61746 Federal Register / Vol. 88, No. 172 / Thursday, September 7, 2023 / Proposed Rules 

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 baselevel 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 selfaddressed 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 


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1Part 192—regulated pipelines refers to gas 

distribution, transmission, and gathering pipelines, 

as applicable. 

2NTSB, 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. 

3The 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-MethaneEmissions-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)). 

4See, 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). 

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 lowpressure 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.1 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. 

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.2

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 highpressure 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. 

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 lowpressure 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.3 Older castiron 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.4 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 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 


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5The SICT can be accessed on the PHMSA Portal 

by authorized users. 

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 part192 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 lowpressure 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 lowprobability 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 lowpressure 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.5 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. 

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 


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Federal Register / Vol. 88, No. 172 / Thursday, September 7, 2023 / Proposed Rules 61749 

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 


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6 ‘‘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). 

7 GPA Midstream Ass’n v. Dep’t of Transp., 67 

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

8 ‘‘Pipeline Safety: Requirement of Valve 

Installation and Minimum Rupture Detection 

Standards: Technical Corrections,’’ 88 FR 50056 

(Aug. 1, 2023). 

9 88 FR 21879 (Apr. 6, 2023); 58 FR 51735 (Oct. 

4, 1993). 

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, 

2015.6

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,7 PHMSA issued a technical 

correction to the April 2022 Valve Rule 

codifying that decision.8 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 crossreferences at § 192.9—emergency 

planning and response (§ 192.615) and 

protocols for notifications of potential 

ruptures (§ 192.635). 

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.9 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 


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10PHMSA, ‘‘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. 

11This 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. 

12U.S. Envtl. Prot. Agency, Global Methane 

Initiative: Importance of Methane (last updated June 

9, 2022), https://www.epa.gov/gmi/importancemethane#:∼:text=Methane%20is%20more%20than

%2025,due%20to%20human%2Drelated

%20activities. 

13Serious 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/dataand-statistics/pipeline/pipeline-incident-20-yeartrends. 

14 ‘‘Pipeline Incident 20 Year Trends’’ (Nov. 15, 

2022), https://www.phmsa.dot.gov/data-andstatistics/pipeline/pipeline-incident-20-year-trends. 

15PHMSA, ‘‘By-Decade Inventory: Reports’’ (Mar. 

16, 2020), https://www.phmsa.dot.gov/data-andstatistics/pipeline-replacement/decade-inventory. 

16PHMSA, ‘‘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. 

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. 

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 

3% 

discount 

rate 

7% 

discount 

rate 

DIMP ......................... $3.2 $4.3 

Small LPG DIMP ...... ¥0.3 ¥0.3 

SICT .......................... 0.0 0.0 

Emergency response 1.0 1.2 

O&M .......................... 42.8 44.7 

Recordkeeping .......... 24.3 27.8 

Qualified personnel ... 34.8 34.8 

District regulator stations ....................... 1.2 1.6 

Inspections ................ 0.04 0.05 

Records: Tests ......... 0.6 0.6 

Annual Reporting ...... 2.3 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.10 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. 

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.11 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.12 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.13 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).14

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.15 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. 

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.16 Efforts implementing 

the Action Plan focused on pipeline age 

and material as significant risk 

indicators. Pipelines constructed of castand 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 


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17Cast 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-andstatistics/pipeline-replacement/cast-and-wroughtiron-inventory (‘‘Cast and Wrought Iron Inventory’’). 

18See Cast and Wrought Iron Inventory. 

19U.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. 

20 ‘‘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/wpcontent/uploads/2019/03/2019-PST-Briefing-Paper02-NatGasBasics.pdf. 

21 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). 

22An 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. 

PHMSA’s distribution operators’ annual 

report data.17

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.18

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.19 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. 

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.20 This lower pressure downstream 

of a district regulator station is more 

suitable for providing service to 

customers. 

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.21 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. 

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 controlline 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 highpressure 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.22

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. 


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23CMA transferred from NiSource, Inc. to 

Eversource Energy in November 2020. 

24NTSB/PAR–19/02 at 49. 

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.23 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. 

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.24

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. 

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 lowpressure 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 lowpressure 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 highpressure 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 lowpressure 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 


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61754 Federal Register / Vol. 88, No. 172 / Thursday, September 7, 2023 / Proposed Rules 

25Operators 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. 

26Mass. 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-ofcolumbia-gas-of-massachusetts-merrimack-valleyrestoration-program/download. 

27See NTSB, PAR–19/02. The full report is 

available at https://www.ntsb.gov/investigations/ 

AccidentReports/Reports/PAR1902.pdf. 

28These 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 

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.25 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. 

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.26 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 longerterm housing solutions as recovery 

efforts extended into the fall and winter 

months. 

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,27 which included 

several findings and safety 

recommendations to NiSource, Inc., the 

Commonwealth of Massachusetts 

(Massachusetts), several other States,28

and PHMSA. 


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Dakota, Texas, Utah, Virginia, and Wyoming. 

NTSB/PAR–19/02 at 50. 

29NTSB 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/srdetails/P-19-014. 

30 ‘‘Pipeline Safety: Overpressure Protection on 

Low-Pressure Natural Gas Distribution Systems,’’ 

ADB–2020–02, 85 FR 61097 (Sept. 29, 2020). 

31 ‘‘Pipeline Safety: Cast Iron Pipe 

(Supplementary Advisory Bulletin),’’ ADB–2012– 

05, 77 FR 17119 (Mar. 23, 2012). 

32On 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. 

33Research 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). 

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 lowpressure 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.29 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. 

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.30 The advisory 

bulletin addressed NTSB safety 

recommendation P–19–15, which 

underscored the elevated possibility of 

a common mode of failure on lowpressure 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 lowpressure distribution systems from an 

overpressurization event. Some 

examples include: 

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.31 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.32 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 33) 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: 

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. 


ddrumheller on DSK120RN23PROD with PROPOSALS3
61756 Federal Register / Vol. 88, No. 172 / Thursday, September 7, 2023 / Proposed Rules 

34 74 FR 63906 (Dec. 4, 2009). 

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 highconsequence 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.34 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. 

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 


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35PHMSA, ‘‘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’’). 

36PHMSA, ‘‘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. 

37The 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. 

38PHMSA, ‘‘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’’). 

39 DIMP Guidance at 18–19. 

40 DIMP Guidance at 19. 

41 DIMP Guidance at 19. 

42 DIMP Guidance at 18–19. 

43 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. 

44 DIMP Guidance at 22, 61. 

45PHMSA 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). 

46 DIMP Guidance at 28. 

(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).35 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. 

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.36 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)). 

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),37 NTSB accident reports, or 

PHMSA advisory bulletins) to help 

identify threats.38 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.39 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.40 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.41

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.42 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.43

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 lowlikelihood, 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.44

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).45

PHMSA’s enforcement guidance 

specifies that the process for identifying 

risk reduction measures should be based 

on identified threats.46 Operators 


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47NTSB/PAR–19/02 at 18. 

48NTSB/PAR–19/02 at 59–61. 

49NTSB/PAR–19/02 at 40. 

50NTSB/PAR–19/02 at 43. 

51This 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). 

52NTSB, 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. 

53NTSB/PAR–21/01 at 66. 

54NTSB/PAR–21/01 at 72. 

should promptly identify the need for 

risk reduction measures if a new risk is 

identified. 

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 lowpressure system regulator stations: a 

faulty, damaged, or unaccounted for 

control line could lead to 

overpressurization, resulting in fires and 

explosions in a populated area.47 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.’’ 48 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.49

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.50

Therefore, the NTSB concluded that 

NiSource’s engineering risk 

management processes were deficient. 

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.51

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.52 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.53

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. 

Following the Atmos incident, NTSB 

issued recommendation P–21–2 to 

PHMSA.54 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.’’ 


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55An 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. 

56 DIMP Guidance at 20. 

57 ‘‘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). 

58RSPA, ALN–92–02 (June 26, 1992); RSPA, 

ALN–91–02 (Oct. 11, 1991). 

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),55 but 

excluding small LPG operators. PHMSA 

discusses the proposal to remove small 

LPG operators from DIMP in IV.A.7. 

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 costeffective 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.56 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).57 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. 

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.58 Similar to cast- and wroughtiron 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. 

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 brittlelike 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 


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59PHMSA 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 selfexecuting 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. 

60Operators 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. 

61AGA, ‘‘Plastic Pipe Data Collection Initiative’’, 

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

visited March 10, 2023). 

62 DIMP Guidance at 19, 59. 

63NTSB/PAR–19/02 at 25. 

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,59 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,60 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). 

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.61 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. 

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.62 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. 

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 ‘‘nearmiss’’ within its network of distribution 

systems.63

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 


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64PHMSA, ‘‘Fact Sheet: Natural Force Damage’’ 

(July 23, 2014), https://primis.phmsa.dot.gov/ 

comm/FactSheets/FSNaturalForce.htm. 

65PHMSA also interprets natural hazards to 

include geohazards. 

66 ‘‘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. 

67On February 16, 2021, Dallas, TX recorded 

temperatures as low as ¥2 °F. 

the local NiSource subsidiary, was 

making a tie-in and failed to monitor the 

pressure and flow of the existing lowpressure 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 lowpressure 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.64 Further, PHMSA has issued 

advisory bulletins alerting operators to 

threats related to natural forces such as 

land movement (i.e., geological hazards 

or ‘‘geohazards’’ 65) (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).66

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.67 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. 

Low temperatures and the 

accumulation of snow and ice also 

increases the potential for physical 


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68Regulators 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. 

69 ‘‘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 BuildUp 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). 

70See, 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). 

71 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. 

72U.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). 

73See A. Park Williams et al., ‘‘Rapid 

Intensification of the Emerging Southwestern North 

American Megadrought in 2020–2021,’’ 12 Nature 

Climate Change 232–234 (2022). 

74U.S. Envtl. Prot. Agency, ‘‘What Climate 

Change Means for Missouri,’’ at 1. 

75U.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). 

76 77 FR at 13388. 

77Performance 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). 

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.68 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.69

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–2022–01.70

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.71 In some 

areas, climate change means higher 

average precipitation,72 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,73 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.74 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.75

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. 

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 1997.76 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.’’ 77

PHMSA has reminded operators 

through ADB–2012–03 that they should 

monitor the performance of their plastic 

piping. 

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 


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78M.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-weathercan-play-havoc-on-natural-gas-systems. 

79Brittle-like cracking failures occur under 

conditions of stress intensification. Stress 

intensification is more common in fittings and 

joints. 

80PHMSA, ‘‘Pipeline Replacement Background’’ 

(Apr. 26, 2021), https://www.phmsa.dot.gov/dataand-statistics/pipeline-replacement/pipelinereplacement-background. 

81NTSB/PAR–21/01 at 82. 

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 timedependent 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 timedependent 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 lowtemperature 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).78 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.79

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.80 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. 

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.81 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. 

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 


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82See Am. Soc’y of Mech. Eng’s, ANSI B31.8S– 

2004, ‘‘Managing System Integrity of Gas 

Pipelines,’’ at sec. 2 (Jan. 14, 2005). 

83 DIMP Guidance at 22. 

84 DIMP Guidance at 23. 

85 DIMP Guidance at 18, 57. 

86NTSB/PAR–19/02 at 18–21, 39–40, 48. 

must, when identifying the threats on its 

distribution system, also consider the 

age of the system, piping, and 

components in identifying threats.82 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. 

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.83

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.84

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.85 This basis should 

consider the pipeline’s failure history, 

design, manufacturing, construction, 

operation, and maintenance. 

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.86

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. 

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 lowpressure gas distribution system, from 

determining that there are no potential 

consequences associated with lowprobability 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: LowPressure Distribution Systems 

PHMSA also proposes to amend 

§ 192.1007(c) by creating a new 

§ 192.1007(c)(3) applicable to lowpressure 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 


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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 lowprobability 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 lowprobability 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 lowprobability event. The notification must 

include information such as the date the 

determination was made (to ensure 

compliance with the proposed 

timeline), descriptions of the lowprobability 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 lowpressure 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. 


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87 DIMP Guidance at 28. 

88See ‘‘Pipeline Safety: Overpressure Protection 

on Low-Pressure Natural Gas Distribution 

Systems,’’ ADB–2020–02, 85 FR 61097 (Sept. 29, 

2020). 

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.87 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. 

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, castiron, 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.88 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: 

1. Installing a full-capacity relief valve 

downstream of the low-pressure 

regulator station, including in 

applications where there is only workermonitor 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 


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89NTSB 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/srdetails/P-19-014. 

90 86 FR 2210 (Jan. 11, 2021) (‘‘Gas Regulatory 

Reform Final Rule’’). The comments submitted by 

stakeholders in this rulemaking may be found in 

Doc. No. PHMSA–2018–0046. 

91 86 FR at 2216. 

92NPGA, Petition for Rulemaking: Small 

Liquefied Petroleum Distribution Systems, Doc. No. 

PHMSA–2022–0102–001 (Dec. 17, 2021) (‘‘NPGA 

Petition’’). 

93NPGA referenced the examples of: (1) PHMSA 

Gas Regulatory Reform Final Rule, 86 FR 2210; (2) 

Nat’l Academies of Sciences, Eng’g, and Med., 

‘‘Safety Regulation for Small LPG Distribution 

Systems’’ (2018), https://nap.edu/25245 (‘‘NAS 

Study’’); and (3) NPGA, Comment Re: Pipeline 

Safety: Integrity Management Program for Gas 

Distribution Pipelines, Doc. No. PHMSA–RSPA– 

2004–19854–0197 (Oct. 23, 2008). 

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 

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. 

PHMSA proposes these amendments 

pursuant to 49 U.S.C. 60102(t) and 

60109(e)(7). The proposed amendments 

would reinforce the recommended 

actions from PHMSA’s 2020 advisory 

bulletin in which PHMSA identified for 

operators of low-pressure distribution 

systems the risks inherent to those 

systems and the preventative or 

mitigative measures they should 

implement to address the risk of 

overpressurization. PHMSA expects that 

operators may already be complying 

with many of these practices subsequent 

to issuance of the advisory bulletin, 

which set forth PHMSA’s existing 

policy and interpretation of the current 

DIMP requirements. In this NPRM, 

PHMSA proposes to codify this existing 

policy and interpretation in its 

regulations. 

This amendment is also aligned with 

the NTSB’s clarification to 

recommendation P–19–14 that PHMSA 

would not have to require that existing 

low-pressure gas distribution systems be 

completely redesigned; rather, PHMSA 

may satisfy the 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.89

7. DIMP—Small LPG Operators (Section 

192.1015) 

a. Current Requirements—DIMP and 

Annual Reporting for Small LPG 

Operators 

A ‘‘small LPG operator’’ is currently 

defined at § 192.1001 as an operator of 

a liquefied petroleum gas (LPG) 

distribution pipeline system that serves 

fewer than 100 customers from a single 

source. Small LPG operators are treated 

differently in the DIMP regulations than 

larger operators and they follow their 

own set of DIMP requirements in 

§ 192.1015 that reflect the relative 

simplicity of these pipeline systems. 

The current DIMP requirements for 

small LPG operators in § 192.1015 are 

less extensive than for other gas 

distribution systems, but still provide 

operator personnel direction for 

implementing their DIMP plans. 

Currently, under § 191.11, operators of 

small LPG systems are not required to 

submit an annual report to PHMSA. 

b. Need for Change—DIMP— 

Applicability for Small LPG Operators 

In the 2009 DIMP Final Rule, PHMSA 

imposed requirements for small LPG 

operators similar to those for other 

operators but with more limited 

requirements for documentation, 

consistent with how these operators are 

treated throughout the pipeline safety 

regulations. PHMSA did not require 

operators to report performance 

measures as they do not file annual 

reports. Although the DIMP 

requirements for small LPG operators 

are similar to those applicable to other 

operators, PHMSA codified them 

separately under § 192.1015, 

emphasizing that DIMPs for small LPG 

operators should reflect the relative 

simplicity of their pipeline systems. 

On January 11, 2021, PHMSA issued 

a final rule titled ‘‘Pipeline Safety: Gas 

Pipeline Regulatory Reform,’’ 90 which 

among other things, excepted master 

meters from the DIMP requirements. 

During the development of that rule, 

PHMSA received several comments in 

support of extending that exception to 

small LPG operators. For example, the 

National Association of Pipeline Safety 

Representatives (NAPSR) suggested that 

small gas distribution utilities with 100 

or fewer customers—including small 

LPG operators—should be excepted 

from the DIMP requirements, stating 

that many master meter systems, small 

distribution systems, and small LPG 

systems typically have no threats 

beyond the minimum threats listed in 

§ 192.1015(b)(2). Various other 

commenters, including the National 

Propane Gas Association (NPGA), 

AmeriGas, and Superior Plus Propane, 

voiced support for excepting small LPG 

operators from the DIMP requirements. 

The Pipeline Safety Trust did not 

oppose an exception from DIMP 

requirements for master meter systems 

in that rulemaking, only urging PHMSA 

and its State partners to ensure that 

master meter operators are managing the 

integrity risks to their systems outside 

the context of a DIMP plan. In response, 

PHMSA in the Gas Regulatory Reform 

Final Rule stated, ‘‘that the decision 

about whether to extend the DIMP 

exception to [other] facilities or to all 

distribution systems with fewer than 

100 customers would benefit from 

additional safety analysis and notice 

and comment procedures prior to 

further consideration.’’ PHMSA went on 

to say that it would ‘‘continue to 

evaluate the issue of DIMP requirements 

for small LPG systems and, if 

appropriate, propose changes in a future 

rulemaking[.]’’ 91

On December 17, 2021, the NPGA 

filed a petition for rulemaking in 

accordance with 49 CFR 190.331.92

NPGA petitioned PHMSA to amend 49 

CFR part 192, subpart P to create an 

exception for small LPG systems in the 

DIMP requirements. In support of their 

petition, they cited that NPGA, PHMSA, 

and the National Academies of Sciences 

(NAS) have considered the operation 

and safety of small LPG systems for 

more than 10 years.93 As an alternative, 

NPGA proposed that PHMSA could 

enable a special permit (through 

§ 190.341) for small LPG systems, for 

which NPGA would assist small LPG 

system operators in providing necessary 

information to PHMSA in the special 

permit process. 


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94NPGA Petition at 3. 

95NPGA Petition at 3–5. PHMSA notes that LPG 

releases are not themselves generally considered to 

be releases of GHGs. 

96NAS Study at 83. 

97NAS Study at 41, Table 3–4. 

98The NAS Study identified as a source of much 

of that regulatory uncertainty the varied 

interpretations of ‘‘public place’’ used at 

§ 192.1(b)(5) to determine if certain petroleum gas 

systems are subject to PHMSA’s 49 CFR part 192 

regulations. NAS Study at 87–88. 

99Nor does PHMSA expect that small LPG 

operators would experience improvements in 

pipeline safety from the regulatory amendments 

that PHMSA is proposing in this NPRM for other 

(larger) gas distribution operators. For example, 

PHMSA’s incident data from 2010 through 2021 

shows 12 incidents involving propane gas. In 

reviewing those incidents, PHMSA found that the 

age, material type, and operations of low-pressure 

distribution systems were not relevant to small LPG 

operators serving fewer than 100 customers; nor did 

those incidents involved an exceedance of MAOP. 

The basis of NPGA’s petition is that 

small LPG system operators are 

comparable to master meter systems, a 

set of operators that PHMSA recently 

removed from the DIMP requirements 

through the 2021 Gas Regulatory Reform 

Final Rule. As NPGA explained, master 

meter systems tend to be operated by 

small entities with simple systems 

compared to natural gas distribution 

operators. Master meters also often 

include only one type of pipe, and the 

systems operate at a single operating 

pressure. Similarly, as NPGA stated, the 

vast majority of small LPG pipeline 

systems are single property systems that 

occupy a small, overall footprint in size 

and generally operate at a single 

operating pressure. Although such 

systems may be metered or nonmetered, the nature of their simplicity 

in size and application make them 

comparable to master meter systems 

such that, owing to their ‘‘nearly 

identical’’ function and structure, ‘‘the 

two systems should be categorized 

together for the same treatment under 

the regulations’’ exempting them from 

DIMP requirements.94

NPGA reiterated that PHMSA further 

noted in the 2021 Gas Regulatory 

Reform Final Rule that the agency’s 

experience indicated the analysis and 

documentation requirements of DIMP 

had little safety benefit for this type of 

operator and that focusing on more 

fundamental risk mitigation activities 

has more safety benefits than 

implementing a DIMP for this class of 

operators. NPGA went on to reiterate 

PHMSA’s position in the Gas Regulatory 

Reform Final Rule (as discussed above), 

where PHMSA indicated that exempting 

master meter operators from subpart P 

would result in cost savings for master 

meter operators without negatively 

impacting safety. NPGA stated that 

PHMSA had previously expressed its 

intention to address small LPG systems 

in a future rulemaking and added that 

this change would not conflict with the 

Administration’s aims of reducing 

methane emissions.95

PHMSA has reviewed and considered 

NPGA’s petition and agrees with its 

assertion that small LPG systems do not 

present the same complexity or incur 

the same risks as large networks of 

pipeline systems crossing hundreds of 

miles. Therefore, PHMSA addresses 

NPGA’s petition through this proposed 

rule and continued oversight through 

partnership with State agencies. 

PHMSA has concluded that its 

existing approach requiring small LPG 

operators to comply with limited DIMP 

requirements offers little public safety 

benefit. Small LPG operators by 

definition have limited systems serving 

a small number of customers; in fact, 

NAPSR data suggests that there are only 

between 3,800 and 5,800 multi-user 

systems nationwide, with most serving 

fewer than 50 customers (often well 

below 50 customers).96 Small LPG 

systems are also more simple systems— 

less piping and fewer components that 

could fail—that are inherently less 

susceptible to loss of pipeline integrity 

than large gas distribution systems. 

Further, PHMSA incident data indicate 

that small LPG systems entail relatively 

low public safety risks. PHMSA’s 

incident data suggest small LPG systems 

average less than one incident involving 

a fatality or serious injury per year. 

Incidents reported by operators to 

PHMSA from 2010 through 2017 

include 10 incidents, seven injuries, and 

approximately $2 million in property 

damage.97 No fatalities have been 

reported since 2006. Incorporating fire 

events from the National Fire Incident 

Reporting System with the PHMSA 

incident data suggests that the number 

of incidents involving LPG distribution 

systems averages in the single digits per 

year. And, because releases of LPG are 

not themselves generally considered 

GHG emissions, continued regulation of 

small LPG systems pursuant to 

PHMSA’s DIMP requirements provides 

little benefit for mitigating climate 

change. 

PHMSA understands that even 

limited DIMP requirements can place a 

significant compliance burden on small 

LPG operators and administrative 

burdens on PHMSA and State regulatory 

authorities—which in turn can detract 

from other safety efforts. A 2018 study 

issued by the NAS found that there is 

significant regulatory uncertainty among 

small LPG operators regarding whether 

PHMSA’s DIMP regulations apply at 

all—resulting in many such operators 

neither understanding they are obliged 

to comply with PHMSA regulations nor 

being regularly inspected by State 

regulatory authorities.98

Given their small size and the relative 

simplicity of their systems, as discussed 

in the preceding paragraphs, and the 

significant compliance burden that 

DIMP requirements impose on such 

entities with limited safety benefit, 

PHMSA has determined that it is more 

appropriate to exempt small LPG 

operators from DIMP requirements but 

impose an annual reporting requirement 

on these operators. 

c. PHMSA’s Proposal To Exempt Small 

LPG Operators From DIMP 

Requirements and Extend Annual 

Reporting Requirements to Small LPG 

Systems 

PHMSA proposes to add a new 

§ 192.1003(b)(4) and delete existing 

§ 192.1015 to remove small LPG 

operators from DIMP requirements but 

extend annual reporting requirements to 

these operators. With small LPG 

operators removed from DIMP 

requirements at § 192.1015, the 

definition of small LPG operators in 

§ 192.1001 becomes redundant and 

therefore PHMSA would also remove it 

from DIMP. In developing this proposal, 

PHMSA considered the comments made 

in the Gas Regulatory Reform Final Rule 

on the topic of the application of DIMP 

requirements to small LPG operators, 

the NPGA’s petition for rulemaking, the 

NAS study, and PHMSA’s incident data. 

PHMSA has preliminarily determined 

that continuing to impose DIMP 

requirements (even in the abbreviated 

form pursuant to existing § 192.1015) on 

small LPG systems that have been 

proven by PHMSA incident data to 

entail inherently limited public safety 

risks imposes outsized compliance 

burdens on operators and administrative 

burdens on PHMSA and State regulatory 

authorities.99 At the same time, 

extending the annual reporting 

requirement to these operators is 

intended to ensure that PHMSA will 

maintain the ability to identify and 

respond to systemic or emerging issues 

on those systems. 

PHMSA does not expect that this 

proposed exception from DIMP 

requirements would adversely impact 

public safety. As discussed above, 

PHMSA understands the public safety 

benefits attributable to existing, limited 

DIMP requirements for small LPG 

operators are limited. PHMSA will be 

able to retain regulatory oversight of 

small LPG operator systems through 


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100PHMSA, ‘‘Guidelines for States Participating 

in the Pipeline Safety Program’’ (Jan. 2022), https:// 

www.phmsa.dot.gov/sites/phmsa.dot.gov/files/ 

2020-07/2020-State-Guidelines-Revision-withAppendices-2020-5-27.pdf. 

101PHMSA proposes below that an inspection 

person-day means ‘‘all or part of a day, including 

travel, spent by State agency personnel in on-site 

or virtual evaluation of a pipeline system to 

determine compliance with Federal or State 

Pipeline Safety Regulations.’’ 

102The SICT is located on PHMSA’s access 

restricted database portal. 

103 Instructions for how to use the SICT and 

inspection activity needs analysis examples are in 

the Guidelines. 

104This 85-day requirement is not tied to each 

individual inspector. It is an 85-day average over all 

inspectors. 

other requirements within 49 CFR part 

192, including the proposed annual 

reporting requirement and the incident 

reporting requirements at 49 CFR part 

191. 

To improve the information available 

to PHMSA and State regulatory 

authorities for identifying and 

addressing systemic public safety issues 

from small LPG systems, PHMSA is 

proposing to revise § 191.11 to require 

operators of small LPG systems to 

submit annual reports using newly 

designated form PHMSA F 7100.1–2. 

These annual reports would require 

operators of small LPG systems to report 

the location and number of customers 

served by their distribution pipeline 

systems, as well as the disposition of 

any discovered leaks. PHMSA expects 

that through an annual reporting 

requirement, PHMSA would also be 

able to provide better data to the public 

on small LPG systems, which the agency 

could assess and may ultimately inform 

a future rulemaking. PHMSA also 

expects that its proposal to require 

annual reporting for small LPG 

operators may help alleviate the 

confusion noted by the NAS Study 

regarding whether those operators are 

subject to PHMSA regulations at 49 CFR 

part 192. 

PHMSA expects the extension of its 

part 191 annual reporting requirements 

to small LPG systems would be 

reasonable, technically feasible, costeffective, and practicable. The 

information PHMSA collects on its 

current annual report form for gas 

distribution operators (Form F7100.1–1) 

does not require significant technical 

expertise or particularly expensive 

equipment to populate; small LPG 

operators may also reduce their burdens 

further by contracting with vendors to 

operate and perform maintenance on 

their systems and complete annual 

report forms. PHMSA also expects that 

the forthcoming annual report form 

(PHMSA F 7100.1–2) specific to small 

LPG operators will be a further 

simplified version of the current annual 

report form. Additionally, PHMSA notes 

that the information it expects will be 

collected within that simplified annual 

report form—operator corporate 

information, length and composition of 

the system, leaks on that system, etc.— 

is minimal information that a 

reasonably prudent small LPG operator 

would maintain in ordinary course 

given that their systems transport 

pressurized (natural, flammable, toxic, 

or corrosive) gasses. Viewed against 

those considerations and the 

compliance costs estimated in section 

V.D herein and the PRIA, PHMSA 

expects the new annual reporting 

requirement for these operators will be 

a cost-effective approach to ensuring 

PHMSA has adequate information to 

monitor the public safety and 

environmental risks associated with 

small LPG systems that would no longer 

be subject to DIMP requirements. Lastly, 

PHMSA expects that the compliance 

timeline proposed for this new reporting 

requirement—which would begin with 

the first annual reporting cycle after the 

effective date of any final rule issued in 

this proceeding (which would 

necessarily be in addition to the time 

since publication of this NPRM)—would 

provide affected operators ample time to 

compile requisite information and 

familiarize themselves with the new 

annual report form (and manage any 

related compliance costs). 

B. State Pipeline Safety Programs 

(Sections 198.3 and 198.13) 

1. Current Requirements—State 

Programs and Use of SICT 

PHMSA relies heavily on its State 

partners for inspecting and enforcing 

the pipeline safety regulations. The 

pipeline safety regulations provide that 

States may assume safety authority over 

intrastate pipeline facilities, including 

gas pipeline, hazardous liquid pipeline, 

and underground natural gas storage 

facilities through certifications and 

agreements with PHMSA under 49 

U.S.C. 60105 and 60106. States may also 

act as an interstate agent on behalf of 

DOT to inspect interstate pipeline 

facilities for compliance with the 

pipeline safety regulations pursuant to 

agreement with PHMSA. 

To support states’ pipeline safety 

programs, PHMSA provides grants to 

reimburse up to 80 percent of the total 

cost of the personnel, equipment, and 

activities reasonably required by the 

State agency to conduct its safety 

programs during a given calendar year. 

49 CFR part 198 contains regulations 

governing grants to aid State pipeline 

safety programs. PHMSA also maintains 

‘‘Guidelines for States Participating in 

the Pipeline Safety Program’’ 

(‘‘Guidelines’’), which contains 

guidance for how State pipeline safety 

programs should conduct and execute 

their delegated responsibilities.100 The 

Guidelines promote consistency among 

the many State agencies that participate 

under certifications and agreements and 

are updated on an annual basis. 

In 2017, PHMSA adopted within its 

Guidelines the State Inspection 

Calculation Tool (SICT), a tool that 

helps states conduct an inspection 

activity needs analysis for regulatory 

oversight of every operator subject to its 

jurisdiction, for the purpose of 

establishing a base level of inspection 

person-days 101 needed to maintain an 

adequate pipeline safety program.102 In 

the SICT, each State agency considers 

the type of inspection it needs to 

conduct (e.g., standard, comprehensive, 

integrity management, operator 

qualification, damage prevent activities, 

drug and alcohol); analyzes each 

operator’s system for several risk factors 

(e.g., cast iron pipe, replacement 

construction activity, compliance 

issues); assigns each operator a risk 

ranking based on the risk factors (e.g., 

leak prone pipe would have a higher 

score than modern, coated, and 

cathodically protected pipe); and lists 

other unique concerns and 

considerations (e.g., travel distance to 

conduct the inspection) applicable to 

each operator.103 Each State agency 

proposes an inspection activity level for 

each operator, which is subsequently 

peer-reviewed before being finalized by 

PHMSA. PHMSA expects that each 

State agency will dedicate a minimum 

of 85 inspection person-days for each of 

its full-time pipeline safety inspectors 

for pipeline safety compliance activities 

each calendar year.104 PHMSA 

considers a State agency’s inspection 

activity level, among several other 

factors, when awarding grants to State 

pipeline safety programs. 

2. Need for Change—State Programs and 

Use of the SICT 

A State is authorized to enforce safety 

standards for intrastate pipeline facility 

or intrastate pipeline transportation if 

the State submits annually to PHMSA a 

certification that complies with 49 

U.S.C. 60105(b) and (c). As amended in 

2020, the certification includes a 

requirement that each State agency have 

the capability to sufficiently review and 

evaluate the adequacy of each 

distribution system operator’s DIMP 

plan, emergency response plan, and 

operations, maintenance, and 

emergency procedures, as well as ‘‘a 


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61770 Federal Register / Vol. 88, No. 172 / Thursday, September 7, 2023 / Proposed Rules 

105PHMSA anticipates issuing updated Guidance 

to reflect the changes to the Pipeline Safety Grant 

Program. 106 87 FR at 20940, 20973. 

