Pipeline Safety: Safety of Gas Distribution Pipelines and Other Pipeline Safety Initiatives

Federal RegisterSep 7, 2023

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DEPARTMENT OF TRANSPORTATION

Pipeline and Hazardous Materials Safety Administration

49 CFR Parts 191, 192, and 198

[Docket No. PHMSA-2021-0046]

RIN 2137-AF53

Pipeline Safety: Safety of Gas Distribution Pipelines and Other Pipeline Safety Initiatives

AGENCY:

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

ACTION:

Notice of proposed rulemaking (NPRM).

SUMMARY:

PHMSA proposes revisions to the pipeline safety regulations to require operators of gas distribution pipelines to update their distribution integrity management programs (DIMP), emergency response plans, operations and maintenance manuals, and other safety practices. These proposals implement provisions of the Leonel Rondon Pipeline Safety Act—part of the Protecting our Infrastructure of Pipelines and Enhancing Safety Act of 2020—and a National Transportation Safety Board (NTSB) recommendation directed toward preventing catastrophic incidents resulting from overpressurization of low-pressure gas distribution systems similar to that which occurred on a gas distribution pipeline system in Merrimack Valley on September 13, 2018. PHMSA also proposes to codify use of its State Inspection Calculation Tool, which is used to help states determine the base-level amount of time needed for inspections to maintain an adequate pipeline safety program. Further, PHMSA proposes other pipeline safety initiatives for all part 192-regulated pipelines, including gas transmission and gathering pipelines, such as updating emergency response plans and inspection requirements. Finally, PHMSA proposes to apply annual reporting requirements to small, liquefied petroleum gas (LPG) operators in lieu of DIMP requirements.

DATES:

Individuals interested in submitting written comments on this NPRM must do so by November 6, 2023.

ADDRESSES:

Comments should reference Docket No. PHMSA-2021-0046 and may be submitted in any of the following ways:

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:

DOT Docket Management System: West Building Ground Floor, Room W12-140, 1200 New Jersey Avenue SE, between 9:00 a.m. and 5:00 p.m. ET, Monday-Friday, except Federal holidays.

Fax:

202-493-2251

Instructions:

Include the agency name and identify Docket No. PHMSA-2021-0046 at the beginning of your comments. Note that all comments received will be posted without change to

https://www.regulations.gov

including any personal information provided. If you submit your comments by mail, submit two copies. If you wish to receive confirmation that PHMSA received your comments, include a self-addressed stamped postcard.

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 (5 U.S.C. 552), CBI is exempt from public disclosure. If your comments in response to this NPRM 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 NPRM, it is important that you clearly designate the submitted comments as CBI. Pursuant to 49 Code of Federal Regulations (CFR) 190.343, you may ask PHMSA to provide confidential treatment to the 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 a copy of the original document with the CBI deleted along with the original, unaltered document; and (3) explain why the information you are submitting is CBI. Submissions containing CBI should be sent to Ashlin Bollacker, 1200 New Jersey Avenue SE, DOT: PHMSA-PHP-30, Washington, DC 20590-0001. Any comment PHMSA receives that is not explicitly designated as CBI will be placed in the public docket.

Docket:

To access the docket, which contains background documents and any comments that PHMSA has received, go to

https://www.regulations.gov.

Follow the online instructions for accessing the docket. Alternatively, you may review the documents in person at DOT's Docket Management Office at the address listed above.

FOR FURTHER INFORMATION CONTACT:

Ashlin Bollacker by phone at 202-680-8303 or by email at

ashlin.bollacker@dot.gov.

SUPPLEMENTARY INFORMATION:

I. Executive Summary

A. Purpose of the Regulatory Action

B. Summary of the Proposed Regulatory Action

C. Costs and Benefits

II. Background

A. Gas Distribution Systems Overview

B. Gas Distribution Configurations

C. Merrimack Valley

D. Low-pressure Gas Distribution System in South Lawrence

E. Gas Main Replacement Project

F. Emergency Response to the Merrimack Valley Incident

III Recommendations, Advisory Bulletins, and Mandates

A. National Transportation Safety Board

B. Advisory Bulletins

C. Statutory Authority

IV. Proposed Amendments

A. Distribution Integrity Management Programs (Subpart P)

B. State Pipeline Safety Programs (Sections 198.3 and 198.13)

C. Emergency Response Plans (Section 192.615)

D. Operations and Maintenance Manuals (Section 192.605)—Overpressurization

E. Operations and Maintenance Manuals (Section 192.605)—Management of Change

F. Gas Distribution Recordkeeping Practices (Section 192.638)

G. Distribution Pipelines: Presence of Qualified Personnel (Sections 192.640 and 192.605)

H. District Regulator Stations—Protections Against Accidental Overpressurization (Sections 192.195 and 192.741)

I. Inspection: General (Section 192.305)

J. Records: Tests (Sections 192.517 and 192.725)

K. Miscellaneous Amendments Pertaining to Part 192—Regulated Gas Gathering Pipelines (Sections 192.3 and 192.9)

V. Regulatory Analyses and Notices

I. Executive Summary

A. Purpose of the Regulatory Action

PHMSA proposes a series of revisions to the pipeline safety regulations (49 CFR parts 190-199) in response to congressional mandates and an NTSB recommendation, and to implement lessons learned from a September 13, 2018, incident resulting from the overpressurization of a low-pressure gas distribution pipeline operated by Columbia Gas of Massachusetts (CMA) in the Merrimack Valley. That incident resulted in one fatality, more than 20 people (including three first responders) being hospitalized, damage to approximately 130 structures, and an evacuation request for more than 50,000

residents. PHMSA expects the proposals of this NPRM will address the root causes and aggravating factors contributing to the severity of that incident and help reduce the frequency and consequence of other failure mechanisms on gas distribution pipeline systems. The proposals include improved design standards for low-pressure gas distribution systems; enhanced distribution integrity management program requirements; strengthened recordkeeping, planning, and monitoring practices for maintenance and construction activities on gas distribution systems; and improved emergency response communication and coordination protocols during emergency events for all 49 CFR part 192-regulated gas pipelines.

PHMSA also proposes codifying within the pipeline safety regulations its State Inspection Calculation Tool (SICT). The SICT is one of many factors used to help States determine the base-level amount of time needed for administering adequate pipeline safety programs, which PHMSA considers when awarding grants to States supporting those programs. PHMSA anticipates these proposed regulatory amendments will improve public safety, while also reducing threats to the environment (including, but not limited to, reduction of greenhouse gas emissions during incidents on gas pipelines), and promoting environmental justice for minority populations, low-income populations, or other underserved and disadvantaged communities, or others who are particularly likely to live and work near higher-risk gas distribution pipeline systems.

Part 192—regulated pipelines refers to gas distribution, transmission, and gathering pipelines, as applicable.

A catalyst for this rulemaking is the 2018 Merrimack Valley incident. The NTSB investigated the cause of this incident and issued a full report on its findings and safety recommendations.

The NTSB found the cause to be CMA's weak engineering management that failed to adequately plan and oversee a cast iron main replacement project. Contributing to the incident was CMA's low-pressure gas distribution system that was designed and operated without adequate overpressure protection. The NTSB reviewed other incidents from the past 50 years and found several previous incidents that involved high-pressure gas entering low-pressure gas systems. The NTSB found that a common cause of failure was an overpressure protection design scheme, common on older low-pressure distribution systems, that can be defeated by a single failure mode (

e.g.,

operator error or equipment failure). Currently, low-pressure gas systems are not required to have a device at the service location that would prevent the overpressurization of a customer's piping, fittings, and appliances, a required design feature on high-pressure distribution systems. Instead, overpressure protection on low-pressure distribution systems often is provided by a redundant design scheme (

i.e.,

worker and monitor regulators at the regulator stations). While overpressurizations on distribution pipelines are infrequent, they have the potential to be catastrophic given their location within population centers. As a result of its investigation, the NTSB recommended that PHMSA revise the pipeline safety regulations to address overpressure protection failures like that which occurred on CMA's low-pressure system.

NTSB, Accident Report PAR-19/02, “Overpressurization of Natural Gas Distribution System, Explosions, and Fires in Merrimack Valley, Massachusetts, September 13, 2018” (Sept. 24, 2019),

https://www.ntsb.gov/investigations/AccidentReports/Reports/PAR1902.pdf.

In 2020, the Leonel Rondon Pipeline Safety Act was enacted as sections 202-206 of the Protecting our Infrastructure of Pipelines and Enhancing Safety Act of 2020 (PIPES Act of 2020, Pub. L. N 116-260). The law requires PHMSA to amend its regulations to ensure operators evaluate the risks associated with the presence of cast iron piping and the possibility of overpressurization on gas distribution systems through updates to their distribution integrity management program (DIMP). (49 U.S.C. 60109(e)(7)). The law further requires PHMSA to amend its regulations to ensure operators' emergency response plans include timely communications with first responders, public officials, customers, and the general public. (49 U.S.C. 60102(r)). PHMSA was also directed to amend its regulations to ensure operators' operations and maintenance (O&M) manuals include procedures for responding to overpressurization and a management of change (MOC) process with review and certification by relevant qualified personnel. (49 U.S.C. 60102(s)). PHMSA must also amend its regulations to ensure operators (1) keep “traceable, reliable, and complete records;” (2) monitor the gas pressure at district regulator stations during construction; and (3) assess and upgrade their district regulator stations to minimize the risk of overpressurization. (49 U.S.C. 60102(t)).

Pursuant to its statutory authority and in furtherance of its mission to protect people and the environment by advancing the safe transportation of energy and other hazardous materials essential to our daily lives, PHMSA proposes in this NPRM a number of regulatory amendments to implement those statutory mandates and NTSB recommendations arising from the 2018 CMA overpressure incident. PHMSA expects the proposed regulatory amendments to reduce the likelihood of another overpressure incident on low-pressure gas distribution systems similar to that which occurred in Merrimack Valley. PHMSA also expects the proposed amendments to reduce the frequency of, as well as public and environmental consequences from, failure mechanisms on gas distribution pipeline systems and other pipeline facilities. Additionally, this rulemaking aligns with the Administration's efforts to improve environmental justice and combat the climate crisis.

Older cast-iron or bare-steel gas distribution pipelines—a type of gas distribution pipeline particularly vulnerable to failure and overpressurization—are disproportionately concentrated in older, residential (often urban) areas with large minority, low- income, and other historically underserved and disadvantaged populations.

In addition, the reduced frequency and severity of incidents on gas pipelines anticipated from this rulemaking would have the benefit of minimizing the release of greenhouse gases from pipeline incidents—in particular methane—to the atmosphere.

The White House Office of Domestic Climate Policy, “U.S. Methane Emissions Reduction Action Plan,” (Nov. 2021),

https://www.whitehouse.gov/wp-content/uploads/2021/11/US-Methane-Emissions-Reduction-Action-Plan-1.pdf.

This and other PHMSA rulemakings are identified in the U.S. Methane Emissions Reduction Action Plan as critical elements in the Federal government's efforts to address the climate crisis.

Id.

at 7-8 (listing PHMSA's Leak Detection and Repair rulemaking (proposed in 88 FR 31890 (May 18, 2023) (Leak Detection NPRM)), its Gas Gathering Final Rule (86 FR 63266 (Nov. 15, 2021)), its Valve Installation and Minimum Rupture Detection Standards Final Rule (87 FR 20940 (Apr. 8, 2022) (Valve Rule)), and its Gas Transmission Pipeline Safety Final Rule (87 FR 52224 (Aug. 24, 2022)).

See, e.g.,

Luna & Nicholas, “An Environmental Justice Analysis of Distribution-Level Natural Gas Leaks in Massachusetts, USA,” 162 Energy Policy 112778 (Mar. 2022); Weller et al., “Environmental Injustices of Leaks from Urban Natural Gas Distribution Systems: Patterns Among and Within 13 U.S. Metro Areas,” Environ. Sci & Tech. (May 11, 2022).

The proposed rule is consistent with the goals of a new grant program established by the Bipartisan Infrastructure Law (BIL, enacted as the Infrastructure Investment and Jobs Act, Pub. L. 117-58). The new grant program, PHMSA's first ever Natural Gas Distribution Infrastructure Safety

and Modernization grant program, authorizes $200 million a year in grant funding with a total of $1 billion in grant funding over the next five years. The grant funding is to be made available to a municipality or community owned utility (not including for-profit entities) to repair, rehabilitate, or replace its natural gas distribution pipeline systems or portions thereof or to acquire equipment to (1) reduce incidents and fatalities and (2) to avoid economic losses. The new grant program authorized by BIL can, however, address only part of the universe of at-risk distribution pipeline systems. While the grant program would assist eligible entities who receive funding in making needed repairs to their pipeline systems, PHMSA's proposal would go further in ensuring that all gas distribution and other part-192 regulated operators improve and maintain the safety of their systems and reduce the risk of public safety impacts and environmental damage from incidents on their pipeline systems.

B. Summary of the Proposed Regulatory Action

In this rulemaking, PHMSA proposes amendments to 49 CFR parts 191, 192, and 198. PHMSA also proposes compliance deadlines for each of the NPRM's regulatory amendments.

1. Clarifications and Updates to DIMP Plans—Part 192, Subpart P. Pursuant to 49 U.S.C. 60109(e)(7), PHMSA proposes several revisions to its DIMP regulations at 49 CFR part 192, subpart P. PHMSA further proposes that, subject to certain exceptions at § 192.1003, all gas distribution pipeline operators—including service lines—would need to update their DIMP plans in conformity with the amended requirements no later than one year after the publication of any final rule in this proceeding.

First, PHMSA proposes to require all operators of gas distribution pipeline systems identify and minimize the risks to their systems from specific threats in their DIMP. These specific threats, where applicable, include: (1) the presence of certain materials, such as cast iron and other piping with known issues; (2) overpressurization of low-pressure systems; and (3) extreme weather and other geohazards. Operators must also consider the effect of age on those specific threats faced by a distribution pipeline.

For operators of low-pressure gas distribution systems, PHMSA proposes that, when evaluating and ranking the above and other threats identified in their DIMP plans, operators must evaluate risks from: (1) abnormal operating conditions; and (2) potential consequences associated with low-probability events. If an operator can demonstrate through a documented engineering analysis, or an equivalent analysis incorporating operational knowledge, that no potential consequences are associated with a particular low-probability event, and therefore no potential risk exists, then the operator must notify PHMSA and state regulatory authorities of that determination within 30 days. Additionally, as part of the proposal to implement measures to minimize the risk of overpressurization, PHMSA would require operators of low-pressure distribution systems to identify, maintain, and obtain pressure control records. PHMSA would also require operators to identify and implement preventive and mitigative measures based on the unique characteristics of their system. If operators choose to implement measures to minimize the risk of an overpressurization on a low-pressure system, then they must notify PHMSA and state regulatory authorities no later than 90 days in advance of implementing any alternative measures. As an alternative to implementing such preventive and mitigative measures, operators could choose to upgrade their systems to meet new proposed design requirements applicable to new systems.

PHMSA is also proposing to omit operators of a liquefied petroleum gas (LPG) distribution pipeline system that serves fewer than 100 customers (small LPG operators) from the DIMP requirements. Based on recommendations from the National Association of Pipeline Safety Representatives (NAPSR), a National Academies of Science (NAS) study, and PHMSA's incident data, current DIMP requirements do not provide a safety benefit warranting the compliance burdens those requirements impose on small LPG operators and the administrative burdens placed on PHMSA and state regulatory authorities. Instead, PHMSA proposes to add a requirement for small LPG operators to complete an annual report providing data that would support PHMSA's regulatory oversight of the safety of those facilities.

2. Codifying in Regulation the Use of the State Inspection Calculation Tool—§§ 198.3 and 198.13. Consistent with 49 U.S.C. 60105(b) and 60105 note, PHMSA will update the SICT and proposes to revise its regulations to require that states use the SICT when ensuring an adequate number of safety inspectors are employed in their pipeline safety programs.

