.

2021 IPCC Report, SPM-8.

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.

Methane, on the other hand, is more short-lived than CO

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.

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.

Buis, “The Atmosphere: Getting a Handle on Carbon Dioxide” (Oct. 9, 2019).

EPA, “Overview of Greenhouse Gases,”

https://www.epa.gov/ghgemissions/overview-greenhouse-gases

(last accessed July 20, 2022).

EPA, “Importance of Methane,”

https://www.epa.gov/gmi/importance-methane

(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.

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 °C above 1850 levels by the end of the century,

and only the very low-emissions scenario (SSP1-1.9) is likely to limit warming to 1.5 °C by the end of the century (specifically, between 1.0 ° to 1.8 °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.

Rapid and full-scale efforts to reduce methane and other GHG emissions are needed to achieve the very low-emissions scenario (SSP1-1.9).

In contrast, the intermediate scenario (SSP2-4.5) results in potentially dangerous warming of2.0 °C by midcentury, rising to between2.1 ° to 3.5 °C by 2100.

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

§§ 191.3 and 192.3 (definitions of “gas” for the purposes of parts 191 and 192, respectively).

2021 IPCC Report, 1.2.

2021 IPCC Report, SPM-16, Table SPM.1.

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,

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.

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.”

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.

See

NOAA National Centers for Environmental Information,

Monthly Global Climate Report for Annual 2021

(Jan. 2022),

https://www.ncei.noaa.gov/news/global-climate-202112.

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.

The IPCC estimates that current levels of warming

have made 10-year extreme heat events

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.

2021 IPCC Report, SPM-8, SPM-18.

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.

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.

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.

An expected contributor to global sea level rise is the loss of virtually all summer ice from the Arctic Ocean before 2050.

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.

2021 IPCC Report, SPM-6.

2021 IPCC Report, SPM-28.

European Space Agency (ESA), “Simulations Suggest Ice-Free Arctic Summers by 2050” (May 13, 2020),

https://climate.esa.int/en/projects/sea-ice/news-and-events/news/simulations-suggest-ice-free-arctic-summers-2050/.

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.

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.

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.

2021 IPCC Report, SPM-15.

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).

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.

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.

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.

2021 IPCC Report, SPM-12.

Yanchin, “Interior Threatens Colorado River Cuts,”

E&E News

(Oct. 28, 2022),

https://www.eenews.net/articles/interior-threatens-colorado-river-cuts/.

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

and doubling the cumulative forest area burned by wildfires between 1984 and 2015.

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).

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.

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.

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

communities that rely on them, throughout the region.

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).

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).

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.

U.S. Global Change Research Program,

Impacts, Risks, and Adaptation in the United States: Fourth National Climate Assessment, Volume II—Southwest

at 1116 (2018).

Williams et al., “Rapid Intensification of the Emerging Southwestern North American Megadrought in 2020-2021,” 12

Nature Climate Change

(Mar. 1, 2022).

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.

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.

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.

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).

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).

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.

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.

Average sea level rise of 6 feet by 2100 could displace an estimated 13.1 million people along the U.S. coasts.

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).

U.S. Global Change Research Program,

Impacts, Risks, and Adaptation in the United States: Fourth National Climate Assessment, Volume II—Northeast

at 692 (2018).

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).

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

(and again in 2016),

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.

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.

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.”

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.

74 FR 66495 (Dec. 15, 2009).

81 FR 54422 (Aug. 15, 2016).

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).

U.S. Department of Health and Human Services, Office of Climate Change and Health Equity,

Climate and Health Outlook: Extreme Heat

(June 2022),

https://www.hhs.gov/sites/default/files/climate-health-outlook-june-2022.pdf;

British Columbia, “Minister's Statement on 619 Lives Lost During 2021 Heat Dome” (June 7, 2022).

https://news.gov.bc.ca/26965.

Methane also directly contributes to adverse air quality because it is a chemical precursor to ozone.

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.

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.”

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

Great Plains states, potentially resulting in significant costs from flood damage and adaptation costs.

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.

U.S. Global Change Research Program,

Impacts, Risks, and Adaptation in the United States: Fourth National Climate Assessment, Volume II—Northeast

at 695 (2018).

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).

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).

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.

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.

Eric S. Blake and David A. Zelinsky. NOAA National Hurricane Center. `National Hurricane Center Tropical Cyclone Report.” May 9, 2018.

https://www.nhc.noaa.gov/data/tcr/AL092017_Harvey.pdf.

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.

https://www.nhc.noaa.gov/data/tcr/AL152017_Maria.pdf.

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.

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.

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.

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.

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).

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).

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.”

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.

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.

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.

And insofar as gas transmission and gas gathering pipeline infrastructure is often located in the vicinity of socially vulnerable populations,

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.

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).

U.S. Global Change Research Program,

The Impacts of Climate Change on Human Health in the United States: A Scientific Assessment

at 21 (2016).

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

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.

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.

Parts 191 and 192 govern not only natural gas, but also any “flammable gas, or gas which is toxic or corrosive.”

See

§§ 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.

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 § 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 §§ 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.”

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.

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 § 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.

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.

These pipelines are subject to scaled safety requirements in § 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, § 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.

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).

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),

https://www.phmsa.dot.gov/news/notice-limited-enforcement-discretion-particular-type-c-gas-gathering-pipelines.

See the pressure criteria in the second column of table 1 in § 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

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.