107PHMSA notes that § 192.9(d) does not 

currently require compliance with § 192.615 for 

Type B gathering lines, however PHMSA has 

proposed, in another rulemaking, to amend 

§ 192.9(d) to require Type B gas gathering operators 

to comply with § 192.615. See 88 FR at 31952–53, 

31955–56. 

sufficient number of employees’’ to help 

ensure the safe operations of pipeline 

facilities, as determined by the SICT. (49 

U.S.C. 60105(b)). PHMSA updates 

Guidelines and its evaluation process 

annually to ensure that State agencies 

are meeting the certification 

requirements.105

In certifying that the State has a 

‘‘sufficient number of employees’’, the 

State must use the SICT to account for: 

1. The number of miles of gas and 

hazardous liquid pipelines in the State, 

including the number of miles of cast 

iron and bare steel pipelines; 

2. The number of services in the State; 

3. The age of the gas distribution 

systems in the State; and 

4. Environmental factors that could 

impact the integrity of the pipeline, 

including relevant geological issues. 

Currently, the SICT accounts for the 

size (e.g., mileage, service line count, 

etc.) of each operator’s system; type of 

operator and product being transported; 

risk factors of material composition, 

including but not limited to, the 

presence of cast iron and bare steel; and 

environmental factors that could impact 

the integrity of a pipeline, including 

geological issues. Total miles of gas and 

hazardous liquid pipelines in a State 

and the age of gas distribution systems 

are, however, only implicitly 

considered. To comply with the 

mandate, PHMSA proposes to codify 

within its regulations the use of the 

SICT for establishing inspection persondays and update the SICT to explicitly 

include the total gas or hazardous liquid 

pipeline mileage in the State and the age 

of a gas distribution system as a factor 

for consideration. 

3. PHMSA’s Proposal To Codify the Use 

of the SICT in Pipeline Safety 

Regulations 

This NPRM proposes amendments to 

the pipeline safety regulations at 49 CFR 

part 198 to codify use of the SICT by all 

PHMSA’s State partners holding 

certifications or agreements per 49 

U.S.C. 60105 or 60106. Specifically, 

PHMSA proposes to revise § 198.3 to 

add definitions for ‘‘inspection personday’’ and ‘‘State Inspection Calculation 

Tool’’ and by revising § 198.13 to 

include the use of the SICT for 

determining inspection person-days. 

PHMSA proposes to define ‘‘inspection 

person-day’’ to mean ‘‘all or part of a 

day, including travel, spent by State 

agency personnel in on-site or virtual 

evaluation of a pipeline system to 

determine compliance with Federal or 

State Pipeline Safety Regulations.’’ 

PHMSA will continue to permit travel 

to be included for inspection persondays even if travel requires a full day 

before or after the inspection because 

some states cover a large geographical 

area that requires substantial travel time 

and a State agency’s staffing 

requirement could be impacted if travel 

is not considered. PHMSA will also 

continue to allow inspection persondays to be counted for those individuals 

who have not completed training 

requirements but who assist in 

inspections if they are supervised by a 

qualified inspector. PHMSA proposes to 

define the term ‘‘State Inspection 

Calculation Tool (SICT)’’ to mean ‘‘a 

tool used to determine the required 

minimum number of annual inspection 

person-days for a State agency.’’ These 

proposed definitions are consistent with 

those in the Guidelines. 

PHMSA is required to promulgate 

regulations to require that a State 

authority with a certification under 49 

U.S.C. 60105 has a sufficient number of 

qualified inspectors to ensure safe 

operations, as determined by the SICT 

and other factors determined 

appropriate by the Secretary. (49 U.S.C. 

60105 note). Pursuant to this legal 

requirement, PHMSA proposes revising 

§ 198.13(c)(6) to state that when 

allocating funding and considering 

various performance factors, PHMSA 

considers the number of State 

inspection person-days, ‘‘as determined 

by the SICT and other factors.’’ These 

amendments would codify PHMSA’s 

current practice of using the SICT in the 

determination of the minimum number 

of inspection person-days each State 

must dedicate to inspections in a given 

calendar year. 

C. Emergency Response Plans (Section 

192.615) 

The pipeline safety regulations 

require operators to have written 

procedures for responding to 

emergencies involving their pipeline 

systems to ensure a coordinated 

response to a pipeline emergency. This 

response includes communicating with 

fire, police, and other public officials 

promptly. Through a final rule issued 

on April 8, 2022, titled ‘‘Requirement of 

Valve Installation and Minimum 

Rupture Detection Standards’’, PHMSA 

extended that emergency 

communication for all gas pipeline 

operators to include a public safety 

answering point (PSAP; i.e., 9–1–1 

emergency call center).106 Among other 

changes, the Valve Rule amended 

§ 192.615(a) to ensure proper 

communication with PSAPs, requiring 

operators to immediately and directly 

notify PSAPs upon notification of a 

potential rupture. However, the Valve 

Rule requirements were not in effect at 

the time of the Merrimack Valley 

incident. 

Subsequent to the 2018 Merrimack 

Valley incident, 49 U.S.C. 60102 was 

amended to improve the emergency 

response and communications of gas 

distribution operators during gas 

pipeline emergencies in several ways. 

Specifically, 49 U.S.C. 60102(r) was 

added, which requires PHMSA to 

promulgate regulations ensuring that gas 

distribution operators develop written 

emergency response procedures for 

notifying and communicating with 

emergency response officials as soon as 

practicable from the time of confirmed 

discovery of certain gas pipeline 

emergencies; communicate with the 

public during and after such a gas 

pipeline emergency; and establish an 

opt-in system for operators to rapidly 

communicate with customers. Gas 

distribution operators must make their 

updated emergency response plans 

available to PHMSA or the relevant 

State regulatory agency within 2 years 

after the final rule is issued, and every 

5 years thereafter (49 U.S.C. 

60108(a)(3)). 

PHMSA, in this NPRM, proposes 

building on the Valve Rule’s changes to 

emergency response plan requirements 

through additional changes to ensure 

prompt and effective emergency 

response coordination. For all gas 

pipeline operators subject to 

§ 192.615,107 PHMSA proposes to 

expand the requirements to have 

procedures for a prompt and effective 

response to include emergencies 

involving notification of potential 

ruptures, a release of gas that results in 

a fatality, and any other emergencies 

deemed significant by the operator, with 

similar requirements to notify PSAPs in 

those instances. PHMSA understands 

these proposed amendments of existing 

emergency response plan requirements 

as applicable to all part 192-regulated 

pipelines would be reasonable, 

technically feasible, cost-effective, and 

practicable. The proposed changes are 

common-sense, incremental 

supplementation of current 

requirements regarding the content and 

execution of emergency response plans 

for gas pipeline operators. 


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108PHMSA expects that ‘‘maintaining adequate 

means of communication’’ should include, but not 

be limited to, considering the frequency of 

communication, changes to the nature of the 

emergency, changes to previously liaised 

information, and updates to other emergency 

response information, as determined by the 

operator. 

109 87 FR at 20983. 

110 ‘‘Pipeline Safety: Communication During 

Emergency Situations,’’ ADB–2012–09, 77 FR 61826 

(Oct. 11, 2012). PHMSA also issued draft FAQs on 

9–1–1 notification on July 8, 2021. ‘‘Frequently 

Asked Questions on 911 Notifications Following 

Possible Pipeline Ruptures,’’ 86 FR 36179 (July 8, 

2021). If PHMSA were to finalize the proposed 

revisions for these emergency plan provisions in a 

subsequent final rule, PHMSA would withdraw the 

draft 9–1–1 notification FAQs as redundant. 

Implementation of the proposed 

requirements should not require special 

expertise or investment in expensive 

new equipment; PHMSA expects that 

some operators may already comply 

with these proposed requirements either 

voluntarily or due to similar 

requirements imposed by State pipeline 

safety regulators. And insofar as these 

incremental proposed additions to 

emergency planning requirements are 

consistent with historical PHMSA 

guidance, industry operational 

experience, and the lessons learned 

from incidents such as the Merrimack 

Valley incident, they are precisely the 

sort of actions a reasonably prudent 

operator of any gas pipeline facility 

would maintain in ordinary course 

given that their systems transport 

commercially valuable, pressurized 

(natural flammable, toxic, or corrosive) 

gasses. Viewed against those 

considerations and the compliance costs 

estimated in the PRIA, PHMSA expects 

its proposed amendments are a costeffective 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 procedures (and 

manage any related compliance costs). 

PHMSA proposes additional 

requirements for gas distribution 

operators. First, those operators would 

be subject to an expanded list of 

emergencies that includes unintentional 

releases of gas with significant 

associated shutdown of customer 

services. Second, gas distribution 

operators must establish written 

procedures for communications with 

the general public during an emergency, 

and continue communications through 

service restoration and recovery efforts, 

to inform the public of the emergency 

and service restoration and recovery 

efforts. Third, gas distribution operators 

would be required to develop and 

implement for their customers an opt-in 

or opt-out notification system to provide 

them with direct communications 

during a gas pipeline emergency. 

PHMSA understands its proposed 

amendments enhancing existing 

emergency response plan requirements 

would be reasonable, technically 

feasible, cost-effective, and practicable 

for affected gas distribution operators. 

PHMSA expects that some gas 

distribution operators may already 

comply with these requirements either 

voluntarily or due to similar 

requirements imposed by State pipeline 

safety regulators. PHMSA also expects 

that operators will already have (due to 

the need to bill their customers) the 

requisite contact information needed to 

implement voluntary opt-in or opt-out 

notification systems; as explained 

below, some operators may also be able 

to leverage existing emergency 

notification systems maintained by local 

and State government officials in 

satisfying this proposed requirement. 

PHMSA further notes that its proposed 

enhancements for emergency 

communications are precisely the sort of 

minimal actions a reasonably prudent 

operator of gas distribution pipeline 

facility would undertake in ordinary 

course to protect each of (1) the public 

safety, given that their systems transport 

pressurized (natural, flammable, toxic, 

or corrosive) gasses; and (2) their 

customers, given the economic cost to 

those customers from interruption of 

supply. Viewed against those 

considerations and the compliance costs 

estimated in the PRIA, PHMSA expects 

its proposed amendments will be a costeffective approach to achieving the 

public safety and environmental 

benefits discussed in this NPRM and its 

supporting documents. Lastly, PHMSA 

understands that its proposed 

compliance timeline—between 12 to 18 

months 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 procedures and procure 

necessary personnel and vendor 

services (and manage any related 

compliance costs). 

Finally, PHMSA is requesting 

comments on whether it should require 

gas distribution operators to follow 

incident command systems (ICS) during 

an emergency response. PHMSA may 

consider whether to include this 

requirement in any final rule in this 

proceeding. The sections below discuss 

each of these proposals in more detail. 

1. Emergency Response Plans—First 

Responders 

a. Current Requirements—Emergency 

Response Plans—Notifying PSAPs, First 

Responders, and Public Officials 

Section 192.615(a) requires that each 

gas pipeline operator have written 

procedures for responding to gas 

pipeline emergencies, including for how 

operators are expected to communicate 

with fire, police, and other appropriate 

public officials before and during an 

emergency. The Valve Rule revised 

§ 192.615(a)(2) to add direct 

communication with PSAPs in response 

to gas pipeline emergencies and 

required operators to establish and 

maintain an adequate means of 

communication with PSAPs.108 Further, 

the Valve Rule revised § 192.615(a)(8) to 

require operators to notify these entities 

and coordinate with them during an 

emergency. This communication to the 

appropriate PSAPs must occur 

immediately and directly upon 

receiving a notification of potential 

rupture to coordinate and share 

information to determine the location of 

any release.109 The Valve Rule also 

revised § 192.615(c) to require each 

operator establish and maintain liaison 

with the appropriate PSAPs ‘‘where 

direct access to a 9–1–1 emergency call 

center is available from the location of 

the pipeline, as well as fire, police, and 

other public officials’’ to coordinate 

responses and preparedness planning. 

Further, PHMSA issued an advisory 

bulletin in 2012 (ADB–2012–09) 

regarding communications between 

pipeline operators and PSAPs.110 In the 

advisory bulletin, PHMSA reminded 

operators that they should notify PSAPs 

of indications of a pipeline facility 

emergency, including an unexpected 

drop in pressure, an unanticipated loss 

of SCADA communications, or reports 

from field personnel. In the advisory 

bulletin, PHMSA recommended that 

pipeline operators immediately contact 

the PSAPs of the communities in which 

such indications occur. Furthermore, 

the advisory bulletin noted that 

operators should have the ability to 

immediately contact PSAPs along their 

pipeline routes if there is an indication 

of a pipeline emergency to determine if 

the PSAP has information that may help 

the operator confirm whether a pipeline 

emergency is occurring or to provide 

assistance and information to public 

safety personnel who may be 

responding to the event. The revisions 

to § 192.615 in the Valve Rule 

essentially codified this advisory. 


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61772 Federal Register / Vol. 88, No. 172 / Thursday, September 7, 2023 / Proposed Rules 

111NTSB, PLD18MR003, ‘‘Interview of: Kevin 

Loughlin, Deputy Chief Lawrence Fire 

Department,’’ (Sept. 15, 2018), https://

data.ntsb.gov/Docket/Document/

docBLOB?ID=40476257&FileExtension=

.PDF&FileName=Emergency%20Response%20-

%20Interview%20of%20Lawrence%20Deputy

%20Fire%20Chief-Master.PDF. 112NTSB/PAR–19/02 at 46. 

113PHMSA also is adding, applicable to all part 

192-regulated gas pipeline operators, ‘‘potential 

rupture’’, consistent with the amendment in the 

Valve Rule to § 192.615(a)(8). 

PHMSA notes that indications of a gas 

pipeline emergency, including 

unexpected pressure drops or reports 

from field personnel, might be a 

notification of potential rupture under 

amended § 192.615, which would 

require the direct and immediate 

notification of the appropriate PSAP. 

b. Need for Change—Emergency 

Response Plans—Notifying PSAPs, First 

Responders, and Public Officials 

During the initial response to the 2018 

Merrimack Valley incident, the three 

fire departments in the affected 

municipalities were inundated with 

emergency calls from residents and 

businesses reporting fires and 

explosions and requesting assistance 

shortly after 4 p.m. on September 13, 

2018. Around that same time, the CMA 

technician reported smoke and 

explosions. However, it was not until 

nearly 4 hours later at 7:43 p.m. that the 

president of CMA declared a ‘‘Level 1’’ 

emergency under CMA’s emergency 

response plan. Lawrence’s deputy fire 

chief told NTSB investigators that, 

during the incident response, he 

attempted to contact CMA through the 

station dispatch to get a status update to 

see if CMA had the gas incident under 

control but did not receive updates from 

the company until hours later. About 2 

hours after the initial fires, Lawrence’s 

deputy fire chief assumed the gas 

company had resolved the incident.111

The Andover fire chief recognized the 

events occurring were gas-related and 

contacted CMA through a regular 

dispatch number to provide status 

updates so the fire department could 

relay information to the public. He told 

NTSB investigators that CMA did call 

him back more than 4 hours later, while 

also acknowledging the delay was likely 

caused by the number of emergency 

calls CMA received. 

The NTSB report noted that CMA had 

emergency response plans but did not 

implement their plans in a manner that 

would allow them to effectively respond 

to such a large incident, explaining that 

ambiguities within the operator’s 

emergency response plans could have 

contributed to the poor emergency 

response in that incident. Specifically, 

the NTSB pointed out that the operator’s 

emergency response plans suggested 

that notification could be discretionary, 

as those procedures stated that when an 

overpressurization of the system occurs, 

there ‘‘may be a need’’ to communicate 

with local government officials and 

emergency management agencies, as 

well as with fire and police 

departments.112 According to the NTSB 

report, the NiSource emergency plan 

also stated that it is ‘‘imperative for all 

entities involved to remain informed of 

each other’s activities,’’ and that CMA’s 

Incident Commander (IC), (in this case, 

the field operations leader (FOL)) was 

required to establish appropriate 

contacts for communication purposes 

throughout the incident. However, 

during the initial hours of the event, the 

IC did not establish these requisite 

communication contacts because the IC 

was involved with shutting down the 

natural gas system. And although CMA 

representatives went to emergency 

responder staging areas and emergency 

operations centers, the NTSB report 

noted that CMA representatives could 

not address many of the questions from 

emergency responders because the 

representatives were not prepared with 

thorough and actionable information. As 

a result of the lack of timely, thorough, 

and actionable information on the 

circumstances of the overpressurization 

event, emergency responders 

unnecessarily evacuated areas, straining 

limited emergency response resources, 

and creating confusion among the 

public. The NTSB concluded that CMA 

was not adequately prepared with the 

resources necessary to assist emergency 

management services with the 

emergency response. 

Subsequent to the 2018 Merrimack 

Valley incident, PHMSA was required 

by law to promulgate regulations to 

ensure that gas distribution system 

operators include in their emergency 

response plans written procedures for 

notifying ‘‘first responders and other 

relevant public officials as soon as 

practicable, beginning from the time of 

confirmed discovery, as determined by 

[PHMSA], by the operator of a gas 

pipeline emergency,’’ and including gas 

distribution-specific indications of what 

constitutes a gas pipeline emergency. 

(49 U.S.C. 60102(r)). 

c. Proposal To Amend § 192.615— 

Emergency Response Plans—Notifying 

PSAPs, First Responders, and Public 

Officials 

As discussed earlier, the Valve Rule 

revised the existing emergency response 

regulations to require operators notify 

PSAPs in the event of gas pipeline 

emergencies, and immediately and 

directly notify PSAPs when receiving a 

notification of potential rupture. In this 

NPRM, PHMSA proposes to revise the 

non-exclusive list at § 192.615(a)(3) of 

gas pipeline emergencies requiring all 

part 192-regulated gas pipeline 

operators to undertake prompt, effective 

response on notification of potential 

ruptures; a release of gas that results in 

one or more fatalities; and any other 

emergency deemed significant by the 

operator. PHMSA is also proposing that 

gas distribution pipeline operators 

would need to undertake prompt, 

effective response on notification of the 

unintentional release of gas and 

shutdown of gas service to either 50 or 

more customers or, if the operator has 

fewer than 100 customers, 50 percent of 

total customers. Additionally, PHMSA 

proposes to amend existing 

requirements at § 192.615(a)(8) to apply 

its requirement for operators of all gas 

pipelines to establish written 

procedures for immediately and directly 

notifying PSAPs, or other coordinating 

agencies for the communities and 

jurisdictions in which the pipeline is 

located, to include after a notification of 

these gas pipeline emergencies. Gas 

distribution operators, moreover, would 

also have to immediately and directly 

notify PSAPs on notification of an 

unintentional release and shutdown of 

gas services where either 50 or more 

customers lose service, or for operators 

with fewer than 100 customers, if 50 

percent of all the operator’s customers 

lose service. 

i. What is a ‘‘Gas Pipeline Emergency?’’ 

PHMSA is revising the list of gas 

pipeline emergencies in § 192.615(a)(3) 

to add: (1) for all part 192-regulated gas 

pipeline operators, events involving 1 or 

more fatalities or any other emergency 

deemed significant by the operator; and 

(2) for gas distribution pipeline 

operators only, an unintentional release 

of gas resulting in a shutdown of gas 

services affecting at least 50 customers, 

or for operators with fewer than 100 

customers, 50 percent of customers.113

The statutory language does not 

elaborate on the meaning of 

‘‘significant’’ within its usage in the 

phrase ‘‘the unscheduled release of gas 

and shutdown of gas service to a 

significant number of customers.’’ 

Therefore, PHMSA proposes to establish 

the threshold for a ‘‘significant number 

of customers’’ to be 50 customers or, for 

operators with fewer than 100 

customers, 50 percent of all the 

operator’s customers. In determining 

this threshold, PHMSA reviewed the 


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114See PHMSA, ‘‘Distribution, Transmission & 

Gathering, LNG, and Liquid Accident and Incident 

Data’’ (Aug. 31, 2022), https://www.phmsa.dot.gov/ 

data-and-statistics/pipeline/distributiontransmission-gathering-lng-and-liquid-accidentand-incident-data. 

115The term ‘‘confirmed discovery,’’ defined at 

§§ 191.3 and 195.3, ‘‘means when it can be 

reasonably determined, based on information 

available to the operator at the time a reportable 

event has occurred, even if only based on a 

preliminary evaluation.’’ 

116Relying on the same operative phrase 

(‘‘confirmed discovery’’) that is already used to 

notify the National Response Center of reportable 

incidents risks introducing confusion and 

uncertainty with respect to what regulations to 

follow and how to incorporate these regulations 

into response plans for when operators must 

contact local emergency responders. In an 

emergency, clarity is critical and PHMSA believes 

that utilizing distinct regulatory phrases for these 

different duties will help distinguish and clarify 

responsibilities in an emergency response. 

117PHMSA’s proposal anticipates that an operator 

will alert local emergency response officials upon 

earliest indications of gas pipeline emergencies. 

118See § 192.635(a)(1) (specifying a 15-minute 

time interval for evaluating significant pressure 

losses on gas pipelines as an indicium of a rupture). 

119FEMA, ‘‘Lesson 3: Communicating in an 

Emergency’’ (Feb. 2014), https://training.fema.gov/ 

emiweb/is/is242b/instructor%20guide/ig_03.pdf. 

data for all reportable gas distribution 

incidents from 2010 to 2021 and 

averaged the number of residential, 

commercial, and industrial customers 

affected by those incidents.114

PHMSA also proposes to add ‘‘other 

emergency deemed significant by the 

operator’’ to the list of examples of a gas 

pipeline emergency to allow operators 

to use their best professional judgment 

when coordinating with first responders 

and other relevant public officials and 

account for other system-specific 

circumstances, such as an outage to a 

single customer that happens to be a 

hospital or other critical-use facility, 

when complying with § 192.615. This 

amendment would specify a nonexclusive list of gas pipeline 

emergencies. 

ii. When must operators communicate 

with PSAPs, first responders, and other 

relevant public officials? 

PHMSA proposes to adopt the 

aforementioned more-inclusive list of 

gas pipeline emergencies into the 

§ 192.615(a)(8) notification requirements 

established in the Valve Rule that 

required the immediate and direct 

notification of PSAPs and other relevant 

emergency responders and public 

officials after receiving notice of such an 

emergency. Pursuant to 49 U.S.C. 

60102(r), operator communications with 

first responders and other relevant 

public officials must occur ‘‘as soon as 

practicable, beginning from the time of 

confirmed discovery, as determined by 

the Secretary, by the operator of a gas 

pipeline emergency.’’ PHMSA, in 

§§ 191.5 and 195.52, already uses the 

term ‘‘confirmed discovery’’ 115 to 

require operators to report certain 

events to the National Response Center 

at the earliest practicable moment 

following ‘‘confirmed discovery;’’ 

however, these notifications may occur 

up to 1 hour after confirmation. Further, 

those §§ 191.5 and 195.52 reportable 

events may not always constitute a gas 

pipeline emergency as proposed in 

§ 192.615. Because the 49 U.S.C. 

60102(r) mandate directs PHMSA to 

improve and expand emergency 

response efforts—distinct from operator 

notification of incidents/accidents for 

reporting purposes—PHMSA 

determines that the timing of local 

emergency communication must come 

immediately and directly upon 

indication of such a gas pipeline 

emergency. PHMSA, therefore, does not 

propose to interpret ‘‘confirmed 

discovery’’ in 49 U.S.C. 60102(r) to 

apply in § 192.615(a) in the same 

manner as the term is used in 49 CFR 

parts 191 and 195.116 Instead, PHMSA 

proposes ‘‘confirmed discovery’’ in 49 

U.S.C. 60102(r), for purposes of 

§ 192.615, to mean immediately after 

receiving notice of a gas pipeline 

emergency.117 This will bring local 

emergency services to bear as near as 

possible to a gas pipeline emergency 

based on early indications, rather than 

considering whether the gas pipeline 

emergency is also a reportable event 

under § 191.5 before initiating an 

emergency response. 

PHMSA proposes that gas pipeline 

emergencies be immediately and 

directly communicated to local 

emergency responders because any 

delays in emergency response may make 

the emergency significantly more 

difficult to contain. PHMSA expects that 

in no case should that ‘‘immediate’’ 

communication to PSAPs begin any 

later than 15 minutes following initial 

notification to the operator of that 

emergency. This expectation is 

consistent with certain criteria for 

‘‘notification of a potential rupture’’ 

adopted in the Valve Rule,118 and 

would ensure the timely and effective 

implementation of the pipeline 

operator’s emergency response plan and 

coordinated response with local public 

safety officials. PHMSA also expects 

that if a gas pipeline emergency also 

meets the criteria of an incident in 

§ 191.3, operators would report the 

incident to the National Response 

Center in accordance with § 191.5, as 

already required. 

iii. What information should operators 

provide to first responders and public 

officials? 

As the emergency response to the 

Merrimack Valley incident continued, 

public safety officials asked CMA for 

detailed information on the locations of 

the overpressurized gas lines to aid in 

assessing the scope and scale of the 

incident. Officials requested maps and 

lists of impacted customers and 

impacted streets, but CMA did not 

provide them in a timely manner. This 

significantly hampered the response to 

the event and caused first responders to 

take unnecessary actions during the 

immediate response efforts. For 

example, instead of targeting specific 

residents based on the location of the 

affected services, first responders 

needed to go door to door to evaluate 

safety impacts and determine where the 

gas lines were overpressurized. To 

prevent such delays from occurring in 

the future, PHMSA recommends 

operators provide first responders and 

public officials with pertinent 

information, as it becomes available, to 

support emergency communications 

during a gas pipeline emergency, 

including: (1) the operator’s response 

efforts; (2) information on the gas 

service sites impacted by the release; (3) 

the magnitude of the incident and its 

expected impact; (4) the location(s) of 

the emergency and of affected 

customers; (5) the specific hazard and 

the potential risks; and (6) the operator 

point of contact responsible for 

addressing first responder and public 

official questions and concerns. 

Procedures to provide such information 

must be included in their emergency 

response plans and should also comport 

with guidance by the Federal 

Emergency Management Agency 

(FEMA) for State and local governments 

in developing effective hazard 

mitigation planning and would help 

ensure that appropriate instructions, 

directions, and information is provided 

to the right people at the appropriate 

time.119

2. Emergency Response Plans—General 

Public 

a. Current Requirements—Emergency 

Response Plans—General Public 

Currently, there are no Federal 

regulations requiring gas distribution 

operators to establish communications 

with the general public during or 

following a gas pipeline emergency. 

Section 192.615 requires operator 


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120Section 192.616 requires operators to develop 

and implement a written continuing publiceducation program that follows the guidance 

provided in American Petroleum Institute’s (API) 

Recommended Practice (RP) 1162 (incorporated by 

reference, see § 192.7). API RP 1162 is a consensus 

standard that establishes a baseline publicawareness program for pipeline operators. It states 

that operators should provide notice of, and 

information regarding, their emergency response 

plans to appropriate local emergency officials. 

121Mass. Emergency Mgmt. Agency & Mass. Nat’l 

Guard, ‘‘Merrimack Valley Natural Gas Explosions 

After Action Report,’’ at 49–50 (Jan. 2020), https:// 

www.mass.gov/doc/merrimack-valley-natural-gasexplosions-after-action-report/download 

(‘‘Merrimack Valley After Action Report’’). 

coordination and communication with 

only fire, law enforcement, emergency 

management, and other public safety 

officials. Section 192.616 contains 

requirements for public awareness but 

does not contain provisions specific to 

communications with the public during 

or after an emergency.120

b. Need for Change—Emergency 

Response Plans—General Public 

In any gas pipeline emergency, 

communicating basic information and a 

consistent message can be difficult. 

While communication with emergency 

responders is important, so too is 

contemporaneously updating affected 

members of the public, as both serve to 

reduce public safety harms. CMA’s 

failure to communicate promptly with 

its affected customers throughout the 

2018 Merrimack Valley incident showed 

deficiencies in CMA’s incident response 

planning. CMA first provided the public 

with information regarding the incident 

at approximately 9:00 p.m. on 

September 13, 2018—nearly 5 hours 

after the onset of the emergency at 

approximately 4:00 p.m. when the first 

9–1–1 calls on the incident were made. 

Although CMA was still gathering 

relevant information during the first 

several hours following the incident and 

did not have a complete understanding 

of the situation, it nevertheless should 

have conveyed information to the public 

on the nature of the incident and 

affected areas more quickly. 

Subsequent to the 2018 Merrimack 

Valley incident, PHMSA was directed in 

49 U.S.C. 60102(r) to revise its 

regulations to ensure that each gas 

distribution operator includes written 

procedures in its emergency plan for 

‘‘establishing general public 

communication through an appropriate 

channel’’ as soon as practicable after a 

gas pipeline emergency. In particular, 

operators should communicate to the 

public information regarding the gas 

pipeline emergency and ‘‘the status of 

public safety.’’ 

c. PHMSA’s Proposal To Amend 

§ 192.615—Emergency Response 

Plans—General Public 

Gas distribution pipeline operators 

are not currently required to 

communicate public safety or service 

interruption and restoration information 

to the public during and following a gas 

pipeline emergency. Therefore, PHMSA 

proposes that gas distribution operators 

include procedures for establishing and 

maintaining communication with the 

general public as soon as practicable 

during a gas pipeline emergency on a 

gas distribution pipeline. Operators 

would need to continue 

communications through service 

restoration and recovery efforts. 

Operators would need to establish 

communication through one or more 

channels appropriate for their 

communities, which could include inperson events (e.g., press conferences or 

town hall-style events), print media, 

broadcast media, the internet or social 

media, text messages, phone apps, or 

any combination of these channels. 

Further, PHMSA proposes that such 

communications must include the 

following components: 

1. Information regarding the gas 

pipeline emergency (which could 

include the specific hazard and 

potential risks to the community, the 

location of the incident and boundaries 

of the impacted area, the magnitude of 

the event and the expected impact, 

protective actions the public should 

take, and how long the public may be 

impacted), 

2. The status of the emergency (e.g., 

have the condition causing the 

emergency or the resulting public safety 

risks been resolved), 

3. The status of pipeline operations 

affected by the gas pipeline emergency 

and when possible, a timeline for 

expected service restoration, and 

4. Directions for the public to receive 

assistance (e.g., provide a phone number 

for customers to call if they are without 

power for 24 hours, or directions to safe 

local shelters should temperatures drop 

below freezing). 

PHMSA believes that providing in its 

regulations a list of information for 

operators to include in their procedures 

will help streamline communications to 

the public during a gas pipeline 

emergency and post-emergency efforts 

and ensure that members of the public 

have information needed to understand 

the risks to public safety posed by a gas 

pipeline emergency. In addition, by 

providing a list of minimum 

requirements for public 

communications, operators can train 

personnel on the type of information 

they should collect and share with the 

public. Operators can require the 

communication of additional 

information in their procedures, but 

should, at a minimum, inform the 

public of the information listed above. 

During an emergency response, an 

operator’s resources may be strained 

such that not all the information 

pertaining to the incident may be 

available at a given time. Therefore, 

during a gas pipeline emergency on a 

distribution line, operators should 

provide updates to the public on a 

reasonable basis as this information 

becomes available or changes. This 

provision allows for a common-sense 

approach to when an operator must 

provide general public updates to an 

emergency. However, it would require 

operators to provide these updates 

based on the circumstances of the 

emergency such that the general public 

timely receives information that could 

influence the public’s response to the 

emergency or benefit affected 

communities’ understanding of recovery 

effort progress. 