States would have to comply with these proposed changes no later than the next SICT update immediately following the effective date of any final rule in this proceeding. PHMSA proposes amendments to 49 CFR part 198 that would codify in regulation the SICT's use and define the terms “State Inspection Calculation Tool” and “inspection person-days” for the purposes of 49 CFR part 198.

The SICT can be accessed on the PHMSA Portal by authorized users.

3. Updates to Emergency Response Communications—§ 192.615. Pursuant to 49 U.S.C. 60102(a), PHMSA proposes a series of updates to its emergency response plan requirements that will be applicable to all operators of part 192-regulated gas pipelines. PHMSA also proposes certain emergency response plan requirements specific to gas distribution pipeline operators pursuant to 49 U.S.C. 60102(r). Unless a different compliance timeline is specified below, operators would need to update their emergency response plans in conformity with those amended requirements no later than one year after the publication of any final rule in this proceeding.

For all gas pipeline operators, PHMSA proposes to expand the existing list of pipeline emergencies in its regulations at § 192.615 for which operators must have procedures ensuring prompt and effective response by adding emergencies involving a release of gas that results in a fatality, as well as any other emergency deemed significant by the operator. In the event of a release of gas resulting in one or more fatalities, all operators must also immediately and directly notify emergency response officials upon receiving notice of the same. For distribution pipeline operators only, PHMSA's proposed expansion of the list of emergencies discussed above will also include the unintentional release of gas and shutdown of gas service to 50 or more customers (or 50 percent of its customers if it has fewer than 100 total customers); operators would need to immediately and directly notify emergency response officials on receiving notice of the same.

PHMSA also proposes regulatory amendments requiring gas distribution operators to update their emergency response plans to improve communications with the public during an emergency. First, PHMSA proposes to require gas distribution operators to establish and maintain communications with the general public as soon as practicable during an emergency. Second, PHMSA proposes to require gas

distribution pipeline operators to develop and implement, no later than 18 months after the publication of any final rule in this proceeding, an opt-in system to keep their customers informed of the safety status of pipelines in their communities should an emergency occur.

PHMSA also seeks comment on whether it should require gas distribution operators to develop and implement emergency response procedures in accordance with incident command system (ICS) tools and practices. PHMSA also invites comment on the technical feasibility, practicability, and cost of immediate emergency notifications to customers via electronic text message or via a cellular phone application (“app”)—including both opt-in and opt-out notification approaches.

4. Updates to Operations and Maintenance Procedural Manuals—§ 192.605. Pursuant to 49 U.S.C. 60102(s), PHMSA also proposes a series of amendments to operations and maintenance (O&M) procedure manuals in § 192.605 that would require all gas distribution operators to implement within one year of the publication of any final rule issued in this proceeding. First, PHMSA proposes to require that operators of all gas distribution pipelines update their O&M procedures to account for the risk of overpressurization. PHMSA would require operators to have procedures for identifying and responding to overpressurization indications, including the specific actions and sequence of actions an operator would carry out to immediately reduce pressure or shut down portions of the gas distribution system, if necessary. PHMSA proposes that these O&M procedures would also describe investigating, responding to, and correcting the cause(s) of overpressurization indications.

Second, and again pursuant to 49 U.S.C. 60102(s), PHMSA proposes to require that operators of gas distribution pipelines develop and follow an MOC process when (1) installing, modifying, replacing, or upgrading regulators, pressure monitoring locations, or overpressure protection devices; (2) modifying alarm setpoints or upper or lower trigger limits on monitoring equipment; (3) introducing new technologies for overpressure protection into the system; (4) revising, changing, or introducing new standard operating procedures for design, construction, installation, maintenance, and emergency response; and (5) making any other changes that could impact the integrity or safety of a gas distribution system. Should any of these changes that an operator makes introduce a public safety hazard into the operator's gas distribution system, PHMSA proposes that the operator must identify, analyze, and control these hazards before resuming operations.

As part of the MOC process, PHMSA also proposes to require that gas distribution operators ensure qualified personnel review and certify construction plans associated with installations, modifications, replacements, or upgrades for accuracy and completeness, before the work begins. This amendment would ensure that qualified personnel—who are competently trained and experienced to identify system design and process deficiencies on gas distribution pipeline systems—provide oversight during the planning of those activities.

5. New Recordkeeping Requirements—§ 192.638. Pursuant to 49 U.S.C. 60102(t)(1), PHMSA proposes that all gas distribution pipeline operators identify and maintain traceable, verifiable, and complete maps and records documenting the characteristics of their systems that are critical to ensuring proper pressure controls for their gas distribution pipeline systems and to ensure that those records are accessible to anyone performing or supervising design, construction, and maintenance activities on their systems. PHMSA proposes to specify that these required records include (1) the maps, location, and schematics related to underground piping, regulators, valves, and control lines; (2) regulator set points, design capacity, and valve-failure mode (open/closed); (3) the system's overpressure protection configuration; and (4) any other records deemed critical by the operator. PHMSA proposes to require that the operator maintain these integrity-critical records for the life of the pipeline because these records are critical to the safe operation and pressure control of a gas distribution system. Operators would need to comply with this new requirement within one year of the publication of any final rule in this proceeding. If an operator does not have traceable, verifiable, and complete records as contemplated by this new requirement, then the operator must (1) identify and document which records they need, and (2) develop and implement procedures for generating or collecting those records, to include procedures for ensuring the generation or collection of those records. PHMSA also proposes that operators update these records on an opportunistic basis (

i.e.,

through normal operations, maintenance, and emergency response activities).

PHMSA expects that many gas distribution pipeline operators already have these records. Where they do not, these amendments would help to ensure that gas distribution pipeline operators improve the completeness and accuracy of their records. This amendment will also help to improve pipeline safety by ensuring operators provide appropriate personnel—such as qualified employees responsible for planning construction activities—with better, more complete, and more accurate records.

6. Monitoring of Gas Systems by Qualified Personnel—§ 192.640. Pursuant to 49 U.S.C. 60102(t)(2), PHMSA proposes that, where operators of gas distribution pipelines do not have the capability to remotely monitor pressure and either remotely or automatically shut off the gas flow at district regulator stations, operators must have qualified personnel on site to monitor certain construction projects so that they can prevent or respond to an overpressurization at a district regulatory station during those construction activities that have been determined to involve potential for such an event. Accordingly, PHMSA proposes requirements for all gas distribution operators to evaluate their construction projects to identify activities that could result in an overpressurization event at a district regulator station. If the operator identifies a potential for overpressurization due to a construction project, then the operator must ensure that at least one qualified employee or contractor is present during those activities that could result in a potential threat of overpressurization of the system. That qualified personnel would be responsible for monitoring the gas pressure in the affected portion of a gas distribution system and for promptly shutting off the gas flow to control an overpressurization event on the system. PHMSA is also proposing that operators must provide those qualified personnel with the location of all critical shutoff valves, pressure control records, and stop-work authority (unless prohibited by operator procedures) as well as the emergency response procedures, including the contact information of appropriate emergency response personnel. PHMSA proposes that gas distribution pipeline operators would need to comply with these requirements beginning one year after the publication of any final rule in this proceeding.

7. Requirements for New Regulator Stations—§§ 192.195 and 192.741. Pursuant to 49 U.S.C. 60102(t)(3), PHMSA proposes to require that

operators design new regulator stations on low-pressure distribution systems so there are redundant technologies installed to avoid or mitigate overpressurizations. Specifically, PHMSA proposes that all gas distribution operators, beginning one year after the publication of any final rule in this proceeding, equip all new, replaced, relocated, or otherwise changed district regulator stations serving low-pressure gas distribution systems with at least two methods of overpressure protection (such as a relief valve, monitoring regulator, automatic shutoff valve, or some combination thereof) that is appropriate for the configuration and siting of the station. Additionally, PHMSA proposes that operators minimize the risks from an overpressurization of a low-pressure system caused by a single event (such as excavation damage, natural forces, equipment failure, or incorrect operations) that either immediately or over time affects the safe operation of more than one overpressure protection device.

PHMSA also proposes to require that operators of low-pressure gas distribution systems monitor the outlet gas pressure at or near the district regulator station on such systems using a device capable of real-time notification to the operator of overpressurization. Low-pressure gas distribution operators are already required to have devices such as telemetering or recording gauges that record the gas pressure on their systems. However, some of these devices are not designed with the ability to provide real-time notification, and there is no explicit requirement that those devices be located near the district regulator station.

8. Construction Inspections for Gas Transmission Pipelines and Distribution Mains—§ 192.305. PHMSA proposes to amend § 192.305 to lift the indefinite stay of a regulatory amendment to that provision that had been introduced within a final rule issued on March 11, 2015.

“Pipeline Safety: Miscellaneous Changes to Pipeline Safety Regulations,” 80 FR 12762, 12779 (Mar. 11, 2015). PHMSA indefinitely stayed § 192.305 in response to a petition for reconsideration.

See

“Pipeline Safety: Miscellaneous Changes to Pipeline Safety Regulations: Response to Petitions for Reconsideration,” 80 FR 58633, 58634 (Sept. 30, 2015).

PHMSA also proposes an exception from this provision's inspection requirements for small gas distribution pipeline operators who would not be able to comply with the construction inspection requirement without using a third-party inspector. These regulatory amendments would, beginning one year after the publication of any final rule issued in this proceeding, apply to all other gas distribution pipelines operators; all gas transmission, all offshore gas gathering, and Type A gas gathering pipelines, and certain Types B and C gathering pipelines (specifically, those that are new, replaced, relocated, or otherwise changed).

9. Test Records—Clarification for Tests on Gas Distribution Systems—§§ 192.517 and 192.725. PHMSA proposes to amend § 192.517 to specifically identify the information that operators must record for tests performed on new, replaced, or relocated gas distribution pipelines and to ensure such records are available to operator personnel throughout the life of the pipeline. PHMSA proposes to amend § 192.725 to clarify that each disconnected service line must be tested in the same manner as a new, replaced, or relocated service line—that is, tested in accordance with 49 CFR part 192, subpart J—before being reinstated. PHMSA proposes to require that gas distribution operators comply with these amended testing recordkeeping requirements in connection with gas distribution pipelines that are new, replaced, or relocated beginning one year after the publication of any final rule in this proceeding.

10. Annual Reporting—§ 191.11. PHMSA proposes to add or expand annual reporting requirements for operators of gas distribution pipeline systems, including small LPG operators. For gas distribution pipelines, PHMSA proposes to collect additional information, such as the number and miles of low-pressure service lines, including their overpressure protection methods. For small LPG operators, these annual reports will collect information on the number and miles of service lines, and the disposition of any leaks. These proposed amendments will not apply to master meter systems, petroleum gas systems excepted from 49 CFR part 192 in accordance with § 192.1(b)(5), or individual service lines directly connected to production pipelines or gathering pipelines, other than a regulated gathering pipeline, as determined in § 192.8. PHMSA proposes that operators would need to comply with the above changes to annual reporting requirements beginning with the first annual reporting cycle after the effective date of any final rule issued in this proceeding.

11. Miscellaneous Amendments Pertaining to Part 192—Regulated Gas Gathering Pipelines—§§ 192.3 and 192.9. Following a decision by the U.S. Court of Appeals for the District of Columbia Circuit in litigation challenging application of requirements of PHMSA's April 2022 Valve Rule to gas and hazardous liquid gathering pipelines,

PHMSA issued a technical correction to the April 2022 Valve Rule codifying that decision.

PHMSA now proposes removal of certain exceptions introduced in the Technical Correction to restore, with respect to certain part 192-regulated gas gathering pipelines, application of specific regulatory amendments from the Valve Rule pertaining certain definitions (§ 192.3) as well as—by way of removal of exceptions within the regulatory cross-references at § 192.9—emergency planning and response (§ 192.615) and protocols for notifications of potential ruptures (§ 192.635).

GPA Midstream Ass'n

Dep't of Transp.,

67 F.4th 1188 (D.C. Cir. 2023).

“Pipeline Safety: Requirement of Valve Installation and Minimum Rupture Detection Standards: Technical Corrections,” 88 FR 50056 (Aug. 1, 2023).

C. Costs and Benefits

Consistent with 49 U.S.C. 60102(b) and Executive Order 12866 “Regulatory Planning and Review,” as amended by Executive Order 14094 “Modernizing Regulatory Review”, PHMSA has prepared an assessment of the benefits and costs of the proposed rule as well as reasonable alternatives.

PHMSA expects that the rulemaking will yield significant public safety benefits associated with reduced frequency and severity of incidents similar to that which occurred in 2018 in Merrimack Valley, which resulted in a number of adverse consequences described in Section I.A. of this NPRM, as well as approximately $1.7 billion in property damage, lost gas, claims, other mitigation costs, and the social cost of methane emissions. PHMSA also expects that the proposed rule will yield other, unquantified benefits, which include improvements in risk reduction for pipeline leaks and incidents; reduced consequences from all incidents and emergencies; improved enforcement and oversight procedures; advanced safety measures and communications; avoided emissions; improved public confidence in the safety of gas pipeline systems; and associated environmental enhancements for populations, including those in historically disadvantaged areas. Cost savings reflect the removal of some requirements for small LPG operators. The costs of the proposed rule are attributed to new requirements and

updates to operators' DIMPs, emergency response plans, operations and maintenance procedures, monitoring and inspection protocols, and other reporting and record-keeping proposals. The provisions include a range of proposals for primarily gas distribution operators, along with some proposals for other gathering and transmission operators.

88 FR 21879 (Apr. 6, 2023); 58 FR 51735 (Oct. 4, 1993).

PHMSA estimates the annualized costs of the proposed rule to be approximately $110 million per year at a 3 percent discount rate. In Table ES-1, below, PHMSA provides a summary of the estimated costs for the major provisions in this rulemaking and the total cost. For the full cost/benefit analysis and additional details on the summaries, please see the preliminary regulatory impact analysis (PRIA) in Docket No. PHMSA-2021-0046.

Table ES-1—Total Annualized Costs

[Millions, 2020$]

Proposed rule

requirement

discount

rate

discount

rate

DIMP

$3.2

$4.3

Small LPG DIMP

−0.3

SICT

0.0

Emergency response

1.0

1.2

O&M

42.8

44.7

Recordkeeping

24.3

27.8

Qualified personnel

34.8

District regulator stations

1.2

1.6

Inspections

0.04

0.05

Records: Tests

0.6

Annual Reporting

2.3

Total

110.0

117.1

Note:

Costs annualized over 20 years.

Source: PHMSA analysis of gas distribution, transmission, and gathering operators, 2022.

PHMSA expects that each of the elements of the rulemaking, as proposed in this NPRM, will be technically feasible, reasonable, cost-effective, and practicable for the reasons stated in this NPRM and its supporting documents (including the PRIA and draft Environmental Assessment, each available in the docket for this rulemaking), and because the commercial, public safety and environmental benefits of those proposed regulatory amendments as described therein (reduced frequency and severity of incidents similar to the 2018 Merrimack Valley incident which bore an approximate cost of $1.7 billion in 2020$), would outweigh any associated costs and support PHMSA's proposed rule compared to alternatives.

II. Background

A. Gas Distribution Systems Overview

More than 2.3 million miles of gas distribution pipelines deliver gas to communities and businesses across the United States.

Gas distribution systems are made up of pipelines called “mains,” which distribute the gas within the system, and much smaller lines called “service lines,” which distribute gas to individual customers. Because the purpose of distribution pipelines is to deliver gas to customers, distribution pipeline systems are located predominantly in urban and suburban areas. Distribution pipelines are generally smaller in diameter than transmission pipelines and operate at lower pressures.

PHMSA, “Annual Report Mileage for Gas Distribution Systems” (June 1, 2022),

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

Risk to the public from gas distribution pipelines result from the potential for unintentional releases of the gas transported through the pipelines. Due to their proximity to populations, releases from distribution pipelines bear a particular risk to surrounding populations, communities, property, and the environment, and may result in death, injuries, and property damage.