“Composite materials” are defined in § 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 § 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),

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

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.

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 × 0.40) is 14,000 psi.

Distribution Pipelines

A gas distribution pipeline is defined at § 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.

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.

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:

https://www.phmsa.dot.gov/working-phmsa/state-programs/state-programs-overview

(last accessed Dec. 20, 2022).

LNG Facilities

An LNG facility is defined in Federal regulations at 49 CFR part 193

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.

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 § 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 § 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.

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.

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).

• 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.

The GHGI includes estimates of GHG emissions from sources including fossil fuel combustion, industrial processes, agriculture, and transportation. The GHGI is updated annually.

EPA,

Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2020

(Apr. 15, 2022) (2022 GHGI).

• 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

injection sites in the United States including large suppliers or facilities that emit more than 25,000 metric tons of CO

equivalent per year.

In the GHGI, the EPA estimates that the global warming potential of 1 metric ton of CH

is equivalent to 25 metric tons of CO

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

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.

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.

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.

One operator may submit multiple GHGRP reports if they operate multiple systems or in multiple states.

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

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.

The current GHGI quantifies emissions from leaks in pipelines using the following approaches and data:

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.

• 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.

• 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.

• 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.

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.

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.

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.

Additional discussion of emissions factors for gas pipelines is available in the Preliminary RIA for this NPRM available in the rulemaking docket.

IEA, Press Release, “Methane emissions from the energy sector are 70% higher than official figures” (Feb. 23, 2022),

https://www.iea.org/news/methane-emissions-from-the-energy-sector-are-70-higher-than-official-figures.

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.

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).

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.

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).

Gas transmission, gas distribution, transportation-related gas and LNG storage, and regulated gas gathering lines as determined in § 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

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.

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 § 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.

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.

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

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

emissions from compressor station engines.

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 CH

Percent

Exploration and Production (excluding gathering)

1,964

Gathering and Boosting

1,500

Processing Plants

494

Transmission, Storage, and LNG

1,625

Distribution

554

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)

and by extension the GHGI estimate for 2020 as well (0.69 million metric tons of methane vs. 0.13 million metric tons).

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

and relies on a 1996 report by the U.S. EPA and the Gas Research Institute (GRI)

and a 2015 study by Lamb et. al.

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.

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).

EPA,

Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2020, Annex 3.6-1

(Apr. 15, 2022).

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).

https://www.epa.gov/sites/default/files/2016-08/documents/final_revision_ng_distribution_emissions_2016-04-14.pdf.

EPA & Gas Research Institute,

Methane Emissions from the Natural Gas Industry

(June 1996) (the 1996 GRI/EPA Report).

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).

Weller et al., 2020, at 8958-59.

2022 GHGI: 2020 Natural Gas Distribution Systems Emissions by Category

Source

Kt CH

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 § 192.3 includes the customer meter in most configurations.

Unlike natural gas transmission systems, the GHGI separately estimates emissions from natural gas distribution mains and service pipelines by construction material.

PHMSA has monitored trends in legacy pipe materials for years, as these materials pose safety risks.

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

in 1990 to 554.5 kt CH

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.

2022 GHGI, Annex 3.6.

PHMSA, “Pipe Replacement Background” (Apr. 26, 2021),

https://www.phmsa.dot.gov/data-and-statistics/pipeline-replacement/pipeline-replacement-background

(last accessed Dec. 20, 2022).

See

PHMSA. “Natural Gas Distribution Infrastructure Safety and Modernization Grants” (Aug. 2, 2022),

https://www.phmsa.dot.gov/grants/pipeline/natural-gas-distribution-infrastructure-safety-and-modernization-grants

(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 CH

Percent

Pipeline Leaks

3.3

0.3

Pipeline Venting (including blowdowns and upset venting)

221.3

17.0

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 CH

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

Total

1,035.8

100.0

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

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 CH

Percent

Station and Compressor Fugitive Emissions

24.5

7.6

Reciprocating Compressors

102.9

32.2

Storage Wells

11.3

3.5

Metering and Regulating (Transmission Interconnect)

75.3

23.5

Metering and Regulating (Farm Taps & Direct Sales)

17.5

5.5

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,

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 § 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.

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.

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

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

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

https://www.phmsa.dot.gov/data-and-statistics/pipeline/distribution-transmission-gathering-lng-and-liquid-accident-and-incident-data

(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 § 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),

https://www.phmsa.dot.gov/data-and-statistics/pipeline/annual-report-mileage-natural-gas-transmission-gathering-systems

(last accessed Aug. 19, 2022).

2022 GHG Inventory: Natural Gas Gathering and Boosting Methane Emissions

Source

Kt CH

Percent

Station Combustion Slip

407.1

Station Compressors

306.9

Station Tanks

244.3

Station Pneumatic Devices

202.0

Pipeline Leaks

126.7

Station Yard Piping

93.3

Station Blowdowns

44.9

Station Dehydrator Vents and Leaks

25.7

Station Pneumatic Pumps

27.2

Pipeline Blowdowns

9.4

Station Flare Stacks

11.1

Station Separators

1.4

Station Acid Gas Removal Units

0.1

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 ± 20 t/h [(metric tonnes per hour)] emitted from pipelines (including underground gas gathering pipelines) and 26 ± 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

/mile in 2017 but decreased to 288.5 in the 2022 GHGI.

See

2022 GHGI, Annex 36 Table 3.6-2.