Further, PHMSA also proposes that 

when communicating this minimum 

information with the general public, 

operators must ensure these messages 

are issued in English and in other 

languages commonly understood by a 

significant number and concentration of 

the non-English speaking population in 

the operator’s service area and are 

delivered in a manner accessible to 

diverse populations in their service 

operators. Operators should use clear 

and simple language in their 

communications. The Merrimack Valley 

incident underscores the value of such 

broadly accessible communications. The 

city of Lawrence, MA, is comprised of 

a higher percentage of Spanish-speaking 

residents than other areas affected by 

the Merrimack Valley incident. In the 

Massachusetts Emergency Management 

Agency (MEMA) After Action Report, 

MEMA reported that CMA did not fully 

account for the demographics of the 

impacted communities when attempting 

to communicate with the public during 

and following the incident, which in 

some cases delayed delivery of 

appropriate information and services to 

impacted customers.121

Operators must prepare their public 

communication plans before a gas 

pipeline emergency develops to ensure 

that the proper tools and resources are 

available to assist limited English 

proficiency (LEP) individuals in the 

communities they serve when an 

emergency arises. PHMSA notes that, as 

required under § 192.616(g), operators 

must conduct their public awareness 

program in other languages commonly 

understood by a significant number and 


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122Ltd. English Proficiency, ‘‘Data and Language 

Maps,’’ U.S. DOJ, https://www.lep.gov/maps (last 

visited Feb. 27, 2023). 123U.S. DOJ, ‘‘Tips and Tools for Reaching 

Limited English Proficiency in Emergency 

Preparedness, Response, and Recovery,’’ (2016), 

https://www.justice.gov/crt/file/885391/download. 124Merrimack Valley After Action Report at 46. 

125PHMSA further understands that some 

utilities (e.g., electric utilities) may have similar 

notification systems for their customers and the 

public within their service areas. 

concentration of the non-English 

speaking population in the operator’s 

area. Therefore, operators should 

already be aware of the languages used 

in their service areas and have this 

information readily available. If 

operators do not already have this 

information, data from the U.S. Census 

Bureau American Community Survey at 

the tract level—including summarized 

information on English proficiency 

along with mapping of critical 

infrastructure and locations of hospitals, 

long-term care facilities, police, and fire 

stations—can help provide more 

targeted and community-specific 

services.122 Operators can use this 

information to understand the 

demographics of their communities and 

build lists of common media sources for 

each language population in their 

service area. More information on how 

to reach LEP communities in emergency 

preparedness, response, and recovery is 

available through the Department of 

Justice.123 Where appropriate, operators’ 

communications during pipeline 

emergencies should account for 

disabilities that might make 

communication difficult by, for 

example, having American Sign 

Language interpreters present during 

press conferences to ensure that 

hearing-impaired residents can receive 

communications during a pipeline 

emergency. 

3. Emergency Response Plans—Opt-in 

System for Customers 

a. Current Requirements—Emergency 

Response Plans—Customers 

As previously discussed, there are 

currently no Federal regulations in 

place that would require gas 

distribution operators to establish 

communications with customers 

throughout a gas pipeline emergency. 

There are also no current Federal 

requirements in place requiring these 

operators establish procedures for 

developing and implementing an opt-in 

communication system whereby 

customers in their service area can 

receive updates of pipeline emergencies 

on their cell phones or other media. 

b. Need for Change—Emergency 

Response Plans—Customers 

As the incident unfolded and local 

leaders made decisions to ensure the 

safety of citizens, each community sent 

their own evacuation notifications 

targeting their residents by using 9–1–1 

call location data to estimate the 

locations of the affected services. Local 

officials used this data to reach a 

consensus about which areas to 

evacuate because they were unable to 

use more accurate data from CMA 

regarding the number and location of 

impacted customers.124

Andover and North Andover used 

their existing emergency notification 

systems to notify residents to evacuate. 

Authorities in North Andover issued a 

voluntary evacuation for all occupied 

structures with natural gas utility 

service, using local cable channels, the 

town website, and a citizen alert 

telephone system that sends public 

service messages. The alert system 

automatically called every landline. 

However, cell phones and private 

numbers had to be registered to receive 

a call. The Andover fire chief called for 

an evacuation using a citizen alert 

telephone system and social media. The 

wireless emergency alerts to evacuate 

South Lawrence, and later to return 

home, were sent out in both English and 

Spanish. The South Lawrence mayor’s 

evacuation order was issued as an alert 

over cell phones and media broadcasts 

to residents in the area. In total, more 

than 50,000 residents were asked to 

evacuate through a variety of methods. 

While many municipalities have 

communication systems to rapidly 

communicate with their constituents 

during an emergency, not all gas 

distribution operators are using these 

tools to rapidly communicate with their 

customers during a gas pipeline 

emergency. PHMSA believes that 

operators could use these tools to 

provide customers with real-time 

information during an emergency to 

protect public safety. The Merrimack 

Valley incident underscored the need 

for operators to improve their 

communication with customers when 

responding to an emergency on a gas 

distribution pipeline. Subsequently, 49 

U.S.C. 60102 was amended to include a 

new mandate to expand the use of 

voluntary, opt-in customer notifications 

during an emergency. Specifically, 

PHMSA was directed to update its 

regulations to ensure that each 

emergency response plan developed by 

an operator of a gas distribution system 

includes written procedures for ‘‘the 

development and implementation of a 

voluntary, opt-in system that would 

allow operators of distribution systems 

to rapidly communicate with customers 

in the event of an emergency.’’ (49 

U.S.C. 60102(r)(3)). PHMSA 

understands that a ‘‘system’’ to ‘‘rapidly 

communicate with customers’’ could 

take many forms; however, in practice, 

it is typically a ‘‘reverse 9–1–1’’ system 

that calls or texts individual customers 

to notify them of significant, timesensitive events. Many cities and 

utilities already use such systems to 

allow emergency officials to notify 

residents and businesses of emergencies 

or outages by telephone, cell phone, text 

message, or email. 

c. Proposal To Amend § 192.615— 

Emergency Response Plans—Customers 

Pursuant to 49 U.S.C. 60102(r)(3), 

PHMSA proposes to add to § 192.615 a 

new paragraph (d) that would require 

operators of gas distribution pipelines to 

establish procedures for developing and 

implementing a voluntary, opt-in 

customer notification system to 

communicate with customers in the 

event of a gas pipeline emergency. 

PHMSA understands the statutory 

mandate for a ‘‘voluntary, opt-in 

system’’ to mean that the gas pipeline 

operators give the customers they serve 

the opportunity to opt-in (or opt-out) to 

receiving notifications from the 

operator’s communication system, 

therefore making the system voluntary 

for customers. Gas distribution 

operators must notify all customers of 

the existence of such a communications 

tool and their ability to elect to receive 

such emergency notifications. 

PHMSA does not expect that a 

voluntary, opt-in emergency notification 

system would impose a significant 

burden on operators. PHMSA notes that 

operators will often already have from 

their billing activities much of the 

information (customer phone numbers, 

email and postal addresses, and 

preferred language) needed to 

implement such a system. And because 

an iteration of a voluntary, opt-in or optout emergency notification systems may 

already be in place in some local 

communities,125 PHMSA concludes that 

operators could comply with this 

proposed requirement by coordinating 

with cities and townships to utilize 

those existing systems. Where 

coordination with an existing 

communication system is not possible, 

operators may choose to utilize a thirdparty vendor or build such a service inhouse. Regardless of who administers 

the notification system proposed in 

§ 192.615(d), operators would need to 

provide a basic description of the 

system and describe the operation of the 

system in their procedures. Operators 


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126As discussed in Section I.A. of the preamble, 

the BIL provides funding for the Natural Gas 

Distribution Infrastructure Safety and 

Modernization Grant Program. Each applicant 

selected for grant funding under this notice must 

demonstrate, prior to the signing of the grant 

agreement, effort to consider and address physical 

and cyber security risks relevant to their natural gas 

distribution system and the type and scale of the 

project. Projects that have not appropriately 

considered and addressed physical and cyber 

security and resilience in their planning, design, 

and project oversight, as determined by the 

Department of Transportation and the Department 

of Homeland Security, will be required to do so 

before receiving funds for construction, consistent 

with Presidential Policy Directive 21—Critical 

Infrastructure Security and Resilience and the 

National Security Presidential Memorandum on 

Improving Cybersecurity for Critical Infrastructure 

Control Systems. 

127While 49 U.S.C. 60109(e)(7)(C)(i)(II) directs gas 

distribution operators to make their updated 

emergency response procedures available to 

PHMSA or the relevant State regulatory agency no 

later than 2 years after issuing a final rule, it does 

not specify a deadline for operators to have 

implemented their customer notification systems. 

128FEMA, ‘‘Glossary of Related Terms, E/L/G 

0300 Intermediate Incident Command System for 

Expanding Incidents, ICS 300’’ at 6 (Mar. 2018), 

https://training.fema.gov/emiweb/is/icsresource/ 

assets/glossary%20of%20related%20terms.pdf. 

129AGA, ‘‘Emergency Preparedness Handbook for 

Natural Gas Utilities’’ at 10, https://www.aga.org/ 

wp-content/uploads/2022/12/aga-emergencypreparedness-handbook-2018.pdf. 

130API Recommended Practice 1174, 

‘‘Recommended Practice for Onshore Hazardous 

Liquid Pipeline Emergency Preparedness and 

Response’’ at 26 (1st ed. Dec. 2015). 

131NFPA, ‘‘NFPA 1600: Standard on Continuity, 

Emergency, and Crisis Management’’ (2019); FEMA, 

‘‘Fact Sheet: NIMS Recommended Standards’’ (Jan. 

4, 2007), https://www.fema.gov/pdf/emergency/ 

nims/fs_standards_010407.pdf. 

must also include in their procedures a 

description of the protocols for 

activating the system and notifying 

customers (i.e., who initiates the 

notification and when). PHMSA notes 

that such a voluntary opt-in or opt-out 

system could have additional benefits 

outside of gas pipeline emergencies, as 

operators could use such a system to 

communicate with their customers 

during non-emergencies (such as service 

outages or planned maintenance) or for 

billing purposes. 

Because periodic testing is essential 

for ensuring proper operation of such an 

emergency customer notification 

system, PHMSA includes within its 

proposed § 192.615(d) that operators’ 

procedures must describe system testing 

protocols and (at least) annual testing. 

Operators would need to maintain the 

results of their testing and operations 

history for at least 5 years. If an operator 

does not control the testing protocol 

(e.g., because they rely on an emergency 

notification system administered by a 

local government), they should describe 

in their procedures the frequency of 

testing performed by partnered 

municipality and arrange to receive 

confirmation of those tests after they 

occur. 

Similar to the requirements discussed 

earlier for public communications 

during and following gas pipeline 

emergencies, PHMSA is also proposing 

that an operator’s written procedures for 

this opt-in notification system include a 

description of how the system’s 

messages will be accessible to Englishspeaking and LEP customers alike. 

Operators should describe the process 

for identifying any LEP or other 

pertinent demographic information for 

the areas they serve. These procedures 

should include a description of any 

non-English languages required in 

standardized emergency 

communications that would be 

provided in an operator’s system. 

Because there may be LEP individuals 

who need to receive these messages, 

operators should be prepared to 

translate messages about public safety 

into the required non-English 

language(s). 

PHMSA also proposes to require 

operators’ procedures include 

cybersecurity measures to protect the 

notification system and customer 

information. As with any system that 

interfaces with operators’ information 

technology assets or customers private 

information, operators should protect 

against cybersecurity vulnerabilities and 

insider threats. Operators should, for 

example, include protocols aimed at 

protecting their infrastructure from 

malicious attacks, false notifications 

being sent to customers, and theft of 

customers’ information. If the 

communication system is operated by a 

third party, operators should document 

the cybersecurity measures managed by 

the vendor.126

PHMSA proposes that operators of gas 

distribution systems must implement 

such a voluntary, opt-in notification 

system in accordance with their 

procedures (i.e., ensure that the system 

is ready for use during a gas pipeline 

emergency) no later than 18 months 

after the publication of the final rule.127

PHMSA proposes that 18 months after 

the publication of the final rule in this 

proceeding is a reasonable timeframe to 

implement these new procedures and 

seeks comment on this conclusion. 

4. Emergency Response—Incident 

Command Systems 

a. Background 

Communication during a pipeline 

emergency is complex and includes 

communication between the pipeline 

operator, other pipeline companies, 

non-pipeline utilities, emergency 

responders, elected officials, PSAPs, 

and the public. Effective 

communication between and within 

each of these entities is crucial to the 

successful response to a gas pipeline 

emergency. For this reason, some gas 

distribution pipeline operators and 

other utilities use an Incident Command 

System (ICS) to coordinate emergency 

response actions. 

An ICS is a standardized approach to 

the command, control, and coordination 

of on-scene management of emergencies 

and other incidents, providing a 

common hierarchy within which 

personnel from multiple organizations 

can be effective.128 An ICS is the 

combination of procedures, personnel, 

facilities, equipment, and 

communications operating within a 

common organizational structure, 

designed to aid in the management of 

on-scene resources. It can be applied to 

incidents (including emergencies and 

planned events alike) of any size. 

The National Incident Management 

System (NIMS), a system commonly 

used in the public and private sectors of 

incident management, uses ICS 

principles. As stated in the American 

Gas Association’s (AGA) Emergency 

Preparedness Handbook, ‘‘[u]tilities 

across our nation are increasingly 

integrating [NIMS] into their planning 

and incident management structure.’’ 129

Additionally, API in API RP 1174 

recommends the use of NIMS for 

responding to accidents on hazardous 

liquid pipelines.130 FEMA has also 

indirectly recommended the use of 

NIMS through its recommendation of 

National Fire Protection Association 

(NFPA) Standard 1600 for emergency 

preparedness, a standard which 

recommends the use of NIMS.131

Typically, local authorities handle 

most incidents using the 

communications systems, dispatch 

centers, and incident personnel within 

their jurisdiction. For larger and more 

complex incidents, however, response 

efforts may rapidly expand to multijurisdictional or multi-disciplinary 

efforts requiring outside resources and 

support. Widespread use of ICSs could 

allow the efficient integration of outside 

resources and enable personnel from 

anywhere in the Nation to participate in 

the incident-management structure. 

Regardless of the size, complexity, or 

scope of the incident, the use of an ICS 

could benefit pipeline operators. 

PHMSA is considering an ICS-based 

system in this rulemaking to provide 

safety benefits. However, PHMSA has 

preliminarily determined further input 

from the public would be beneficial in 

assessing the feasibility of doing so, as 

well as the best practices that would 


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132NTSB/PAR–19/02 at 45–47, 48–49. 

133FEMA, ‘‘National Incident Management 

System’’ (May 24, 2022), https://www.fema.gov/ 

emergency-managers/nims. 134 49 CFR 192.603(b). 

inform such a regulatory standard. 

Specifically, PHMSA is considering 

requirements under § 192.615 for 

operators of gas distribution pipelines to 

follow ICS procedures in response to gas 

pipeline emergencies. For example, 

PHMSA could require that operators of 

gas distribution pipelines develop 

written procedures in accordance with 

ICS tools and practices. An example of 

an ICS practice would be to identify the 

roles and responsibilities of emergency 

responders and communicate those 

responsibilities to designated personnel, 

which would be similar to the current 

requirements in § 192.615(c). PHMSA 

recognizes the benefit of pipeline 

operators using ICS for gas pipeline 

emergencies, as such an approach can 

help hone and maintain skills needed to 

coordinate response efforts effectively, 

even as poor implementation of an ICS 

may hinder effectiveness. For example, 

in the Merrimack Valley incident, both 

the operator and emergency responders 

had an ICS in their respective 

emergency response manuals; however, 

the ICS procedures were implemented 

with mixed results. While State and 

local emergency responders were able to 

effectively manage, organize, and 

coordinate the activities of multiple 

agencies serving in the emergency 

response by following the ICS, the 

NTSB concluded that CMA’s Incident 

Commander (IC) struggled to manage 

the multiple competing priorities, such 

as communicating with affected 

municipalities, updating emergency 

responders, and shutting down the 

natural gas distribution system, which 

adversely affected the IC’s ability to 

complete tasks in a timely manner.132

The Merrimack Valley incident 

underscores that effective execution of 

an ICS is still dependent upon each 

operator’s ability to implement the 

practices during a crisis. 

PHMSA is also considering, if it 

determines to adopt requirements for 

operators of gas distribution pipelines to 

follow ICS procedures in response to gas 

pipeline emergencies, requiring 

operators to train personnel on ICS tools 

and practices. PHMSA expects that to 

develop an ICS for a response to gas 

pipeline emergencies, operator 

personnel would need to undergo 

extensive training and coordination 

exercises with first responders, and 

local and State public safety officials. 

FEMA provides free resources for 

implementing and training on ICS on 

their website.133 Because this training is 

free, PHMSA expects there should be no 

upfront costs to provide training, 

however, there would be a burden in 

terms of time for operators to (1) take 

these trainings and (2) incorporate ICS 

tools and practices into their training 

and emergency response procedures. 

Further, the ICS tools and guidance are 

designed to be integrated into an 

organization’s existing infrastructure, so 

PHMSA would not expect operators to 

have to hire additional personnel to 

meet a new requirement in its 

regulations for an ICS. PHMSA seeks 

comment on these assumptions. 

b. Request for Input on the Adoption of 

ICS Requirements in PHMSA 

Regulations 

PHMSA is seeking public comments 

regarding the potential adoption within 

the pipeline safety regulations of a 

requirement at § 192.615 that each 

operator employ an ICS for gas pipeline 

emergencies to include the following 

topics that could inform the specifics of 

any such requirement: 

1. Should PHMSA promulgate new 

regulations requiring ICS for all gas 

distribution systems? Any other 

pipeline facilities? 

2. If PHMSA were to adopt ICS 

requirements, should there be any 

exceptions from the ICS requirements? 

3. Should PHMSA develop a standard 

for ICS or incorporate by reference an 

existing industry-based standard for 

ICS? 

4. What are current sources of ICS 

training? 

5. How long does it take, or would it 

take, for operators to train an employee 

on ICS tools and practices? 

6. How often should qualified 

employees receive periodic training on 

ICS tools and practices? 

7. What is an appropriate timeline for 

operators to incorporate ICS practices 

into their procedures if PHMSA were to 

promulgate an ICS standard? 

PHMSA requests that commenters 

provide specific proposals for what 

provisions should be adopted or 

changes that should be made to the 

regulations related to the questions 

listed above. 

In addition to the questions above, 

PHMSA requests commenters to provide 

information and supporting data related 

to: 

1. The number of gas distribution 

operators that have currently adopted an 

ICS in their emergency procedures. 

2. The technical feasibility, costeffectiveness, and practicability of 

implementing any requirement for 

operators to adopt ICS. 

3. The potential quantifiable safety 

and societal benefits of adopting ICS. 

4. The potential impacts on small 

businesses adopting ICS. 

5. The potential environmental 

impacts of adopting ICS. 

D. Operations and Maintenance 

Manuals (Section 192.605)— 

Overpressurization 

1. Current Requirements—O&M 

Manuals—Overpressurization 

Section 192.605 includes minimum 

requirements for gas pipeline operators’ 

procedural manuals for operations, 

maintenance, and emergencies. Section 

192.605(a) requires gas pipeline 

operators to have ‘‘a manual of written 

procedures for conducting operations 

and maintenance activities and for 

emergency response,’’ otherwise known 

as an O&M manual. Operators must 

review and update this manual at 

intervals that do not exceed 15 months 

and at least once each calendar year. 

Appropriate parts of the manual must be 

kept where operations and maintenance 

activities take place. 

Section 192.605(b) lists various 

procedures that each gas pipeline 

operator must include in the manual to 

provide safety during operation and 

maintenance. Among other 

requirements, § 192.605(b)(5) requires 

that the O&M manual include a 

procedure for ‘‘[s]tarting up and 

shutting down any part of the pipeline 

in a manner designed to assure 

operation within the MAOP limits 

prescribed in this part, plus the buildup allowed for operation of pressurelimiting and control devices’’ in order 

‘‘to provide safety during maintenance 

and operations.’’ 

Subpart L also requires an operator to 

‘‘keep records necessary to administer 

the procedures established under 

§ 192.605.’’ 134 Among the records 

required to be kept and made available 

to operating personnel are ‘‘construction 

records, maps and operating history,’’ 

per § 192.605(b)(3). Sections 

192.605(d)–(e) require an O&M manual 

to include procedures for both reporting 

safety-related conditions and for 

surveillance, emergency response, and 

accident investigations, respectively. 

2. Need for Change—O&M Manuals— 

Overpressurization 

Clearly written procedures aid in the 

successful execution of tasks and 

processes necessary to ensure a gas 

distribution pipeline system is operated 

and maintained in a safe manner. 

Overpressurizations, while rare, can 

cause a pipeline failure if not addressed 

in a timely manner. Including measures 


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135Although PHMSA expects that among the 

immediate actions that operators will take in 

response to an overpressurization indication would 

be confirming as soon as practicable whether an 

overpressurization exists or is imminent, operators 

may not delay other immediate actions necessary to 

protect hazards to public safety and the 

environment while they obtain such confirmation. 

136PHMSA also notes that pipeline employees 

and contractors who raise concerns that a pipeline 

operator is not complying with pertinent PHMSA 

safety requirements or the pipeline’s implementing 

procedures may have statutory whistleblower 

protections pursuant to 49 U.S.C. 60129. Pipeline 

employees and contractors who are concerned that 

they have been retaliated against for raising safety 

concerns should be raised with Department of 

Labor (via the Occupational Health and Safety 

Administration). See OHSA, ‘‘Fact Sheet: 

Whistleblower Protection for Pipeline Facility 

Workers,’’ (Feb. 2022), https://www.osha.gov/sites/ 

default/files/publications/OSHA4072.pdf. 

in O&M manuals to respond to 

indications of an overpressurization can 

help ensure a timely, effective response. 

As demonstrated by the Merrimack 

Valley incident, operators of gas 

distribution pipelines must be prepared 

to recognize and respond to 

overpressurization indications, as these 

events can have significant 

consequences for public safety and the 

environment. PHMSA regulations have 

a requirement in § 192.605(b)(5) for 

operators to have procedures for 

‘‘starting up and shutting down any part 

of the pipeline in a manner designed to 

assure operation within the MAOP 

limits prescribed by this part, plus the 

build-up allowed for operation of 

pressure-limiting and control devices.’’ 

To further reduce the likelihood of 

future incidents like the 2018 

Merrimack Valley incident, however, 

PHMSA proposes to amend § 192.605 to 

ensure that operators explicitly account 

for overpressurization in their O&M 

procedures. 

Subsequent to the 2018 Merrimack 

Valley incident, 49 U.S.C. 60102 was 

amended to require PHMSA to 

undertake a new rulemaking that would 

require operators of gas distribution 

systems to update their operations, 

maintenance, and emergency plans to 

include procedures for specific actions 

to be taken on receipt of an indication 

of an overpressurization on their 

systems. Those actions include an order 

of operations for immediately reducing 

pressure in, or shutting down portions 

of, the gas distribution system, if 

necessary. (49 U.S.C. 60102(s)). 

Amendments to 49 U.S.C. 60108 require 

gas distribution operators to make their 

updated O&M manuals available to 

PHMSA or the relevant State regulatory 

agency within 2 years after any final 

rule is issued and every 5 years 

thereafter. 

3. Proposal To Amend § 192.605—O&M 

Manuals—Overpressurization 

In this NPRM, PHMSA proposes to 

amend § 192.605 to require that 

operators of gas distribution pipelines 

establish procedures for responding to, 

investigating, and correcting the cause 

of overpressurization indications as 

soon as practicable. This will include 

specific actions to take and an order of 

operations for immediately reducing 

pressure in portions of the gas 

distribution system affected by the 

overpressurization, shutting down that 

portion, or taking other actions as 

necessary. 

A timely response to an 

overpressurization event will require 

operators to promptly recognize 

overpressurization indications. Operator 

procedures would need to document 

potential overpressurization indications 

based on the design and operating 

characteristics of their systems. For 

example, a common indication of an 

overpressure condition would be an 

increase in pressure or flow rate outside 

of normal operating limits—but 

precisely how much a pressure change 

outside normal conditions would 

exceed MAOP will depend on the 

characteristics of that system. 

PHMSA also proposes to require that 

an operator’s procedures must 

document specific actions and the 

sequence of events various personnel 

must follow in response to an 

overpressurization indication. Those 

procedures should contain clear 

statements of authority for relevant 

operator personnel to undertake 

particular actions both on initial receipt 

of notification of an overpressurization 

indication and subsequent confirmation 

that an overpressurization condition 

exists or is imminent.135 An example 

would include the actions a controller 

in the monitoring center (i.e., SCADA 

system) would take and the protocols to 

follow when in receipt of a pressure 

alarm indicating an overpressurization. 

Similarly, field personnel may witness 

overpressurization indications such as 

fires, explosions, control lines damage 

during excavation, instrumentation or 

valve failures, or the activation of safety 

valves. Operators must develop 

procedures for those personnel to 

recognize the signs of an 

overpressurization as well as identify 

the steps they should take in response 

(such as applying a stop-work authority, 

reducing the pressure, isolating portions 

of the gas distribution system, and 

notifying emergency responders). The 

operator must also provide training on 

these procedures to ensure that 

personnel—including field personnel 

and construction workers—are able to 

recognize the indications of an 

overpressurization and respond 

appropriately.136

Operators must also develop and 

document procedures for, as soon as 

practicable, investigating and correcting 

the cause of an overpressurization or an 

overpressurization indication. While the 

amendments proposed throughout this 

NPRM, if adopted, are expected to 

prevent or reduce the frequency of 

future overpressurizations, they may 

still occur. If an operator experiences an 

overpressurization or any indication 

that an overpressurization could occur, 

PHMSA proposes to require operators to 

investigate and correct the cause(s) of 

the overpressurization or 

overpressurization indication. During 

their investigation, operators could find 

a mode of failure common to other parts 

of their systems and take action to 

prevent or mitigate a potential 

overpressurization, such as promptly 

repairing or replacing parts of the 

system. 

PHMSA proposes the requirements 

described above to ensure operators 

have clear direction as to what 

procedures are necessary to prevent 

catastrophic overpressurizations similar 

to that of the Merrimack Valley incident 

and to improve the safety of gas 

distribution systems generally. PHMSA 

also expects this proposed amendment 

of subpart L requiring distribution 

operators to update O&M manuals to 

address overpressure scenarios would 

reinforce the updates to DIMP plans 

proposed elsewhere in this NPRM. 

PHMSA expects that this amendment 

would improve pipeline safety by 

bringing additional awareness to gas 

distribution pipeline operators and 

personnel regarding overpressurization 

indications. This amendment would 

also ensure operators establish 

procedures for monitoring and 

controlling gas pressure should they 

detect an indication of an 

overpressurization. PHMSA further 

proposes to respond to the risk of 

overpressurization in an operator’s O&M 

manuals through adopting an MOC 

process, as discussed below. 

PHMSA understands these proposed 

requirements for enhancements of gas 

distribution operators’ O&M manuals to 

address a well-understood threat to 

pipeline integrity would be reasonable, 

technically feasible, cost-effective, and 

practicable for gas distribution 

operators. PHMSA expects that some 

gas distribution operators may already 

be complying with these requirements 

either voluntarily (e.g., in response to 

the Merrimack Valley incident), as a 

result of similar requirements imposed 


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Federal Register / Vol. 88, No. 172 / Thursday, September 7, 2023 / Proposed Rules 61779 

137Am. Soc’y of Mech. Eng’s, ANSI B31.8S–2004, 

‘‘Managing System Integrity of Gas Pipelines’’ (Jan. 

14, 2005). 

138NTSB/PAR–19/02 at 16. 

139NTSB/PAR–19/02 at 51. 

140PHMSA has not included its proposed MOC 

requirements for distribution pipeline operators 

within integrity management regulations at 49 CFR 

part 192, subpart P (as it did for gas transmission 

pipelines within subpart O) because 49 U.S.C. 

Continued 

by State pipeline safety regulators, or 

pursuant to their DIMPs. PHMSA 

further notes that its proposed 

enhancements of baseline expectations 

for O&M manual contents are precisely 

the sort of minimal actions a reasonably 

prudent operator of gas distribution 

pipeline facility would adopt in 

ordinary course to protect public safety 

given that their systems transport 

pressurized (natural, flammable, toxic, 

or corrosive) gasses typically within or 

in close proximity to population 

centers. Viewed against those 

considerations and the compliance costs 

estimated in the PRIA, PHMSA expects 

its proposed amendments will be a costeffective approach to achieving the 

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 

O&M manuals (and manage any related 

compliance costs). 

E. Operations and Maintenance 

Manuals (Section 192.605)— 

Management of Change 

1. Current Requirements—O&M 

Manuals—Management of Change 

(MOC) 

There are no current requirements in 

the pipeline safety regulations for 

operators of gas distribution pipelines to 

follow management of change (or MOC) 

processes in their operations and 

maintenance activity. While not 

specifically an MOC process, the 

operator qualification provisions in 

§ 192.805(f) require that changes that 

affect covered tasks be communicated to 

individuals performing these tasks. As 

such, operators may have in place some 

type of process for reviewing changes, 

including whether such changes will 

impact O&M procedures and those 

performing the procedures. Further, gas 

transmission pipelines located in a high 

consequence area have an MOC 

requirement in § 192.911(k), which 

adopts an MOC process outlined in the 

American Society of Mechanical 

Engineers/American National Standards 

Institute (ASME/ANSI) standard B31.8S, 

section 11.137 The 192.911(k) 

requirement, however, applies only to 

operators of gas transmission pipelines 

subject to subpart O integrity 

management requirements (i.e., highconsequence areas, which are not 

applicable to gas distribution pipelines). 

2. Need for Change—O&M Manuals— 

MOC 

Inadequately reviewed or documented 

design, construction, maintenance, or 

operational changes can seriously 

impact pipeline integrity. MOC 

procedures are designed to prevent such 

impacts. In the Merrimack Valley 

incident, NTSB investigators discovered 

omissions in CMA’s engineering work 

package and construction 

documentation for the South Union 

Street project and that the work package 

was completed without a proper 

constructability review. NTSB 

investigators reviewed the engineering 

plans that CMA used during the 

construction work and found that the 

CMA engineers did not document the 

location of regulator control lines.138

Had CMA accurately documented the 

regulator control lines, engineers and 

work crews would have been able to 

relocate them prior to abandoning the 

pipeline main. 

CMA did not employ MOC processes 

for its maintenance and construction 

operations. Instead, CMA’s engineering 

department relied on simple checklists 

in its workflow documentation. The 

NTSB determined that if NiSource had 

adequately employed a MOC process, it 

could have identified potential risk of 

overpressurization of its system from a 

common mode of failure as a result of 

the South Union Street project 

construction activity and employed 

control measures to prevent or mitigate 

the Merrimack Valley incident. As a 

result, the NTSB recommended in P– 

18–8 that NiSource apply an MOC 

process to all changes to adequately 

identify system threats that could result 

in a common mode of failure.139

NTSB also stated that CMA did not 

identify the omission of regulator 

control lines from its engineering work 

package during its constructability 

review of that documentation. 

Constructability reviews—an element of 

MOC processes—are recognized and 

accepted as a necessary engineering 

practice for the execution of 

construction services. If properly 

implemented, constructability reviews 

provide structured reviews of 

construction plans and specifications to 

ensure functionality, sustainability, and 

safety, thus reducing the potential for 

shortcomings, omissions, inefficiencies, 

conflicts, or errors. The NTSB 

concluded that the CMA 

constructability review process was not 

sufficiently robust to detect the 

omission of a work order to relocate the 

sensing lines. The NTSB identified that 

part of the failure of the process was 

likely due to the absence of a review by 

a critical department (CMA’s 

measurement and regulation or M&R 

department). Despite there being at least 

two constructability reviews for the 

South Union Street project, the M&R 

department did not participate. The 

NTSB stated that a comprehensive 

constructability review, which would 

require all pertinent departments to 

review each project, along with the 

endorsement by a professional engineer 

(PE), would likely have identified the 

omission of the regulator control lines, 

thereby preventing the error that led to 

the Merrimack Valley incident. As a 

result of its investigation, the NTSB 

recommended that NiSource revise its 

constructability review process to 

ensure that all pertinent departments 

review construction documents for 

accuracy and completeness, and that the 

documents or plans be endorsed by a PE 

prior to commencing work. 

Subsequent to the 2018 Merrimack 

Valley incident, PHMSA was required 

by statute to update its regulations to 

require gas distribution operators to 

include in their O&M manuals an MOC 

process which must apply to 

‘‘significant technology, equipment, 

procedural, and organizational changes 

to the distribution system[.]’’ (49 U.S.C. 