Even small releases of natural gas can result in environmental harm, as methane (the primary constituent of natural gas) is a significant contributor to the climate crisis, with more than 25 times the impact on an equivalent basis as carbon dioxide.

While the overall trend in pipeline safety has steadily improved over the past two decades, gas distribution pipelines are still involved in a majority of serious gas pipeline incidents.

According to PHMSA's data, between 2003 and 2022, excavation damage was the leading cause of serious incidents along gas distribution pipelines (28 percent), followed by other outside force damage (23 percent) and incorrect operation (14 percent).

This gas, regulated under 49 CFR parts 191 and 192, can be natural gas and any “flammable gas, or gas which is toxic or corrosive.”

See

§§ 191.3 and 192.3 (definitions of “gas”). By way of example, in addition to natural gas, PHMSA regulates as a “flammable gas” over 1,500 miles of hydrogen gas pipelines.

See

PHMSA Interpretation Response Letter No. PI-92-030 (July 14, 1992) (noting PHMSA regulates hydrogen pipelines under 49 CFR part 192); PHMSA, “Presentation of Vincent Holohan for Workgroup#4: Hydrogen Network Components at December 2021 Meeting” at slide 11 (Dec. 1, 2021),

https://primis.phmsa.dot.gov/meetings/FilGet.mtg?fil=1227.

PHMSA consequently understands the proposed revisions to 49 CFR parts 191 and 192 within this NPRM would apply not only to natural gas pipelines but also to other gas pipeline governed by 49 CFR parts 191 and 192.

U.S. Envtl. Prot. Agency, Global Methane Initiative: Importance of Methane (last updated June 9, 2022),

https://www.epa.gov/gmi/importance-methane#:~:text=Methane%20is%20more%20than%2025,due%20to%20human%2Drelated%20activities.

Serious incidents are those including a fatality or injury requiring in-patient hospitalization, excluding incidents when secondary ignition is involved, sometimes called “fire first” incidents. Between 2001 and 2020, gas distribution incidents comprised 81 percent of all the serious incidents reported to PHMSA. The three-year average incident count between 2018 and 2020 is 25, down from an average of 28 serious incidents between 2001 and 2020. “Pipeline Incident 20 Year Trends” (Nov. 15, 2022),

https://www.phmsa.dot.gov/data-and-statistics/pipeline/pipeline-incident-20-year-trends.

“Pipeline Incident 20 Year Trends” (Nov. 15, 2022),

https://www.phmsa.dot.gov/data-and-statistics/pipeline/pipeline-incident-20-year-trends.

Much of the Nation's gas distribution piping has been in the ground for a long time. Per PHMSA's gas distribution operator database, more than 50 percent of the nation's pipelines were constructed before 1970 during the creation of the interstate pipeline network built in response to the demand for energy in the post-World War II economy.

Historically, gas distribution pipelines were constructed from many different materials, including cast iron, steel, and copper. However, material fabrication and installation practices have improved since much of the Nation's gas distribution pipeline systems were installed, in acknowledgment that iron alloys like cast iron and steel degrade or corrode over time. Consequently, the age of a gas distribution system pipeline is an important factor in evaluating the risk it poses to public safety and the environment.

PHMSA, “By-Decade Inventory: Reports” (Mar. 16, 2020),

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

On April 4, 2011, following a string of major gas pipeline incidents, the Secretary of Transportation announced a Pipeline Safety Action Plan (Action Plan) that was a vehicle for Federal and State cooperation to accelerate the repair, rehabilitation, and replacement of the highest-risk pipeline infrastructure.

Efforts implementing the Action Plan focused on pipeline age and material as significant risk indicators. Pipelines constructed of cast- and wrought iron and bare steel were among those materials identified as posing the highest risk. In fact, operators of cast-iron and bare-steel distribution pipelines perform the vast majority of all leak repairs, despite these lines only making up about 21 percent of all distribution pipelines according to

PHMSA's distribution operators' annual report data.

PHMSA, “U.S. Transportation Secretary Ray LaHood Announces Pipeline Safety Action Plan” (Apr. 4, 2011),

https://www.phmsa.dot.gov/sites/phmsa.dot.gov/files/docs/dot4111.pdf.

Cast iron or bare steel pipelines account for 95 percent of corrosion leaks on mains, 92 percent of natural-force leaks on mains, 91 percent of pipe/weld/joint failure leaks; 97 percent “other cause” leaks on mains; and 76 percent of all known leaks. PHMSA, “Cast and Wrought Iron Inventory” (Apr. 26, 2021),

https://www.phmsa.dot.gov/data-and-statistics/pipeline-replacement/cast-and-wrought-iron-inventory

(“Cast and Wrought Iron Inventory”).

Though the amount of cast and wrought iron pipe in use within gas distribution systems has declined significantly in recent years thanks to State and Federal safety initiatives and pipeline operators' replacement efforts, there are still approximately 20,000 miles of mains and 7,000 miles of service lines in the United States.

According to the U.S. Department of Energy, the total cost of replacing all cast iron and bare steel distribution pipelines in the United States would be approximately $270 billion.

PHMSA understands that both cost and practical barriers, such as urban excavation and disruption of gas supplies, can also limit replacement efforts. However, PHMSA finds that proactive management of the integrity of aging pipe infrastructure enhances safety and reliability, contributes to cost savings over the longer term, and can be less disruptive to customers and communities than a reactive approach. Accelerating leak detection, repair, rehabilitation, or replacement efforts also delivers the desired integrity and safety benefits more expeditiously, lowering maintenance requirements associated with the aging pipe that is being replaced.

See

Cast and Wrought Iron Inventory.

U.S. Dep't of Energy, “Transforming U.S. Energy Infrastructures in a Time of Rapid Change: The First Installment of the Quadrennial Energy Review” at S-5 (Apr. 2015)

https://www.energy.gov/sites/prod/files/2015/08/f25/QER%20Summary%20for%20Policymakers%20April%202015.pdf.

There is no simple formula for determining which parts of the Nation's pipeline infrastructure should be of greatest concern. Factors often associated with higher risk include pipeline age, materials of construction, exposure to elements or outside forces, and an operator's practices in managing the integrity of its pipeline system. Each of these factors can contribute to a pipeline's risk, but effective integrity management can counterbalance the impact of aging and types of construction materials.

B. Gas Distribution Configurations

In a distribution system, gas is sourced from a transmission pipeline operating at a high pressure and must be safely delivered to the customer at lower pressures that are safe for customer piping and appliances. There are multiple points along the system where operators can reduce the pressure to be more suitable for the needs of the customer. City gate stations are the first such reduction point, and district regulator stations are pressure-reducing facilities downstream of city gate stations that further reduce the pressure from the pipeline coming from the city gate.

This lower pressure downstream of a district regulator station is more suitable for providing service to customers.

“At the city gate the pressure of the gas is reduced, and [this] is normally the location where odorant (typically mercaptan) is added to the gas, giving it the characteristic smell of rotten eggs so leaks can be detected.” Pipeline Safety Trust, “Pipeline Basics & Specifics About Natural Gas Pipelines” at 4 (Feb. 2019),

https://pstrust.org/wp-content/uploads/2019/03/2019-PST-Briefing-Paper-02-NatGasBasics.pdf.

Each gas distribution system must be designed to operate safely at or below a certain pressure, also known as its maximum allowable operating pressure (MAOP), as determined in accordance with § 192.619. Exceeding this pressure can cause the gas to build up in the pipeline and potentially cause the failure of piping, joints, fittings, or customer appliances. As gas flows through a distribution system, devices called regulators control the flow of gas to maintain a constant pressure. If a regulator senses a drop or rise in pressure above or below a set point, it will open or close accordingly to adjust the pressure of gas. As an additional safety precaution against overpressurization, some distribution pipelines are also designed with a relief valve to vent the gas into the atmosphere. While modern gas regulators are highly reliable devices, they can fail due to physical damage, equipment failure (

e.g.,

degradation of materials such as seals and gaskets, defects or maintenance issues, or inability to control pressure as set), or the presence of foreign material in the gas stream.

Because there is the possibility of a regulator failing, distribution systems are typically designed with multiple means of protection and redundancies to reduce the likelihood of a catastrophic failure.

Gas may contain moisture, dirt, sand, welding slag, metal cuttings from tapping procedures, or other debris. Problems caused by such foreign material in the gas stream are most prevalent following construction on the pipeline supplying gas to the district regulator station. American Gas Association, “Leading Practices to Reduce the Possibility of a Natural Gas Over-Pressurization Event” at 447 (Nov. 26, 2018).

Many regulators require external control lines, which sense the outlet pressure of the regulator. Based on the pressure sensed through the control lines, the regulator valve will open or close to control the downstream pressure of the regulator. In some older installations, control lines are located farther downstream of the regulator station on the buried outlet piping based on either the manufacturer's recommendations or previous control-line standards and practices at the time of installation. However, a break in the control line (

e.g.,

if it is damaged during an excavation) will make the regulator sense a lower downstream pressure and will cause the regulator valve to open wider automatically. This could result in overpressurization of the downstream piping, which could lead to a catastrophic event. The same result occurs if the flow through the control line is otherwise disrupted, for example if the control line valve is shut off or if the control line is isolated from the regulator it is controlling.

In general, gas distribution pipeline systems can be classified as either low pressure or high pressure. In a high-pressure gas distribution system, the gas pressure in the main is substantially higher than what the customer requires, and a pressure regulator installed at each meter reduces the pressure from the main to a pressure that can be used by the customer's equipment and appliances. These regulators incorporate an overpressure-protection device to prevent overpressurization of the customer's piping and appliances should the regulator fail. Additionally, all new or replaced service lines connected to a high-pressure distribution system must have excess flow valves (see § 192.383). Excess flow valves can reduce the flow of gas through the service line by minimizing unplanned, excessive gas flows.

An excess-flow valve is a mechanical safety device installed on a gas service line to a residence or small commercial gas customer. In the event of damage to the gas service line between the street and the meter, the excess-flow valve will minimize the flow of gas through the service line. The pipeline safety regulations require a gas distribution company to install such a device on new or replacement service lines for single-family residences and certain multifamily and commercial buildings where the service line pressure is above 10 pounds per square inch gauge (psig). See 49 CFR 192.383 for specific requirements.

In a low-pressure distribution system, the gas pressure in the main is substantially the same as the pressure provided to the customer (see § 192.3). Since a district regulator station located upstream of service lines acts as the primary means of pressure control in low-pressure distribution systems, an overpressurization in the system served by the district regulator could affect all the customers served by the system.

This is what occurred during the Merrimack Valley incident and is an inherent weakness of low-pressure gas distribution systems.

C. Merrimack Valley

On September 13, 2018, fires and explosions occurred after high-pressure natural gas entered a low-pressure natural gas distribution system operated by CMA, a subsidiary of NiSource, Inc.

One person, 18-year-old Leonel Rondon, was killed, and 22 people, including 3 firefighters, were transported to hospitals for treatment of their injuries. At least five homes were destroyed in the city of Lawrence and the towns of Andover and North Andover, MA, by the fires and explosions. More than 130 structures were damaged in total. Most of the damage occurred from fires ignited by natural gas-fueled appliances. More than 50,000 residents were asked to evacuate.

CMA transferred from NiSource, Inc. to Eversource Energy in November 2020.

In response, fire departments from three municipalities were dispatched to the fires and explosions. First responders initiated the Massachusetts fire mobilization plan and received mutual aid from neighboring districts in Massachusetts, New Hampshire, and Maine. Emergency management officials had the electric utility shut off electrical power in the area. Additionally, CMA shut down its low-pressure natural gas distribution system, affecting 10,894 customers, including some outside of the affected area who had their service shut off as a precaution.

The NTSB on September 24, 2019, issued a final report of its investigation into the Merrimack Valley incident.

The NTSB found the cause of the incident was CMA's weak engineering management that failed to adequately plan, review, sequence, and oversee the construction project that led to the abandonment of a cast iron main without first relocating the regulator control lines to the new plastic main. The NTSB also found that contributing to the accident was CMA's low-pressure natural gas distribution system that was designed and operated without adequate overpressure protection.

NTSB/PAR-19/02 at 49.

D. Low-Pressure Gas Distribution System in South Lawrence

At the time of the incident, CMA owned and operated a network of gas pipeline systems for the transportation and delivery of natural gas that included approximately 25 different low-pressure gas distribution systems in Massachusetts. Among these systems, CMA owned and operated a low-pressure system in the area of South Lawrence, Massachusetts that served Lawrence, Andover, and North Andover, among other communities (South Lawrence system). The South Lawrence system was installed in the early 1900s and was constructed with cast iron and bare steel mains and used several regulator stations to control downstream pressure. The regulator stations were located below ground and contained regulators that monitored and controlled downstream pressure. Natural gas came into the South Lawrence system at a pressure of about 75 pounds per square inch, gauge (psig). The regulators reduced the pressure to about 0.5 psig for delivery to customers.

The South Lawrence system consisted of 14 regulator stations, wherein the regulator valves opened or closed based on the pressure the regulator sensed downstream to maintain the downstream pressure at a pre-set limit called a “set point.” This was to ensure the pressure in the system did not exceed the MAOP and become unsafe. Each regulator station in the South Lawrence system had at least two regulators in series—a “worker regulator” and a “monitor regulator”—each with a control line that sensed downstream pressure and connected back to its regulator, thereby enabling the regulator station to regulate system pressure. The worker regulator was the primary regulator that maintained system pressure. The monitor regulator was the redundant backup in case the worker regulator was damaged or malfunctioned. If both control lines experienced a decrease in pressure, such as when the cast iron main was disconnected, the worker regulator and monitor regulator would automatically and continually increase the pressure, resulting in an overpressurization of the low-pressure system. That is precisely what occurred in CMA's gas main replacement project.

E. Gas Main Replacement Project

Beginning in 2016, CMA began a pipe replacement project in the South Lawrence system called the South Union Street project. CMA's field engineering department initiated the project in part due to the pending City of Lawrence water main project that would encroach on two aging cast iron mains on South Union Street. The construction project was also part of CMA's Gas System Enhancement Plan that called for replacing existing low-pressure cast iron pipelines (both mains and the accompanying service lines) with higher-pressure modern plastic piping.

The South Union Street project proposed replacing two low-pressure cast iron mains with one plastic high-pressure main. Once installed, the new plastic main would be “tied-in” to the distribution system and service lines supplying gas to customers. As is typical in pipe replacement projects, the two cast iron mains would be completely disconnected from the low-pressure system and abandoned in the ground upon completion.

The scope of the South Union Street project included the replacement of the cast iron mains near a belowground regulator station located at the intersection of Winthrop Avenue and South Union Street (the Winthrop regulator station), one of the 14 regulator stations that monitored and controlled downstream pressure in the South Lawrence system. Up until the time of the incident, two control lines connected the Winthrop regulator station and the two cast iron and bare steel mains on South Union Street.

CMA contracted with a pipeline services firm to complete the replacement project. CMA prepared a work package, which included materials such as isometric drawings and procedural details for disconnecting and connecting pipes, for each of the planned construction activities. However, CMA did not prepare a package for the relocation of the control lines serving the regulator station. The absence of a complete work package led to the contractor completing the installation of the plastic main with the regulator control lines at the regulator station still connected to the cast iron main that was being replaced.

In 2016, the construction crew installed the new plastic main on South Union Street and began feeding the new plastic main with gas from the Winthrop regulator station. However, CMA put the work on hold due to a city-wide moratorium on all gas, water, and sewer projects in Lawrence. Consequently, the construction crew was unable to begin any of the tie-in and abandonment procedures to tie-in or connect the mains or services to the new plastic main and thus was also unable to abandon the cast iron mains on South Union Street. The regulator control lines at the Winthrop regulator station remained connected to the cast iron mains that would ultimately be decommissioned.

The final stage of the South Union Street project involved the installation of tie-ins to the new plastic main, after which the legacy cast iron mains would be decommissioned and abandoned in

their existing location. CMA then connected the plastic pipe to the gas distribution system, which allowed it to be monitored for pressure changes.

On September 13, 2018, at 4:00 p.m., the construction crew completed the final “tie-in” and abandonment procedure following the procedures CMA provided to the crew at South Union Street. Unbeknownst to the construction crew, the control lines were still connected to the abandoned cast iron main despite the gas now flowing through the new plastic main. At the Winthrop regulator station, about 0.5 miles south of the work area, the control lines that were still connected to the cast-iron mains on South Union Street sensed a sharp decline in pressure, causing the Winthrop regulator station to add more pressure into the South Lawrence low-pressure system. Feeding high-pressure gas into the low-pressure system resulted in a catastrophic overpressurization of the system. The overpressurization of the low-pressure system in the city of Lawrence and the towns of Andover and North Andover sent gas into home appliances at a rate that they were not designed to handle. This created explosions and fires in those homes and businesses. Local fire departments were the first to receive notification of the start of the incident via 9-1-1 calls. Shortly after 4:00 p.m., the local fire departments were inundated with calls from the public.

F. Emergency Response to the Merrimack Valley Incident

On September 13, 2018, the monitoring center in Columbus, OH, which was overseeing the CMA system, received pressure alarms on its supervisory control and data acquisition (SCADA) system.

The system recorded a sudden increase in pressure in the Merrimack Valley low-pressure system at 3:57 p.m. The SCADA's high-pressure alarms activated at 4:04 p.m. and 4:05 p.m. for the South Lawrence district regulator station and Andover, respectively. The SCADA system was only able to monitor system pressures; it could not remotely control the pressure of this system.

Operators use SCADA systems to monitor and control critical assets remotely.

See

§ 192.631. Here, the South Lawrence system was monitored by CMA's corporate owner at the time, NiSource.

Following company protocol, at 4:06 p.m., the SCADA controller called the on-call technician in Lawrence, MA, and reported the high-pressure event. The on-call technician dispatched 3 field technicians to perform field checks on the 14 regulators within the South Lawrence system. Not until about 4:30 p.m. did a CMA field technician at the Winthrop regulator station (the location of the control lines still connected to the cast iron main) hear a loud sound and recognize that a large quantity of natural gas was flowing through the Winthrop regulator station. The CMA field technician adjusted the set point on the two regulators to reduce flow and isolated them. The CMA field technician then noticed that the sound of the flowing natural gas began to decrease.

Meanwhile, at 4:18 p.m., a CMA field engineer and a CMA field operations leader (FOL) were at another construction site when they received notice to respond to fire coming out of house chimneys. Due to traffic congestion, a police officer escorted the FOL to the construction site at Salem and South Union streets (location of the September 13 tie-in). When the FOL arrived at 5:08 p.m., crew members stated that they had confirmed the pressure in the entire low-pressure system was in the normal range before removing the bypass (

i.e.,

disconnecting the cast iron main from the Winthrop regulator station and connecting the new plastic main). At 5:19 p.m. the FOL took pressure readings at a nearby house and found the pressure was elevated. The FOL then recommended to a supervisor that CMA shut down the low-pressure system.

After being designated as the CMA Incident Commander by the Lawrence Operations Center manager, the FOL then called CMA's engineering department for the list of valves that needed closing to isolate and shut down the system. While waiting for this information, the FOL assigned crews to regulator stations and directed them to verify, with CMA's engineering department, the correct valve to close once they arrived at the regulator station. Once confirmed, they closed the valves. The FOL confirmed the closure of all valves at 7:24 p.m.

At 7:43 p.m., almost 4 hours after the CMA SCADA system detected the overpressurization, the president of CMA declared a “Level 1” emergency, in accordance with CMA's emergency response plan. According to the NTSB's report, the operator's Emergency Response Manual defines a “Level 1” emergency as a “catastrophic event” that includes the loss of a major natural gas facility or the loss of critical natural gas infrastructure.

Working through the night, CMA's engineering department worked under the FOL's direction to confirm that no gas was flowing into the regulator stations on the low-pressure system. On September 14, 2018, at 6:27 a.m., CMA confirmed the low-pressure distribution system was shut down for the 8,447 customers in the Lawrence, Andover, and North Andover areas. CMA shut down the natural gas to an additional 2,447 customers outside the immediate area as a precaution.

The following days required an unprecedented response effort. More than 50,000 residents were asked to evacuate from their homes following the overpressurization.

Thousands of homes needed to be entered, rendered safe, and secured to ensure that dangerous gas levels no longer existed. As the emergency response concluded, it was clear that the recovery effort would span months. CMA's work in the aftermath of the incident focused on repairing infrastructure damage, providing shelter, and finding longer-term housing solutions as recovery efforts extended into the fall and winter months.

Mass. Dep't of Pub. Utilities, “Independent Assessment of Columbia Gas of Massachusetts' Merrimack Valley Restoration Program: Final Report,” at A-2 (June 22, 2020),

https://www.mass.gov/doc/independent-assessment-of-columbia-gas-of-massachusetts-merrimack-valley-restoration-program/download.

The 2018 incident impacted three communities in the Merrimack Valley that, while geographically near one another, are different demographically. Lawrence is a densely populated city with many Spanish-speaking residents and a higher poverty rate than Andover and North Andover. Andover and North Andover are middle-class suburban communities, and although each has half the population size of Lawrence, their geographic size is four to five times that of Lawrence.

III. Recommendations, Advisory Bulletins, and Mandates

A. National Transportation Safety Board

The NTSB investigates serious pipeline accidents, including those that occur on gas distribution pipeline systems. The NTSB investigated CMA's overpressurization incident and issued its final report,

which included several findings and safety recommendations to NiSource, Inc., the Commonwealth of Massachusetts (Massachusetts), several other States,

and PHMSA.

See

NTSB, PAR-19/02. The full report is available at

https://www.ntsb.gov/investigations/AccidentReports/Reports/PAR1902.pdf.

These states were Alabama, Alaska, Arizona, Arkansas, California, Colorado, Connecticut, Florida, Georgia, Idaho, Illinois, Kentucky, Louisiana, Maine, Maryland, Mississippi, Missouri, Montana, Nebraska, Nevada, New York, North Carolina, Pennsylvania, South Carolina, South

Dakota, Texas, Utah, Virginia, and Wyoming. NTSB/PAR-19/02 at 50.

In its accident report, the NTSB issued two safety recommendations to PHMSA. The first, P-19-14, recommended that PHMSA require overpressure protection for low-pressure natural gas distribution systems that cannot be defeated by a single operator error or equipment failure. The NTSB further clarified that to satisfy this recommendation, PHMSA would not have to require that existing low-pressure gas distribution systems be completely redesigned; rather, PHMSA may satisfy this recommendation by requiring operators to add additional protections, such as slam-shut or relief valves, to existing district regulator stations or other appropriate locations in the system.

The second, P-19-15, recommended that PHMSA issue an advisory bulletin to all low-pressure natural gas distribution system operators of the possibility of a failure of overpressure protection. Further, P-19-15 stated that the advisory bulletin should recommend that operators use a failure modes and effects analysis or an equivalent structured and systematic method to identify potential failures and take action to mitigate those identified failures. In developing this NPRM, PHMSA also reviewed additional recommendations relating to the Merrimack Valley incident that NTSB made to states and operators.

NTSB clarified this in an official correspondence to PHMSA on July 31, 2020. NTSB, “Safety Recommendation P-19-014” (July 31, 2020),

https://data.ntsb.gov/carol-main-public/sr-details/P-19-014.

B. Advisory Bulletins

1. Possibility of Overpressurization of Low-Pressure Distribution Systems Advisory Bulletin

On September 29, 2020, PHMSA issued an advisory bulletin (ADB-2020-02) to urge owners and operators of gas distribution systems to conduct a comprehensive review of their systems for the possibility of a failure of overpressure protection on low-pressure distribution systems.

The advisory bulletin addressed NTSB safety recommendation P-19-15, which underscored the elevated possibility of a common mode of failure on low-pressure distribution systems. Specifically, PHMSA requested owners and operators of low-pressure distribution systems to review the NTSB's report concerning the 2018 Merrimack Valley overpressurization event. PHMSA also recommended that operators review their current systems for a similar overpressure-protection configuration to that on the CMA pipeline involved in the incident. In the review of their systems, PHMSA urged operators to consider the possibility of a failure of overpressure-protection devices as a threat to their system's integrity. Additionally, PHMSA reminded owners and operators of their responsibilities under 49 CFR part 192, subpart P, to follow their DIMP and to revise their DIMP based on the new information provided in the NTSB's report and PHMSA's advisory bulletin. Finally, PHMSA recommended several ways that an operator can protect low-pressure distribution systems from an overpressurization event. Some examples include:

“Pipeline Safety: Overpressure Protection on Low-Pressure Natural Gas Distribution Systems,” ADB-2020-02, 85 FR 61097 (Sept. 29, 2020).

1. Installing a full-capacity relief valve downstream of the regulator station, including in applications where there is only worker-monitor pressure control;

2. Installing a “slam-shut” device;

3. Using telemetered pressure recordings at district regulator stations to signal failures immediately to operators at control centers; and

4. Completely and accurately documenting the location for all control lines on the system.

2. Cast-Iron Pipe Advisory Bulletin

On March 23, 2012, PHMSA issued advisory bulletin ADB-2012-05 to owners and operators of cast-iron distribution pipelines and State pipeline safety representatives.

PHMSA issued this advisory bulletin partly in response to the 2011 deadly explosions in Philadelphia and Allentown, PA, involving cast-iron pipelines installed in 1942 and 1928, respectively.

These incidents gained national attention and highlighted the need for continued safety improvements to aging gas pipeline systems. This advisory bulletin updated two prior advisory bulletins (ALN-91-02, issued on October 11, 1991, and ALN-92-02, issued on June 26, 1992

) covering the continued use of cast-iron pipe in gas distribution pipeline systems. The ADB-2012-05 reiterated the two prior advisory bulletins, urging owners and operators to conduct a comprehensive review of their cast-iron gas distribution pipelines and replacement programs and to accelerate repair and replacement of high-risk pipelines. ADB-2012-05 also requested that State agencies consider enhancements to cast-iron replacement plans and programs. Specifically, in ADB-2012-05, PHMSA asked owners and operators of cast-iron distribution pipelines and State safety representatives to consider the following where improvements in safety are necessary:

“Pipeline Safety: Cast Iron Pipe (Supplementary Advisory Bulletin),” ADB-2012-05, 77 FR 17119 (Mar. 23, 2012).

On January 18, 2011, an explosion and fire caused the death of one gas utility employee and injuries to several other people while gas utility crews were responding to a natural gas leak in Philadelphia, Pennsylvania. On February 9, 2011, five people lost their lives, several homes were destroyed, and other properties were impacted by an explosion and subsequent fire in Allentown, Pennsylvania.

Research and Special Programs Administration (RSPA), ALN-91-02 (Oct. 11, 1991),

https://www.phmsa.dot.gov/sites/phmsa.dot.gov/files/docs/RSPA%20Alert%20Notice%2091-02.pdf;

RSPA, ALN-92-02 (June 26, 1992),

https://www.phmsa.dot.gov/sites/phmsa.dot.gov/files/docs/RSPA%20Alert%20Notice%2092-02.pdf

(supplementing ALN-91-02).

1. Review current cast-iron replacement programs and consider establishing mandated replacement programs;

2. Establish accelerated leakage survey frequencies or leak testing;

3. Focus pipeline safety efforts on identifying the highest-risk pipe;

4. Use rate adjustments to incentivize pipeline rehabilitation, repair, and replacement programs;

5. Strengthen pipeline safety inspections, accident investigations, and enforcement actions; and

6. Install interior/home methane gas alarms.

PHMSA reminded owners and operators of their responsibilities under § 192.617 to establish procedures for analyzing incidents and failures to determine the causes of the failures and to minimize the possibility of a reoccurrence.

Finally, the advisory bulletin notes that the DOT, in accordance with the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 (Pub. L. 112-90), will continue to monitor the progress made by operators to implement plans of safe management and replacement of cast-iron gas pipelines and identify the total miles of cast iron pipelines in the United States.

C. Statutory Authority

Title II of the PIPES Act of 2020, the “Leonel Rondon Pipeline Safety Act,” included several mandates for PHMSA to update the regulations governing operators of gas distribution systems. This NPRM addresses mandates codified at 49 U.S.C. 60102(r)-(t), 60105(b), and 60109(e)(7). (

See

sections 202, 203, 204, and 206 of the PIPES Act of 2020). Additionally, PHMSA has general statutory authority to regulate the safety of gas pipeline facilities subject to this rulemaking as discussed in section V.A of this NPRM.

1. Distribution Integrity Management Program Plans and State Inspection Calculation Tool (49 U.S.C. 60109(e)(7) and 49 U.S.C. 60105(b) and 60105 Note; PIPES Act of 2020 Section 202)

PHMSA is required to issue regulations ensuring that DIMP plans for gas distribution operators include an evaluation of certain risks, such as those posed by cast iron pipes and mains and low-pressure distribution systems, as well as the possibility of future accidents to better account for high-consequence but low-probability events. (49 U.S.C. 60109(e)(7)). Gas distribution operators were required make their DIMP plans, emergency response plans, and O&M manuals available to PHMSA or the relevant State regulatory agency no later than December 27, 2022. Gas distribution operators must also make these documents, in updated form, available to PHMSA or the relevant State regulatory agency: (1) two years after the promulgation of regulations as required; and (2) every 5 years thereafter, as well as following any significant change to the document. PHMSA must also update and codify the use of the SICT, a tool used to help states determine the minimum amount of time it must dedicate to inspections. (

See

49 U.S.C. 60105(b) and 60105 note).

2. Emergency Response Plans (49 U.S.C. 60102(r); PIPES Act of 2020 Section 203)

PHMSA is required to update its emergency response plan regulations to ensure that each emergency response plan developed by a gas distribution system operator includes written procedures for how to handle communications with first responders, other relevant public officials, and the general public after certain significant pipeline emergencies (49 U.S.C. 60102(r)). Specifically, the updated regulations would ensure that pipeline operators contact first responders and public officials as soon as practicable after they know a release of gas has occurred that resulted in a fire related to an unintended release of gas, an explosion, one or more fatalities, or the unscheduled release of gas and shutdown of gas service to a significant number of customers. Similarly, the updated regulations would provide for general public communication of pertinent emergencies as soon as practicable and leverage communications methods facilitating rapid notice to the general public.

3. Operation and Maintenance Manuals (49 U.S.C. 60102(s); PIPES Act of 2020 Section 204)

PHMSA is required to update the regulations for O&M manuals to require distribution system operators to have a specific action plan to respond to overpressurization events (49 U.S.C. 60102(s)). Additionally, operators must develop written procedures for management of change processes for significant technology, equipment, procedural, and organizational changes to their distribution system and ensure that relevant qualified personnel, such as an engineer with a professional engineer (PE) license, reviews and certifies such changes (49 U.S.C. 60102(s)).

4. Pipeline Safety Practices (49 U.S.C. 60102(t); PIPES Act of 2020 Section 206)

PHMSA is required to issue regulations that require distribution pipeline operators to identify and manage “traceable, reliable, and complete” maps and records of critical pressure-control infrastructure and update these records as appropriate. The records must be submitted or made available to the relevant regulatory agency (

i.e.,

PHMSA or the State). These regulations must require records to be gathered on an opportunistic basis. (49 U.S.C. 60102(t)(1)).