60102(s)(2)). This provision also 

requires that operators ‘‘ensure that 

relevant qualified personnel, such as an 

engineer with a professional engineer 

licensure, subject matter expert, or other 

employee who possesses the necessary 

knowledge, experience, and skills 

regarding natural gas distribution 

systems, review and certify construction 

plans for accuracy, completeness, and 

correctness.’’ In addition, 49 U.S.C. 

60108 requires gas distribution 

operators to make their updated O&M 

manuals available to PHMSA or the 

relevant State regulatory agency within 

2 years after the final rule is issued in 

this proceeding and every 5 years 

thereafter. 

3. Proposal To Amend § 192.605 To 

Require an MOC Process 

Pursuant to 49 U.S.C. 60102(s), 

PHMSA proposes to require that gas 

distribution operators update their O&M 

manuals to include a detailed MOC 

process.140 Under this proposal, 


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61780 Federal Register / Vol. 88, No. 172 / Thursday, September 7, 2023 / Proposed Rules 

60102(s) explicitly required update of regulations 

governing ‘‘procedural manuals for operations, 

maintenance, and emergencies’’—located at 

§ 192.605. 

141 ‘‘Qualified’’ under § 192.803 means that an 

individual has been evaluated pursuant to the 

requirements of Subpart N and can perform 

assigned covered tasks and recognize and react to 

abnormal operating conditions. 142NTSB/PAR–19/02 at 50. 

143ASME/ANSI, B31.8S–2004, ‘‘Managing 

System Integrity of Gas Pipelines, Supplement to 

B31.8’’ (Jan. 14, 2005) (incorporated by reference 

under § 192.7). 

operators would be required to apply an 

MOC process to technology, equipment, 

procedural, and organizational changes 

that may impact the integrity or safety 

of the gas distribution system. 

Specifically, operators must apply an 

MOC process to changes to their 

pipeline systems, organization, and 

O&M procedures in connection with the 

(1) installation, modification, or 

replacement of, or upgrades to, 

regulators, pressure monitoring 

locations, or overpressure protection 

devices; (2) modifications to alarm set 

points or upper/lower trigger limits on 

monitoring equipment; (3) introduction 

of new technologies for overpressure 

protection into the system; (4) revisions, 

changes to, or introduction of new 

standard operating procedures for 

design, construction, installation, 

maintenance, and emergency response; 

and (5) other changes that may impact 

the integrity or safety of the gas 

distribution system. PHMSA notes that 

although most of the occasions for 

changes to operator pipelines and 

procedures listed above are directed 

toward reducing the potential for 

overpressurization, it expects that MOC 

processes will also help reduce the risk 

of other incidents on gas distribution 

pipelines. Towards that end, PHMSA 

proposes savings language (‘‘other 

changes that may impact the integrity or 

safety of the gas distribution systems’’) 

that would require operators to employ 

a MOC process in connection with 

changes to their systems and procedures 

in connection with high-risk activities. 

PHMSA also proposes to require that 

the MOC process must ensure that 

qualified personnel review and certify 

construction plans associated with 

installations, modifications, 

replacements, or upgrades for accuracy 

and completeness before the work 

begins. These personnel must be 

qualified to perform these tasks under 

subpart N of 49 CFR part 192.141

Qualified personnel could include an 

engineer with a professional engineer 

(PE) license, a subject matter expert, or 

any other employee who possesses the 

necessary knowledge, experience, and 

skills regarding gas distribution systems. 

This proposal would ensure that 

personnel who work on planning 

construction projects have the 

appropriate qualifications and training 

necessary to ensure these tasks are 

performed safely. 

In developing this proposed 

requirement, PHMSA reviewed NTSB 

recommendation P–19–16, which called 

on states to require that all future gas 

infrastructure projects require licensed 

PE approval and stamping.142 This 

NPRM in no way prohibits states from 

applying a higher standard than that 

provided in the Federal regulations. 

Additionally, PHMSA acknowledges 

that a PE could provide the best 

assurance of high-quality review of 

construction plans. PHMSA is uncertain 

as to the availability of those personnel 

resources in all states or for all gas 

distribution operators, however, and 

any shortage of licensed PEs could 

cause delays in the construction or 

remediation of integrity issues. Other 

qualified professionals, such as 

experienced engineers or subject matter 

experts, may have an equivalent level of 

experience or skills without holding the 

licensure. PHMSA is proposing this 

amendment pursuant to 49 U.S.C. 

60102(s), which contemplates a larger 

pool of personnel qualified to perform 

these reviews and certifications than 

just licensed PEs. Nevertheless, PHMSA 

expects that when operators evaluate 

construction projects, operators 

consider assigning qualified personnel 

with experience commensurate to the 

complexity of each project and its 

potential impacts on public safety and 

the environment. The most complex and 

riskiest projects should be reviewed by 

a licensed PE, if available, while less 

complex or routine construction 

projects may be suitable for review by 

qualified personnel who do not hold 

such a credential. PHMSA welcomes 

comments on the availability of PE 

licensure in various jurisdictions and 

the appropriateness of review by other, 

non-licensed qualified individuals. 

Finally, PHMSA proposes to require 

that operators’ MOC process must 

ensure that any hazards introduced by 

a change are identified, analyzed, and 

controlled before resuming operations. 

Quality originates at the planning stages 

of a pipeline project. When pipeline 

facilities are designed or modified, 

operators intend for these changes to 

provide decades of safe and reliable 

operation. But any change to a pipeline 

system can also introduce potential 

hazards. Operators can manage risks 

introduced by changes to the system 

through a robust MOC process. It is a 

standard practice in any MOC process 

or system to analyze and control for 

risks. PHMSA is proposing this general 

requirement for operators to identify 

any hazards they are introducing as the 

result of a change, to analyze those 

risks, and to control for those hazards 

and risks through preventive and 

mitigative measures. These steps are 

necessary to establish appropriate 

preventive and mitigative measures to 

reduce the likelihood and consequences 

of failure on a gas distribution system 

should an accident occur. PHMSA, 

therefore, proposes this requirement to 

ensure that operators incorporate these 

steps into their MOC process. 

PHMSA understands this proposed 

requirement for gas distribution 

operators’ O&M manuals to incorporate 

a MOC process would be reasonable, 

technically feasible cost-effective, and 

practicable. PHMSA expects that some 

gas distribution operators may already 

comply with these requirements either 

voluntarily (e.g., to minimize losses of 

commercially valuable commodities, in 

response to the Merrimack Valley 

incident and NTSB recommendations, 

or consistent with broadly applicable, 

consensus industry standards such as 

ASME/ANSI B31.8S 143), as a result of 

similar requirements imposed by State 

pipeline safety regulators, or as risk 

mitigation measures pursuant to their 

DIMPs. PHMSA further notes that the 

proposed construction plans 

certification requirement within those 

MOC procedures is consistent with 

longstanding industry best practices and 

NTSB recommendations; PHMSA’s 

proposal also affords operators 

optionality to use either their own or 

contractor personnel when 

implementing this requirement on a 

going-forward basis. Indeed, PHMSA 

submits that its proposed enhancements 

of baseline expectations for O&M 

manual contents are precisely the sort of 

minimal actions a reasonably prudent 

operator of gas distribution pipeline 

facility would adopt in ordinary course 

to protect public safety given that their 

systems transport pressurized (natural, 

flammable, toxic, or corrosive) gasses 

typically within or in close proximity to 

population centers. 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 


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Federal Register / Vol. 88, No. 172 / Thursday, September 7, 2023 / Proposed Rules 61781 

144On January 15, 2021, PHMSA issued the 

NPRM, ‘‘Periodic Updates of Regulatory References 

to Technical Standards and Miscellaneous 

Amendments,’’ which included a proposal to 

replace the incorporated by reference ASME/ANSI 

B31.8S 2004 edition to the 2016 edition. 86 FR 

3938, 3944 (Jan. 15, 2021). PHMSA reviewed both 

2004 and 2016 editions for consideration in this 

rulemaking. 

145See §§ 192.603(b), 192.605(b)(1), and subpart 

M (incorporating §§ 192.199 and 192.201). 

146NTSB/PAR–19/02 at 16–17. 

necessarily be in addition to the time 

since publication of this NPRM)—would 

provide operators ample time to 

implement requisite changes to their 

O&M manuals and identify or procure 

personnel resources needed to comply 

with the new certification requirement 

(and manage any related compliance 

costs). 

PHMSA is also requesting comments 

on whether it should promulgate the 

MOC requirement described above, 

adopt the industry standard ASME/ 

ANSI B31.8S for gas distribution 

operators, or both.144 PHMSA has 

adopted ASME/ANSI B31.8S for gas 

transmission operators subject to 49 

CFR, part 192, subpart O integrity 

management requirements. Specifically, 

PHMSA at § 192.911(k) requires 

operators of certain gas transmission 

pipelines to develop and follow an MOC 

process, as outlined in ASME/ANSI 

B31.8S, section 11, that addresses 

technical, design, physical, 

environmental, procedural, operational, 

maintenance, and organizational 

changes to the pipeline or processes, 

whether permanent or temporary. While 

provisions in section 11 of ASME/ANSI 

B31.8S outline formal elements of an 

MOC process resembling the elements 

within the regulatory text proposed in 

this NPRM, other provisions of ASME/ 

ANSI B31.8S section 11, such as (b)(1), 

are specific to changes in population 

that may be more appropriate for gas 

transmission operators required to 

identify high consequence areas (HCAs) 

along their pipeline. But the HCA 

concept does not apply to gas 

distribution operators, and as noted 

above, PHMSA expects it can capture 

the public safety and environmental 

benefits from MOC processes by 

adopting the regulatory text proposed in 

this NPRM without incorporating by 

reference ASME/ANSI B31.8S directly. 

Nevertheless, PHMSA requests 

comments on whether adoption within 

a final rule of a similar approach for gas 

distribution operators would provide 

better protection for public safety and 

the environment, and otherwise be 

technically feasible, cost-effective, and 

practicable. 

F. Gas Distribution Recordkeeping 

Practices (Section 192.638) 

1. Current Requirements— 

Recordkeeping 

Operators must collect and maintain 

records about their gas distribution 

pipelines in compliance with 

requirements of 49 CFR part 192, 

including those governing DIMPs. 

Section 192.1007(a) requires operators 

to identify reasonably available 

information necessary to develop an 

understanding of the characteristics of 

their pipelines, identify applicable 

threats, and analyze the risk associated 

with the threats. Section 192.1007(a)(3) 

requires that operators have a plan to 

collect information needed to conduct 

the risk analysis required in DIMP. 

Section 192.1007(a)(5) requires 

operators to capture and retain 

information on any new pipeline 

installed, including, at a minimum, the 

location of the pipeline and the material 

of which it is constructed. 

In addition to keeping records as part 

of complying with DIMP requirements, 

an operator must also consider the data 

it needs to comply with the various 

recordkeeping requirements in 49 CFR 

part 192, such as those for pipeline 

design, testing and construction 

(§ 192.517); corrosion control 

(§ 192.491); customer notification 

(§ 192.16); uprating (§ 192.553); 

surveying, patrolling, monitoring, 

inspections, operations, maintenance, 

and emergencies (§§ 192.603 and 

192.605); and operator qualification 

(§ 192.807). Sections 192.603(b) and 

192.605 further require that each 

operator establish a written operating 

and maintenance plan that meets the 

requirements of the pipeline safety 

regulations and keep records necessary 

to administer the plan. Sections 

192.603(b) and 192.605(e) require 

operators to maintain current records 

and maps of the location of their 

facilities for use in operations, 

maintenance, and emergency response 

activities (e.g., surveillance, leak 

surveys, cathodic protection, etc.). 

Further, § 192.605 requires that 

operators make construction records, 

maps, and the pipeline’s operating 

history available to appropriate 

operating personnel. Therefore, if an 

operator requires maps as a record to 

properly administer its O&M procedures 

consistent with Federal safety 

requirements, these maps must be 

maintained by the operator. 

Additionally, operators must keep 

records related to the design and 

installation of their pipeline 

components, including protection 

against overpressurization under 49 CFR 

part 192, subparts L and M.145 These 

records would include valve failure 

position and capacity records, which 

include information operators used 

when designing the system to ensure 

sufficient overpressure protection. 

2. Need for Change—Recordkeeping 

Maintaining accurate and reliable 

records is critical for safe operation, 

maintenance, pipeline integrity 

management, and emergency response. 

Records of the physical components on 

a gas distribution system, such as 

regulators, valves, and underground 

piping (including control lines), are 

necessary for an operator to have the 

basic knowledge of its system needed to 

maintain control of system pressure. 

Mapping of all gas systems enables 

proper planning of system upgrade 

activities, maintenance, and protection 

of the system from excavation damage. 

Knowing the location of control lines is 

critically important to preventing 

incidents on low-pressure distribution 

systems because they can be easily 

damaged during excavation activities or 

inadvertently taken out of service, as 

demonstrated by the Merrimack Valley 

incident. Further, mapping of all gas 

systems, such as documenting the 

location of shutoff valves, could 

improve the response time during an 

emergency. In the event of an incident 

or other emergency, being able to locate 

and operate valves is critical to 

achieving the effective shutdown and 

isolation of any sections of a gas 

distribution system. Incomplete, 

inaccurate, unreliable, or inaccessible 

records hinder the safe operation of a 

pipeline, reduce the effectiveness of the 

integrity assessment (as required under 

DIMP regulations), and impede timely 

emergency response. 

The 2018 Merrimack Valley incident 

illustrated how incomplete records of 

gas distribution systems can lead to or 

exacerbate safety issues. One of the 

issues identified in the NTSB’s report 

was that the engineers responsible for 

developing CMA’s construction plan 

did not have all the records necessary to 

plan the construction project correctly, 

such as control line drawings and 

location information. Further, the CMA 

engineers knew that even if they had 

access to the records regarding the 

location of the control lines, the records 

CMA maintained were often outdated, 

and thus potentially inaccurate and 

incomplete.146 For example, for the 

Winthrop regulator station, the records 

had the location of the control lines as 


ddrumheller on DSK120RN23PROD with PROPOSALS3
61782 Federal Register / Vol. 88, No. 172 / Thursday, September 7, 2023 / Proposed Rules 

147As discussed elsewhere in the preamble, 

PHMSA also proposes to introduce a crossreference to this new § 192.638 within its existing 

DIMP plan knowledge management requirements at 

§ 192.1007(a)(3). 

148 ‘‘Pipeline Safety: Safety of Gas Transmission 

Pipelines: MAOP Reconfirmation, Expansion of 

Assessment Requirements, and Other Related 

Amendments,’’ 84 FR 52180 (Oct. 1, 2019). 

149Compare 192.607 (requiring ‘‘traceable, 

verifiable, and complete records’’ of certain material 

properties and attributes) and 192.624 (requiring 

‘‘traceable, verifiable, and complete records’’ for 

MAOP confirmation) with 49 U.S.C. 60102(t) 

(requiring gas distribution operators identify and 

manage ‘‘traceable, reliable, and complete records 

. . . critical to ensuring proper pressure controls for 

a gas distribution system . . . .’’). 

they existed around May 2010; however, 

CMA installed a new control line 

around September 2015 and never 

updated its records to reflect the change. 

Without access to accurate maps and 

drawings of the system, CMA did not 

include control line maps or procedures 

for handling control line removal in the 

construction plan. CMA then passed 

along an inaccurate and incomplete 

construction plan to the contractor 

doing the work. As a result, NTSB 

recommended that NiSource review and 

ensure that all records and 

documentation of its natural gas systems 

are traceable, reliable, and complete. 

The Merrimack Valley incident 

further illustrated how the lack of 

accurate maps of pipeline systems can 

inhibit effective emergency response. 

During the emergency response to the 

overpressurization, the operator took too 

long to provide maps of the lowpressure system to emergency response 

officials, who needed street maps 

showing the layout of the natural gas 

distribution system to understand where 

the affected customers were located. 

CMA did not provide the information 

requested until hours after the 

overpressurization began. The 

emergency responders emphasized to 

the NTSB that the absence of this 

information impeded their emergency 

response and public safety decisionmaking. Without maps of the lowpressure system, the ICs managing 

emergency response had to evacuate 

thousands of people from their homes, 

including people in unaffected areas, 

out of an abundance of caution. 

Subsequent to the 2018 Merrimack 

Valley incident, 49 U.S.C. 60102 was 

amended to ensure that operators keep 

better, more complete records (such as 

maps that include the location of 

control lines and other critical 

infrastructure) and make those available 

to the emergency responders and public 

officials who need them. Specifically, 

49 U.S.C. 60102(t)(1) directs PHMSA 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 other records needed for risk 

analysis. Operators must update their 

records ‘‘on an opportunistic basis.’’ 

These records must be accessible to all 

personnel responsible for performing or 

overseeing relevant construction or 

engineering work. Pursuant to 49 U.S.C. 

60102(t)(1), PHMSA proposes to amend 

its regulations to supplement existing 

requirements pertaining to gas 

distribution operators’ recordkeeping 

critical to pressure control on their 

systems. The proposal would require 

operators to collect or generate 

complete, reliable, and accurate records 

if they are not available, and make the 

records accessible to the personnel who 

need them. 

3. Proposal To Add a New § 192.638— 

Records: Distribution System Pressure 

Controls 

PHMSA proposes a new § 192.638 to 

specify that an operator of a gas 

distribution system must identify and 

maintain traceable, verifiable, and 

complete records documenting the 

characteristics of the pipeline critical to 

ensuring proper pressure controls.147

In 2019, PHMSA introduced a 

regulatory amendment requiring gas 

transmission records pertaining to 

MAOP to be ‘‘traceable, verifiable, and 

complete.’’ 148 49 U.S.C. 60102(t)(1) 

similarly requires PHMSA to require 

operators to identify and manage 

‘‘traceable, reliable, and complete’’ 

records. PHMSA understands that the 

phrase ‘‘traceable, reliable, and 

complete,’’ as used in 49 U.S.C. 

60102(t)(1) is substantively the same 

standard with respect to the quality and 

accessibility of records maintained as 

the ‘‘traceable, verifiable, and complete’’ 

language adopted in the 2019 final rule 

for gas transmission pipelines.149

PHMSA interprets ‘‘reliable’’ as used in 

49 U.S.C. 60102(t)(1) to mean the same 

as ‘‘verifiable’’ as used in the 2019 rule 

because both verifiable and reliable 

would mean to prove that a record is 

trustworthy and authentic. A record is 

considered reliable if it is verifiable and 

vice versa. PHMSA’s proposed 

§ 192.638 recordkeeping requirement is 

intended to encompass any records 

essential to pressure control on a system 

and not just pertain to MAOP or 

material property and attribute 

verification activities. PHMSA would 

require operators to identify what 

records they currently have that 

document the characteristics of the 

pipeline that are ‘‘critical to ensuring 

proper pressure controls’’ for the 

system. 

In § 192.638(a), PHMSA identifies the 

types of records that it proposes are 

critical to ensuring proper pressure 

control for a gas distribution system. 

These records include: (1) current 

location information (including maps 

and schematics) for regulators, valves, 

and underground piping (including 

control lines); (2) attributes of the 

regulator(s), such as set points, design 

capacity, and the valve failure position 

(open/closed); (3) the overpressure 

protection configuration; and (4) other 

records deemed critical by the operator. 

Regarding item (1), operators 

generally keep records, such as maps 

and schematics, when designing their 

system and district regulator stations. 

Operators should also have records of 

selected regulators, valves, and other gas 

pressure control equipment based on 

several factors, for the purpose of 

determining, for example, the overall 

capacity and future flow requirements 

of the system. 

Regarding item (2), records related to 

the attributes of the regulators’ set 

points, design capacity, and valve 

failure position are necessary to ensure 

that the design of the district regulator 

station can protect the distribution 

system from overpressurization. For 

example, demands on the system may 

change over time due to customer usage, 

weather, or maintenance requirements. 

Operators can use design capacity 

records to validate and revalidate that 

their systems are capable of meeting 

changing customer demands and 

weather dynamics. 

Regarding item (3), maintaining 

records for the overpressure protection 

configuration are necessary for the safe 

operation of the pipeline and for 

performing a robust risk analysis 

required under DIMP regulations. As 

demonstrated by the 2018 Merrimack 

Valley incident, certain overpressure 

protection configurations on lowpressure distribution systems (i.e., 

redundant worker-monitor regulators) 

alone are inadequate for preventing an 

overpressurization. Requiring operators 

to keep records of their systems’ 

overpressure configurations will ensure 

that operators will be able to identify 

any higher-risk configurations in their 

systems. Once identified, operators can 

properly assess the overall risk to their 

systems and take preventive or 

mitigative actions to reduce the 

likelihood or consequences of a 

potential failure. 

Regarding item (4), PHMSA proposes 

that operators must have traceable, 

verifiable, and complete records for any 

records they deem critical but that were 


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150ASME/ANSI, B31.8S–2004, ‘‘Managing 

System Integrity of Gas Pipelines, Supplement to 

B31.8’’ (Jan. 14, 2005) (incorporated by reference 

under § 192.7). 

not mentioned in the list provided by 

PHMSA. This general requirement 

would ensure that operators keep 

records based on the unique 

characteristics of their system. 

When taking inventory of the records 

described above, operators must identify 

if those records are traceable (e.g., can 

be clearly linked to original information 

about, or changes to, a pipeline segment, 

facility, or district regulator station), 

verifiable (e.g., their information is 

confirmed by other complementary but 

separate documentation), and complete 

(e.g., as evidenced by a signature, date, 

or other appropriate marking such as a 

corporate stamp or seal). This 

amendment would improve the 

completeness and accuracy of the 

records needed during normal 

operations, emergency response 

activities, and risk analyses. 

In § 192.638(b), PHMSA proposes to 

require that if an operator does not yet 

have traceable, verifiable, and complete 

records, then the operator must develop 

a plan for collecting those records. 

PHMSA also proposes to revise 

§ 192.605 to ensure that operators have 

procedures for implementing the new 

recordkeeping requirements proposed in 

§ 192.638. Because the availability and 

form of records, as well as records 

retention practices, will vary among 

operators, PHMSA proposes that 

operators must identify what records 

they need to collect under this 

requirement. 

In § 192.638(c), PHMSA proposes that 

operators must collect records needed to 

meet this standard on an opportunistic 

basis, which is defined as occurring 

during normal operations conducted on 

the pipeline including (but not limited 

to) design, construction, operations, or 

maintenance activities. PHMSA notes 

that its proposed language in paragraph 

(c) mirrors the language at 

§ 192.1007(a)(3) governing operator 

knowledge management in connection 

with a performance of the risk analysis 

within their DIMPs. PHMSA expects 

this approach will minimize compliance 

burdens on operators, as they would be 

able to collect or generate records 

through existing regulatory mechanisms 

such as DIMPs or annual inspections. 

PHMSA also proposes to revise 

§ 192.1007(a)(3) so that it references 

§ 192.638(c). This would require 

operators to identify records specified in 

§ 192.638(c) that they could collect as 

part of their DIMP plan. 

In § 192.638(d), PHMSA proposes to 

require that operators ensure the records 

required in this section are accessible to 

personnel performing or overseeing 

design, construction, operations, and 

maintenance activities. In the 2018 

Merrimack Valley incident, the 

engineering staff did not have access to 

the maps containing control line 

information and were unaware if the 

department had access to such records. 

This lack of access and awareness 

resulted in the omission of critical 

information that should have been 

considered through a proper risk 

analysis under their DIMPs. Therefore, 

PHMSA proposes to add a requirement 

for operators to provide the personnel 

responsible for planning and performing 

work on critical infrastructure with the 

records they need to perform their work 

safely and effectively. Operators should 

note that access would extend to the 

qualified employees monitoring the gas 

pressure (as proposed in § 192.640). 

PHMSA expects that during a 

construction activity, these qualified 

personnel may need records such as 

maps of control lines to effectively 

monitor the safety of excavation 

activities around gas distribution 

systems. 

In § 192.638(e), PHMSA proposes to 

require that once a record is generated 

or collected under this section, that 

operators must keep the record for the 

life of the pipeline. This will help 

facilitate traceability of records as 

required by 49 U.S.C. 60102(t). 

In § 192.638(f), PHMSA specifies that 

the requirements in this section would 

not apply to master meter systems, 

liquefied petroleum gas (LPG) 

distribution pipeline systems that serve 

fewer than 100 customers from a single 

source, or any individual service line 

directly connected to a transmission, 

gathering, or production pipeline that is 

not operated as part of a distribution 

system. As discussed above, small LPG 

operators are relatively simple, low-risk 

systems affecting a finite (generally 

small) number of customers such that 

the public safety and environmental 

benefits from imposing new 

requirements on these systems would be 

limited. Similar reasoning applies to 

master meter systems. PHMSA 

understands that compliance costs 

generally are felt more acutely by small 

LPG operators and master meter system 

operators. PHMSA does not expect that 

these operators would have the means 

(e.g., access to detailed maps and GIS 

tools) to be able to comply with the 

recordkeeping requirements proposed in 

this NPRM. For individual service lines, 

the consequences of an 

overpressurization are smaller relative 

to a district regulator station. Given the 

relatively low public safety and 

environmental benefits from extending 

the new § 192.638 recordkeeping 

requirements to those operators, 

PHMSA proposes to except those 

systems from the new recordkeeping 

requirement at § 192.638. Nevertheless, 

PHMSA does encourage these excepted 

operators to, where applicable, follow 

the recordkeeping specifications 

proposed in this NPRM. 

Overall, PHMSA expects that its 

proposed new § 192.638 would ensure 

that operators are documenting and 

maintaining records of how their critical 

pressure controlling facilities operate so 

that they can review and assess their 

performance over time. Keeping 

complete and accurate records for the 

life of these assets could help improve 

operators’ risk analyses, as required by 

DIMP regulations, and thus improve the 

overall integrity of gas distribution 

pipelines. 

PHMSA also understands this 

proposed requirement for gas 

distribution operators to identify and 

maintain traceable, accurate, and 

complete records documenting system 

characteristics pertinent to pressure 

control would be reasonable, technically 

feasible, cost-effective, and practicable. 

As explained above, the proposed 

requirement is analogous to material 

property documentation requirements 

elsewhere in PHMSA regulations (e.g., 

§ 192.607) for gas transmission systems. 

And PHMSA understands that some gas 

distribution operators may already 

comply with this proposed requirement 

either voluntarily (e.g., to minimize 

losses of commercially valuable 

commodities, in response to the 

Merrimack Valley incident and NTSB 

recommendations, or consistent with 

broadly applicable, consensus industry 

standards such as ASME/ANSI 

B31.8S 150), as a result of similar 

requirements imposed by State pipeline 

safety regulators, or as risk mitigation 

measures pursuant to their DIMPs. 

Indeed, the sort of records subject to this 

proposed requirement are precisely the 

sort of records that a reasonably prudent 

operator of gas distribution pipeline 

facility would in ordinary course 

already have identified and be 

maintaining to protect the public given 

that their systems transport pressurized 

(natural, flammable, toxic, or corrosive) 

gasses typically within or in close 

proximity to population centers. 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 


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151NTSB, Safety Recommendation Report PSR– 

18–02, ‘‘Natural Gas Distribution System Project 

Development and Review (Urgent)’’ at 6 (Nov. 24, 

2018), https://www.ntsb.gov/investigations/ 

AccidentReports/Reports/PSR1802.pdf. 

152This exception will be reflected by addition of 

new paragraph (d). 

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 review 

and compile pertinent existing records 

and develop and implement procedures 

to generate or obtain missing records on 

a going-forward basis (and manage any 

related compliance costs). 

G. Distribution Pipelines: Presence of 

Qualified Personnel (Sections 192.640 

and 192.605) 

1. Current Requirements—Procedures 

for Qualified Personnel Monitoring Gas 

Pressure 

Currently, PHMSA does not require 

operators to have procedures for 

monitoring gas pressure with qualified 

persons and equipment capable of 

ensuring pressure control and having 

the ability to shut off the flow of gas. 

There are other provisions related to 

personnel qualification included in 49 

CFR part 192, subpart N, which contain 

requirements for operators of gas 

pipelines to develop a qualification 

program to qualify employees for certain 

covered tasks. Covered tasks include 

those activities that affect the operation 

or integrity of the pipeline. PHMSA 

defines ‘‘Qualified’’ in § 192.803 to 

mean that ‘‘an individual has been 

evaluated and can: (a) [p]erform 

assigned covered tasks; and (b) 

[r]ecognize and react to abnormal 

operating conditions.’’ 

2. Need for Change—Distribution 

Pipelines: Presence of Qualified 

Personnel 

Gas pipelines are often monitored in 

a control room by controllers using 

computer-based equipment, such as a 

SCADA system, that records and 

displays operational information about 

the pipeline system, such as pressures, 

flow rates, and valve positions. Some 

SCADA systems are used by controllers 

to operate pipeline equipment remotely 

or automatically; in other cases, 

controllers may dispatch other 

personnel to operate equipment in the 

field. For those operators whose systems 

are not capable of remote or automatic 

shut down or pressure control, control 

room operators may have to respond to 

overpressure indications by 

communicating to field personnel to go 

to the location of the suspected event, 

gather additional information to 

determine if there is an emergency, and 

initiate response actions, if needed. This 

process creates delays in identifying and 

responding to overpressurization 

indications on gas distribution systems. 

During the Merrimack Valley 

incident, the SCADA controller 

responded to a high-pressure alarm by 

contacting the field technician who 

could adjust the flow of gas at the 

Winthrop regulator station. CMA’s 

system had remote pressure monitoring 

but no remote or automatic shutoff. It 

took 30 minutes from the time CMA’s 

SCADA controller noticed an alarm to 

the time when the field technician 

began to adjust the flow of gas. NTSB 

investigators learned that, at one time, 

CMA required that a technician monitor 

any gas main revision work that 

required depressurizing the main.151 Per 

those historical procedures, the 

technician would use a gauge to monitor 

the pressure readings on the impacted 

main and would communicate directly 

with the crew performing the work. If a 

pressure anomaly occurred, the 

technician could quickly act to prevent 

an overpressurization event. CMA 

offered no explanation to the NTSB as 

to why this procedure was phased out. 

As a result of the incident, the NTSB 

recommended in P–18–9 that NiSource, 

Inc., develop and implement control 

procedures during modifications to gas 

distribution mains to mitigate the risks 

identified during MOC operations, and 

stated that gas main pressures should be 

continually monitored during these 

modifications and that assets should be 

placed at critical locations to 

immediately shut down the system if 

abnormal operations are detected. 

PHMSA agrees with NTSB’s 

recommendation and concludes that 

requiring these procedures could benefit 

safety for all gas distribution operators. 

Further, PHMSA believes that operators 

can mitigate the consequences of the 

overpressurization by requiring 

qualified personnel capable of shutting 

off the gas to monitor the gas pressure 

during construction associated with 

installations, modifications, 

replacements, or upgrades on gas 

distribution mains that could result in 

overpressurization. 

Subsequent to the 2018 Merrimack 

Valley incident, PHMSA was directed to 

issue regulations requiring qualified 

personnel of a gas distribution system 

operator, with the ability to ensure 

proper pressure control and shut off, or 

limit gas pressure should 

overpressurization occur, monitor gas 

pressure at district regulator stations 

during certain times. (49 U.S.C. 

60102(t)(2)). The mandate specifies that 

those times are during any construction 

project that has the potential to cause an 

overpressurization, including projects 

such as tie-ins or abandonment of 

distribution mains. These requirements 

do not apply if a district regulator 

station has a monitoring system and the 

capability of remote or automatic 

shutoff. Further, amendments to 49 

U.S.C. 60108 now require gas 

distribution operators to make their 

updated O&M manuals available to 

PHMSA or the relevant State regulatory 

agency within 2 years after any final 

rule is issued and every 5 years 

thereafter. 