PHMSA must also issue regulations requiring a qualified employee of a distribution system operator to monitor gas pressure at district regulator stations and be able to shut off flow or limit gas pressure during construction projects that have the potential to cause a hazardous overpressurization. An exception to this requirement would be made for a district regulator station that has a monitoring system and capability for a remote or automatic shutoff (49 U.S.C. 60102(t)(2)). PHMSA is further required to issue regulations on district regulator stations to ensure that gas distribution system operators minimize the risk of a common mode of failure at low-pressure district regulator stations, monitor the gas pressure of low-pressure distribution systems, and install overpressure protection safety technology at low-pressure district regulator stations. If it is not operationally possible to install such technology, this section would require the operator to identify plans that would minimize the risk of overpressurization (49 U.S.C. 60102(t)(3)).

IV. Proposed Amendments

A. Distribution Integrity Management Programs (Subpart P)

In 2009, PHMSA issued a final rule titled “Pipeline Safety: Integrity Management Program for Gas Distribution Pipelines,” creating 49 CFR part 192, subpart P.

As specified in § 192.1003, subpart P applies to operators of all gas distribution pipelines covered under part 192, subject to certain exceptions, and prescribes minimum requirements for integrity management programs for any such pipelines (referred to in this rulemaking as DIMPs). Adherence to a DIMP is an overall approach by operators to ensure the integrity of their distribution systems. The purpose of DIMP is to enhance safety by identifying and reducing pipeline integrity risks. DIMP regulations require that operators develop an integrity management plan that they must re-evaluate periodically; that integrity management plan complements operator efforts in complying with prescriptive operating and maintenance requirements elsewhere in part 192.

74 FR 63906 (Dec. 4, 2009).

Pursuant to § 192.1007, DIMP regulations require operators implement the following steps in developing their DIMP plans:

(1)

Knowledge

(§ 192.1007(a))—Requires operators to understand their pipeline system's design and material characteristics, operating conditions and environment, and maintenance and operating history;

(2)

Identify Threats

(§ 192.1007(b))—Requires operators to identify existing and potential threats to their pipeline systems;

(3)

Evaluate and Rank Risk

(§ 192.1007(c))—Requires operators to evaluate and identify threats to determine their relative importance and rank the risks associated with their pipeline systems;

(4)

Identify and Implement Measures to Address Risks

(§ 192.1007(d))—Requires operators to determine and implement measures designed to reduce the risks from failure of their pipeline systems;

(5)

Measure Performance, Monitor Results, and Evaluate Effectiveness

(§ 192.1007(e))—Requires operators to measure the performance of their DIMPs and reevaluate threats and risks to their pipeline systems;

(6)

Periodic Evaluation and Improvement

(§ 192.1007(f))—Requires operators to periodically reevaluate threats and risks across the entire pipeline system; and

(7)

Report Results

(§ 192.1007(g))—Requires operators to report their performance results to PHMSA and the applicable State agency through annual reports (required by § 191.11).

The first step in developing a robust DIMP plan, as required in § 192.1007(a), is for operators to have knowledge of their gas distribution system. PHMSA has clarified through enforcement guidance that this knowledge should include, but is not limited to, the following characteristics: location, material composition, piping sizes, joining methods, construction methods, date of installation, soil conditions (where appropriate), operating and design pressures, operating history, operating performance data, condition of system, and any other characteristics noted by operators as important to understanding their system. This information may be obtained from sources including system maps, construction records, work management system, geographic information systems (GIS), corrosion records, and personnel who have knowledge of the system (subject matter experts).

This step also requires operators to identify missing data and to develop a plan to collect relevant information as part of their normal pipeline activities over time.

PHMSA, “Gas Distribution Pipeline Integrity Management Enforcement Guidance” at 19-23 (Dec. 7, 2015),

https://www.phmsa.dot.gov/sites/phmsa.dot.gov/files/docs/DIMP_Enforcement_Guidance_12_7_2015.pdf

(“DIMP Guidance”).

The second step in developing and implementing a DIMP plan, as required in § 192.1007(b), is for operators to use the information they have gathered in compliance with § 192.1007(a) to identify threats to the integrity of their gas distribution systems. Section 192.1007(b) currently requires that operators consider eight broad categories of threats. These threats are corrosion (including atmospheric corrosion), natural forces, excavation damage, other outside force damage, material or welds, equipment failure, incorrect operations, and other issues that could threaten the integrity of the pipeline.

Operators must consider reasonably available information to identify existing and potential threats. Sources of data may include incident and leak history, corrosion control records (including atmospheric corrosion records), continuing surveillance records, patrolling records, maintenance history, and excavation damage experience (see § 192.1007(b)).

PHMSA, “F 7100.1-1, Annual Report: Gas Distribution System” (May 2021),

https://www.phmsa.dot.gov/sites/phmsa.dot.gov/files/2021-05/Current_GD_Annual_Report_Form_PHMSA%20F%207100.1-1_CY%202021%20and%20Beyond.pdf.

Section 192.1007(b) requires operators to consider certain categories of threats and consider reasonably available information to identify other existing and potential threats not specifically listed. PHMSA has clarified through guidance that operators should use sources of information such as past O&M procedures, abnormal operating events, purchase orders, material lists from old field orders or standards, and information from industry sources (

e.g.,

plastic pipe database committee (PPDC),

NTSB accident reports, or PHMSA advisory bulletins) to help identify threats.

PHMSA identified potential threats that include, but are not limited to, non-leak events such as near misses, overpressurizations, and material and appurtenance failures. Even though certain potential threats may not have caused system integrity issues on an operator's particular system in the past, the fact that known industry or systemic risks exist requires operators to account for the threat in their DIMP. Further, operators should not eliminate any existing or potential threat to a system without an adequate basis for doing so.

PHMSA reiterated through guidance material that operators should consider environmental conditions that may be conducive to threats developing over time (

e.g.,

atmospheric corrosion, hurricanes, flooding, excavation damage, or materials with known integrity issues), so that operators do not eliminate potential threats without proper consideration.

Prior to excluding a potential threat, operators should perform an analysis of their records to ensure that the pipeline has not experienced the threat to date.

The Plastic Pipe Database Committee, composed of representatives of the American Gas Association (AGA), American Public Gas Association (APGA), Plastics Pipe Institute (PPI), National Association of Regulatory Utility Commissioners (NARUC), NAPSR, NTSB, and PHMSA, coordinates the creation and maintenance of a database to proactively monitor the performance of in-service plastic piping system failures and leaks with the objective of identifying possible performance issues.

PHMSA, “Gas Distribution Pipeline Integrity Management Enforcement Guidance” at 19-23 (Dec. 7, 2015),

https://www.phmsa.dot.gov/sites/phmsa.dot.gov/files/docs/DIMP_Enforcement_Guidance_12_7_2015.pdf

(“DIMP Guidance”).

DIMP Guidance at 18-19.

DIMP Guidance at 19.

PHMSA clarified through enforcement guidance that to exclude a threat from consideration, an operator should document the basis for that conclusion and should not exclude a threat based on the unavailability of information to support the existence of such a threat.

Where data is missing or insufficient, an operator should use a conservative assumption in the risk assessment. Operators must maintain records that identify how they use unsubstantiated data so that operators and regulators can consider the impact on the variability and accuracy of risk analysis results.

DIMP Guidance at 18-19.

DIMP Guidance at 19, 58. Section 192.1011 requires that operators must maintain records demonstrating compliance with the requirements of this subpart for at least 10 years. The records must include copies of superseded integrity management plans developed under this subpart.

The third step in developing and implementing a DIMP plan, as required in § 192.1007(c), is to evaluate and rank risk. Risk is the likelihood of an event occurring multiplied by the consequence of that event. An event that is highly likely and has significant public safety or environmental consequences constitutes an event of greatest concern, while an unlikely event that has minimal consequences may not justify any particular precautions. On the other hand, an unlikely event that could have very high consequences may justify special precautions. Incidents on gas distribution systems are generally low-likelihood, but high-consequence, events.

Risk analysis is an ongoing process of understanding the risk each identified threat presents to a pipeline. Operators use the threats identified in § 192.1007(b) and any knowledge gained when complying with § 192.1007(a) to evaluate the risks associated with their pipelines. Operators then must rank the risks to determine their relative importance. PHMSA has recommended that operators prioritize and address the risks of greatest concern first.

DIMP Guidance at 22, 61.

The fourth step in developing and implementing a DIMP plan, as required in § 192.1007(d), is for operators to determine and implement measures designed to reduce the risks from failure of their gas distribution pipelines. These measures include having an effective leak management program (unless all leaks are repaired when found).

PHMSA's enforcement guidance specifies that the process for identifying risk reduction measures should be based on identified threats.

Operators

should promptly identify the need for risk reduction measures if a new risk is identified.

PHMSA notes that it recently proposed in a separate rulemaking a number of revisions to its prescriptive part 192 leak detection requirements that would

(inter alia

) require gas distribution to adopt advanced leak detection programs based on commercially available, advanced leak detection equipment.

See

“Gas Pipeline Leak Detection and Repair,” 88 FR 31890 (May 18, 2023).

DIMP Guidance at 28.

Overall, DIMP requirements direct operators to identify conditions that can result in hazardous leaks or other unintended consequences and take actions to reduce the likelihood of the occurrence of a hazardous condition and the consequences of a resulting failure. It is critical for operators to identify threats that affect, or could potentially affect, a distribution pipeline to ensure that pipeline's integrity. Knowledge of applicable threats, whether actual or potential, allows operators to evaluate the safety risks they pose and to rank those risks, allowing the operator to apply safety resources where they will be most effective. For the most effective results, operators should break down these broad threat categories into more specific threats. An operator must use the knowledge of their system gained as a result of complying with § 192.1007(a), combined with the threats identified pursuant to § 192.1007(b), to perform a risk analysis to evaluate the likelihood and consequences of failures for those threats described in § 192.1007(c) for which risk-reduction measures are then identified and implemented under § 192.1007(d). The more accurately and completely an operator characterizes their system, the more accurate the risk analysis results will be. This in turn should inform how an operator allocates resources to mitigate the risks associated with its system.

Pipeline incidents since the promulgation of the DIMP rules in 2011 have demonstrated that some distribution operators whose systems are subject to DIMP requirements are not adequately identifying (step 2), evaluating (step 3), or mitigating (step 4) the threats that are degrading and reducing the integrity of their pipeline systems. For example, NTSB's report on the Merrimack Valley incident found that, by at least September 2015, CMA employees knew of overpressure dangers associated with maintenance on belowground control lines for low-pressure system regulator stations: a faulty, damaged, or unaccounted for control line could lead to overpressurization, resulting in fires and explosions in a populated area.

In September 2015, NiSource and CMA internally disseminated Operational Notice (ON) 15-05, titled “Below Grade Regulator Control Lines: Caution When Excavating Near Regulator Stations or Regulator Buildings.”

The impetus for ON 15-05 was a “near-miss” experience involving another NiSource company outside of Massachusetts where a construction crew that was excavating to repair a gas leak near a regulator station came close to hitting a control line and was unaware of its purpose and importance. The NTSB's report concludes that even though NiSource had historically identified overpressurization as a threat in at least some of its internal procedures, NiSource had nevertheless failed to undertake a systemic evaluation (

e.g.,

a failure modes and effects analysis) of the risks associated with that threat and the mitigating actions needed to manage those risks.

NTSB/PAR-19/02 at 18.

NTSB/PAR-19/02 at 59-61.

NTSB/PAR-19/02 at 40.

More robust risk management was also needed in the planning of the South Union Street project, particularly with respect to the threat of overpressurization. NTSB concluded that NiSource's engineering package for that construction project failed to identify, and control for the vulnerability of its system to, a common mode of failure during the construction project that could result in an overpressurization. After the incident in the Merrimack Valley, NiSource worked to improve its risk management processes and installed automatic pressure-control equipment.

Therefore, the NTSB concluded that NiSource's engineering risk management processes were deficient.

NTSB/PAR-19/02 at 43.

Subsequent to the Merrimack Valley incident, 49 U.S.C. 60109(e)(7) was amended to require PHMSA to add more specificity to the DIMP requirements to ensure that operators consider specific threats to their systems. Specifically, PHMSA must update its regulations to ensure DIMP plans for distribution operators include an evaluation of certain risks, such as those posed by cast iron pipes and mains and low-pressure distribution systems, as well as the possibility of future accidents, to better account for high-consequence but low-probability events. Distribution operators must make their updated DIMP plans available to PHMSA or the relevant State regulatory agency two years after any final rule in this proceeding is issued and every 5 years thereafter, as well as following any significant change to an operator's DIMP plan or distribution system.

This provision also requires that operators make their current DIMP plans, emergency response plans, and O&M manuals available to PHMSA or the relevant State regulatory agency no later than December 27, 2022, which PHMSA intends to continue to review as appropriate in the course of inspection.

See

49 U.S.C. 60109(e)(7).

Another recent incident that illustrates operator failure to adequately identify, evaluate, and rank risk is a series of leaks and explosions that occurred on a gas distribution system operated by Atmos Energy Corporation between February 21, 2018, and February 23, 2018, in Dallas, TX. The NTSB investigated the February 2018 incident.

As specified by the NTSB, although Atmos' DIMP plan was consistent with the currently applicable minimum requirements, their plan did not adequately address the inherent risks of its 71-year-old system. In addressing the likelihood of failure, the age of a pipe is generally recognized as an important performance factor.

Currently, PHMSA's regulations do not explicitly require gas distribution operators to consider the age of their pipelines under a DIMP. Instead, PHMSA's regulations in § 192.1007(c) state that “[a]n operator may subdivide its pipeline into regions with similar characteristics (

e.g.,

contiguous areas within a distribution pipeline consisting of mains, services and other appurtenances; areas with common materials or environmental factors), and for which similar actions likely would be effective in reducing risk.” Similar to what is described in PHMSA's regulations, Atmos grouped its assets into failure families based on asset attributes, such as material and coating. This method of evaluating the risks proved to be inadequate, given the high number of leaks observed that were due to the degradation of their pipelines over time.

NTSB, Accident Report PAR-21/01, “Atmos Energy Corporation Natural Gas-Fueled Explosion: Dallas, Texas: February 23, 2018” (Jan. 12, 2021),

https://www.ntsb.gov/investigations/AccidentReports/Reports/PAR2101.pdf.

NTSB/PAR-21/01 at 66.

Following the Atmos incident, NTSB issued recommendation P-21-2 to PHMSA.

This recommendation requires PHMSA to evaluate industry's implementation of DIMP requirements and to develop updated guidance for improving the effectiveness of operator DIMP plans. The recommendation goes on to say that the evaluation should “specifically consider factors that increase the likelihood of failure such as age, increase the overall risk (including factors that simultaneously increase the likelihood and consequence of failure), and limit the effectiveness of leak management programs.”

NTSB/PAR-21/01 at 72.

In this NPRM, PHMSA proposes to revise DIMP requirements so that operators of gas distribution systems will improve their identification of existing and potential threats to their pipelines' integrity, improve the accuracy of their risk analyses, and take meaningful, timely actions to remediate or mitigate the highest risks to their infrastructure. When developing the proposals in this NPRM, PHMSA considered applicable statutory mandates and the NTSB recommendations that followed the CMA and Atmos incidents. The proposals described in the paragraph's below apply to all gas distribution operators, including individual service lines (also known as farm taps),

but excluding small LPG operators. PHMSA discusses the proposal to remove small LPG operators from DIMP in IV.A.7.

An individual gas service line directly connected to a gas transmission, production, or gathering pipeline is commonly referred to as a “farm tap.” Individual service lines have the option of following either § 192.740, for service lines that are

not

operated as part of a distribution system, or DIMP (as detailed in § 192.1003(b)) for any portion of the individual service line that is classified as a service line. This rule proposed no change to this scope. The proposals apply to those individual service lines (aka farm taps) that apply DIMP.

Based on its review of the evidence in the record, PHMSA expects the proposed amendments to the DIMP requirements would be reasonable, technically feasible, cost-effective, and practicable for gas distribution operators. As explained above, these operators are already required by PHMSA regulations to have DIMPs for (

inter alia

) identifying threats to pipeline integrity, evaluating the risks of those threats, and implementing mitigation measures to manage those risks. The NPRM's proposed amendments would clarify baseline expectations for implementation of those existing DIMP elements consistent with historical PHMSA guidance, industry operational experience and research, and statutory mandates in the PIPES Act of 2020, enacted after the Merrimack Valley incident. Said another way, the NPRM's proposed revisions are consistent with the actions reasonably prudent gas distribution operators would undertake in ordinary course in implementing current DIMP requirements on gas distribution pipelines transporting pressurized (natural, flammable, toxic, or corrosive) gasses that are typically in close proximity to, or within, population centers. Within the guardrails proposed herein, operators would retain the significant flexibility contemplated by current DIMP regulations for operators to design and implement their DIMPs in a manner appropriate for managing integrity risks on their specific pipeline facilities while minimizing compliance costs. Viewed against those considerations and the compliance costs estimated in the PRIA, PHMSA expects its proposed amendments will be a cost-effective approach to achieving the commercial, public safety, and environmental benefits discussed in this NPRM and its supporting documents. Lastly, PHMSA understands that its proposed compliance timeline—one year after publication of a final rule (which would necessarily be in addition to the time since publication of this NPRM)—would provide operators ample time to implement requisite changes to their DIMPs and manage any related compliance costs.

1. DIMP—Identify Threats (§ 192.1007(b))—Materials

a. Current Requirements—DIMP—Identify Threats—Materials

Section 192.1007(b) requires operators to consider the general threat category of “material or welds,” but the requirement does not state that operators must consider specific material types and how each type could pose a threat to the integrity of a system. PHMSA has clarified through enforcement guidance that operators should consider subcategories of “material” threats to better categorize their pipelines by age or specific pipe type (such as bare steel, cast iron, wrought iron, and plastic piping) to focus on the root cause of potential failures.

PHMSA has also issued advisory bulletins alerting operators of threats related to specific material types, including cast iron (ADB-2012-05) and plastic piping (ADB-07-01 and ADB-2012-03).

PHMSA's annual report form, PHMSA F 7100.1-1 (see 49 CFR 191.11), also requires operators to identify specific subtypes of materials and the pipeline mileage of each.

DIMP Guidance at 20.

“Pipeline Safety: Cast Iron Pipe (Supplementary Advisory Bulletin),” ADB-2012-05, 77 FR 17119 (Mar. 23, 2012); “Pipeline Safety: Notice to Operators of Driscopipe® 8000 High Density Polyethylene Pipe of the Potential for Material Degradation,” ADB-2012-03, 77 FR 13387 (Mar. 6, 2012); “Updated Notification of Susceptibility to Premature Brittle‐Like Cracking of Older Plastic Pipe,” ADB-07-02, 72 FR 51301 (Sept. 6, 2007).

b. Need for Change—DIMP—Identify Threats—Materials

Different piping materials could pose different threats to gas distribution systems and should be identified prior to conducting a risk analysis of those threats. All things equal, pipelines that are made of certain materials, like cast iron, wrought iron, bare steel, unprotected steel, and certain plastic pipelines, are more susceptible to leaks and other pipeline integrity issues. In particular, cast-iron pipe was the subject of an advisory bulletin (ADB-2012-05) that reiterated two alert notices previously issued by PHMSA that addressed the continued use of cast- and wrought-iron pipe in gas distribution pipeline systems and reminded owners and operators and State pipeline safety representatives of the need to maintain an effective cast-iron management program.

Similar to cast- and wrought-iron piping, steel pipelines without corrosion protection coating—also known as bare-steel or unprotected pipelines—are made of a material that could be a threat to a gas distribution system, as that material is more susceptible to corrosion than coated steel.

RSPA, ALN-92-02 (June 26, 1992); RSPA, ALN-91-02 (Oct. 11, 1991).

Certain vintages and types of plastic piping are also known throughout the industry to present acute threats to pipeline integrity. For example, susceptibility to premature brittle‐like cracking of certain Aldyl “A” pipe, along with other vintages and manufacturers' products, is a well‐documented problem in the industry and the subject of the advisory bulletin ADB-07-02. In this advisory bulletin, PHMSA recommended that operators consider the threat of brittle-like cracking applicable to any Aldyl “A” pipe in service (under the general category of “material”), regardless of whether the threat had resulted in leakage to date. Similarly, PHMSA also alerted operators to the risks of material degradation on Driscopipe8000 (Driscopipe Series 8000 high-density poly-ethylene (HDPE)) pipe in Arizona and Nevada in ADB-2012-03.

While many of these pipelines have been taken out of service, some of them continue to operate today. As discussed earlier, the Merrimack Valley incident involved the replacement of cast-iron and bare-steel pipelines with modern plastic piping. This was part of CMA's pipeline replacement program, which called for the replacement of leak-prone low-pressure cast iron pipelines (both mains and services) with modern plastic pipe. Many operators are also engaged in pipeline replacement projects in response to PHMSA's Action Plan; managing the reduction in cast- and wrought-iron inventory has been a priority and in progress for many years.

Following the Merrimack Valley incident, PHMSA was required by

statute to ensure that operators evaluate the risk of the presence of cast iron in their DIMP plans. While only cast-iron was specifically identified as a material warranting explicit mention in DIMP regulations,

PHMSA understands that the Merrimack Valley incident (which occurred on a pipeline with both cast iron and bare steel) underscores that other types of high-risk materials on gas distribution systems warrant similar treatment. Although operators are already identifying what specific piping materials are on their system,

and § 192.1007(b) requires operators to actively monitor and consider the presence of piping material with known issues under the general threat category of “material or welds,” PHMSA believes that clarifying this practice in the DIMP regulations would ensure that as operators implement their DIMP plans, they consider the risks associated with the presence of these leak-prone materials, as required by the risk analysis in § 192.1007(c).

PHMSA notes, however, the threats to pipeline integrity posed by other materials. Specifically, 49 U.S.C. 60108 (Section 114 of PIPES Act of 2020) imposes a self-executing mandate on gas transmission, distribution, and part-192 regulated gas gathering pipeline operators to update their inspection and maintenance procedures to provide for replacement or remediation of pipelines “known to leak based on their material (including cast iron, unprotected steel, wrought iron, and historic plastics with known issues) . . . .” PHMSA is considering within a separate rulemaking (under RIN 2137-AF54) whether to incorporate that self-executing statutory mandate within its 49 CFR part 192 regulations.

See

“Gas Pipeline Leak Detection and Repair,” 88 FR 31890 (May 18, 2023). PHMSA submits that this NPRM's amendments to DIMP requirements at subpart P would complement any revisions to prescriptive regulations elsewhere in 49 CFR part 192 that PHMSA may adopt in that parallel rulemaking.

Operators are already subcategorizing their pipeline segments by material type (

i.e.,

cast iron, wrought iron, bare steel, and certain plastics with known issues) in their annual report form, PHMSA F 7100.1-1.

See supra

note 36.

c. Proposal To Amend § 192.1007(b)—DIMP—Identify Threats—Materials

PHMSA proposes to revise § 192.1007(b) to clarify that operators must identify the threats posed by specific material types in their pipeline system, such as cast iron, wrought iron, bare steel, and historic plastic pipe with known issues. PHMSA expects that, in determining whether a plastic pipe material is a “historic plastic with known issues” representing a threat to pipeline integrity, operators should consider PHMSA and State regulatory actions and industry technical resources identifying systemic integrity issues on plastic pipe made from particular materials manufactured at particular times or by particular companies, or fabricated and installed pursuant to particular processes. As noted above, PHMSA issues advisory bulletins cautioning operators regarding the susceptibility of certain historic plastic pipelines to systemic integrity issues. Similarly, State pipeline safety regulatory actions, PHMSA pipeline failure investigation reports, and NTSB findings can inform operator determinations whether historic plastic pipe is at a high-risk loss of integrity. Industry efforts and resources are another resource for operators in determining whether historic plastic pipe has known issues. For example, the PPDC publishes periodic status reports of data submitted by program participants that incorporates information regarding investigations of materials of concern or potential concern.

PHMSA expects that these and other authoritative resources—coupled with an operator's own design expertise and operational and maintenance history—would be adequate for a reasonably prudent operator to determine whether the particular plastic pipe in its distribution system is a historic plastic with known issues. PHMSA further invites comment on whether, within a final rule in this proceeding, there would be value (in addition to being cost-effective, practicable, and technically feasible) in either explicitly listing (within subpart P or periodically-issued implementing guidance) historic plastics prone to leakage, or deleting the scope qualification “historic” from proposed regulatory text.

AGA, “Plastic Pipe Data Collection Initiative”,

https://www.aga.org/natural-gas/safety/promoting-safety/plastic-pipe-data-collection-initiative/

(last visited March 10, 2023).

Once the threats are identified under § 192.1007(b), operators are also required to evaluate these risks under § 192.1007(c) and to ensure that risk reduction measures are identified and implemented under § 192.1007(d).

2. DIMP—Identify Threats (§ 192.1007(b))—Overpressurization

a. Current Requirements—DIMP—Identify Threats—Overpressurization

Section 192.1007(b) does not explicitly require operators to consider the threat of overpressurization as a threat under their DIMP plans. Instead, § 192.1007(b) requires operators to consider the general threat category of “incorrect operations” or “other issues that could threaten the integrity of [a] pipeline” and requires operators to consider whether those threats exist on their systems. However, overpressurization is a potential threat to gas distribution systems. PHMSA has stated through previous enforcement guidance and an advisory bulletin (ADB-2020-02) that overpressurization is a threat, especially for low-pressure gas distribution systems, and recommended that operators identify overpressurization as a threat in their DIMP plans. Further, § 192.195 provides design requirements for the protection against accidental overpressurization, including additional requirements for distribution systems.

b. Need for Change—DIMP—Identify Threats—Overpressurization

The threat of overpressurization, particularly on low-pressure gas distribution systems, is a threat that PHMSA expects operators to consider in their DIMP plans. PHMSA considers the threat of overpressurization to fall under the threat categories of both “incorrect operations” and “other issues that could threaten the integrity of [a] pipeline” in § 192.1007(b). In enforcement guidance, PHMSA lists “overpressurization events” as an example of potential threats operators could experience on their pipelines.

PHMSA also requires operators to have sufficient knowledge of their systems, per § 192.1007(a), to determine if overpressurization is a threat on their specific systems and to develop and implement measures to mitigate the consequences of a potential overpressurization. As discussed earlier, PHMSA also issued an advisory bulletin (ADB-2020-02) alerting operators of low-pressure gas distribution systems of the increased risk of overpressurization on those systems and recommended that operators consider the threat of overpressurization in their DIMP plans.

DIMP Guidance at 19, 59.

Recent incidents underscore the importance of operators adequately identifying the risk of overpressurization on distribution systems. Prior to the Merrimack Valley incident on September 13, 2018, the operator experienced four other overpressurizations and one “near-miss” within its network of distribution systems.

NTSB/PAR-19/02 at 25.

On March 1, 2004, a system overpressurized when debris lodged at the seat of the bypass valve in Lynchburg, VA.

On February 28, 2012, an operator error during an inspection resulted in accidental overpressurization in Wellston, OH. 300 customers were without service for 14 hours.

On March 21, 2013, a segment of a pipe with an MAOP of 1 psig was pressurized at over 2 psig in Pittsburgh, PA. A work crew, under the direction of

the local NiSource subsidiary, was making a tie-in and failed to monitor the pressure and flow of the existing low-pressure natural gas distribution system during the tie-in process.

On August 11, 2014, a local NiSource crew in Frankfort, KY, was excavating to repair a leak located on the outside of a regulator station building. The crew uncovered and narrowly missed hitting the 1-inch control line and tap located on the 8-inch outlet pipeline. The crew was unaware of the purpose of the 1-inch line and called local measurement and regulation (M&R) personnel. The M&R personnel advised the crew of the purpose of a control line and what would have happened had the line been broken. As discussed earlier, in 2015 NiSource issued ON 15-05 in response to this near miss. ON 15-05 required that M&R personnel be consulted on all future excavation work done within 25 feet of a regulator station with sensing lines, other communications and/or electric lines critical to the operation of the regulator station, or buried odorant lines. On September 13, 2018 (the date of the Merrimack Valley incident), however, CMA did not follow those procedures or implement any preventive or mitigative measures as they should have if they were correctly following DIMP requirements.

On January 13, 2018, during the investigation of a service complaint, an overpressurization was discovered on a natural gas distribution system in Longmeadow, MA. The cause was associated with debris accumulation on both the worker and monitor regulator seats at a regulator station. Once the debris was removed, the pressure returned to normal. This event illustrates that, in some cases, an overpressurization can occur that does not cause a catastrophic failure of the entire system, but if the operator takes timely, mitigative action, the system can safely return to normal. Operators know debris accumulation at regulator stations can cause an overpressurization and can plan routine maintenance of regulator stations to remove debris or install a device to prevent the debris from reaching the regulator station. However, an operator must first recognize overpressurization as a threat to ensure that they allocate resources to address this threat.

While overpressurization is a threat that PHMSA expects operators to consider in their DIMP plans, the pipeline safety regulations do not explicitly state that operators must identify and evaluate the threat of overpressurization in their DIMP plans. Following the Merrimack Valley incident on September 13, 2018, PHMSA was required by law to ensure that operators evaluate the risk of overpressurization in their DIMP plans. PHMSA therefore proposes to amend § 192.1007(b) to explicitly require operators to identify overpressurization as a threat to low-pressure distribution systems. The proposal is intended to ensure that operators consider this risk on their system as required by the risk analysis in § 192.1007(c) and identify risk reduction measures in accordance with § 192.1007(d).

c. Proposal To Amend § 192.1007(b)—DIMP—Identify Threats—Overpressurization on Low-Systems

PHMSA proposes to amend § 192.1007(b) to create a new threat category of “overpressurization on low-pressure systems.” This change would ensure that consideration of risks under the DIMP regulations explicitly includes overpressurization of a low-pressure system as a threat. Once identified as a threat under § 192.1007(b), operators would also have to evaluate the likelihood and the potential consequences of such a failure, as required in § 192.1007(c), and ensure risk-reduction measures are identified and implemented under § 192.1007(d). PHMSA discusses the actions operators must take to implement § 192.1007(c) and § 192.1007(d) in subsection IV.A.5 and 6 of this preamble.

3. DIMP—Identify Threats (§ 192.1007(b))—Natural Forces

a. Current Requirements—DIMP—Identify Threats—Natural Forces Including Extreme Weather and Geohazards

Section 192.1007(b) requires operators to consider the general threat category of “natural forces,” but the requirement does not explicitly state what natural forces could pose a threat to the integrity of the system. Natural force damage occurs as a result of naturally occurring events, including: (1) earthquakes and landslides; (2) heavy rains and flooding; (3) high winds, tornadoes, or hurricanes; (4) temperature extremes; and (5) lightning.

Further, PHMSA has issued advisory bulletins alerting operators to threats related to natural forces such as land movement (

i.e.,

geological hazards or “geohazards”

) (ADB-2022-01 and ADB-2019-02), severe flooding (ADB-2019-01), snow and ice build-up (ADB-2016-03), and extreme temperatures (ADB-2012-03).

PHMSA, “Fact Sheet: Natural Force Damage” (July 23, 2014),

https://primis.phmsa.dot.gov/comm/FactSheets/FSNaturalForce.htm.

PHMSA also interprets natural hazards to include geohazards.