3. Proposal To Add a New § 192.640 

Distribution Pipelines: Presence of 

Qualified Personnel 

In a new § 192.640, PHMSA proposes 

an additional layer of safety at district 

regulator stations during construction 

projects by requiring qualified 

personnel to be present, monitor the gas 

pressure, and have the capability to shut 

off the flow of gas during an 

overpressurization event. This 

provision, including each of the below 

proposed parts, would not apply if an 

operator already has equipped that 

district regulator station with a remote 

pressure monitoring system that has the 

capability for remote or automatic 

shutoff.152

In paragraph (a), PHMSA proposes 

that operators of a distribution system 

must conduct an evaluation of planned 

and future installation, modification, or 

replacement of, or upgrade construction 

projects and identify any potential for 

an overpressurization to occur at a 

district regulator station. Operators must 

perform this evaluation before 

performing activities that could result in 

an overpressurization. PHMSA 

recognizes that not every construction 

project performed on a gas distribution 

system has the same risk profile and not 

all would require on-site gas monitoring 

by a qualified employee. However, the 

pre-construction evaluation must occur 

regardless to assess the probability of an 

overpressurization. Some construction 

projects clearly entail a potential for 

overpressurization, such as tie-ins and 

abandonment of distribution pipelines 

and mains, because work is done while 

part of the gas system remains active. 

Similarly, the consequences of 

overpressurization during construction 

projects may increase when that work is 

on low-pressure gas distribution 

systems where customers do not have 


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secondary pressure regulation at their 

individual meter. 

In paragraph (b), PHMSA proposes 

that once the evaluation is complete, if 

an operator has determined that a 

construction project activity presents a 

potential for overpressurization, then 

the operator must ensure that at least 

one qualified employee or contractor 

with the capability to shut off the flow 

of gas is present at that district regulator 

station to monitor the gas pressure 

during the construction project activity. 

This will result in safer construction 

activities on gas distribution pipelines 

by requiring operators to ensure that 

resources have been deployed to 

effectively mitigate risks the operator 

had determined exist. 

Under this proposal, the employee or 

contractor must be qualified to monitor 

the gas pressure in accordance with 49 

CFR, part 192, subpart N. Subpart N 

already requires that operators ensure 

on-site personnel, such as maintenance 

crew members and inspectors, are 

qualified by training and experience to 

perform covered tasks. Further, subpart 

N requires that operators qualify these 

individuals to ensure that covered tasks 

are conducted in a safe, reliable manner 

in compliance with regulatory 

standards. In complying with this new 

proposal, operators would need to 

qualify employees and contractors 

responsible for monitoring the gas 

pressure during construction to perform 

various tasks, such as reading and 

understanding gas monitoring 

equipment; responding to abnormal 

operating conditions (see § 192.805), 

including overpressurization 

indications; shutting off or reducing the 

pressure to the system; implementing 

any stop-work authority granted by the 

operator; and notifying appropriate 

emergency response personnel should 

an incident occur. They should also be 

qualified on the relevant proposed new 

O&M requirements discussed in 

subsection IV.D and E. 

In paragraph (c), PHMSA proposes to 

require that, when monitoring the 

system as described in this section, the 

qualified personnel should be provided, 

at a minimum, information regarding 

the location of all valves necessary for 

isolating the pipeline system and 

pressure control records (see § 192.638). 

Providing access to this information 

could be essential to an employee or 

contractor performing their gas 

monitoring responsibilities effectively 

and help shorten the response time to 

emergency indications. For example, a 

qualified employee responsible for 

monitoring the gas pressure may need to 

access valves on the system so that they 

can shut off the flow of gas, isolate the 

pipeline system, or otherwise mitigate 

the consequences of an incident. 

Similarly, a qualified employee 

responsible for monitoring the gas 

pressure may need to have more 

extensive maps of the entire gas system 

to identify an affected area and detailed 

information—such as a specific 

regulator’s set point—to determine if a 

system is operating abnormally. The 

records proposed in § 192.638 would 

provide this information and must be 

accessible to qualified personnel who 

monitor gas pressure. 

Further, under paragraph (c), PHMSA 

proposes that operators must also 

ensure that qualified employees 

monitoring the gas pressure have 

information regarding emergency 

response procedures. PHMSA expects 

such information would include the 

contact information of the appropriate 

emergency response personnel. Should 

field personnel recognize an emergency 

condition, it is critical for those 

personnel to have updated emergency 

contacts and to know what to do and 

how to respond in an emergency. 

PHMSA expects operators would 

already have general emergency contact 

information in an emergency response 

plan under § 192.615; however, given 

that these qualified personnel may be 

the first to witness overpressurization 

indications, PHMSA believes it is 

essential they have immediate access to 

this information on site during their 

activities. 

Some operators may already provide 

qualified employees with ‘‘stop-work 

authority’’ to halt work that does not 

conform to specifications or if they 

observe unsafe activities on the job site. 

Although this authority is not required 

to be given to all qualified employees 

under proposed § 192.640, it is 

recommended. Where operators have 

granted this authority to these qualified 

personnel monitoring the gas pressure, 

operators should ensure these 

employees are trained to recognize 

unsafe, abnormal conditions that are 

consistent with an overpressurization. 

Overall, the proposals in § 192.640 

would reduce the time to respond to an 

overpressurization by ensuring qualified 

employees are on site or at an 

alternative location, and that they are 

capable of actively monitoring the gas 

pressure during certain construction 

project activities. Should an 

overpressurization occur, these 

qualified employees would be able to 

respond (i.e., shutting off or reducing 

the flow of gas) and thereby mitigate the 

impact. Under PHMSA’s proposal, the 

qualified employees would be trained to 

recognize overpressurization indications 

and be able to respond more quickly. 

This should mitigate some of the impact 

of an overpressurization and improve 

the response time of the operator. 

PHMSA also understands that this 

proposed new requirement would be 

reasonable, technically feasible, costeffective, and practicable for gas 

distribution operators. That operators 

should evaluate construction projects on 

their systems to determine whether they 

could result in an overpressurization at 

a district regulator station and then 

ensure that personnel are present who 

can monitor pressure and prevent such 

a condition during the work is a 

common-sense, best practice within 

industry—whose value was underscored 

by the Merrick Valley incident and 

subsequent NTSB recommendation P– 

18–9. Indeed, PHMSA understands that 

some operators may already employ 

compliant maintenance and 

construction protocols in ordinary 

course. For other operators, integration 

of this new requirement within their 

procedures could be accomplished via 

supplementation rather than material 

revisions; the proposed new staffing 

requirements for construction activity 

would not require unique skills or 

equipment to which operators would 

not have access. Viewed against those 

considerations and the compliance costs 

estimated in the PRIA, PHMSA expects 

its proposed amendments will be a costeffective approach to achieving the 

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 develop 

procedures implementing this new 

regulatory requirement (and manage any 

related compliance costs). 

4. Proposal To Amend § 192.605 

Procedures for Qualified Personnel 

Monitoring Gas Pressure 

PHMSA proposes to revise § 192.605, 

by adding paragraph (b)(13), to ensure 

gas distribution operators have 

procedures for implementing the 

monitoring requirements in the 

proposed § 192.640. During construction 

projects on a gas distribution system, 

qualified personnel may need to 

perform their monitoring or shutdown 

activities in a specific sequence. Doing 

work out of sequence may result in an 

overpressurization or exacerbate an 

emergency. For this reason, it is critical 

to pipeline safety that operators have 

written procedures for personnel 

performing the construction activity 

monitoring requirements proposed in 


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153See ‘‘Pipeline Safety: Statutory Mandate to 

Update Inspection and Maintenance Plans to 

Address Eliminating Hazardous Leaks and 

Minimizing Releases of Natural Gas from Pipeline 

Facilities,’’ ADB–2021–01, 86 FR 31002 (June 10, 

2021). 

154There are a few types of monitor regulating, 

all of which operate substantially similarly as 

described herein: working monitor, series 

regulation, and relief monitoring. 

§ 192.640 to follow. This amendment 

would ensure that operators must 

provide qualified personnel with clear 

procedures for how to perform their 

responsibilities in a safe manner, and 

specifically how to monitor for 

abnormal operating conditions that 

could lead to an overpressurization. 

PHMSA also understands that this 

proposed new requirement would be 

reasonable, technically feasible, costeffective, and practicable for gas 

distribution operators. As noted above, 

many operators may already have 

compliant procedures; those operators 

lacking such procedures should be able 

to develop new procedures (or 

supplement existing procedures) with 

relatively little difficulty. Viewed 

against those considerations and the 

compliance costs estimated in the PRIA, 

PHMSA expects its proposed 

amendments are a cost-effective 

approach to achieving the 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 develop procedures 

implementing this new regulatory 

requirement (and manage any related 

compliance costs). 

H. District Regulator Stations— 

Protections Against Accidental 

Overpressurization (Sections 192.195 

and 192.741) 

1. Background—Overpressure 

Protection 

Gas distribution systems are designed 

to operate at or below an MAOP. As 

discussed earlier, a district regulator 

station is a pressure-reducing facility 

that receives gas from a high-pressure 

source (such as a transmission line) and 

delivers it to a distribution system at a 

pressure suitable for the demands on the 

system. An overpressurization occurs 

when the pressure of the system rises 

above the set point of the devices 

controlling its pressure. Pressure 

regulating and control devices (housed 

in these district regulator stations) keep 

the systems’ pressure under their MAOP 

and at or below the desired set point. 

These devices act as overpressure 

protection. Because of varying 

conditions and requirements, there are 

no standard designs for distribution 

systems or overpressure protection on 

such systems. However, among the 

common approaches to overpressure 

protection in use today are the 

following: (1) pressure relief valves, (2) 

a worker and monitor regulator system, 

and (3) automatic or remote shutoff (or 

‘‘slam-shut’’) valves. 

Pressure relief valves provide 

overpressure protection by venting 

excess gas into the atmosphere and can 

be used alone or in combination with 

other methods of overpressure 

protection. If the relief valve senses that 

the downstream pressure has exceeded 

a set point, then the relief valve 

automatically begins to open to relieve 

excess gas pressure in the system. If 

activated, the relief valve protects from 

overpressurization while allowing gas to 

flow at a safe pressure, maintaining 

normal service to customers. In general, 

the relief valve is a highly reliable 

device for overpressure protection. 

Relief valves also provide benefits with 

respect to alerting or warning operator 

personnel or the public that an 

emergency has occurred because (1) 

these devices are loud if operated at or 

near a full discharge of excess gas 

pressure, and (2) the smell of the 

odorized gas that is vented is also 

noticeable. However, pressure relief 

valves entail their own potential public 

safety harms through their release of 

gas—which can sometimes ignite—into 

the atmosphere when activated. Venting 

of gas to the atmosphere by a relief valve 

also entails environmental risks: a 

primary component of natural gas is 

methane, an ignitable, potent 

greenhouse gas. For these reasons, 

section 114 of the PIPES Act of 2020 

(codified at 49 U.S.C. 60108(a)(2)(D)(ii)) 

contains a self-executing requirement 

for operators of gas distribution 

pipelines to have a written plan to 

minimize releases of natural gas—such 

as by venting from relief valves—from 

their systems.153

A worker and monitor regulator 

system is a type of pressure control and 

overpressure protection configuration 

that involves two pressure reducing 

valves (e.g., control or pilot valves) 

installed in a series.154 One regulator 

valve controls the pressure of gas to the 

downstream system. The second 

regulator valve remains on standby with 

a slightly higher set point and only 

begins operating in the event of a 

malfunction of the first regulator or 

another failure results in pressure 

exceeding the set point of the first 

regulator. If the first, primary regulator 

(the ‘‘worker’’ regulator) cannot control 

the pressure, the second regulator (the 

‘‘monitor’’), which senses the rising 

downstream pressure, automatically 

begins to operate to maintain the 

pressure downstream at a gas pressure 

slightly higher than normal, albeit still 

within safe operation. Sometimes an 

operator will also install a small relief 

valve downstream to act as a ‘‘token 

relief’’ or an alarm to alert the operator 

that the regulator has failed. 

When working properly, a worker and 

monitor regulator system should not 

interrupt service if an 

overpressurization occurs. An advantage 

of the worker and monitor regulator 

system is that it does not result in 

venting large volumes of gas to the 

atmosphere, thereby reducing public 

safety and environmental harms. Unlike 

with pressure relief valves, the pressure 

reducing valves used in the worker and 

monitor regulator system described 

above are not self-operated; instead, 

control lines are installed in this type of 

system. Control lines (often called 

‘‘sensing’’ or ‘‘impulse’’ lines) are smalldiameter pipes that transmit the signal 

pressure from the tie-in point on the 

downstream piping line to the pressure 

regulating device. When the 

downstream pressure decreases, the 

regulator opens wider to allow more gas 

to flow. The regulator valve remains 

open until it senses an increase in 

pressure or the demand of the 

downstream pressure has been met. 

Control lines must be protected against 

breakage because the regulator will open 

wide if the control lines are cut or 

damaged because the regulator will not 

detect that the demand has been met, it 

will remain open, allowing gas to flow 

freely. This could result in full upstream 

pressure being forced into the lowpressure system, resulting in a 

catastrophic situation as seen in the 

Merrimack Valley incident. 

A third type of overpressure 

protection is automatic shutoff devices. 

In the event of an overpressurization 

indication or event, an automatic 

shutoff device completely shuts off the 

gas flow to the system until the operator 

determines the cause of the malfunction 

and resets the device. In many cases, an 

automatic shutoff device is used as a 

secondary form of overpressure 

protection. 

2. Current Requirements—Overpressure 

Protection 

Section 192.195 describes the 

minimum requirements for protection 

against accidental overpressurization. 

Section 192.195(a) requires that ‘‘each 

pipeline that is connected to a gas 


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155Except as provided in § 192.197, which only 

applies to high-pressure gas distribution systems. 

156See ‘‘Establishment of Minimum Standards,’’ 

35 FR 13248, 13264 (Aug. 19, 1970). 

157PHMSA, ‘‘Operations & Maintenance 

Enforcement Guidance Part 192 Subparts L and M’’ 

at 149 (July 21, 2017), https://www.phmsa.dot.gov/ 

sites/phmsa.dot.gov/files/docs/regulatorycompliance/pipeline/enforcement/5776/o-menforcement-guidance-part-192-7-21-2017.pdf. 

158NTSB/PAR–19/02 at 39. 159NTSB/PAR–19/02 at 39–40. 160NTSB, Accident Report PAR–82/03, ‘‘Missouri 

Power and Light Company Natural Gas Fires, 

Centralia, Missouri, January 28, 1982’’ (Aug. 24, 

1982). 

source so that the [MAOP] could be 

exceeded as the result of pressure 

control failure or of some other type of 

failure, must have pressure relieving or 

pressure limiting devices that meet the 

requirements of §§ 192.199 and 

192.201.’’ 155 Section 192.195(b) adds 

that ‘‘[e]ach distribution system that is 

supplied from a source of gas that is at 

a higher pressure than the [MAOP] for 

the system must—(1) [h]ave pressure 

regulation devices capable of meeting 

the pressure, load, and other service 

conditions that will be experienced in 

normal operation of the system, and that 

could be activated in the event of failure 

of some portion of the system; and (2) 

[b]e designed so as to prevent accidental 

overpressuring.’’ This pipeline safety 

regulation has existed in 49 CFR part 

192 since its inception.156

Section 192.199 describes the 

minimum requirements for the design of 

pressure relief and limiting devices. 

Section 192.199(g) states that ‘‘[w]here 

installed at a district regulator station to 

protect a pipeline system from 

overpressuring, [the pressure relief or 

pressure-limiting device must] be 

designed and installed to prevent any 

single incident such as an explosion in 

a vault or damage by a vehicle from 

affecting the operation of both the 

overpressure protective device and the 

district regulator[.]’’ 

Section 192.201 describes the 

minimum requirements for the required 

capacity of pressure-relieving and 

-limiting stations. Section 192.201(a)(1) 

requires that ‘‘[i]n a low-pressure 

distribution system, the pressure may 

not cause the unsafe operation of any 

connected and properly adjusted gas 

utilization equipment.’’ Section 

192.201(c) requires that ‘‘[r]elief valves 

or other pressure limiting devices must 

be installed at or near each regulator 

station in a low-pressure distribution 

system, with a capacity to limit the 

maximum pressure in the main to a 

pressure that will not exceed the safe 

operating pressure for any connected 

and properly adjusted gas utilization 

equipment.’’ Section 192.203(b)(9) adds 

that ‘‘[e]ach control line must be 

protected from anticipated causes of 

damage and must be designed and 

installed to prevent damage to any one 

control line from making both the 

regulator and the over-pressure 

protective device inoperative.’’ PHMSA 

has clarified through its enforcement 

guidance that an occurrence of 

overpressurization may be indicative of 

an equipment failure or design flaw.157

In addition, § 192.739 describes the 

minimum requirements for the 

inspection and testing of pressurelimiting and regulating stations. Section 

192.739 requires annual inspection and 

testing of each pressure limiting or 

regulating stations, including relief 

devices. The inspection and tests should 

determine that the station is: (1) in good 

mechanical condition; (2) adequate from 

the standpoint of capacity and 

reliability of operation for the service in 

which it is employed; (3) except as 

provided in § 192.739(b) applicable to 

certain steel pipelines, set to control or 

relieve at the correct pressure consistent 

with the pressure limits of § 192.201(a); 

and (4) properly installed and protected 

from dirt, liquids, or other conditions 

that might prevent proper operation. 

These requirements are intended to 

address inspection and testing of 

pressure-limiting and regulator stations 

necessary to maintain safe pressures on 

the gas distribution system. 

Section 192.741 describes minimum 

requirements for the telemetering or 

recording gauges on pressure-limiting 

and regulating stations. Section 

192.741(a) states that ‘‘[e]ach 

distribution system supplied by more 

than one district pressure regulating 

station must be equipped with 

telemetering or recording pressure 

gauges to indicate the gas pressure in 

the district.’’ Section 192.741(b) requires 

that, ‘‘[o]n distribution systems supplied 

by a single district pressure regulating 

station, the operator shall determine the 

necessity of installing telemetering or 

recording gauges in the district, taking 

into consideration the number of 

customers supplied, the operating 

pressures, the capacity of the 

installation, and other operating 

conditions.’’ 

3. Need for Change—Overpressure 

Protection 

The pipeline safety regulations 

governing overpressure protection of 

low-pressure distribution systems have 

not changed since their inception in the 

1970s. For years, low-pressure gas 

distribution systems, like CMA’s system 

in the Merrimack Valley, have relied on 

overpressure protection systems like the 

redundant worker and monitor 

regulators to regulate and control the 

pressure and flow of gas. While these 

overpressure protection methods are 

safe under normal operating conditions, 

this method of overpressure protection 

on low-pressure distribution systems 

can be too easily defeated, as recent 

events with a common mode of failure 

have demonstrated. PHMSA’s proposed 

change to regulations governing 

overpressure protection is intended to 

facilitate the operation of gas 

distribution systems to avoid 

catastrophic overpressurization. 

According to the NTSB’s report, the 

low-pressure system in Merrimack 

Valley met the requirements for 

overpressure protection contained in 

§ 192.195 (Protection Against 

Accidental Overpressuring) and 

§ 192.197 (Control of the Pressure of Gas 

Delivered from High-pressure 

Distribution Systems). ‘‘At each of the 

14 regulator stations feeding natural gas 

into [CMA’s] low-pressure system, there 

were two regulators [(i.e., a worker and 

monitor regulator system)] installed in a 

series to control the natural gas flow 

from the high-pressure [. . .] 

system.’’ 158 The worker regulator and 

the monitor regulator were set to limit 

the pressure to a maximum safe value to 

the customer. But the system 

nonetheless failed. After reviewing 

accidents investigated by the NTSB over 

the past 50 years, as well as prior 

NiSource incidents, the NTSB found 

that this scheme for overpressure 

protection can be defeated by a common 

mode of failure, like operator error or 

equipment failure.159

CMA’s overpressurization was not an 

isolated event. For example, on January 

28, 1982, in Centralia, MO, highpressure natural gas entered a lowpressure natural gas distribution system 

after a backhoe damaged the regulator 

control line at the Missouri Power and 

Light Company’s district regulator 

station.160 Because the regulator no 

longer sensed system pressure, the 

regulator opened, and high-pressure 

natural gas entered customer piping 

systems. In some cases, this resulted in 

high pilot-light flames that ignited fires 

in buildings. In other cases, the pilotlight flames were blown out, allowing 

natural gas to escape within the 

buildings. Of the 167 buildings affected 

by the overpressurization, 12 were 

destroyed and 32 sustained moderate to 

heavy damage. Five occupants suffered 

minor injuries. 

The NTSB investigated one other 

incident in 1977 that was nearly 

identical to the 2018 incident in 


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161NTSB, Safety Recommendation(s) P–77–43 

(Dec. 9, 1977), https://www.ntsb.gov/safety/safetyrecs/RecLetters/P77_43.pdf. 

162Sec. and Exch. Comm’n, Form 10–Q Quarterly 

Report, ‘‘NiSource, Inc.’’ at 42 (Oct. 30, 2019), 

https://www.sec.gov/Archives/edgar/data/1111711/ 

000111171119000041/ni-2019930x10q.htm. 

163An underpressurization could occur if there is 

a pipeline rupture downstream, which is a risk 

during excavation. 

Merrimack Valley. Both incidents 

occurred when a cast-iron main with 

control lines attached was isolated as 

part of a pipe replacement project. On 

August 9, 1977, natural gas under high 

pressure entered a Southern Union Gas 

Company’s low-pressure natural gas 

distribution pipeline and 

overpressurized a system serving more 

than 750 customers in a 7-block area in 

El Paso, TX. The gas company was 

replacing a section of 10-inch cast-iron 

low-pressure natural gas main 

containing the pressure-sensing control 

lines for a nearby upstream regulator 

station and its monitor and isolated it 

between two valves with a temporary 

bypass installed. Southern Union Gas 

Company was aware that the isolated 

section contained the control lines but 

did not realize the potential hazard of 

isolating the pressure-sensing control 

lines, which would make the two 

regulators inoperative. Without the 

ability to sense the actual pressure in 

the gas main, the regulators allowed the 

pressure to build up and 

overpressurized the rest of the affected 

system. The problem was corrected 

before causing any fatalities or major 

injuries.161

As a result of its investigation of the 

CMA overpressurization event, as well 

as a review of multiple 

overpressurizations that occurred as the 

result of a common mode of failure, the 

NTSB recommended in P–19–14 that 

PHMSA revise 49 CFR part 192 to 

require additional overpressure 

protection for low-pressure natural gas 

distribution systems that cannot be 

defeated by a single operator error or 

equipment failure. NiSource also took 

action to remove this vulnerable design 

on their systems. On December 14, 

2018, the CEO of NiSource committed to 

the NTSB that they would install 

automatic pressure control equipment, 

referred to as ‘‘slam-shut’’ devices, on 

every low-pressure system throughout 

their operating area.162 These devices 

provide another level of control and 

protection, as they immediately shut off 

gas to the system when they sense 

operating pressure that is too high or too 

low. That measure exceeds current 

Federal requirements. 

Subsequent to the 2018 CMA 

incident, PHMSA was required by 

statute to issue regulations ensuring that 

distribution system operators minimize 

the risk of a common mode of failure at 

low-pressure district regulator stations, 

monitor the gas pressure of a lowpressure system, and install 

overpressure protection safety 

technology at low-pressure district 

regulator stations. (49 U.S.C. 

60102(t)(3)). The mandate also provides 

that if it is not operationally possible to 

install such technology, PHMSA’s 

regulations must provide that operators 

would have to develop and follow plans 

that would minimize the risk of an 

overpressurization. 

After reviewing NTSB’s 

recommendations, the CMA and other 

related incidents, and the requirements 

of 49 U.S.C. 60102(t)(3), PHMSA 

proposes additional requirements to 

improve the design standard for 

overpressure protection on low-pressure 

distribution systems. Gas distribution 

systems that use only regulators and 

control lines as the means to prevent 

overpressurization are not sufficient 

protection from overpressurization 

events. Therefore, PHMSA is proposing 

additional layers of protection specific 

to low-pressure distribution systems to 

set a safer design standard for these 

systems. 

4. Proposal To Amend § 192.195— 

Overpressure Protection 

Consistent with 49 U.S.C. 60102(t)(3), 

PHMSA proposes to amend § 192.195 to 

impose three additional requirements 

for each district regulator station that 

serves a low-pressure distribution 

system. First, each district regulator 

station must consist of at least two 

methods of overpressure protection 

(such as a relief valve, monitoring 

regulator, or automatic shutoff valve) 

appropriate for the configuration and 

location of the station. Under this 

proposal, operators have options for 

meeting the new requirements for 

overpressure protection. For example, 

one option is for operators of lowpressure distribution systems to install 

a full relief valve downstream of 

existing overpressure protections. 

Another option is to install an automatic 

shutoff valve. In that case, for operators 

with the worker and monitor regulator 

set up, the addition of an automatic 

shutoff valve downstream of the existing 

setup would stop the flow of gas if an 

overpressurization occurred and both 

regulators failed. Further, some 

automatic shutoff valves have the 

capability to activate if the system 

experiences an underpressurization.163

PHMSA discussed these additional 

options in the overpressure protection 

advisory bulletin (ADB–2020–02), but 

there are other configurations that 

would be suitable as well. 

PHMSA proposes this two-method 

requirement as mandatory for district 

regulator stations that are new, replaced, 

relocated, or otherwise changed after the 

effective date of the final rule. For all 

other systems, PHMSA proposes to 

amend § 192.1007(d)(2)(ii) to require 

operators to ensure district regulator 

stations have two methods of 

overpressure protection consistent with 

proposed § 192.195(c)(1), or identify and 

notify PHMSA of alternative preventive 

and mitigative measures. PHMSA finds 

that this approach meets the mandate 

found at 49 U.S.C. 60102(t)(3)(iii) and 

(iv) for all district regulator stations to 

have at least two methods of 

overpressure protection technology 

appropriate for the configuration and 

siting of the station, while allowing for 

alternate action where PHMSA 

determines it is not operationally 

possible to have such secondary relief. 

PHMSA concludes that it is 

operationally possible for operators to 

include at least two methods of 

overpressure protection in new, 

replaced, relocated, or otherwise 

changed district regulator stations. And, 

for existing district regulator stations, 

PHMSA recognizes that there may be 

unique cases where it is not 

operationally possible to have a second 

measure, in which circumstance an 

operator may notify PHMSA under 

§ 192.1007(d)(2)(ii)(B) of the alternative 

measures to minimize the risk of an 

overpressure event. 

Second, PHMSA proposes that each 

district regulator station that services a 

low-pressure system must minimize the 

risk of overpressurization that could be 

caused by any 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 notes that 49 U.S.C. 

60102(t)(3) requires the promulgation of 

regulations that minimize the risk of gas 

pressure exceeding the MAOP from a 

common mode of failure. PHMSA 

interprets the statutory term ‘‘common 

mode of failure’’ to mean a failure where 

a single common cause could 

immediately or over time cause multiple 

failures that result in an 

overpressurization on a downstream 

distribution system. PHMSA’s 

interpretation of ‘‘common mode of 

failure’’ is intended to ensure that 

operators are identifying as many 

potential failure modes in their systems 

as possible. 


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164 ‘‘Pipeline Safety: Miscellaneous Changes to 

Pipeline Safety Regulations,’’ 76 FR 73570 (Nov. 29, 

2011). On July 11, 2012, the Gas Pipeline Advisory 

Committee (GPAC) recommended that PHMSA 

adopt this amendment. 165NAPSR, Resolution CR–1–02, Doc. No. 

PHMSA–2010–0026–0002 (Dec. 15, 2011). 

This practice of identifying potential 

common modes of failure will be 

particularly important for operators of 

low-pressure gas distribution systems, 

whose designs make them more 

vulnerable to overpressurization. For 

example, hydrotesting upstream of the 

district regulator station could cause 

moisture to be injected into the gas 

system, which then could cause the 

working and monitor regulators to 

freeze up before the gas distribution 

operator responds. Construction work 

upstream of the district regulator station 

could cause contaminants like metal 

shavings to be introduced into the gas 

system, which then could damage the 

working and monitor regulator 

diaphragms before the gas distribution 

operator could respond. Oil, hydrates, 

or high sulfides that enter the gas 

system could affect both the working 

and monitoring regulators before the gas 

distribution operator could respond. A 

contractor or third party could damage 

both downstream control lines at the 

same time. And, as seen in the 2018 

Merrimack Valley incident, connecting 

a new main to the district regulator 

station without connecting the control 

lines to the new piping could result in 

an overpressurization. In its proposed 

§ 192.195(c)(2), PHMSA provides 

examples of single events that could 

cause a common mode of failure, such 

as excavation damage, natural forces, 

equipment failure, or incorrect 

operations. While operators are best 

positioned to identify other scenarios 

that could introduce a common mode of 

failure on their unique gas distribution 

systems, applying any of the design 

standards described in this proposed 

amendment could eliminate most of the 

common modes of failure described in 

this paragraph and in § 192.195(c)(2) by 

providing additional redundancy in the 

gas distribution system. 

Third, pursuant to 49 U.S.C. 

61012(t)(3), PHMSA proposes in 

§ 192.195(c)(3) to require that lowpressure distribution systems have 

remote monitoring of gas pressure at or 

near the location of overpressure 

protection devices. Remote monitoring 

in this context means that the device is 

capable of monitoring the gas pressure 

near the location of overpressure 

protection devices and remotely 

displaying the gas pressure to operator 

personnel in real time. Low-pressure gas 

distribution operators are already 

required to have devices such as 

telemetering or recording gauges that 

record gas pressure (see §§ 192.199 and 

192.201). However, the current 

telemetering and recording device 

requirements in § 192.741 do not require 

active monitoring and some of these 

devices employed under §§ 192.199, 

192.201, and 192.741 are not designed 

to provide real-time awareness or 

notification of potential 

overpressurizations. Installing these 

real-time monitoring devices will 

improve an operator’s ability to receive 

timely overpressurization indications, 

thereby giving operator personnel an 

opportunity to avoid or mitigate adverse 

consequences. Accordingly, PHMSA 

also proposes a conforming change in a 

new § 192.741(d) to specify that 

operators of low-pressure distribution 

systems that are new, replaced, 

relocated, or otherwise changed 

beginning one year after the publication 

of any final rule in this proceeding must 

monitor the gas pressure in accordance 

with § 192.195(c)(3). 

These three new design standards 

would be applicable to low-pressure 

distribution systems that are new, 

replaced, relocated, or otherwise 

changed beginning one year after the 

publication of any final rule in this 

proceeding. A modification to either the 

low-pressure system or the district 

regulator station made on or after the 

compliance date above would require an 

operator to meet the proposed new 

design standards described in this 

section. For example, as operators 

upgrade their low-pressure systems as 

part of the cast iron replacement 

program or implement mitigating 

measures to address the risk of 

overpressurization through the DIMP 

requirements in § 192.1007, they would 

be required to ensure those upgrades 

meet the proposed design standard in 

§ 192.195(c). PHMSA would not expect 

operators performing routine 

maintenance to upgrade their systems to 

meet the proposed design standard. 

PHMSA understands this proposed 

requirement for gas distribution 

operators to incorporate in their design 

of low-pressure distribution systems the 

overpressure protection measures 

described above would be reasonable, 

technically feasible, cost-effective, and 

practicable. These proposed enhanced 

design and installation requirements 

would be applicable only to certain gas 

distribution operators—those with 

district regulators serving low-pressure 

systems—and then only when 

components within their systems are 

new, replaced, relocated, or otherwise 

changed. Affected operators would 

therefore be able to integrate these 

common-sense, proposed safety 

enhancements within larger 

construction, installation, and 

replacement projects. Indeed, some lowpressure gas distribution system 

operators may already be complying 

with this proposed requirement either 

as a voluntarily for commercial reasons 

(to minimize the loss of a valuable 

commodity), as a safety practice 

(implementing lessons learned from the 

Merrimack Valley incident and NTSB 

recommendation P–19–14) or as a 

mitigation measure pursuant to their 

DIMP. Viewed against those 

considerations and the compliance costs 

estimated in the PRIA, PHMSA expects 

its proposed amendments will be a costeffective 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 incorporate these 

requirements in plans for new, replaced, 

relocated, or otherwise changed low 

pressure distribution systems (and 

manage any related compliance costs). 

I. Inspection: General (Section 192.305) 

1. Current Requirements—Inspections 

Section 192.305 (Inspection: General) 

states that ‘‘[e]ach transmission line or 

main must be inspected to ensure that 

it is constructed in accordance with this 

part.’’ 