“Pipeline Safety: Potential for Damage to Pipeline Facilities Caused by Earth Movement and Other Geological Hazards,” ADB-2022-01, 87 FR 33576 (June 2, 2022); “Pipeline Safety: Potential for Damage to Pipeline Facilities Caused by Earth Movement and Other Geological Hazards,” ADB-2019-02, 84 FR 18919 (May 2, 2019); “Pipeline Safety: Potential for Damage to Pipeline Facilities Caused by Flooding, River Scour, and River Channel Migration,” ADB-2019-01, 84 FR 14715 (Apr. 11, 2019); “Pipeline Safety: Dangers of Abnormal Snow and Ice Build-Up on Gas Distribution Systems,” ADB-2016-03, 81 FR 7412 (Feb. 11, 2016); “Notice to Operators of Driscopipe 8000 High Density Polyethylene Pipe of the Potential for Material Degradation,”ADB-2012-03, 77 FR 13387 (Mar. 6, 2012). PHMSA notes that many of those advisory bulletins identify resources maintained by other Federal agencies that can assist pipeline operators in identifying and evaluating integrity threats to their pipelines.

b. Need for Change—DIMP—Identify Threats—Natural Forces Including Extreme Weather and Geohazards

A distribution pipeline system operates in a discrete environment due to the limited geographic scope of each individual system. The environment in which a system operates significantly affects the threats to pipeline integrity that it faces. Factors such as weather (dry or wet, hot or subject to freezing) can significantly shape the threats affecting individual distribution operators and the actions necessary to address those threats. Major climate trends, such as elevated average surface temperatures, more intense storm events, and flooding, can, independently and in combination, affect the reliability and integrity of the United States' gas distribution infrastructure. As climate change has made extreme weather more common, it is harder to categorize what types of environmental factors facing distribution pipelines are “normal” based on geography and historical averages alone.

While freezing weather once seemed like a problem reserved for northern regions of the United States, southern regions are also experiencing unseasonable and extremely cold weather. For example, in February of 2021, Texas experienced a winter storm that brought some of the coldest temperatures in its history.

Extremely cold weather can cause thermal contraction stress or fractures of pipelines due to the expansion of moisture trapped inside components. In addition, safety relief devices can malfunction due to icing or freezing.

On February 16, 2021, Dallas, TX recorded temperatures as low as −2 °F.

Low temperatures and the accumulation of snow and ice also increases the potential for physical

damage to meters and regulators and other aboveground pipeline facilities and components. For example, ice forming on regulators or pressure relief devices can cause them to malfunction or stop working completely.

Exposed piping at metering and pressure regulating stations, at service regulators, and at propane tanks are at the greatest risk. On February 11, 2016, PHMSA issued advisory bulletin ADB-2016-03 alerting operators to the dangers of abnormal snow and ice buildup on gas distribution systems. PHMSA has issued four other advisory bulletins since 1993 on this same issue.

Regulators must be adequately protected from obstructions such as dirt, insects, and ice. If the vent on a regulator becomes completely obstructed, then the regulator can either shut off the flow of gas to a customer or increase the pressure to the upstream pressure, causing possible failures.

“Pipeline Safety: Dangers of Abnormal Snow and Ice Build-Up on Gas Distribution Systems,” ADB-11-02, 76 FR 7238 (Feb. 9, 2011); “Pipeline Safety: Dangers of Abnormal Snow and Ice Build-Up on Gas Distribution Systems,” ADB-08-03, 73 FR 12796 (Mar. 10, 2008); “Potential Damage to Pipelines by Impact of Snowfall, and Actions Taken by Homeowners and Others to Protect Gas Systems from Abnormal Snow Build-up,” ADB-97-01 (Jan. 24, 1997); “Pipeline Safety Advisory Bulletin; Snow Accumulation on Gas Pipeline Facilities,” ADB-93-01, 58 FR 7034 (Feb. 3, 1993).

Natural forces such as severe flooding, river scour, and river channel migration can also adversely affect the safe operation of a pipeline. These incidents can damage a pipeline as a result of additional stresses imposed on the pipe by undermining underlying support soils, exposing the pipeline to lateral water forces and impact from waterborne debris. Additionally, the proper function of valves, regulators, relief sets, pressure sensors, and other facilities normally above ground or above water can be jeopardized when covered by water. PHMSA has issued several advisory bulletins alerting operators to the dangers severe flooding, river scour, and river channel migration can impose on a pipeline, most recently in 2019 through ADB-2019-01 and again in 2022 through ADB-2022-01.

Sometimes flooding is seasonal and predictable; however, the Intergovernmental Panel on Climate Change (IPCC) predicts increases in the frequency and intensity of heavy precipitation, which will give rise to increased risk of flooding.

In some areas, climate change means higher average precipitation,

resulting in water saturation that inhibits the ability of soil to absorb extreme precipitation events. Climate change may, however, result in drought for other parts of the United States,

as lower average annual precipitation rates result in lower soil moisture—and therefore, less ability to absorb extreme precipitation events. Also, rainfall during the four wettest days of the year has increased about 35 percent, and the amount of water flowing in most streams during the worst flood of the year has increased by more than 20 percent.

For parts of the United States, spring rainfall and average precipitation are likely to increase and severe rainstorms are likely to intensify during the next century.

Each of these factors will tend to further increase the risk of flooding—operators must assess how this may impact the integrity of their pipelines.

See, e.g.,

“Pipeline Safety: Potential for Damage to Pipeline Facilities Caused by Flooding, River Scour, and River Channel Migration,” ADB-2016-01, 81 FR 2943 (Jan. 19, 2016); “Pipeline Safety: Potential for Damage to Pipeline Facilities Caused by the Passage of Hurricanes,” ADB-2015-02, 80 FR 36042 (June 23, 2015); “Pipeline Safety: Potential for Damage to Pipeline Facilities Caused by Flooding, River Scour, and River Channel Migration,” ADB-2015-01, 80 FR 19114 (Apr. 9, 2015); “Pipeline Safety: Potential for Damage to Pipeline Facilities Caused by Flooding,” ADB-2013-02, 78 FR 41991 (July 12, 2013); “Pipeline Safety: Potential for Damage to Pipeline Facilities Caused by Flooding,” ADB-11-04, 76 FR 44985 (July 27, 2011).

IPCC, Seneviratne, S.I., N. Nicholls et al., “Managing the Risks of Extreme Events and Disasters to Advance Climate Change Adaptation” at 113 (2012),

https://www.ipcc.ch/site/assets/uploads/2018/03/SREX-Chap3_FINAL-1.pdf.

U.S. Envtl. Prot. Agency, “What Climate Change Means for Missouri”, EPA 430-F-16-027, at 1 (Aug. 2016),

https://19january2017snapshot.epa.gov/sites/production/files/2016-09/documents/climate-change-mo.pdf

(noting that over the last half century, average annual precipitation in most of the Midwest has increased by 5 to 10 percent).

See

A. Park Williams et al., “Rapid Intensification of the Emerging Southwestern North American Megadrought in 2020-2021,” 12 Nature Climate Change 232-234 (2022).

U.S. Envtl. Prot. Agency, “What Climate Change Means for Missouri,” at 1.

U.S. Envtl. Prot. Agency, “Climate Impacts in the Midwest,” Climate Change Impacts,

https://climatechange.chicago.gov/climate-impacts/climate-impacts-midwest

(last visited Feb. 25, 2023).

Extremely high temperatures can also pose integrity threats to certain materials. In March 2012, PHMSA issued advisory bulletin ADB-2012-03 regarding the potential for degradation of Driscopipe8000 pipes, which were produced from 1979 through 1997.

All reported occurrences of in-service degradation and leaks related to Driscopipe8000 pipes were installed in the desert region of the southwestern United States, particularly in the Mojave Desert region in Arizona, California, and Nevada. The ambient temperatures in the southwestern United States are very high (typically over 100 degrees Fahrenheit) and may contribute to issues for plastic piping. Driscopipe Series 7000 and 8000 HDPE pipe exposed to prolonged elevated temperatures may degrade as a result of thermal oxidation. One of the largest producers of polyethylene piping products in North America, has noted that “the mechanism for this oxidation appears to be the depletion of the thermal stabilizer, which has been shown to occur over time in high ambient temperature conditions.”

PHMSA has reminded operators through ADB-2012-03 that they should monitor the performance of their plastic piping.

77 FR at 13388.

Performance Pipe, “Driscopipe® 8000 Pipe Degradation in High Temperature Applications”

https://www.cpchem.com/sites/default/files/2020-05/DriscopipeDegradation.pdf

(last visited Mar. 1, 2023).

Following the Merrimack Valley incident, PHMSA reviewed its current DIMP regulations for areas where additional clarification could improve the safety of gas distribution pipelines. As climate change increases the frequency of extreme weather events and natural forces that can impact the integrity of pipelines, PHMSA proposes to add clarity to the DIMP regulations to ensure that operators are considering these threats when evaluating risks. Operators would, therefore, need to consider and take appropriate action to address the impacts of extreme weather as a threat, regardless of whether they had experienced such events in their pipelines' history, while still recognizing regional differences. PHMSA expects operators to continue evaluating reasonably available information regarding changing operating environments (

i.e.,

climate) and the regional impacts of extreme weather on their pipeline.

c. PHMSA's Proposal To Amend § 192.1007(b)—DIMP—Identify Threats—Natural Forces Including Extreme Weather and Geohazards

PHMSA proposes to amend § 192.1007(b) to specify that operators must include the threat of extreme weather and geohazards as subcategories under the threat category of “natural forces.” This amendment would ensure that operators consider the threat of extreme weather under the DIMP regulations. Once identified as a threat under § 192.1007(b), operators would be required to consider how potential extreme weather events could increase the likelihood of failure. They would also need to consider the potential consequences of such a failure, as required in § 192.1007(c), and ensure that they identify risk-reduction measures and implement them under § 192.1007(d). PHMSA expects that operators would not limit their

consideration of the threat of extreme weather solely on past normal weather patterns but would also consider any anticipated increases in extreme weather conditions and fluctuations. This proposed requirement would improve safety by ensuring that operators address the impacts of climate change and protect the reliability and integrity of their pipeline systems, even if operators have yet to experience these issues on their systems.

4. DIMP—Identify Threats (§ 192.1007(b))—Age of the System, Pipe, and Components

a. Current Requirements—DIMP—Identify Threats—Age of the System, Pipe, and Components

Section 192.1007(b) includes a generic threat category of “other issues that could threaten the integrity of [a] pipeline,” which operators should use to identify threats that do not fit into the other threat categories. When performing their risk analysis, § 192.1007(c) states that operators “may subdivide [their] pipeline into regions with similar characteristics.” PHMSA has observed operators using age as a method of subdividing their pipeline segments when performing the risk analysis. Further, PHMSA's annual report form, PHMSA F 7100.1-1, requires operators to identify the miles of pipeline by decade of installation. Section 192.1007(b) does not, however, specifically require that operators consider the age of a pipe or components when identifying threats to pipeline integrity.

b. Need for Change—DIMP—Identify Threats—Age of the System, Pipe, and Components

Over time, all pipeline systems are subject to time-dependent degradation processes threatening pipeline integrity. Pipelines made from ferrous materials (steel, wrought iron, cast iron, etc.) are all susceptible to oxidation corrosion over time. Plastic and composite materials used in pipelines are subject to photodegradation if exposed to sunlight. Joints, fittings, and welds connecting various pipeline components can be subject to dissimilar materials corrosion or chemical degradation of bonding agents and sealants. And the longer the timeline, the more any gas pipeline components are exposed to a variety of phenomena—

e.g.,

from internal mechanical stresses, changes in temperature, changes in external loads (including external force damage)—that threaten pipeline integrity, exacerbate existing material weaknesses, or accelerate time-dependent degradation processes.

Age can impact and potentially modify each of the threats an operator identifies in § 192.1007(b). The potential threat to pipeline integrity posed by age depends on the age of the pipeline components of which it is comprised. PHMSA understands the cumulative effect of those age-related threats to integrity across an entire pipeline are not merely the sum of age-related, component-specific threats; rather, those threats can magnify or exacerbate one another when integrated within a pipeline system. For example, one component's failure due to time-dependent degradation processes can strain other components throughout the system (

e.g.,

by releasing corrosion products that can damage other, newer components within the system). PHMSA further notes that trending failure rates by age can be a useful tool for revealing degraded performance throughout a pipeline system.

Similarly, the overall age of the pipeline system can provide more opportunities for safety-critical gaps in material records. Poor recordkeeping with respect to a pipeline component dating from a certain time period may threaten not only pipeline integrity on that segment, but also other components of the same pipeline installed at a different time period.

Age can also be expressed in terms of vintage of pipes or components. Specific manufacturing techniques and materials used during certain periods of time can result in similar characteristics among pipes and components of a given vintage. The vintage of pipes or components can interact with other threats, including materials, equipment failures, or natural forces. For example, pipe installed earlier than 1950 has disproportionately high susceptibility to problems from cold weather and freezing, which could interact with the threat of natural forces. The greater susceptibility of pre-1950 pipe is thought to be due to inferior low-temperature ductility of the steels of the era and the methods used to join pipe at the time (such as electric arc welds, acetylene welds, couplings, and threaded collars).

Additionally, as described in section IV.A.1 (materials), some of the early plastic piping products manufactured from the 1960s and into the early 1980s are more susceptible to brittle-like cracking (also known as slow-crack growth) than newer materials.

M.J. Rosenfeld, “Cold Weather Can Play Havoc On Natural Gas Systems” 242 Pipeline & Gas J. 1 (Jan. 2015),

https://pgjonline.com/magazine/2015/january-2015-vol-242-no-1/features/cold-weather-can-play-havoc-on-natural-gas-systems.

Brittle-like cracking failures occur under conditions of stress intensification. Stress intensification is more common in fittings and joints.

Even though time-dependent degradation processes are widely understood threats to the integrity of pipeline systems, as discussed earlier, § 192.1007(b) does not specifically state that operators must account for the age of the system, pipe, and components in identifying threats. Increasing failure rates have been observed in older gas distribution infrastructure that has certain attributes.

The increasing failure rate typically occurs toward the end of life and accelerates the rate by which the reliability decreases. This behavior is typically attributed to cumulative degradation that occurs in the system over its service period. Trending failure rates by system age can reveal degrading performance.

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

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

Recent incidents have illustrated that operators may be inadequately identifying and managing threats related to the age of components on their systems. For example, in its risk analysis, Atmos used a commercially available software that did not explicitly consider the age of the pipeline segments, instead grouping them into failure categories based on similar attributes, such as material and coating. Although such an approach may have been compliant with current regulations, this approach to risk analysis disregards how the age could contribute to failures. Following the 2018 Atmos incidents, the NTSB recommended that Gas Piping Technology Committee develop guidance and identify steps operators can take to ensure that their gas distribution IM programs appropriately consider threats that degrade a system over time.

By adopting such a practice, operators would recognize the full threat based on the impact of age and prioritize remediating or replacing segments of the pipe and components that pose more acute threats. PHMSA therefore proposes to revise § 192.1007(b) to explicitly identify age as a factor in addressing threats to integrity.

NTSB/PAR-21/01 at 82.

c. Proposal To Amend § 192.1007(b)—DIMP—Identify Threats—Age of the System, Pipe, and Components

PHMSA proposes to amend § 192.1007(b) to clarify that operators

must, when identifying the threats on its distribution system, also consider the age of the system, piping, and components in identifying threats.

For example, once an operator identifies a time-dependent threat exists on their pipeline, such as corrosion, the operator would then consider how the age of the pipe, or the components, could influence the severity of the threat. All things equal, an older pipe or component exposed to the threat of corrosion could carry additional risk compared to newer pipe. Similarly, for time-independent threats, such as natural forces, the operator would consider how the age of the pipeline or components would expose the pipeline to multiple threats over its lifetime, a threat that may evolve or increase over time. PHMSA's proposal would ensure that the DIMP regulations explicitly account for how the age of the system, pipes, and components contribute to a pipeline's integrity degrading over time.

See

Am. Soc'y of Mech. Eng's, ANSI B31.8S-2004, “Managing System Integrity of Gas Pipelines,” at sec. 2 (Jan. 14, 2005).