2. Need for Change—Inspections 

On November 29, 2011, PHMSA 

issued an NPRM that included a 

proposal to modify the requirements 

contained in § 192.305 to specify that a 

gas transmission pipeline or distribution 

main cannot be inspected by someone 

who participated in its construction.164

This addressed concerns expressed by 

State and Federal regulators and was 

based in part on a 2011 NAPSR 

resolution calling for revisions to 

§ 192.305 to provide that contractors 

who install a transmission pipeline or 

distribution main should be prohibited 

from inspecting their own work for 

compliance purposes.165 At the time, 

§ 192.305 had simply provided that each 

transmission pipeline or distribution 

main must be inspected to ensure that 

it was constructed in accordance with 

49 CFR part 192. In a final rule issued 

on March 11, 2015, PHMSA amended 

§ 192.305 to specify that a pipeline 

operator may not use the same operator 

personnel to perform a required 


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61790 Federal Register / Vol. 88, No. 172 / Thursday, September 7, 2023 / Proposed Rules 

166 ‘‘Pipeline Safety: Miscellaneous Changes to 

Pipeline Safety Regulations,’’ 80 FR 12762, 12779 

(Mar. 11, 2015). 

167APGA, ‘‘Petition for Clarification or in the 

Alternative Reconsideration of the American Public 

Gas Association,’’ Doc. No. PHMSA–2010–0026– 

0055, at 4 (Apr. 10, 2015); American Gas 

Association, ‘‘Request for Effective Date Extension 

for Construction Inspection Changes and Petition 

for Reconsideration of ‘Pipeline Safety: 

Miscellaneous Changes to Pipeline Safety 

Regulations,’’ Doc. No. PHMSA–2010–0026–0056 

(Apr. 10, 2015); NAPSR, ‘‘NAPSR Request for Delay 

in the Effective Date of Amended Rule 192.305 on 

Construction Inspection,’’ Doc. No. PHMSA–2010– 

0026–0059 (July 28, 2015). 

168APGA, ‘‘Petition for Clarification or in the 

Alternative Reconsideration of the American Public 

Gas Association,’’ Doc. No. PHMSA–2010–0026– 

0055, at 4 (Apr. 10, 2015). 

169NAPSR, ‘‘NAPSR Request for Delay in the 

Effective Date of Amended Rule 192.305 on 

Construction Inspection,’’ Doc. No. PHMSA–2010– 

0026–0059 (July 28, 2015). 

170 ‘‘Pipeline Safety: Miscellaneous Changes to 

Pipeline Safety Regulations: Response to Petitions 

for Reconsideration,’’ 80 FR 58633, 58634 (Sept. 30, 

2015). 

171PHMSA incorporates by reference in this 

proceeding pertinent materials from the 

administrative record in the earlier proceeding. 

Those materials can be found in Doc. No. PHMSA– 

2010–0026. 

172 ‘‘Pipeline Safety: Safety of Gas Gathering 

Pipelines: Extension of Reporting Requirements, 

Regulation of Large, High-Pressure Lines, and Other 

Related Amendments,’’ 86 FR 63266 (Nov. 15, 

2021). 

173PHMSA’s preliminary review of the incoming 

reported data supports its estimates in the PRIA for 

Type C lines. 

174See Preliminary Regulatory Impact Analysis, 

available in the docket for this rulemaking. 

inspection who also performed the 

construction task that required 

inspection.166

PHMSA received petitions for 

reconsideration of various elements of 

the March 2015 final rule, including 

petitions from the American Public Gas 

Association (APGA) and other 

stakeholders raising concern about the 

construction inspection requirement in 

§ 192.305 for smaller operators for 

whom it may be particularly difficult to 

have different personnel perform 

construction and inspection 

activities.167 The APGA petition noted 

that utilities with only one qualified 

crew who work together to construct 

distribution mains would not have 

anyone working for the utility available 

and qualified to perform the inspection 

under the amended language, which 

could significantly increase the costs for 

those utilities by requiring small 

utilities to contract with third parties for 

such inspections.168 In 2015, according 

to the APGA, 585 municipal gas utilities 

had 5 or fewer employees. The APGA 

stated that its concerns would be 

alleviated by a clarification stating a 

two-man utility crew may inspect each 

other’s work and comply with the 

amendment to § 192.305. 

NAPSR, on the other hand, submitted 

a petition criticizing the March 2015 

final rule for not limiting the § 192.305 

prohibition to contractor personnel 

inspecting the work performed by their 

own company’s crews, contending that 

such an approach would not resolve the 

potential conflict of interest that had 

been the occasion for its 2011 

resolution.169 NAPSR added that 

prohibition should not apply to an 

operator’s own construction personnel 

as NAPSR believed they would have 

less of an incentive to accept poor 

quality work when conducting an 

inspection than a contractor inspecting 

his colleagues’ work. NAPSR asked for 

a delay in the effective date of the final 

rule relative to § 192.305 until PHMSA 

had reviewed the rule and worked with 

NAPSR to address its concerns. 

PHMSA responded to the petitions for 

reconsideration of the March 2015 final 

rule on September 30, 2015, and, in 

recognition of the concerns expressed, 

indefinitely delayed the effective date of 

the § 192.305 amendment.170 Because 

other proposed amendments in this 

NPRM may impact the number of 

inspections and construction activities 

on gas distribution mains, PHMSA 

believes it is appropriate to re-examine 

this issue. 

3. Proposal To Amend § 192.305— 

Inspections 

In this NPRM, PHMSA proposes to 

remove the existing suspension of 

§ 192.305, relocate the existing 

regulatory language adopted in the 

March 2015 final rule to a new 

paragraph (a), and add a new paragraph 

(b) addressing concerns raised in 

APGA’s petition for reconsideration 

pertaining to the potential impact on 

small operators. 

If adopted, PHMSA’s proposed 

§ 192.305(a) would require each gas 

transmission pipeline (along with each 

offshore gas gathering, and Types A, B, 

and C gathering pipelines pursuant to 

§ 192.9) and distribution main that is 

newly installed, replaced, relocated, or 

otherwise changed beginning one year 

after the publication of a final rule to be 

inspected to ensure that it is constructed 

in accordance with the requirements of 

this subpart, using different personnel 

to conduct the inspection than had 

performed the construction activity. 

This requirement—which would lift the 

suspension of the regulatory 

amendments adopted in the March 2015 

final rule—was the subject of extensive 

consideration in PHMSA’s earlier notice 

and comment rulemaking (including 

during a meeting of the Gas Pipeline 

Advisory Committee (GPAC)).171

PHMSA understands that the public 

safety and environmental risks 

associated with releases from Type C 

gathering pipelines, a category created 

in a final rule issued in November 

2021 172 and thus not included in the 

2015 assessment of cost-effectiveness, 

technical feasibility, and practicability, 

are similar to the risks associated with 

other part 192-regulated gas gathering 

pipelines (which generally transport 

unprocessed natural gas containing 

higher percentages of volatile organic 

compounds, corrosives, and hazardous 

airborne pollutants than processed 

natural gas transported in other 

pipelines). PHMSA therefore proposes 

to subject Type C gathering pipelines to 

the inspection requirements at 

§ 192.305(a). PHMSA expects to have 

operator-reported data after the 

reporting cycle completes in spring of 

2023 for these newly regulated gathering 

lines.173 To address this uncertainty, 

PHMSA estimates that most Type C 

lines are operated by operators of other 

part 192-regulated gathering pipelines 

such that they are already included in 

the 2015 assessment of this regulatory 

requirement for other lines.174 PHMSA 

explains this estimate in greater length 

in the associated preliminary regulatory 

impact analysis. 

Additionally, PHMSA has evaluated 

concerns raised in APGA and other 

petitioners’ reconsideration petitions, 

and PHMSA proposes to add a 

paragraph (b) that would provide an 

exception to the construction inspection 

requirement for gas distribution mains 

for small gas distribution operators for 

whom complying with paragraph (a) 

may prove difficult due to their limited 

staffing. Specifically, PHMSA proposes 

to allow operator personnel involved in 

the same construction task to inspect 

each other’s work on mains when the 

operator could otherwise comply with 

the construction inspection requirement 

in paragraph (a) of this section only by 

using a third-party inspector. This 

justification must be documented and 

retained for the life of the pipeline. This 

exception is in acknowledgment that, as 

highlighted by APGA, there are times 

when only one or two people are 

available to perform a task and the 

current requirements may be overly 

burdensome for smaller gas distribution 

operators. PHMSA proposes to limit this 

exception to distribution operators 

because it understands that: (1) many of 

these operators are likely to have a 

limited number of employees, thereby 

necessitating reliance on contractor 

personnel; and (2) the public safety risks 

from delays in undertaking safetyimproving construction projects 


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175See NAPSR, Res. 2015–01, ‘‘A Resolution 

Seeking Suspension of the Effective Date of a 

Recently Adopted Federal Final Rule, and 

Reconsideration of that Rule,’’ at 2 (Sept. 3, 2015), 

https://www.napsr.org/resolutions.html. 

176Paragraph (b) provides an exception to 

paragraph (a) for any part of the original service line 

used to maintain continuous service during testing 

if provisions are made to maintain continuous 

service. 

177NAPSR, Res. 2021–02, ‘‘A Resolution Seeking 

a Modification of 49 CFR 192.517(b) to Require 

Certain Distribution Pipeline Pressure Test 

Information Be Documented and to Require the 

Retention of Test Documentation for Distribution 

Pipelines for the Lifetime of the Corresponding 

Pipeline Segment,’’ Doc. No. PHMSA–2021–0046– 

0005 (Oct. 7, 2021). This extended retention period 

would include records of tests establishing an 

MAOP, as NAPSR explains in its petition: ‘‘PHMSA 

has set forth regulations requiring the availability 

and use of pipeline pressure documentation to 

establish the maximum allowable operating 

pressure (MAOP) of pipelines, including short 

segments of replaced or relocated pipe, prior to 

placing them in service within Subpart L of 49 CFR 

192, specifically 49 CFR 192.619.’’ 

(because of a lack of qualified 

inspection personnel) on these pipelines 

would be particularly compelling given 

their (typical) location near or within 

population centers. PHMSA believes 

this proposed amendment addresses 

concerns raised in APGA’s petitions for 

reconsideration regarding the 

unintended burdens of the March 2015 

rulemaking on small operators. 

PHMSA acknowledges that NAPSR, 

in its 2011 resolution and petition for 

reconsideration of the March 2015 final 

rule, called for limiting the prohibition 

to contractor personnel inspecting the 

work of their own crew, as NAPSR does 

not view an ‘‘inherent conflict of 

interest’’ arising from operatoremployed personnel doing the same.175

PHMSA agrees with NAPSR that a lack 

of independence in inspection activity 

raises public safety concerns but 

disagrees that there is a material 

distinction in risk between those 

personnel directly employed by the 

operator and those third-party personnel 

contracted by the operator. Further, 

creating such a distinction could 

diminish the scope of the safety benefit 

while placing burden on smaller 

operators who rely on contractors for a 

large portion of their construction work. 

Therefore, PHMSA does not see a 

reasoned basis to discriminate between 

operator personnel and contracted 

personnel for the purposes of this 

inspection. 

PHMSA understands this proposed 

amendment to restore a previously 

approved (but now suspended) 

requirement that post-construction 

inspections be performed by personnel 

other than those who performed the 

construction work being inspected 

would be reasonable, technically 

feasible, cost-effective, and practicable 

for all affected operators. That 

requirement reflects the proposition— 

reflected in industry best practice—that 

an independent second set of eyes 

inspecting a construction project 

provides more robust assurance of work 

product quality than allowing 

construction personnel to inspect their 

own work. Although PHMSA 

acknowledges that this proposed 

requirement could entail additional 

compliance burdens (in terms of costs 

and stretching limited personnel 

resources) for some operators, PHMSA 

believes those burdens would be 

manageable because (1) all operators 

could account for them at the project 

planning phase in a way that allows 

them to control costs or secure requisite 

supplemental personnel (or contractors), 

and (2) small gas distribution system 

operators whose limited personnel 

resources would make them dependent 

on (potentially expensive) contractors 

would be excepted from this 

requirement. Viewed against those 

considerations and the compliance costs 

estimated in the PRIA, PHMSA expects 

its proposed amendments will be a costeffective 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 procedures and obtain 

access to inspection personnel for nearterm installation projects (as well as 

manage any resulting compliance costs). 

J. Records: Tests (Sections 192.517 and 

192.725) 

1. Current Requirements—Records: 

Tests 

Section 192.517(b) applies to all gas 

pipeline operators and states that 

‘‘[e]ach operator must maintain a record 

of each test required by §§ 192.509 

[pipelines operating below 100 psig], 

192.511 [service lines], and 192.513 

[plastic pipelines], respectively, for at 

least 5 years.’’ Section 192.725(a) states 

that ‘‘each disconnected service line 

must be tested in the same manner as a 

new service line, before being 

reinstated.’’ 176

2. Need for Change—Records: Tests 

On October 7, 2021, NAPSR 

submitted a resolution seeking that 

PHMSA amend § 192.517(b) in several 

ways. NAPSR recommended PHMSA 

amend its regulations to require 

operators to retain test documentation 

under § 192.517(b) for the life of the 

corresponding pipeline segment as 

opposed to the current 5 years.177 The 

resolution also requested that PHMSA 

require operators to retain for the life of 

the pipeline ‘‘the test pressure 

documentation created within the five 

years prior’’ to any such amendment. 

Additionally, NAPSR requested that 

PHMSA require additional, more 

detailed, information be documented as 

part of these test records. PHMSA agrees 

that the detailed recordkeeping content 

and retention requirements suggested by 

NAPSR will improve consistency and 

promote public safety and protection of 

the environment. 

NAPSR also requested that PHMSA 

add § 192.725 (‘‘Test requirements for 

reinstating service lines’’) to the list of 

required test records in § 192.517(b). It 

reasoned that § 192.603(b), which 

requires operators to keep records 

necessary to administer the procedures 

established under § 192.605, is 

potentially in conflict with § 192.517. 

PHMSA clarifies that the requirement in 

§ 192.725 to perform a test ‘‘in the same 

manner as a new service line’’ is meant 

to direct an operator to conduct a test 

required for a new service line in 

accordance with 49 CFR part 192, 

subpart J. A test performed to meet 

§ 192.725 does not constitute a new type 

of test for purposes of identifying 

recordkeeping requirements for such a 

test. PHMSA expects an operator to 

select the appropriate test in subpart J 

to meet the testing requirement of 

§ 192.725, which includes meeting the 

corresponding recordkeeping 

requirements of § 192.517. For that 

reason, PHMSA does not propose to 

include § 192.725 in the list of tests 

identified within § 192.517. 

3. Proposal To Amend § 192.517— 

Records: Tests 

PHMSA proposes to amend § 192.517 

to require that records of tests covered 

by § 192.517(b) (i.e., tests performed 

according to § 192.509, 192.511, and 

192.513) be retained for the life of the 

pipeline. This amendment would be 

applicable to all gas pipeline operators. 

PHMSA would require operators to 

retain the records for all tests presently 

being retained under the existing 

language of § 192.517(b) from the 

preceding five years, which under the 

proposal would then be retained for the 

life of the pipeline. PHMSA also 

proposes to require that the records of 

these tests include, at a minimum, 

sufficient information to document the 

test, including information about the 


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178 GPA Midstream Assn. v. Dep’t of Transp., 67 

F.4th 1188, 1201 (D.C. Cir. 2023). 179 88 FR at 50058, 50060–61 (Aug. 1, 2023). 

180See, e.g., ‘‘Gas Gathering Line Definition; 

Alternative Definition for Onshore Lines and New 

Safety Standards—Final Rule,’’ 71 FR 13292, 

13296–97 (Mar. 15, 2006) (discussing safety basis 

for broadly extending part 192 requirements for gas 

transmission lines to Type A gas gathering 

pipelines); 86 FR at 63284–85 (discussing safety 

basis for extending § 192.615 requirements to highpressure, large-diameter Type C gas gathering 

pipelines). 

181 87 FR at 20969–70, 20973. 

operator, the individual or any company 

used to perform the test, pipeline 

segment being tested, test date, medium, 

pressure, duration, and any leaks or 

failures noted and their disposition. 

Retaining tests for the life of the 

pipeline, instead of the current retention 

period of 5 years, ensures that records 

are available whenever repairs are 

necessary, or should an incident occur, 

records are available to support an 

operator’s inspection and investigation 

into the root cause of a failure. Further, 

PHMSA currently requires (per 

§ 192.603(b) and § 192.605) operators to 

keep MAOP records for life of facility 

but MAOP records established by 

§ 192.517(b) tests are just 5 years. 

PHMSA believes that these changes will 

improve the quality and availability of 

test records, including records of leaks 

occurring during testing activities and 

MAOP establishment records. 

PHMSA understands this proposed 

amendment of an existing record 

retention requirement to be reasonable, 

technically feasible, cost-effective, and 

practicable. The proposed changes are 

incremental supplementation of current 

requirements regarding recording and 

retaining record of pressure tests 

operators are already required to 

conduct. The proposed amendments 

require operators to document 

information they may already be 

obtaining through the required tests 

under this current requirement, more 

clearly states that information which 

operators should record from the tests 

and extends the retention period; 

PHMSA expects some operators may 

already be in their substantial 

compliance with this proposed 

requirement. Viewed against those 

considerations and the compliance costs 

estimated in the PRIA, PHMSA expects 

its proposed amendments will be a costeffective 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 procedures to ensure 

identification or generation of pertinent 

records (and manage any related 

compliance costs). 

4. Proposal To Amend § 192.725—Test 

Requirements for Reinstating Service 

Lines 

PHMSA proposes to revise § 192.725 

to clarify that ‘‘tested in the same 

manner as a new service line’’ in the 

existing regulation means ‘‘tested in 

accordance with subpart J of this part’’, 

by inserting that clarifying language 

within a parenthetical. PHMSA 

understands that this proposed revision 

merely clarifies an existing requirement 

and is therefore technically feasible and 

practicable. PHMSA further notes 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 updates, if any 

are needed, to their procedures. 

K. Miscellaneous Amendments 

Pertaining to Part 192—Regulated Gas 

Gathering Pipelines (Sections 192.3 and 

192.9) 

1. Current Requirements—Gas Gathering 

Among the regulatory amendments 

adopted in the April 2022 Valve Rule 

were enhanced emergency planning and 

notification requirements applicable to 

all part 192-regulated gas pipeline 

operators subject to § 192.615, to 

include new references to public safety 

answering points (such as 9–1–1 call 

centers) and a requirement for those 

operators to update their written 

procedures to provide for timely rupture 

identification; certain new, 

implementing definitions at § 192.3 

applicable to all part 192-regulated gas 

pipelines; and within a new § 192.635, 

a definition of the term ‘‘notification of 

potential rupture’’ applicable to those 

part 192-regulated pipelines subject to 

that provision. 

The D.C. Circuit, however, vacated 

those new requirements as to gas 

gathering pipelines in a decision issued 

in May 2023.178 PHMSA subsequently 

issued a Technical Correction codifying 

the court’s decision by introducing 

exceptions to the above provisions 

restricting their application to the part192 regulated gas gathering pipelines to 

which they had applied.179 Specifically, 

the Technical Correction introduced 

language in each of the § 192.3 

definitions adopted in the Valve Rule 

(‘‘entirely replaced onshore 

transmission pipeline segments’’; 

‘‘notification of potential rupture’’; and 

‘‘rupture-mitigation valve (RMV)’’) 

excepting all part 192-regulated gas 

gathering pipelines from those 

definitions. The Technical Correction 

also introduced a series of exceptions 

within the regulatory cross-reference 

provision at § 192.9 preventing 

application of the Valve Rule’s 

amendments at §§ 192.615 and 192.635 

regarding emergency response and 

notification and rupture identification 

procedures to each of offshore gas 

gathering pipelines (§ 192.9(b)) as well 

as onshore Types A (§ 192.9(c)) and C 

(§ 192.9(e)) gas gathering pipelines. 

2. Need for Change—Gas Gathering 

Written emergency planning and 

notification procedures are critical tools 

for the safe operation of any gas 

pipeline. Offshore, Type A, and Type C 

gas gathering pipelines had—consistent 

with the risks to public safety and the 

environment posed by an emergency 

involving those high-pressure, gas 

pipeline facilities 180—been subject to 

extensive emergency planning and 

notification requirements before 

issuance of the Valve Rule in April 

2022. Those long-standing safety 

standards include requirements for 

operators to have written emergency 

procedures for notifying, establishing, 

and maintaining communications with 

fire, police, and other public officials 

(§ 192.615(a)(2) and (8); § 192.615(c)); 

taking actions necessary to minimize 

hazards to public safety from the 

emergency (§ 192.615(a)(6)); and 

directing operator control room 

response actions in an emergency 

(§ 192.615(a)(11)). 

The amendments to § 192.615 

introduced in the Valve Rule were 

modest refinements to those longstanding emergencies response planning 

and notification requirements. The 

Valve Rule explained its amendments to 

§ 192.615(a)(2), (a)(8), and (c) adding 

language requiring notification of, and 

communication with, public safety 

answering points (PSAPs) or emergency 

coordination agencies ensure 

notifications of pipeline emergencies are 

channeled to resources best positioned 

to alert first responders and coordinate 

response efforts across multiple 

jurisdictions that may be affected by a 

pipeline emergency.181 The Valve Rule 

also made a pair of incremental changes 

to § 192.615(a)(6)’s requirement that 

operator procedures provide for taking 

certain actions—emergency shutdown 

or pressure reduction—to minimize 

public safety risks. The first change was 

to add language (‘‘including, but not 

limited to . . .’’) clarifying that operator 

procedures could provide for actions 


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182The severity of harms to public safety and the 

environment from a rupture on a gas pipeline 

depend (inter alia) on the volume of gas released, 

the duration of the release, and the time before 

mitigation/response actions are initiated and 

completed. 

183 87 FR at 20949–52, 20972, 20972. 

184 87 FR 20952–53. 

185PHMSA understands that in so doing, the 

§ 192.635 definition of ‘‘notification of potential 

rupture’’ referenced within § 192.3 would apply to 

all part 192-regulated gas gathering pipelines as 

well. 

other than system shutdown or pressure 

reduction in an emergency, thereby 

granting operators greater flexibility in 

designing response actions best capable 

of minimizing hazards in a pipeline 

emergency; this includes the 

additionally enumerated action of valve 

shut-off. The second change included a 

reference to environmental hazards. 

Among those hazards operator 

procedures must minimize, reflecting 

the fact that the mechanism for public 

safety and environmental harms 

(namely, the release of gas from a 

pipeline) is identical. 

The Valve Rule also made several 

regulatory amendments to address the 

time-dependent 182 risks to public safety 

and the environment posed by ruptures 

on gas pipelines. First, the Valve Rule 

added at § 192.3 (which in turn 

references a new § 192.935) the new 

term ‘‘notification of potential rupture’’ 

codifying commonly-understood indicia 

of a rupture.183 The Valve Rule also 

added a pair of requirements ensuring 

timely identification of, and response to, 

this particular emergency in which 

every second lost can increase public 

safety and environmental consequences: 

a new § 192.615(a)(12) requiring 

operators develop procedures for 

confirming actual ruptures following 

reports of the indicia listed in the new 

definition of ‘‘notification of potential 

rupture’’, as well as language at 

§ 192.615(a)(8) introducing a new 

requirement for immediate and direct 

notification of PSAPs on an operator’s 

notification of a potential rupture.184

Similarly, PHMSA enhanced a 

longstanding requirement at 

§ 192.615(a)(11) governing emergency 

procedures for control room personnel 

by adding a cross-reference to newlyadopted provisions pertaining to 

rupture mitigation valves at §§ 192.634 

and 192.636. 

Lastly, the Valve Rule adopted certain 

other definitions of terms (‘‘entirely 

replaced onshore transmission 

segment’’; and ‘‘rupture-mitigation 

valve’’) employed in its regulatory 

amendments. 

3. Proposal To Amend §§ 192.3 and 

192.9—Emergency Procedures and 

Notification; Rupture Identification 

Procedures 

PHMSA proposes several 

amendments to restore certain 

emergency planning, notification, and 

rupture identification procedures 

vacated by the D.C. Circuit with respect 

to gas gathering pipelines. First, PHMSA 

proposes to delete from each of the 

§ 192.3 definitions introduced in the 

Technical Correction language 

disclaiming application of those terms 

to any part 192-regulated gas gathering 

line.185 Second, PHMSA proposes to 

delete from § 192.9 similar language 

excluding application of the Valve 

Rule’s amendments to § 192.615 

discussed in section IV.K.2 above to 

offshore gas gathering (§ 192.9(b)), Type 

A (§ 192.9(c)), and Type C (§ 192.9(e)) 

gas gathering lines. This proposal is 

focused on application of these 

emergency response provisions to 

gathering lines; PHMSA is not, however, 

proposing in this rulemaking to restore 

application to part 192-regulated gas 

gathering lines of other regulatory 

amendments adopted in the Valve Rule 

pertaining to rupture mitigation valve 

installation, operation, and 

maintenance. 

As explained in section IV.K.2 above, 

the Valve Rule’s amendments to 

§ 192.615 are incremental improvements 

on existing requirements applicable to 

offshore, Type A, and Type C gas 

gathering pipelines. Some of those 

amendments are broad in scope and are 

applicable to any emergency on those 

gas gathering pipelines; others are 

specific to ruptures on those pipelines. 

And each of those amendments is a 

common-sense, baseline expectation 

ensuring operator emergency planning 

and notification procedures are directed 

toward timely and effective response 

and mitigation of risks to public safety 

and the environment. 

PHMSA understands these proposed 

amendments would be reasonable, 

technically feasible, cost-effective and 

practicable for affected gas gathering 

pipeline operators. The restoration of 

definitions at § 192.3 are not themselves 

operative provisions entailing 

compliance burdens for operators; 

several of those definitions, moreover, 

are used in operative provisions 

inapplicable to gas gathering pipelines. 

And although the restored applicability 

of the Valve Rule’s revisions to 

§ 192.615 could entail additional 

compliance burdens for affected gas 

gathering operators, some operators may 

already incorporate the required content 

in their pipelines’ emergency planning 

and notification procedures; indeed, 

such procedures are precisely the sort of 

procedures a reasonably prudent 

operator of any gas pipeline facility 

would maintain in ordinary course 

given that their systems transport 

commercially valuable, pressurized 

(natural flammable, toxic, or corrosive) 

gasses. Viewed against those 

considerations and the compliance costs 

estimated in the PRIA, PHMSA expects 

its proposed amendments will be a costeffective approach to achieving the 

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 

procedures (as well as manage any 

resulting compliance costs). 

V. Regulatory Analyses and Notices 

A. Authority for This Rule 

This proposed rule is published under 

the authority of the Secretary of 

Transportation delegated to the PHMSA 

Administrator pursuant to 49 CFR 1.97. 

Among the statutory authorities 

delegated to PHMSA are those set forth 

in the Federal Pipeline Safety Statutes 

(49 U.S.C. 60101 et seq.). 49 U.S.C. 

60102 grants authority to issue 

standards for the transportation of gas 

via any part 192-regulated gathering 

pipelines to protect public safety and 

the environment; and 49 U.S.C. 

60102(b)(5) specifies that PHMSA must 

consider both public safety and 

environmental benefits. 

This NPRM proposes to implement 

several provisions of the PIPES Act of 

2020, including those codified at 49 

U.S.C. 60102, 60105, 60106, and 60109. 

Section 60102 authorizes the Secretary 

of Transportation to issue regulations 

governing the design, installation, 

inspection, emergency plans and 

procedures, testing, construction, 

extension, operation, replacement, and 

maintenance of gas pipeline facilities, 

including gas transmission, gas 

distribution, offshore gas gathering, and 

Types A, B, and C gas gathering 

pipelines, each of which would be 

subject to various proposed 

requirements in this NPRM. Sections 

60105 and 60106 permit States to 

assume safety authority over intrastate 

pipelines, including gas and hazardous 

liquid pipelines, and underground 

natural gas storage facilities through 

certifications or agreements with 

PHMSA, while section 60107 authorizes 

the Secretary to establish requirements 

governing award of grants supporting 


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186E.O. 12866 is available at 58 FR 51735 (Oct. 

4, 1993); E.O. 14094 is available at 88 FR 21879 

(Apr. 6, 2023). 187 59 FR 7629 (Feb. 16, 1994). 

188See, 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). 

189Agencies are not required to conduct an IRFA 

if the head of the agency certifies that the proposed 

rule will not have a significant impact on a 

substantial number of small entities. 5 U.S.C. 605. 

190 67 FR 53461 (Aug. 16, 2002). 

191 DOT, ‘‘Rulemaking Requirements Concerning 

Small Entities’’, https://www.transportation.gov/ 

regulations/rulemaking-requirements-concerningsmall-entities (last updated May 18. 2012). 

State pipeline safety programs. 

Additionally, 49 U.S.C. 60117 

authorizes the Secretary of 

Transportation to direct operators of 

those gas pipeline facilities to submit 

reports to PHMSA to inform PHMSA’s 

regulatory oversight activities. As 

described above, 49 U.S.C. 60102, 

60105, and 60109 also require the 

Secretary to issue regulations updating 

PHMSA regulations in 49 CFR parts 192 

and 198. 

B. Executive Orders 12866 and 14094; 

DOT Regulatory Policies and Procedures 

Executive Order 12866 (‘‘Regulatory 

Planning and Review’’), as amended by 

Executive Order 14094 (‘‘Modernizing 

Regulatory Review’’), requires that 

agencies ‘‘should assess all costs and 

benefits of available regulatory 

alternatives, including the alternative of 

not regulating.’’ 186 Agencies should 

consider quantifiable measures and 

qualitative measures of costs and 

benefits that are difficult to quantify. 

Further, Executive Order 12866 requires 

that agencies maximize net benefits 

(including potential economic, 

environmental, public health and safety, 

and other advantages; distributive 

impacts; and equity), unless a statute 

requires another regulatory approach. 

Similarly, DOT Order 2100.6A 

(‘‘Rulemaking and Guidance 

Procedures’’) requires that regulations 

issued by PHMSA and other DOT 

Operating Administrations should 

consider an assessment of the potential 

benefits, costs, and other important 

impacts of the proposed action and 

should quantify (to the extent 

practicable) the benefits, costs, and any 

significant distributional impacts, 

including any environmental impacts. 

Executive Order 12866 (as amended 

by Executive Order 14094) and DOT 

Order 2100.6A require that PHMSA 

submit ‘‘significant regulatory actions’’ 

to the Office of Management and Budget 

(OMB) for review. The proposed rule 

has been determined to be significant 

under section 3(f) of Executive Order 

12866 (as amended by section 1(b) of 

Executive Order 14094) and DOT Order 

2100.6A and was reviewed by the Office 

of Information and Regulatory Affairs 

(OIRA) within OMB. 

Consistent with Executive Order 

12866 (as amended by Executive Order 

14094) and DOT Order 2100.6A, 

PHMSA has prepared a PRIA assessing 

the benefits and costs of the proposed 

rule as well as reasonable alternatives. 

PHMSA estimates the proposed rule 

will result in unquantified public safety 

and environmental benefits associated 

with preventing and mitigating 

incidents on gas distribution and other 

part 192-regulated gas pipeline 

facilities. PHMSA estimates annualized 

costs of $110 million per year (using a 

3 percent discount rate) due to costs 

associated with the proposed 

requirements for updating emergency 

response plans, updating O&M manuals, 

keeping records, gas monitoring by 

qualified employees, and assessing and 

upgrading district regulator stations. For 

the full cost/benefit analysis, please see 

the PRIA in the rulemaking docket. 

PHMSA seeks comment on the PRIA, its 

approach, and the accuracy of its 

estimated costs and benefits. 

C. Environmental Justice 

Executive Order 12898 (‘‘Federal 

Actions to Address Environmental 

Justice in Minority Populations and 

Low-Income Populations’’),187 directs 

Federal agencies to take appropriate and 

necessary steps to identify and address 

disproportionately high and adverse 

effects of Federal actions on the health 

or environment of minority and lowincome populations to the greatest 

extent practicable and permitted by law. 