5. DIMP—Evaluate and Rank Risk (Section 192.1007(c))

a. Current Requirements—DIMP—Evaluate and Rank Risk

Section 192.1007(c) requires that operators evaluate and rank the risks associated with their distribution pipeline systems. This evaluation must consider each applicable current and potential threat, the likelihood of failure associated with each threat, and the potential consequences of such a failure. Operators may subdivide their distribution systems into regions (areas within a distribution system consisting of mains, services, and other appurtenances) that have similar characteristics and reasonably consistent risks, and for which similar actions would be effective in reducing risk.

Through enforcement guidance, PHMSA recommended that operators develop weighted factors for each threat specific to their system depending upon their unique operating environment.

PHMSA has further stressed that it may be inadequate for operators to conclude that a pipeline is not subject to any particular threat based solely on the fact that it has not experienced a pipeline failure attributed to the threat.

PHMSA has used enforcement guidance to clarify that if operators conclude that a particular threat is not applicable to sections of their pipeline, then operators should document the basis for drawing that conclusion.

This basis should consider the pipeline's failure history, design, manufacturing, construction, operation, and maintenance.

DIMP Guidance at 22.

DIMP Guidance at 23.

DIMP Guidance at 18, 57.

b. Need for Change—DIMP—Evaluate and Rank Risk

Recent incidents have demonstrated the importance of operators adequately evaluating and ranking risks on their systems and in their DIMP plans. For example, as demonstrated by the 2018 Merrimack Valley and other incidents investigated by the NTSB, some operators have not been adequately evaluating the risk of overpressurization, and thus not taking appropriate mitigating measures to account for those risks.

Overpressurization incidents—in particular on low-pressure gas distribution systems—merit mitigation because they have a high-consequence. As previously noted, CMA had knowledge of the risks of an overpressurization, updated their procedures, and still did not take appropriate action to mitigate the risks. Similarly, the Atmos incident in Texas demonstrated how operators can underestimate the risks associated with the presence of leak-prone materials.

NTSB/PAR-19/02 at 18-21, 39-40, 48.

PHMSA is required by law to ensure that operators' DIMP plans evaluate the presence and risks associated with cast iron piping and the threat of overpressurization on low-pressure gas distribution systems (49 U.S.C. 60109(e)(7)). PHMSA is also required to prohibit operators, when evaluating risks related to the operation of a low-pressure gas distribution system, from determining that there are no potential consequences associated with low-probability events unless that determination is supported by “engineering analysis or operational knowledge.” PHMSA must also ensure that operators of gas distribution systems consider factors other than past observed “abnormal operating conditions”—as that term is defined at § 192.803—when ranking risks and identifying measures to mitigate those risks.

c. PHMSA's Proposal To Amend § 192.1007(c)—DIMP—Evaluate and Rank Risk

PHMSA proposes to redesignate the general requirements of § 192.1007(c) under a new paragraph (c)(1). These general requirements still require operators to consider the identified threats proposed in § 192.1007(b) as they evaluate and rank risks.

i. Certain Pipe Materials With Known Issues

PHMSA proposes to amend § 192.1007(c) by creating a new § 192.1007(c)(2) to specify that operators must evaluate the risks resulting from pipelines constructed with certain materials (including cast iron, bare steel, unprotected steel, wrought iron, and historic plastics with known issues) when such materials are present in their pipeline systems. Overall, these proposed requirements would improve safety by codifying in DIMP requirements some of the known, industry-wide threats if the materials that have exhibited these threats are present in the operator's systems, even if operators have not yet experienced any of these issues on their systems.

ii. Evaluate and Rank Risk: Low-Pressure Distribution Systems

PHMSA also proposes to amend § 192.1007(c) by creating a new § 192.1007(c)(3) applicable to low-pressure distribution systems. Consistent with the mandate in 49 U.S.C. 60109(e)(7), PHMSA proposes to require operators of low-pressure gas distribution systems to evaluate “the risks that could lead to or result from the operation of a low-pressure distribution system at a pressure that makes the operation of any connected and properly adjusted low-pressure gas burning equipment unsafe.” For the purposes of this NPRM, PHMSA determines that “unsafe” in this context means that gas flowing into the downstream equipment is at a pressure beyond the rated supply pressure specified by the manufacturer of that equipment. This amendment would ensure that operators are addressing the risks on their pipeline that could result in an overpressurization.

In evaluating the risks to low-pressure distribution systems, the mandate in 49 U.S.C. 60109(e)(7)(B) requires PHMSA to ensure that operators consider “factors other than past observed abnormal operating conditions [. . .] in ranking risks.” This includes any abnormal operating conditions (AOCs) that operators have experienced (

i.e.,

observed) on their system and any unobserved AOCs that could occur on their system (

i.e.,

an overpressurization on a low-pressure system), including any known industry threats, risks, or hazards, as identified by an operator from available sources (

e.g.,

PHMSA advisory bulletins, PHMSA incident and accident reports, PHMSA and NTSB accident reports, State pipeline safety regulatory actions, and operator knowledge sharing). PHMSA proposes

in § 192.1007(c)(3)(i) to require operators of low-pressure systems to evaluate risks to their systems in accordance with the mandate. This amendment would ensure that operators are reviewing their past observed operational performance to evaluate the risks on their systems. This amendment would also ensure that operators are considering risks even if they have yet to experience those risks on their systems. For example, if an operator has not experienced an overpressurization on its system, that operator must still consider the risks of an overpressurization on its system.

The mandate in 49 U.S.C. 60109(e)(7)(B) also states that operators may not determine that low probability events have no potential consequences without a supporting determination. PHMSA proposes integrating this mandate by adding a new paragraph § 192.1007(c)(3)(ii) that will direct operators to evaluate the potential consequences associated with low-probability events, unless a determination—supported and documented by an engineering analysis or other equivalent analysis incorporating operational knowledge—demonstrates that the event results in no potential consequences (and therefore no potential risk).

An engineering analysis would include documentation of the engineering principles used to calculate the flows, pressures, and other parameters of the piping and systems to calculate the actual downstream pressure. This engineering analysis would also include documentation of the methods used to determine that the system cannot fail and cause overpressurization, including any data and assumptions (including mitigation and control measures) utilized by the operator. This engineering analysis may necessarily include degrees of measurable operational knowledge regarding specific pipeline characteristics and evidence from that analysis combined with documentable known pipeline characteristics. An operator that determines there are no potential consequences from a low-probability event must document all these reasons as part of its “engineering analysis” submitted to PHMSA according to § 192.18 with sufficient detail as listed in § 192.1007(c)(3)(ii)(A)-(F).

Because the statute requires operators to make an affirmative determination that there are no potential consequences associated with low probability events and recognizing that some operators might not have fully considered the risk of low-probability events based solely on operational knowledge, PHMSA proposes that any operational knowledge relied upon must include with it a quantifiable assessment and support the operator's determination with a level of rigor equal to that of an engineering analysis. This operational knowledge could be included as part of the proposed regulatorily required “engineering analysis, or an equivalent analysis,” as used in § 192.1007(c)(3)(ii). For example, should an operator determine that a release of gas from the pipeline, such as a leak, has no potential consequences, the operator should include documentation demonstrating that many scenarios were considered (such as a leak with ignition or gas migration under nearby pavement) and that no potential consequences were identified in any of those potential scenarios. This amendment would ensure that operators do not dismiss material risks without a meaningful evidentiary basis, and PHMSA or pertinent State authorities would have the opportunity to review and consider the validity of the operator's determination when reviewing DIMP plans.

State regulatory authorities already review operators' DIMP plans during regular inspections. Because incorrectly determining that a potential threat has no consequences would have serious public safety impacts, however, PHMSA understands there is a compelling policy reason for an operator's determination that a low-frequency event entails zero risk be reviewed by those State regulatory authorities as well as PHMSA. Therefore, if operators choose to apply the proposed exception in § 192.1007(c)(3)(ii), they must notify PHMSA and the appropriate State Authority in accordance with § 192.18 within 30 days of making this determination that there are no potential consequences associated with the low-probability event. The notification must include information such as the date the determination was made (to ensure compliance with the proposed timeline), descriptions of the low-probability events being considered, and a description of the logic supporting the determination, including information from an engineering analysis or an equivalent analysis incorporating operational knowledge. Further, this notification should contain a description of any preventive and mitigative measures, including any measures considered but not taken, as determined through the engineering analysis or an equivalent analysis incorporating operational knowledge. The notification should also include a description of the low-pressure system, including, at a minimum, miles of pipe, number of customers, number of district regulators supplying the system, and other relevant information. In addition, operators must provide a written statement summarizing the documentation it evaluated and how the conclusion that there would be no potential consequences associated with the low-probability event was reached. This documentation could include the inspection and maintenance history of the pipeline segment, incident reports, any leak repair data, and any failure investigations or abnormal operations records. Providing this information would be critical in ensuring that operators robustly evaluated methods of reducing risk and that the operator did not ignore any material factors in their engineering analysis or an equivalent analysis incorporating operational knowledge.

In a new § 192.1007(c)(3)(iii), PHMSA proposes to require that in evaluating and ranking risks in their DIMP plans, operators of low-pressure gas distribution systems must evaluate the configuration of their primary and any secondary overpressure protection installed at the district regulator stations, the availability of gas pressure monitoring at or near overpressure protection equipment, and the likelihood of any single event that immediately or over time could result in an overpressurization of the low-pressure system (see amended § 192.195(c)). Operators' overpressure protection configurations vary—some include a combination of relief valves, monitoring regulators, or automatic shutoff valves. Other operators have real-time monitoring devices located at the district regulator station, while yet others rely on telemetering devices. Some operators, as demonstrated by the events of September 13, 2018, may have an overpressure protection configuration that can be defeated by a single event, such as excavation damage, natural forces, an equipment failure, or incorrect operations. This amendment would ensure that operators are evaluating their existing overpressure protection system for inadequacies or additional risks that could result in an overpressurization of the system.

6. DIMP—Identify and Implement Measures To Address Risks (Section 192.1007(d))

a. Current Requirements—DIMP—Identify and Implement Measures To Address Risks

Section 192.1007(d) requires operators to determine and implement measures designed to reduce the risks from failure of their gas distribution pipeline systems following the identification of threats (in accordance with § 192.1007(b)) and the evaluation and ranking of risks (in accordance with § 192.1007(c)). Section 192.1007(d) also requires that these risk mitigation measures include an effective leak management program (unless all leaks are repaired when found). Although the specific process is not defined in § 192.1007(d), PHMSA has issued guidance material to support the implementation of these requirements.

In the guidance material, PHMSA states that operators should have a documented list of measures to reduce risks identified on their pipeline system.

The process for identifying risk mitigation measures must be based on identified threats to each pipeline segment and the risk analysis. Operators should rank pipeline segments and group segments that represent the highest risk as the most important candidates for which measures are taken to reduce risk. The operator should ensure that the highest priority measures for reducing risk are for the highest-ranked segments as indicated by the risk analysis. Because the design and operation of gas distribution systems are so diverse, no single risk control method is appropriate in all cases. Therefore, the objective of § 192.1007(d) is to ensure that each operator has documented and described existing and proposed measures to address the unique risks to its system and that the operator has evaluated and prioritized actions to reduce risks to pipeline integrity.

DIMP Guidance at 28.

b. Need for Change—DIMP—Identify and Implement Measures To Address Risks

Proper implementation of a DIMP plan should result in aggressive oversight and replacement of higher-risk infrastructure. For example, there are many benefits to replacing old, cast-iron, low-pressure distribution pipes with newer materials, such as modern plastic pipe. Replacement projects, however, entail their own risks to public safety and the environment that need to be balanced against the risks associated with leaving a pipeline segment undisturbed. Poorly managed construction projects can result in property damage and personal injury, and replacement activity can include blowdowns to the atmosphere of methane gas that contribute to climate change. Work on existing pipeline facilities can also cause a catastrophic overpressurization, as was the case in CMA's 2018 incident. Operators must manage those risks while still implementing preventive and mitigative measures that would reduce the risk of identified threats.

In 2020, PHMSA issued an advisory bulletin to remind operators of the possibility of failure due to an overpressurization on low-pressure distribution systems.

In that advisory bulletin, PHMSA reminded operators of the existing DIMP regulations and recommended that per § 192.1007(d), operators take additional actions to reduce risks if they found their current overpressure protection design to be insufficient. PHMSA also identified for operators that “[t]here are several ways that operators can protect low-pressure distribution systems from overpressure events,” such as:

See

“Pipeline Safety: Overpressure Protection on Low-Pressure Natural Gas Distribution Systems,” ADB-2020-02, 85 FR 61097 (Sept. 29, 2020).

1. Installing a full-capacity relief valve downstream of the low-pressure regulator station, including in applications where there is only worker-monitor pressure control;

2. Installing a “slam shut” device;

3. Using telemetered pressure recordings at district regulator stations to signal failures immediately to operators at control centers; and

4. Completely and accurately documenting the location for all control (

i.e.,

sensing) lines on the system.

As discussed earlier, subsequent to the 2018 Merrimack Valley incident, PHMSA was required by statute to ensure that operators of low-pressure gas distribution systems evaluate the risk of overpressurization in their DIMP plans. (49 U.S.C. 60109(e)(7)(A)(ii)). For existing low-pressure systems, operators already have a mechanism in place—their DIMP—to evaluate their systems to ensure they can identify and implement measures to minimize the risk imposed by any inadequate overpressure protection.

c. PHMSA's Proposal To Amend § 192.1007(d)—DIMP—Identify and Implement Measures To Address Risks

PHMSA proposes to amend § 192.1007(d) to establish additional criteria for operators to evaluate when identifying and implementing measures to address risks identified in DIMP plans. PHMSA's proposal would require operators—when identifying and implementing measures—to specifically account for risks associated with the age of the pipe, the age of the system, the presence of pipes with known issues, and overpressurization of low-pressure distribution systems. PHMSA is adding these specific risks to § 192.1007(d) because they were the subject of recent incidents, as discussed earlier. This amendment would ensure that operators are not only identifying these specific threats (in § 192.1007(b)), but also implementing measures to address those risks. In a new § 192.1007(d)(2), PHMSA is proposing to explicitly require operators of existing low-pressure systems to take certain actions to prevent and mitigate the risk of an overpressurization that could be the result of any single event or failure. These actions include identifying, maintaining, and (if necessary) obtaining traceable, verifiable, and complete records that document the characteristics of the pipeline that are critical to ensuring proper pressure controls for the system. PHMSA discusses the criteria for these pressure control records in section IV.F of this NPRM.

In addition to this recordkeeping requirement, in a new § 192.1007(d)(2), PHMSA proposes that operators must confirm and document that each district regulator station meets the design standards in § 192.195(c)(1)-(3) or take the following actions: (1) identify preventative and mitigative measures based on the unique characteristics of their system to minimize the risk of overpressurization on low-pressure systems, or (2) upgrade their systems to meet design standards in § 192.195(c)(1)-(3). PHMSA discusses the criteria for this proposed upgrade in section IV.H of this NPRM. Should an operator choose to identify preventative and mitigative measures based on the unique characteristics of their system to minimize the risk of overpressurization, PHMSA proposes that the operator notify PHMSA and State or local pipeline authorities no later than 90 days in advance of implementing any alternative measures. PHMSA proposes that an operator must make this notification in accordance with § 192.18, which would include a description of the operator's proposed alternative measures, identification, and location of facilities to which the measures would be applied, and a description of how the measures would

ensure the safety of the public, affected facilities, and environment. This notification would ensure that operators are keeping PHMSA and State authorities informed of alternative measures to address risk. This amendment would apply to existing low-pressure systems that have evaluated and identified inadequate overpressure protections in accordance with § 192.1007(c).

PHMSA has also proposed to amend § 192.18 to reflect this proposed change by including a reference to § 192.1007. Should an operator choose to implement an alternative method of minimizing overpressurization, PHMSA proposes that the operator notify PHMSA and State or local pipeline authorities no later than 90 days in advance of implementing any alternative measures. PHMSA proposes that operators must make this notification in accordance with § 192.18, which would include a description of the operators' proposed alternative measures, identification, and locat

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