DOT Order 5610.2C (‘‘U.S. Department 

of Transportation Actions to Address 

Environmental Justice in Minority 

Populations and Low-Income 

Populations’’) establishes departmental 

procedures for effectuating Executive 

Order 12898 promoting the principles of 

environmental justice through full 

consideration of environmental justice 

principles throughout planning and 

decision-making processes in the 

development of programs, policies, and 

activities—including PHMSA 

rulemaking. 

PHMSA has evaluated this NPRM 

under DOT Order 5610.2C and 

Executive Order 12898 and has 

preliminarily determined it will not 

cause disproportionately high and 

adverse human health and 

environmental effects on minority and 

low-income populations. The proposed 

rule is facially neutral and national in 

scope; it is neither directed toward a 

particular population, region, or 

community, nor is it expected to result 

in any adverse environmental or health 

impact any particular population, 

region, or community. Rather, PHMSA 

anticipates the rulemaking will reduce 

the safety and environmental risks 

associated with losses of integrity on gas 

pipeline facilities—particularly gas 

distribution pipelines in urban or rural 

areas posing higher risks due to their 

vintage, material, and proximity to 

minority and low-income communities 

in the vicinity of those pipelines.188

Lastly, as explained in the draft 

environmental assessment in the 

rulemaking docket, PHMSA anticipates 

that the regulatory amendments in this 

proposed rule will yield greenhouse gas 

emissions reductions, thereby reducing 

the risks posed by anthropogenic 

climate change to minority and lowincome, populations, underserved and 

other disadvantaged communities. This 

finding is consistent with the most 

recent Environmental Justice Executive 

Order 14096—Revitalizing Our Nation’s 

Commitment to Environmental Justice 

for All, by achieving several goals 

including continuing to deepen the 

Administration’s whole of government 

approach to environmental justice and 

to better protect overburden 

communities from pollution and 

environmental harms. 

D. Regulatory Flexibility Act 

The Regulatory Flexibility Act, as 

amended by the Small Business 

Regulatory Flexibility Fairness Act of 

1996 (5 U.S.C. 601 et seq.), generally 

requires Federal agencies to prepare an 

initial regulatory flexibility analysis 

(IRFA) for a proposed rule subject to 

notice-and-comment rulemaking under 

the Administrative Procedure Act. 5 

U.S.C. 603(a).189 Executive Order 13272 

(‘‘Proper Consideration of Small Entities 

in Agency Rulemaking’’) 190 obliges 

agencies to establish procedures 

promoting compliance with the 

Regulatory Flexibility Act; DOT’s 

implementing guidance is available on 

its website.191

This NPRM was developed in 

accordance with Executive Order 13272 

and DOT guidance to ensure 

compliance with the Regulatory 

Flexibility Act and provide appropriate 

consideration of the potential impacts of 

the rulemaking on small entities. 

PHMSA conducted an IRFA, which has 

been made available in the docket for 

this rulemaking and is summarized 

below. A description of the reasons why 


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192See PRIA Table 45. 

193For the other 18% of operators, PHMSA did 

not have sufficient data to calculate the revenue 

percentage for the compliance costs of the rule at 

this time. PHMSA seeks comment on compliance 

costs generally, but in particular for transmission 

and gathering operators for which sufficient data 

was not available. 

PHMSA is considering this action and a 

succinct statement of the objectives of, 

and legal basis for, the proposed rule are 

described elsewhere in the preamble for 

this rule and not repeated here. PHMSA 

seeks comment on whether the 

proposed rule, if adopted, would have a 

significant economic impact on a 

significant number of small entities. 

Description and Estimate of the Number 

of Small Entities to Which the Proposed 

Rule Would Apply 

PHMSA analyzed privately owned 

entities (inclusive of investor-owned 

entities) that could be impacted by the 

rule, which include companies with 

natural gas extraction, pipeline 

transportation, and natural gas 

distribution businesses, as well as 

entities with another primary business. 

PHMSA determined whether these 

entities were small entities based on the 

size of the parent entity and using the 

relevant SBA size standards set out in 

Table 43 of the PRIA. PHMSA also 

analyzed publicly owned entities that 

could be impacted by the rule, 

including State, municipal, and other 

political subdivision entities. Publicly 

owned entities with population less 

than 50,000 are considered small. 

PHMSA identified 1,239 gas 

distribution parent entities and 

determined that of these parent entities, 

92 percent (1,135 parent entities) are 

classified as ‘‘small’’ based on the 

relevant criteria listed above. PHMSA 

also identified 831 gas transmission and 

gathering parent entities in this analysis 

that do not also operate distribution 

systems. Of these gas transmission and 

gas gathering parent entities, 82 percent 

are classified as ‘‘small’’ (681 parent 

entities). Because PHMSA did not have 

sufficient information to individually 

categorize master meter operators or 

operators of small LPGs by size, PHMSA 

conservatively made the over-inclusive 

decision to consider all master meter 

operators and operators of small LPGs to 

be small entities for purposes of its 

analysis. 

Description of Projected Reporting, 

Recordkeeping, and Other Compliance 

Requirements of the Proposed Rule, 

Including an Estimate of the Classes of 

Small Entities Which Would Be Subject 

to the Requirement and the Type of 

Professional Skills Necessary for 

Preparation of the Report or Record 

PHMSA analyzed the costs of 

compliance for the small gas 

distribution, gas transmission and 

gathering, and master meter and small 

LPG operators. PHMSA assessed the 

annualized cost for gas distribution 

operators based on the number of 

services, and provided a minimum, 

average, and maximum annualized cost 

estimate for each size category. For 

small gas distribution operators with 

100,000 or fewer services, PHMSA 

calculated annualized estimated 

compliance costs that ranged from 

$8,051 to $10,528 depending on the cost 

scenario and discount rate.192 For gas 

transmission and gathering operators, 

PHMSA calculated minimum, average, 

and maximum annualized estimated 

compliance costs that ranged from $44 

to $52,029 depending on the cost 

scenario, industry type (transmission or 

gathering), and discount rate. For small 

master meter systems, PHMSA 

estimated pre-tax annualized 

compliance costs for individual 

operators from $4,421 to $4,590, 

depending on the discount rate. For 

small LPG systems, PHMSA estimated 

pre-tax annualized compliance costs for 

individual operators from $4,764 to 

$4,928, again depending on the discount 

rate. 

PHMSA then calculated cost-torevenue ratios using the calculated 

compliance costs of each small parent 

entity. PHMSA estimated that 98 

percent of small gas distribution parent 

entities will face after-tax compliance 

costs of less than 1 percent of revenue 

under all evaluated cost scenarios. 

PHMSA estimated that 80 to 82 percent 

of small gas transmission parent entities 

operators will incur after-tax 

compliance costs of less than 1 percent 

of revenue. Under the maximum cost 

scenario, PHMSA estimates that 1 

percent of small parent entities will 

incur compliance costs above 1 percent 

but below 3 percent of revenue. Under 

this maximum cost scenario, PHMSA 

also estimates that one small parent 

entity will incur compliance costs above 

3 percent of revenue. However, PHMSA 

believes the maximum cost scenario is 

unlikely, as it assumes the entirety of 

estimated new and replaced lines are 

attributable to a single operator.193 For 

master meter operators and operators of 

small LPGs, PHMSA calculated the 

break-even value of annual revenue that 

would be required for their calculated 

after-tax compliance costs to be 1 

percent and 3 percent of revenue. For 

master meter operators, PHMSA 

estimated that revenue would need to be 

$442,122 or less for compliance costs to 

be 1 percent of revenue and that 

revenue would need to be $147,374 or 

less for compliance costs to be 3 percent 

of revenue. For operators of small LPGs, 

PHMSA estimated that revenue would 

need to be $476,357 or less for 

compliance costs to be 1 percent of 

revenue and that revenue would need to 

be $158,786 or less for compliance costs 

to be 3 percent of revenue. 

Relevant Federal Rules Which May 

Duplicate, Overlap or Conflict With the 

Proposed Rule 

PHMSA did not identify any Federal 

rules that may duplicate, overlap, or 

conflict with the proposed rule. In 

Section 7.6 of the PRIA accompanying 

this NPRM, PHMSA provides details on 

other Federal regulations that may 

impact operators of gas pipelines. 

Description and Analysis of Significant 

Alternatives to the Proposed Rule 

Considered 

PHMSA analyzed a number of 

alternatives to the NPRM, which are 

described in detail in Section 2 of the 

PRIA accompanying this NPRM. In 

addition to retaining the status quo and 

not issuing the proposal, which PHMSA 

determined would fail to satisfy PIPES 

Act mandates to improve safety and 

update PHMSA regulations, PHMSA 

also analyzed: 

1. Retaining DIMP requirements for 

small LPG operators and imposing the 

updated DIMP requirements of this 

NPRM on those same operators. 

2. Extending to all part 192-regulated 

pipelines an exception that currently 

allows, for distribution mains only, 

distribution operator personnel 

involved in the same construction task 

to inspect each other’s work. 

3. An alternative compliance date. 

4. Imposing an ICS requirement for 

emergency response. 

5. Requiring all future construction 

projects associated with installations, 

modifications, replacements, or system 

upgrades on gas distribution pipelines 

to have licensed professional engineer 

approval and stamping. 

6. Requiring gas distribution operators 

to develop and follow an MOC process 

as outlined in ASME/ANSI B31.8S. 

PHMSA did not identify any viable 

alternative that could accomplish the 

stated objectives of applicable statutes 

while further minimizing any 

significant economic impact of the 

proposed rule on small entities. As 

discussed in more detail elsewhere in 

this preamble and in Section 2 of the 

PRIA for this NPRM, PHMSA 

determined that these requirements 

could result in reductions in safety 

benefits that were not justified by any 

potential cost savings (e.g., the proposal 


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194 65 FR 67249 (Nov. 6, 2000). 

to extend the exception for distribution 

mains that allows distribution operator 

personnel to inspect each other’s work 

on the same construction task to all 

part-192 regulated pipelines) or impose 

costs on small entities that were not 

justified by any increased safety 

benefits. PHMSA therefore declined to 

propose these alternatives but seeks 

comment on them in this proposed rule. 

E. Executive Order 13175: Consultation 

and Coordination With Indian Tribal 

Governments 

PHMSA analyzed this proposed rule 

in accordance with the principles and 

criteria contained in Executive Order 

13175 (‘‘Consultation and Coordination 

with Indian Tribal Governments’’) 194

and DOT Order 5301.1A (‘‘Department 

of Transportation Programs, Policies, 

and Procedures Affecting American 

Indians, Alaska Natives, and Tribes’’). 

Executive Order 13175 requires agencies 

to ensure meaningful and timely input 

from Tribal government representatives 

in the development of rules that 

significantly or uniquely affect Tribal 

communities by imposing ‘‘substantial 

direct compliance costs’’ or ‘‘substantial 

direct effects’’ on such communities, or 

the relationship or distribution of power 

between the Federal Government and 

Tribes. 

PHMSA assessed the impact of the 

proposed rule and does not expect it 

will significantly or uniquely affect 

Tribal communities or Indian Tribal 

governments. The proposed rule’s 

regulatory amendments are facially 

neutral and will have broad, national 

scope. PHMSA, therefore, does not 

expect this rule to significantly or 

uniquely affect Tribal communities, 

impose substantial compliance costs on 

Native American Tribal governments, or 

mandate Tribal action. And insofar as 

PHMSA expects the NPRM will improve 

safety and reduce environmental risks 

associated with gas distribution 

pipelines, PHMSA expects it will not 

entail disproportionately high adverse 

risks for Tribal communities. Therefore, 

PHMSA concludes that the funding and 

consultation requirements of Executive 

Order 13175 and DOT Order 5301.1A do 

not apply to this proposed rule. 

While PHMSA is not aware of specific 

Tribal-owned business entities that 

operate part 192-regulated gas pipelines, 

any such business entities could be 

subject to direct compliance costs as a 

result of this proposed rule. PHMSA 

seeks comment on the applicability of 

Executive Order 13175 to this proposed 

rule and the existence of any Tribalowned business entities operating 

pipelines affected by the proposed rule 

(along with the extent of such potential 

impacts). 

F. Paperwork Reduction Act 

Pursuant to 5 CFR 1320.8(d), PHMSA 

is required to provide interested 

members of the public and affected 

agencies with an opportunity to 

comment on information collection and 

recordkeeping requests. If adopted, the 

proposals in this rulemaking would 

impose new notification and 

recordkeeping requirements for all part 

192-regulated pipelines, including gas 

distribution, gas transmission and 

gathering pipelines. 

PHMSA proposes to require gas 

distribution operators to review their 

integrity management plans to ensure 

that the plans identify specific threats 

such as: (1) certain materials, such as 

cast iron and other piping with known 

issues, (2) the age of each component of 

the operator’s pipelines along with the 

overall age of its system, (3) 

overpressurization of low-pressure 

systems, and (4) extreme weather and 

geohazards. PHMSA also proposes that, 

when identifying and implementing 

measures to address those risks, 

operators must address (at a minimum) 

the risks associated with each of the 

following: the presence of known issues, 

the age of each part of a pipeline along 

with the overall age of the system, and 

(for operators of low-pressure gas 

distribution systems) 

overpressurization. PHMSA plans to 

revise the ‘‘Pipeline Safety: Integrity 

Management Program for Gas 

Distribution Pipelines’’ information 

collection that is currently approved 

under OMB Control No. 2137–0625 to 

include this new requirement. Since 

pipeline operators are already required 

to review and update their integrity 

management plans on a regular basis, 

PHMSA expects operators to incur 

minimal burden in complying with this 

information collection request. 

PHMSA also proposes to repeal the 

requirement for operators of small LPGs 

to participate in the distribution 

integrity management program. Based 

on a recent study, PHMSA estimates 

there are as many as 4,492 small LPG 

operators. PHMSA proposes to create a 

new form, PHMSA Form 7100.1–2, to 

collect limited data from these operators 

of small LPGs on an annual basis. As a 

result, PHMSA expects the burden of 

the ‘‘Pipeline Safety: Integrity 

Management Program for Gas 

Distribution Pipelines’’ information 

collection under OMB Control No. 

2137–0625 to be reduced and the 

burden for information collection under 

OMB Control No. 2137–0522 for the 

collection of annual and incident report 

data to increase due to the creation of 

the new form. Specifically, PHMSA 

expects each small LPG operator to 

spend 6 hours, annually, completing the 

new report form, resulting in an 

increase of 4,492 responses and 26,952 

hours to the overall burden for the 

information collection under OMB 

Control No. 2137–0522. For the 

information collection under OMB 

Control No. 2137–0625, PHMSA 

previously estimated there were 2,539 

operators of small LPG systems. 

Consequently, PHMSA expects the 

burden of that currently approved 

collection to be reduced by 2,539 

responses and 66,014 hours due to the 

removal of small LPG operators. 

PHMSA also plans to revise the ‘‘Gas 

Distribution Annual Report Form 

F7100.1–1’’ information collection 

currently approved under OMB Control 

No. 2137–0629 to include the newly 

proposed requirements. For gas 

distribution pipelines, PHMSA proposes 

to collect additional information such as 

the number and miles of low-pressure 

service pipelines, including their 

overpressure protection methods. 

PHMSA 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 and 

is a consideration when PHMSA awards 

grants to states supporting those 

programs. PHMSA plans to revise the 

‘‘Gas Pipeline Safety Program 

Performance Progress Report’’ and 

‘‘Hazardous Liquid Pipeline Safety 

Program Performance Progress Report’’ 

information collection currently 

approved under OMB Control No. 2137– 

0584 to account for the burden incurred 

by state representatives to report data 

via the SICT. 

Operators are required to maintain 

records pertaining to various aspects of 

their pipeline systems. Under the 

proposals in this rulemaking, PHMSA 

would expand the recordkeeping 

requirements for all gas pipeline 

operators. Operators would be required 

to revise their emergency response plans 

to include 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 would also be required to 

immediately and directly notify 

emergency response officials upon 

receiving notice of the same. For 

distribution pipeline operators only, 


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PHMSA’s proposed expansion of the list 

of emergencies discussed above would 

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 a series of 

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 introduce a new requirement for gas 

distribution operators to establish and 

maintain communications with the 

general public as soon as practicable 

during an emergency. Second, PHMSA 

proposes to add a new requirement for 

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 status of pipeline safety in their 

communities should an emergency 

occur. PHMSA also proposes a new 

requirement for gas distribution 

operators to notify their customers and 

public officials in certain instances. 

PHMSA plans to create a new 

information collection to cover these 

notification requirements for gas 

distribution operators. PHMSA will 

request a new Control Number from 

OMB for these information collections. 

PHMSA will submit these information 

collection requests to OMB for approval 

based on the proposed requirements in 

this rule. 

Operators would also be required to 

review and update their O&M manuals 

as needed pursuant to the proposal. Gas 

distribution operators would also be 

required to document and maintain 

records on their MOC processes and 

additional safety procedures. Further, 

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 overpressureprotection 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. PHMSA plans to revise the 

‘‘Recordkeeping Requirements for Gas 

Pipeline Operators’’ information 

collection currently approved under 

OMB Control No. 2137–0049 to include 

the newly proposed recordkeeping 

requirements. PHMSA expects the 

impact to be minimal and absorbed by 

the currently approved burden for this 

information collection. 

The information collections in this 

proposed rule would be required 

through the proposed amendments to 

the pipeline safety regulations, 49 CFR 

190–199. The following information is 

provided for each information 

collection: (1) Title of the information 

collection; (2) OMB control number; (3) 

Current expiration date; (4) Type of 

request; (5) Abstract of the information 

collection activity; (6) Description of 

affected public; (7) Estimate of total 

annual reporting and recordkeeping 

burden; and (8) Frequency of collection. 

The information collection burden 

under the proposed rule is estimated as 

follows: 

1. Title: Pipeline Safety: Integrity 

Management Program for Gas 

Distribution Pipelines. 

OMB Control Number: 2137–0625. 

Current Expiration Date: 5/31/2024. 

Abstract: The pipeline safety 

regulations require operators of gas 

distribution pipelines to develop and 

implement integrity management (IM) 

programs. The purpose of these 

programs is to enhance safety by 

identifying and reducing pipeline 

integrity risks. PHMSA requires 

operators to maintain records 

demonstrating compliance with this 

information collection for 10 years. 

PHMSA uses the information to 

evaluate the overall effectiveness of gas 

distribution Integrity Management 

requirements. 

PHMSA proposes to repeal the 

requirement for operators of small LPGs 

to participate in the distribution IM 

program. PHMSA previously estimated 

that there were 2,539 operators of small 

LPG systems. Consequently, PHMSA 

expects the burden of this information 

collection to be reduced by 2,539 

responses and 66,014 hours due to the 

removal of small LPG operators. 

Affected Public: Owners and 

operators of gas distribution pipelines. 

Annual Reporting Burden: 

Total Annual Responses: 1,343. 

Total Annual Burden Hours: 657,178. 

Frequency of Collection: On occasion. 

2. Title: Recordkeeping Requirements 

for Gas Pipeline Operators. 

OMB Control Number: 2137–0049. 

Current Expiration Date: 3/31/2025. 

Abstract: This mandatory information 

collection request would require owners 

and/or operators of gas pipeline systems 

to make and maintain records in 

accordance with the requirements 

prescribed in 49 CFR part 192 and to 

provide information to the Secretary of 

Transportation at the Secretary’s 

request. Certain records are maintained 

for a specific length of time while others 

are required to be maintained for the life 

of the pipeline. PHMSA uses these 

records to verify compliance with 

regulated safety standards and to inform 

the agency on possible safety risks. 

Affected Public: Operators of gas 

pipeline systems. 

Annual Reporting Burden: 

Total Annual Responses: 4,056,052. 

Total Annual Burden Hours: 

5,031,086. 

Frequency of Collection: On occasion. 

3. Title: Emergency Notification 

Requirements for Gas Operators. 

OMB Control Number: Will Request 

from OMB. 

Current Expiration Date: TBD. 

Abstract: This information collection 

covers the requirement for owners and 

operators of gas distribution pipelines to 

notify their customers and public 

officials in the event of certain instances 

pertaining to pipeline safety. PHMSA 

estimates there will be an average of 75 

incidents per year where gas 

distribution operators will need to make 

such notifications. PHMSA expects gas 

distribution operators will spend 

approximately 8 hours notifying the 

public in each instance, resulting in an 

annual burden of 600 hours. PHMSA 

expects gas distribution operators to 

spend an additional 2 hours per 

incident notifying their customers, 

resulting in an added burden of 150 

hours. PHMSA also requires operators 

of all gas pipelines to notify and 

communicate with emergency 

responders if gas is detected inside or 

near a building; fire is located near or 

directly involving a pipeline facility; 

and explosion occurs near or directly 

involving a pipeline facility; or in the 

event of a natural disaster. Based on 

incident report trends, PHMSA expects 

there to be 44 incidents (1 gas gathering, 

16 gas transmission, 27 gas distribution) 

annually, which would require gas 

operators to notify emergency 

responders. PHMSA estimates each 

notification will take 2 hours per 

incident resulting in an annual burden 

of 88 hours. 


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Affected Public: Owners and 

operators of gas pipelines. 

Annual Reporting Burden: 

Total Annual Responses: 194. 

Total Annual Burden Hours: 838. 

Frequency of Collection: On occasion. 

4. Title: Annual and Incident Report 

for Gas Pipeline Operators. 

OMB Control Number: 2137–0522. 

Current Expiration Date: 03/31/2026. 

Abstract: This mandatory information 

collection covers the collection of data 

from operators of natural gas pipelines, 

underground natural gas storage 

facilities, and liquefied natural gas 

(LNG) facilities for annual reports. 49 

CFR 191.17 requires operators of 

underground natural gas storage 

facilities, gas transmission systems, and 

gas gathering systems to submit an 

annual report by March 15 for the 

preceding calendar year. The Gas 

Distribution NPRM proposes to collect 

limited data from operators of small 

LPGs. PHMSA proposes to create Form 

F7100.1–2. to collect this data, ‘‘Small 

LPG Annual Report Form F7100.1–2.’’ 

The burden for this information 

collection is being revised to account for 

this new data collection. PHMSA 

estimates that 4,492 small LPG operators 

will spend 6 hours annually completing 

this new report resulting in an increase 

of 4,492 responses and 26,952 hours to 

the currently approved burden for this 

information collection. 

Affected Public: Owners and 

operators of gas distribution pipelines. 

Annual Reporting Burden: 

Total Annual Responses: 7,813. 

Total Annual Burden Hours: 122,763. 

Frequency of Collection: Annually. 

5. Title: Gas Pipeline Safety Program 

Performance Progress Report and 

Hazardous Liquid Pipeline Safety 

Program Performance Progress Report. 

OMB Control Number: 2137–0584. 

Current Expiration Date: 5/31/2025. 

Abstract: 49 U.S.C. 60105 sets forth 

specific requirements a State must meet 

to qualify for certification status to 

assume regulatory and enforcement 

responsibility for intrastate pipelines, 

i.e., state adoption of minimum Federal 

safety standards, state inspection of 

pipeline operators to determine 

compliance with the standards, and 

state provision for enforcement 

sanctions substantially the same as 

those authorized by Chapter 601, Title 

49 of the U.S. Code. A State must 

submit an annual certification to assume 

responsibility for regulating intrastate 

pipelines, and states who receive 

Federal grant funding must have 

adequate damage prevention plans and 

associated records in place. PHMSA 

uses this information to evaluate a 

State’s eligibility for Federal grants and 

to enforce regulatory compliance. This 

information collection request requires a 

participating State to annually submit a 

Gas Pipeline Safety Program 

Performance Progress Report and 

Hazardous Liquid Pipeline Safety 

Program Performance Progress Report to 

PHMSA’s Office of Pipeline Safety 

(OPS) signifying compliance with the 

terms of the certification and to 

maintain records detailing a damage 

prevention plan for PHMSA inspectors 

whenever requested. The purpose of the 

collection is to exercise oversight of the 

grant program and to ensure that States 

are compliant with Federal pipeline 

safety regulations. PHMSA is revising 

this information collection to include 

the reporting of inspection data via the 

State Inspection Calculation Tool 

(SICT). PHMSA expects 66 State 

representatives to submit data 

pertaining to the number of safety 

inspectors employed in their pipeline 

safety programs via the SICT. PHMSA 

estimates that, on average, State 

representatives will spend 8 hours 

annually compiling and submitting 

SICT data. 

Affected Public: Pipeline operators 

applying for State grants. 

Annual Reporting Burden: 

Total Annual Responses: 183. 

Total Annual Burden Hours: 5,001. 

Frequency of Collection: Annual. 

6. Title: Annual for Gas Distribution 

Operators. 

OMB Control Number: 2137–0629. 

Current Expiration Date: 06/30/2026. 

Abstract: This mandatory information 

collection request would require 

operators of gas distribution pipeline 

systems to submit annual report data to 

the Office of Pipeline Safety in 

accordance with the regulations 

stipulated in 49 CFR part 191 by way of 

form PHMSA F 7100.1–1. The form is to 

be submitted once for each calendar 

year. The annual report form collects 

data about the pipe material, size, and 

age. The form also collects data on leaks 

from these systems as well as excavation 

damages. PHMSA uses the information 

to track the extent of gas distribution 

systems and normalize incident and 

leak rates. 

The Gas Distribution NPRM proposes 

to revise the Annual Report for Gas 

Distribution Operators, form PHMSA F 

7100.1–1, to collect additional 

information on gas distribution systems 

such as the number and miles of lowpressure service pipelines, including 

their overpressure protection methods. 

The current approved burden for gas 

distribution operators to complete this 

report is 20 hours, annually. As a result 

of the proposed change, the burden for 

completing PHMSA F 7100.1-collection 

is being increased by 6 hours annually, 

resulting in an overall burden of 26 

hours, per annual report, for gas 

distribution operators. 

Affected Public: Owners and 

operators of gas distribution pipelines. 

Annual Reporting Burden: 

Total Annual Responses: 1,446. 

Total Annual Burden Hours: 37,596. 

Frequency of Collection: Annually. 

Requests for a copy of these 

information collections should be 

directed to Angela Hill via email at 

angela.hill@dot.gov or via telephone 

(202) 366–4595. 

Comments are invited on: 

(a) The need for the proposed 

collection of information for the proper 

performance of the functions of the 

agency, including whether the 

information will have practical utility; 

(b) The accuracy of the agency’s 

estimate of the burden of the revised 

collection of information, including the 

validity of the methodology and 

assumptions used; 

(c) Ways to enhance the quality, 

utility, and clarity of the information to 

be collected; 

(d) Ways to minimize the burden of 

the collection of information on those 

who are to respond, including the use 

of appropriate automated, electronic, 

mechanical, or other technological 

collection techniques; and 

(e) Ways the collection of this 

information is beneficial or not 

beneficial to public safety. 

Send comments directly to the Office 

of Management and Budget, Office of 

Information and Regulatory Affairs, 

Attn: Desk Officer for the Department of 

Transportation, 725 17th Street NW, 

Washington, DC 20503. 

G. Unfunded Mandates Reform Act of 

1995 

The Unfunded Mandates Reform Act 

(UMRA, 2 U.S.C. 1501 et seq.) requires 

agencies to assess the effects of Federal 

regulatory actions on State, local, and 

Tribal governments, and the private 

sector. For any NPRM or final rule that 

includes a Federal mandate that may 

result in the expenditure by State, local, 

and Tribal governments, in the aggregate 

of $100 million or more (in 1996 

dollars) in any given year, the agency 

must prepare, amongst other things, a 

written statement that qualitatively and 

quantitatively assesses the costs and 

benefits of the Federal mandate. 

As explained further in the PRIA, 

PHMSA does not expect that the 

proposed rule will impose enforceable 

duties on State, local, or Tribal 

governments or on the private sector of 

$100 million or more (in 1996 dollars) 

in any one year. A copy of the PRIA is 


ddrumheller on DSK120RN23PROD with PROPOSALS3
Federal Register / Vol. 88, No. 172 / Thursday, September 7, 2023 / Proposed Rules 61799 

195 64 FR 43255 (Aug. 10, 1999). 

196 74 FR 24693 (May 22, 2009). 197 66 FR 28355 (May 22, 2001). 198 77 FR 26413 (May 4, 2012). 

available for review in the docket. 

Therefore, the requirement to prepare a 

statement pursuant to UMRA does not 

apply. 

H. National Environmental Policy Act 

The National Environmental Policy 

Act of 1969 (NEPA, 42 U.S.C. 4321 et 

seq.) requires Federal agencies to 

prepare a detailed statement on major 

Federal actions significantly affecting 

the quality of the human environment. 

The Council on Environmental Quality’s 

implementing regulations (40 CFR parts 

1500–1508) require Federal agencies to 

conduct an environmental review 

considering (1) the need for the action, 

(2) alternatives to the action, (3) 

probable environmental impacts of the 

action and alternatives, and (4) the 

agencies and persons consulted during 

the consideration process. DOT Order 

5610.1C (‘‘Procedures for Considering 

Environmental Impacts’’) establishes 

departmental procedures for evaluation 

of environmental impacts under NEPA 

and its implementing regulations. 

PHMSA has completed a draft 

environmental assessment and expects 

that an environmental impact statement 

will not be required for this rulemaking 

because it will not have a significant 

impact on the human environment. To 

the extent that the proposed rule could 

impact the environment, PHMSA 

expects those impacts will be primarily 

beneficial impacts from reducing the 

likelihood and consequences of 

incidents on gas distribution pipelines 

and other part 192-regulated gas 

pipelines. A copy of the draft 

environmental assessment is available 

in the docket. PHMSA invites comment 

on the potential environmental impacts 

of this proposed rule. 

I. Executive Order 13132: Federalism 

PHMSA has analyzed this proposed 

rule in accordance with the principles 

and criteria contained in Executive 

Order 13132 (‘‘Federalism’’) 195 and the 

Presidential Memorandum titled 

‘‘Preemption.’’ 196 Executive Order 

13132 requires agencies to ensure 

meaningful and timely input by State 

and local officials in the development of 

regulatory policies that may have 

‘‘substantial direct effects on the states, 

on the relationship between the national 

government and the states, or on the 

distribution of power and 

responsibilities among the various 

levels of government.’’ 

PHMSA does not expect this 

proposed rule will have a substantial 

direct effect on State and local 

governments, the relationship between 

the Federal Government and the States, 

or the distribution of power and 

responsibilities among the various 

levels of government. The provisions 

proposed involving SICT codify in 

regulation existing practice and do not 

impose any noteworthy additional 

direct compliance costs on State and 

local governments. 

States are generally prohibited by 49 

U.S.C. 60104(c) from regulating the 

safety of interstate pipelines. States that 

have submitted a current certification 

under 49 U.S.C. 60105(a) can augment 

Federal pipeline safety requirements for 

intrastate pipelines regulated by 

PHMSA but may not approve safety 

requirements less stringent than those 

required by Federal law. A State may 

also regulate an intrastate pipeline 

facility that PHMSA does not regulate. 

In this instance, the preemptive effect 

of the proposed rule would be limited 

to the minimum level necessary to 

achieve the objectives of the statutory 

authority under which the proposed 

rule is promulgated. While the 49 CFR 

part 192 safety requirements in this 

proposed rule may, if adopted in a final 

rule, preempt some State requirements, 

preemption arises by operation of 49 

U.S.C. 60104, and this proposed rule 

would not impose any regulation that 

has substantial direct effects on the 

states, the relationship between the 

national government and the states, or 

the distribution of power and 

responsibilities among the various 

levels of government. Therefore, the 

PHMSA has determined that the 

consultation and funding requirements 

of Executive Order 13132 do not apply 

to this proposed rule. 

J. Executive Order 13211: Significant 

Energy Actions 

Executive Order 13211 (‘‘Actions 

Concerning Regulations That 

Significantly Affect Energy Supply, 

Distribution, or Use’’) 197 requires 

Federal agencies to prepare a Statement 

of Energy Effects for any ‘‘significant 

energy action.’’ Executive Order 13211 

defines a ‘‘significant energy action’’ as 

any action by an agency (normally 

published in the Federal Register) that 

promulgates or is expected to lead to the 

promulgation of a final rule or 

regulation that (1)(i) is a significant 

regulatory action under Executive Order 

12866 or any successor order, and (ii) is 

likely to have a significant adverse effect 

on the supply, distribution, or use of 

energy; or (2) is designated by OIRA as 

a significant energy action. 

This proposed rule is not anticipated 

to be a ‘‘significant energy action’’ under 

Executive Order 13211. It is not likely 

to have a significant adverse effect on 

the supply, distribution, or use of 

energy. Further, the OIRA has not 

designated this proposed rule as a 

significant energy action. 

K. Privacy Act Statement 

In accordance with 5 U.S.C. 553(c), 

DOT solicits comments from the public 

to better inform its rulemaking process. 

DOT posts these comments without 

edit, including any personal information 

the commenter provides, to https://

www.regulations.gov, as described in 

the system of records notice (DOT/ALL– 

14 FDMS), which can be reviewed at 

https://www.dot.gov/privacy. 

L. Regulation Identifier Number 

A regulation identifier number (RIN) 

is assigned to each regulatory action 

listed in the Unified Agenda of 

Regulatory and Deregulatory Actions 

(Unified Agenda). The RIN contained in 

the heading of this document can be 

used to cross-reference this action with 

the Unified Agenda. 

M. Executive Order 13609 and 

International Trade Analysis 

Executive Order 13609 (‘‘Promoting 

International Regulatory 

Cooperation’’) 198 requires agencies to 

consider whether the impacts associated 

with significant variations between 

domestic and international regulatory 

approaches are unnecessary or may 

impair the ability of American business 

to export and compete internationally. 

In meeting shared challenges involving 

health, safety, labor, security, 

environmental, and other issues, 

international regulatory cooperation can 

identify approaches that are at least as 

protective as those that are or would be 

adopted in the absence of such 

cooperation. International regulatory 

cooperation can also reduce, eliminate, 

or prevent unnecessary differences in 

regulatory requirements. 

Similarly, the Trade Agreements Act 

of 1979 (Pub. L. 96–39), as amended by 

the Uruguay Round Agreements Act 

(Pub. L. 103–465), prohibits Federal 

agencies from establishing any 

standards or engaging in related 

activities that create unnecessary 

obstacles to the foreign commerce of the 

United States. For purposes of these 

requirements, Federal agencies may 

participate in the establishment of 

international standards so long as the 

standards have a legitimate domestic 

objective, such as providing for safety, 


ddrumheller on DSK120RN23PROD with PROPOSALS3
61800 Federal Register / Vol. 88, No. 172 / Thursday, September 7, 2023 / Proposed Rules 

199 86 FR 26633 (May 17, 2021). 

200E.g., TSA, ‘‘Ratification of Security Directive,’’ 

86 FR 38209 (July 20, 2021) (ratifying TSA Security 

Directive Pipeline–2012–01, which requires certain 

pipeline owners and operators to conduct actions 

to enhance pipeline cybersecurity). 

201See, e.g., CISA, National Cyber Awareness 

System Alerts, https://www.cisa.gov/uscert/ncas/ 

alerts (last accessed Feb. 1, 2023). 

and do not operate to exclude imports 

that meet this objective. The statute also 

requires consideration of international 

standards and, where appropriate, that 

they serve as the basis for U.S. 

standards. PHMSA participates in the 

establishment of international standards 

to protect the safety of the American 

public. 

PHMSA assessed the effects of the 

proposed rule and expects that it will 

not cause unnecessary obstacles to 

foreign trade. 

N. Cybersecurity and Executive Order 

14028 

Executive Order 14028 (‘‘Improving 

the Nation’s Cybersecurity’’) 199 directed 

the Federal government to improve its 

efforts to identify, deter, and respond to 

‘‘persistent and increasingly 

sophisticated malicious cyber 

campaigns.’’ Accordingly, PHMSA has 

assessed the effects of this NPRM to 

determine what impact the proposed 

regulatory amendments may have on 

cybersecurity risks for pipeline facilities 

and has preliminarily determined that 

this NPRM will not materially affect the 

cybersecurity risk profile for pipeline 

facilities. 

Operator DIMPs, O&M manuals and 

procedures, and facility design 

standards are largely static materials; 

because those materials are not means of 

manipulating pipeline operations in 

real-time, PHMSA’s proposed 

amendments of requirements governing 

those materials are therefore unlikely to 

increase the risk of cybersecurity 

incidents. Although other proposals 

within the NPRM—in particular, realtime overpressurization monitoring and 

customer opt-in/opt-out emergency 

communication systems—may offer 

more attractive targets for cybersecurity 

incidents, PHMSA understands the 

incremental additional risk from the 

NPRM’s proposed regulatory 

amendments to be minimal. Operator 

compliance strategies for these proposed 

requirements will be subject to current 

Transportation Security Agency (TSA) 

pipeline cybersecurity directives; 200

PHMSA further understands 

Cybersecurity & Infrastructure Security 

Agency (CISA) and the Pipeline 

Cybersecurity Initiative (PCI) of the U.S. 

Department of Homeland Security 

conduct ongoing activities to address 

cybersecurity risks to U.S. pipeline 

infrastructure and may introduce other 

cybersecurity requirements and 

guidance for gas pipeline operators.201

Lastly, because PHMSA expects that 

this NPRM’s proposed regulatory 

amendments (notably those regarding 

emergency response planning) will 

reduce the severity of any gas pipeline 

incidents that occur, this rulemaking 

could reduce the public safety and the 

environmental consequences in the 

event of a cybersecurity incident on a 

gas pipeline. 

M. Severability 

The purpose of this proposed rule is 

to operate holistically in addressing a 

panoply of issues necessary to ensure 

safe operation of regulate pipelines, 

with a focus on gas distribution 

pipelines’ protection against 

overpressurization events. However, 

PHMSA recognizes that certain 

provisions focus on unique topics. 

Therefore, PHMSA preliminarily finds 

that the various provisions of this 

proposed rule are severable and able to 

function independently if severed from 

each other. In the event a court were to 

invalidate one or more of the unique 

provisions of any final rule issued in 

this proceeding, the remaining 

provisions should stand, thus allowing 

their continued effect. 

List of Subjects 

49 CFR Part 191 

Liquefied petroleum gas, Pipeline 

reporting requirements. 

49 CFR Part 192 

District regulator stations, Emergency 

response, Gas monitoring, Integrity 

management, Inspections, Gas, 

Overpressure protection, Pipeline 

safety, Reporting and recordkeeping 

requirements. 

49 CFR Part 198 

State inspector staffing requirements. 

For the reasons provided in the 

preamble, PHMSA proposes to amend 

49 CFR parts 191, 192, and 198 as 

follows: 

PART 191—TRANSPORTATION OF 

NATURAL AND OTHER GAS BY 

PIPELINE; ANNUAL, INCIDENT, AND 

OTHER REPORTING 

■ 1. The authority citation for 49 CFR 

part 191 continues to read as follows: 

Authority: 30 U.S.C. 185(w)(3); 49 U.S.C. 

5121, 60101 et seq., and 49 CFR 1.97. 

■ 2. Revise § 191.11 to read as follows: 

§ 191.11 Distribution system: Annual 

report. 

(a) General. Except as provided in 

paragraph (b) of this section, each 

operator of a distribution pipeline 

system, excluding a liquefied petroleum 

gas system that serves fewer than 100 

customers from a single source, must 

submit an annual report for that system 

on DOT Form PHMSA F 7100.1–1. Each 

operator of a liquefied petroleum gas 

system that serves fewer than 100 

customers from a single source must 

submit an annual report for that system 

on DOT Form PHMSA F 7100.1–2. 

Reports must be submitted each year, 

not later than March 15, for the 

preceding calendar year. 

(b) Not required. The annual report 

requirement in this section does not 

apply to a master meter system, a 

petroleum gas system excepted from 

part 192 in accordance with 

§ 192.1(b)(5), or an individual service 

line directly connected to a production 

pipeline or a gathering line other than 

a regulated gathering line as determined 

in § 192.8. 

PART 192—TRANSPORTATION OF 

NATURAL AND OTHER GAS BY 

PIPELINE: MINIMUM FEDERAL 

SAFETY STANDARDS 

■ 3. The authority citation for 49 CFR 

part 192 continues to read as follows: 

Authority: 30 U.S.C. 185(w)(3), 49 U.S.C. 

5103, 60101 et seq., and 49 CFR 1.97. 

§ 192.3 [Amended] 

■ 4. Amend § 192.3, by removing the 

last sentence ‘‘This definition does not 

apply to any gathering line.’’ from the 

definitions of ‘‘Entirely replaced 

onshore transmission pipeline 

segments’’, ‘‘Notification of potential 

rupture’’ and ‘‘Rupture-mitigation valve 

(RMV)’’. 

§ 192.9 [Amended] 

■ 5. Amend § 192.9 by: 

■ a. Removing from paragraph (b) the 

last sentence; 

■ b. Removing from paragraph (c) the 

last sentence; and 

■ c. Removing from paragraph (e)(1)(iv) 

the words ‘‘effective as of October 4, 

2022.’’ 

■ 6. Amend § 192.18 by revising 

paragraph (c) to read as follows: 

§ 192.18 How to notify PHMSA. 

* * * * * 

(c) Unless otherwise specified, if an 

operator submits, pursuant to §§ 192.8, 

192.9, 192.13, 192.179, 192.319, 

192.506, 192.607, 192.619, 192.624, 

192.632, 192.634, 192.636, 192.710, 

192.712, 192.714, 192.745, 192.917, 

192.921, 192.927, 192.933, 192.937, or 


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192.1007, a notification for use of a 

different integrity assessment method, 

analytical method, compliance period, 

sampling approach, pipeline material, 

or technique (e.g., ‘‘other technology’’ or 

‘‘alternative equivalent technology’’) 

than otherwise prescribed in those 

sections, that notification must be 

submitted to PHMSA for review at least 

90 days in advance of using the other 

method, approach, compliance timeline, 

or technique. An operator may proceed 

to use the other method, approach, 

compliance timeline, or technique 91 

days after submitting the notification 

unless it receives a letter from the 

Associate Administrator for Pipeline 

Safety, or his or her delegate, informing 

the operator that PHMSA objects to the 

proposal or that PHMSA requires 

additional time and/or more 

information to conduct its review. 

■ 7. Amend § 192.195 by adding 

paragraph (c) to read as follows: 

§ 192.195 Protection against accidental 

overpressuring. 

* * * * * 

(c) Additional requirements for lowpressure distribution systems. Each 

regulator station, serving a low-pressure 

distribution system, that is new, 

replaced, relocated, or otherwise 

changed after [ONE YEAR AFTER THE 

PUBLICATION DATE OF THE RULE] 

must include: 

(1) At least two methods of 

overpressure protection (such as a relief 

valve, monitoring regulator, or 

automatic shutoff valve) appropriate for 

the configuration and siting of the 

station; 

(2) Measures to minimize the risk of 

overpressurization of the low-pressure 

distribution system that could be caused 

by any 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; and 

(3) Remote monitoring of gas pressure 

at or near the location of overpressure 

protection devices. 

■ 8. Amend § 192.305 by: 

■ a. Lifting the stay of the section; and 

■ b. Revising the section. 

The revision reads as follows: 

§ 192.305 Inspections: General. 

(a) Each transmission pipeline and 

main that is new, replaced, relocated, or 

otherwise changed after [ONE YEAR 

AFTER THE PUBLICATION DATE OF 

THE RULE] must be inspected to ensure 

that it is constructed in accordance with 

this subpart. Except as provided in 

paragraph (b) of this section, an operator 

must not use operator personnel to 

perform a required inspection if the 

operator personnel performed the 

construction task requiring inspection. 

Nothing in this section prohibits the 

operator from inspecting construction 

tasks with operator personnel who are 

involved in other construction tasks. 

(b) For the construction inspection of 

a main that is new, replaced, relocated, 

or otherwise changed after [ONE YEAR 

AFTER THE PUBLICATION DATE OF 

THE RULE], operator personnel 

involved in the same construction task 

may inspect each other’s work in 

situations where the operator could 

otherwise only comply with the 

construction inspection requirement in 

paragraph (a) of this section by using a 

third-party inspector. This justification 

must be documented and retained for 

the life of the pipeline. 

■ 9. Amend § 192.517 by revising 

paragraph (b) to read as follows: 

§ 192.517 Records. 

* * * * * 

(b) Each operator must maintain a 

record of each test required by 

§§ 192.509, 192.511, and 192.513 for the 

life of the pipeline. 

(1) For tests performed before [ONE 

YEAR AFTER THE PUBLICATION 

DATE OF THE FINAL RULE] for which 

records are maintained, the record must 

continue to be maintained for the life of 

the pipeline. 

(2) For tests performed on or after 

[ONE YEAR AFTER THE 

PUBLICATION DATE OF THE FINAL 

RULE], the records must contain at least 

the following information: 

(i) The operator’s name, the name of 

the employee responsible for making the 

test, and the name of the company or 

contractor used to perform the test. 

(ii) Pipeline segment pressure tested. 

(iii) Test date. 

(iv) Test medium used. 

(v) Test pressure. 

(vi) Test duration. 

(vii) Leaks and failures noted and 

their disposition. 

■ 10. Amend § 192.605 by adding 

paragraphs (b)(13), (f), and (g) to read as 

follows: 

§ 192.605 Procedural manual for 

operations, maintenance, and emergencies. 

* * * * * 

(b) * * * 

(13) Implementing the applicable 

requirements for distribution systems in 

paragraphs (f) and (g) of this section, 

§ 192.638, and § 192.640. 

* * * * * 

(f) Overpressurization. For 

distribution lines, the manual required 

by paragraph (a) of this section must, no 

later than [ONE YEAR AFTER THE 

PUBLICATION DATE OF THE RULE], 

include procedures for responding to, 

investigating, and correcting, as soon as 

practicable, the cause of 

overpressurization indications. The 

procedures must include the specific 

actions and an order of operations for 

immediately reducing pressure in or 

shutting down portions of the 

distribution system affected by an 

overpressurization. 

(g) Management of Change (MOC) 

Process. For distribution lines, the 

manual required by paragraph (a) of this 

section must, no later than [ONE YEAR 

AFTER THE PUBLICATION DATE OF 

THE RULE], include a detailed MOC 

process for the following: 

(1) Technology, equipment, 

procedural, and organizational changes, 

including: 

(i) Installations, modifications, 

replacements, or upgrades to regulators, 

pressure monitoring locations, or 

overpressure protection devices; 

(ii) Modifications to alarm set points 

or upper/lower trigger limits on 

monitoring equipment; 

(iii) The introduction of new 

technologies for overpressure protection 

into the system; 

(iv) Revisions, changes, or the 

introduction of new standard operating 

procedures for design, construction, 

installation, maintenance, and 

emergency response; 

(v) Other changes that may impact the 

integrity or safety of the gas distribution 

system. 

(2) Ensuring that personnel—such as 

an engineer with a professional engineer 

license, a subject matter expert, or 

another person who possesses the 

necessary knowledge, experience, and 

skills regarding gas distribution 

systems—review and certify 

construction plans associated with 

installations, modifications, 

replacements, or system upgrades for 

accuracy and completeness before the 

work begins. These personnel must be 

qualified to perform these tasks under 

subpart N of this part. 

(3) Ensuring that any hazards 

introduced by a change are identified, 

analyzed, and controlled before 

resuming operations. 

■ 11. Amend § 192.615 by: 

■ a. Adding paragraphs (a)(3)(v) through 

(viii); 

■ b. Revising paragraph (a)(8); and 

■ c. Adding paragraphs (a)(13) and 

paragraph (d). 

The additions and revision read as 

follows: 

§ 192.615 Emergency plans. 

(a) * * * 

(3) * * * 


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(v) Notification of potential rupture 

(see § 192.635). 

(vi) Beginning no later than [ONE 

YEAR AFTER THE PUBLICATION 

DATE OF THE FINAL RULE], release of 

gas that results in one or more fatalities. 

(vii) Beginning no later than [ONE 

YEAR AFTER THE PUBLICATION 

DATE OF THE FINAL RULE], for 

distribution line operators only, 

unintentional release of gas and 

shutdown of gas service to 50 or more 

customers or, if the operator has fewer 

than 100 customers, 50 percent or more 

of its total customers. 

(viii) Beginning no later than [ONE 

YEAR AFTER THE PUBLICATION 

DATE OF THE FINAL RULE], any other 

emergency deemed significant by the 

operator. 

* * * * * 

(8) Notifying the appropriate public 

safety answering point (i.e., 9–1–1 

emergency call center) where direct 

access to a 9–1–1 emergency call center 

is available from the location of the 

pipeline, and fire, police, and other 

public officials, of gas pipeline 

emergencies to coordinate and share 

information to determine the location of 

the emergency, including both planned 

responses and actual responses during 

an emergency. The operator must 

immediately and directly notify the 

appropriate public safety answering 

point or other coordinating agency for 

the communities and jurisdictions in 

which the pipeline is located after 

receiving notice of a gas pipeline 

emergency under paragraph (a)(3) of this 

section. The operator must coordinate 

and share information to determine the 

location of any release, regardless of 

whether the segment is subject to the 

requirements of §§ 192.179, 192.634, or 

192.636. 

* * * * * 

(13) For distribution line operators, 

beginning no later than [ONE YEAR 

AFTER THE PUBLICATION DATE OF 

THE FINAL RULE], establishing and 

maintaining communication with the 

general public in the operator’s service 

area as soon as practicable during a gas 

pipeline emergency on a distribution 

line. The communication(s) must be in 

English, and any other languages 

commonly understood by a significant 

number and concentration of the nonEnglish speaking population in the 

operator’s service area; be in one or 

more formats or media accessible to the 

population in the operator’s service 

area; continue through service 

restoration and recovery efforts; and 

provide the following: 

(i) Information regarding the gas 

pipeline emergency; 

(ii) The status of the emergency (e.g., 

have the condition causing the 

emergency or the resulting public safety 

risks been resolved); 

(iii) Status of pipeline operations 

affected by the gas pipeline emergency, 

and when possible, a timeline for 

expected service restoration; and 

(iv) Directions for the public to 

receive assistance. 

The operator must provide updates 

when the information in 

§ 192.615(a)(13)(i) through (iv) changes. 

* * * * * 

(d) No later than [DATE 18 MONTHS 

AFTER THE PUBLICATION DATE OF 

THE RULE], each distribution line 

operator must develop and implement a 

system, including written procedures, 

that allows operators to rapidly 

communicate with customers in the 

event of a gas pipeline emergency under 

this section. The notification system 

must be voluntary for the public, 

allowing customers to opt-in (or opt-out) 

to receiving notifications from the 

system. The written procedures must 

provide for the following: 

(i) A description of the notification 

system and how it will be used to notify 

customers of a gas pipeline emergency; 

(ii) Who is responsible for the 

development, operation, and 

maintenance of the system; 

(iii) How information on the system is 

delivered to customers, ensuring that all 

customers are notified of the existence 

of the system and necessary steps if they 

wish to opt-in (or opt-out); 

(iv) Description of the system-wide 

testing protocol, including the testing 

interval (which must not be less than 

once per calendar year), to ensure the 

system is functioning properly and 

performing notifications as designed; 

(v) Maintenance of the results of 

testing and operations history for at 

least 5 years; 

(vi) Details regarding how the 

operator ensures messages are accessible 

in other languages commonly 

understood by a significant number and 

concentration of the non-English 

speaking population in the operator’s 

area; 

(vii) Message content, including 

updates as emergency conditions 

change; 

(viii) A process to initiate, conduct, 

and complete notifications; and 

(ix) Cybersecurity measures to protect 

the system and customer information. 

■ 12. Add § 192.638 to read as follows: 

§ 192.638 Distribution lines: Records for 

pressure controls. 

(a) An operator of a distribution 

system, except those identified in 

paragraph (f) of this section, must, no 

later than [ONE YEAR AFTER THE 

PUBLICATION DATE OF THE RULE], 

identify and maintain traceable, 

verifiable, and complete records that 

document the characteristics of its 

pipeline system that are critical to 

ensuring proper pressure control. These 

records must include: 

(1) Current location information 

(including maps and schematics) for 

regulators, valves, and underground 

piping (including control lines); 

(2) Attributes of the regulator(s), such 

as set points, design capacity, and the 

valve failure position (open/closed); 

(3) The overpressure protection 

configuration; and 

(4) Other records deemed critical. 

(b) If an operator does not have 

traceable, verifiable, and complete 

records as required by paragraph (a) of 

this section, the operator must, no later 

than [ONE YEAR AFTER THE 

PUBLICATION DATE OF THE RULE], 

identify and document those records 

needed and develop and implement 

procedures for collecting those records. 

(c) The records identified in 

paragraph (a) of this section must be 

collected, generated, or updated on an 

opportunistic basis, as specified in 

§ 192.1007(a)(3). 

(d) An operator must ensure the 

records required by this section are 

accessible to all personnel responsible 

for performing or supervising design, 

construction, operations, and 

maintenance activities. 

(e) An operator must retain the 

records required in this section for the 

life of the pipeline. 

(f) Exception. This section does not 

apply to master meter systems, liquefied 

petroleum gas (LPG) distribution 

pipeline systems that serve fewer than 

100 customers from a single source, or 

any individual service line directly 

connected to a transmission, gathering, 

or production pipeline that is not 

operated as part of a distribution 

system. 

■ 13. Add § 192.640 to read as follows: 

§ 192.640 Distribution lines: Presence of 

qualified personnel. 

(a) An operator of a distribution 

system must conduct a documented 

evaluation of each construction project 

that begins after [ONE YEAR AFTER 

THE PUBLICATION DATE OF THE 

RULE] to identify any potential project 

activities during which an 

overpressurization could occur at a 

district regulator station. This 

evaluation must occur before such 

activities begin. Activities that may 

present a potential for 

overpressurization include, but are not 

limited to, tie-ins, abandonment of 


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distribution lines, and equipment 

replacement. 

(b) If the evaluation in paragraph (a) 

of this section results in a determination 

that a potential for overpressurization 

exists during construction project 

activity, the operator must: 

(1) Ensure that at least one person 

qualified according to subpart N of this 

part is present at that district regulator 

station, or at an alternative site, during 

the construction project activity that 

could cause an overpressurization; 

(2) Monitor gas pressure with 

equipment capable of ensuring proper 

pressure controls; and 

(3) Have the capability to promptly 

shut off the flow of gas or control 

overpressurization at a district regulator 

station. 

(c) When monitoring the system as 

described in this section, the qualified 

personnel must be provided, at a 

minimum: information regarding the 

location of all valves necessary for 

isolating the pipeline system; pressure 

control records (see § 192.638); the 

authority to stop work (unless 

prohibited by operator procedures); 

operations procedures under § 192.605; 

and emergency response procedures 

under § 192.615. 

(d) Exception. Distribution systems 

with a remote monitoring system in 

effect with the capability for remote or 

automatic shutoff need not comply with 

the requirements in paragraphs (a) 

through (c) of this section. 

■ 14. Amend § 192.725 by revising 

paragraph (a) to read as follows: 

§ 192.725 Test requirements for reinstating 

service lines. 

(a) Except as provided in paragraph 

(b) of this section, each disconnected 

service line being restored to service on 

or after [ONE YEAR AFTER THE 

PUBLICATION DATE OF THE RULE] 

must be tested in the same manner as a 

new service line (i.e., tested in 

accordance with subpart J of this part) 

before being restored to service. 

* * * * * 

■ 15. Amend § 192.741 by: 

■ a. Revising the title of the section, and 

■ b. Adding paragraph (d). 

The revision and addition read as 

follows: 

§ 192.741 Pressure limiting and regulating 

stations: Telemetering, recording gauges, 

and other monitoring devices. 

* * * * * 

(d) On low-pressure distribution 

systems that are new, replaced, 

relocated, or otherwise changed after 

[ONE YEAR AFTER THE 

PUBLICATION DATE OF THE RULE], 

the operator must monitor the gas 

pressure in accordance with 

§ 192.195(c)(3). 

§ 192.1001 [AMENDED] 

■ 16. Amend § 192.1001 by removing 

the definition of ‘‘Small LPG Operator.’’ 

■ 17. Amend § 192.1003 by adding 

paragraph (b)(4) to read as follows: 

§ 192.1003 What do the regulations in this 

subpart cover? 

* * * * * 

(b) * * * 

(4) A system of a liquefied petroleum 

gas (LPG) distribution pipeline that 

serves fewer than 100 customers from a 

single source. 

■ 18. Amend § 192.1005 by revising the 

title of the section to read as follows: 

§ 192.1005 What must a gas distribution 

operator do to implement this subpart? 

■ 19. Amend § 192.1007 by revising 

paragraphs (a)(3), (b), (c), and (d) to read 

as follows: 

§ 192.1007 What are the required elements 

of an integrity management plan? 

* * * * * 

(a) * * * 

(3) Identify additional information 

needed and provide a plan for obtaining 

that information over time (including 

the records specified in § 192.638(c)) 

through normal activities conducted on 

the pipeline (for example, design, 

construction, operations, or 

maintenance activities). 

* * * * * 

(b) Identify threats. The operator must 

consider the following categories of 

threats to each gas distribution pipeline: 

corrosion (including atmospheric 

corrosion); natural forces (including 

extreme weather, land movement, and 

other geological hazards); excavation 

damage; other outside force damage; 

material (including the presence and age 

of pipes such as cast iron, bare steel, 

unprotected steel, wrought iron, and 

historic plastics with known issues) or 

welds; equipment failure; incorrect 

operations; overpressurization of lowpressure distribution systems; and other 

threats that pose a risk to the integrity 

of a pipeline. An operator must also 

consider the age of the system, pipe, and 

components in identifying threats. An 

operator must consider reasonably 

available information to identify 

existing and potential threats. Sources 

of data may include, but are not limited 

to, incident and leak history, corrosion 

control records (including atmospheric 

corrosion records), continuing 

surveillance records, patrolling records, 

maintenance history, and excavation 

damage experience. 

(c) Evaluate and rank risk. 

(1) General. An operator must 

evaluate the risks associated with its 

distribution pipeline. In this evaluation, 

the operator must determine the relative 

importance of each threat and estimate 

and rank the risks posed to its pipeline. 

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. An 

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, age, or 

environmental factors), and for which 

similar actions likely would be effective 

in reducing risk. 

(2) Certain pipe with known issues. 

An operator must, no later than [ONE 

YEAR AFTER THE PUBLICATION 

DATE OF THE RULE], evaluate the risks 

in the distribution system resulting from 

pipelines with known issues based on 

the material (including, cast iron, bare 

steel, unprotected steel, wrought iron, 

and historic plastics with known 

issues), design, age, or past operating 

and maintenance history. 

(3) Low-pressure Distribution Systems. 

An operator must, no later than [ONE 

YEAR AFTER THE PUBLICATION 

DATE OF THE RULE], 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. In the 

evaluation of risks, an operator must: 

(i) Evaluate factors other than past 

observed abnormal operating conditions 

(as defined in § 192.803) in ranking 

risks, including any known industry 

threats, risks, or hazards to public safety 

that could occur on its system based on 

knowledge gained from available 

sources; 

(ii) Evaluate potential consequences 

associated with low-probability events 

unless a determination, supported and 

documented by an engineering analysis, 

or an equivalent analysis incorporating 

operational knowledge, demonstrates 

that the event results in no potential 

consequences and therefore no potential 

risk. An operator must notify PHMSA 

and State or local pipeline safety 

authorities, as applicable, in accordance 

with § 192.18 within 30 days of making 

such a determination. The notification 

must include the following: 

(A) Date the determination was made; 

(B) Description of the low-probability 

event being considered; 

(C) Logic supporting the 

determination, including information 


ddrumheller on DSK120RN23PROD with PROPOSALS3
61804 Federal Register / Vol. 88, No. 172 / Thursday, September 7, 2023 / Proposed Rules 

from an engineering analysis, or an 

equivalent analysis incorporating 

operational knowledge; 

(D) Description of any preventive and 

mitigative measures, including any 

measures considered but not taken; 

(E) Details of the low-pressure system 

applicable to the event that results in no 

potential consequence and risk, 

including, at a minimum, the miles of 

pipe, number of customers, number of 

district regulators supplying the system, 

and other relevant information; and 

(F) Written statement summarizing 

the documentation provided in the 

notification. 

(iii) Evaluation of the configuration of 

primary and any secondary 

overpressure protection installed at 

district regulator stations (such as a 

relief valves, monitoring regulators, or 

automatic shutoff valves), the 

availability of gas pressure monitoring 

at or near overpressure protection 

equipment, and the likelihood of any 

single event (such as excavation 

damage, natural forces, equipment 

failure, or incorrect operations), that 

either immediately or over time, could 

result in an overpressurization of the 

low-pressure distribution system. 

(d) Identify and implement measures 

to address risks. 

(1) General. An operator must identify 

and implement measures to reduce the 

risks of failure of its distribution 

pipeline system. The measures 

identified and implemented must 

address, at a minimum, risks associated 

with the age of pipeline components, 

the overall age of the system and 

components, the presence of pipes with 

known issues, and overpressurization of 

low-pressure distribution systems. The 

measures must also include an effective 

leak management program (unless all 

leaks are repaired when found). 

(2) Minimization of 

Overpressurization of Low-Pressure 

Distribution Systems. An operator must, 

no later than [ONE YEAR AFTER THE 

PUBLICATION DATE OF THE RULE], 

implement the following preventive and 

mitigative measures to minimize the 

risk of overpressurization of a lowpressure distribution system that could 

be the result of any single event or 

failure: 

(i) Identify, maintain, and obtain, if 

necessary, pressure control records in 

accordance with §§ 192.638 and 

192.1007(a)(3). 

(ii) Confirm and document that each 

district regulator station meets the 

requirements of § 192.195(c)(1) through 

(3). If an operator determines that a 

district regulator station does not meet 

the requirements of § 192.195(c)(1) 

through (3), then by [ONE YEAR AFTER 

THE PUBLICATION DATE OF THE 

RULE], the operator must take either of 

the following actions: 

(A) Upgrade the district regulator 

station to meet the requirements of 

§ 192.195(c)(1) through (3), or 

(B) Identify alternative preventive and 

mitigative measures based on the 

unique characteristics of its system to 

minimize the risk of overpressurization 

of a low-pressure distribution system. 

The operator must notify PHMSA and 

State or local pipeline safety authorities, 

as applicable, no later than 90 days in 

advance of implementing any 

alternative measures. The notification 

must be made in accordance with 

§ 192.18(c) and must include a 

description of 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. 

* * * * * 

§ 192.1015 [Removed] 

■ 20. Remove § 192.1015. 

PART 198—REGULATIONS FOR 

GRANTS TO AID STATE PIPELINE 

SAFETY PROGRAMS 

■ 21. The authority citation for part 198 

continues to read as follows: 

Authority: 49 U.S.C. 60101 et seq.; 49 CFR 

1.97. 

■ 22. Amend § 198.3 by adding the 

definitions for ‘‘Inspection person-day’’ 

and ‘‘State Inspection Calculation Tool 

(SICT)’’ in alphabetical order to read as 

follows: 

§ 198.3 Definitions. 

* * * * * 

Inspection person-day means all or 

part of a day, including travel, spent by 

State agency personnel in on-site or 

virtual evaluation of a pipeline system 

to determine compliance with Federal 

or State pipeline safety regulations. 

* * * * * 

State Inspection Calculation Tool 

(SICT) means a tool used to determine 

the required number of annual 

inspection person-days for a State 

agency. 

* * * * * 

■ 23. Amend § 198.13 by revising 

paragraph (c)(6) to read as follows: 

§ 198.13 Grant-allocation formula. 

* * * * * 

(c) * * * 

(6) Number of state inspection persondays, as determined by the SICT and 

other factors; 

* * * * * 

Issued in Washington, DC, on August 23, 

2023, under authority delegated in 49 CFR 

1.97. 

Alan K. Mayberry, 

Associate Administrator for Pipeline Safety. 

[FR Doc. 2023–18585 Filed 9–6–23; 8:45 am] 

BILLING CODE 4910–60–P 


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