
[Federal Register Volume 88, Number 172 (Thursday, September 7, 2023)]
[Proposed Rules]
[Pages 61746-61804]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2023-18585]



[[Page 61745]]

Vol. 88

Thursday,

No. 172

September 7, 2023

Part III





Department of Transportation





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Pipeline and Hazardous Materials Safety Administration





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49 CFR Parts 191, 192, and 198





Pipeline Safety: Safety of Gas Distribution Pipelines and Other 
Pipeline Safety Initiative; Proposed Rule

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

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DEPARTMENT OF TRANSPORTATION

Pipeline and Hazardous Materials Safety Administration

49 CFR Parts 191, 192, and 198

[Docket No. PHMSA-2021-0046]
RIN 2137-AF53


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

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

ACTION: Notice of proposed rulemaking (NPRM).

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

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

ADDRESSES: Comments should reference Docket No. PHMSA-2021-0046 and may 
be submitted in any of the following ways:
    E-Gov Web: https://www.regulations.gov. This site allows the public 
to enter comments on any Federal Register notice issued by any agency. 
Follow the online instructions for submitting comments.
    Mail: Docket Management System: U.S. Department of Transportation, 
1200 New Jersey Avenue SE, West Building Ground Floor, Room W12-140, 
Washington, DC 20590-0001.
    Hand Delivery: DOT Docket Management System: West Building Ground 
Floor, Room W12-140, 1200 New Jersey Avenue SE, between 9:00 a.m. and 
5:00 p.m. ET, Monday-Friday, except Federal holidays.
    Fax: 202-493-2251
    Instructions: Include the agency name and identify Docket No. 
PHMSA-2021-0046 at the beginning of your comments. Note that all 
comments received will be posted without change to https://www.regulations.gov including any personal information provided. If you 
submit your comments by mail, submit two copies. If you wish to receive 
confirmation that PHMSA received your comments, include a self-
addressed stamped postcard.
    Confidential Business Information: Confidential Business 
Information (CBI) is commercial or financial information that is both 
customarily and actually treated as private by its owner. Under the 
Freedom of Information Act (5 U.S.C. 552), CBI is exempt from public 
disclosure. If your comments in response to this NPRM contain 
commercial or financial information that is customarily treated as 
private, that you actually treat as private, and that is relevant or 
responsive to this NPRM, it is important that you clearly designate the 
submitted comments as CBI. Pursuant to 49 Code of Federal Regulations 
(CFR) 190.343, you may ask PHMSA to provide confidential treatment to 
the information you give to the agency by taking the following steps: 
(1) mark each page of the original document submission containing CBI 
as ``Confidential;'' (2) send PHMSA a copy of the original document 
with the CBI deleted along with the original, unaltered document; and 
(3) explain why the information you are submitting is CBI. Submissions 
containing CBI should be sent to Ashlin Bollacker, 1200 New Jersey 
Avenue SE, DOT: PHMSA-PHP-30, Washington, DC 20590-0001. Any comment 
PHMSA receives that is not explicitly designated as CBI will be placed 
in the public docket.
    Docket: To access the docket, which contains background documents 
and any comments that PHMSA has received, go to https://www.regulations.gov. Follow the online instructions for accessing the 
docket. Alternatively, you may review the documents in person at DOT's 
Docket Management Office at the address listed above.

FOR FURTHER INFORMATION CONTACT: Ashlin Bollacker by phone at 202-680-
8303 or by email at [email protected].

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

[[Page 61747]]

residents. PHMSA expects the proposals of this NPRM will address the 
root causes and aggravating factors contributing to the severity of 
that incident and help reduce the frequency and consequence of other 
failure mechanisms on gas distribution pipeline systems. The proposals 
include improved design standards for low-pressure gas distribution 
systems; enhanced distribution integrity management program 
requirements; strengthened recordkeeping, planning, and monitoring 
practices for maintenance and construction activities on gas 
distribution systems; and improved emergency response communication and 
coordination protocols during emergency events for all 49 CFR part 192-
regulated gas pipelines.\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.
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    \1\ Part 192--regulated pipelines refers to gas distribution, 
transmission, and gathering pipelines, as applicable.
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    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 high-pressure gas 
entering low-pressure gas systems. The NTSB found that a common cause 
of failure was an overpressure protection design scheme, common on 
older low-pressure distribution systems, that can be defeated by a 
single failure mode (e.g., operator error or equipment failure). 
Currently, low-pressure gas systems are not required to have a device 
at the service location that would prevent the overpressurization of a 
customer's piping, fittings, and appliances, a required design feature 
on high-pressure distribution systems. Instead, overpressure protection 
on low-pressure distribution systems often is provided by a redundant 
design scheme (i.e., worker and monitor regulators at the regulator 
stations). While overpressurizations on distribution pipelines are 
infrequent, they have the potential to be catastrophic given their 
location within population centers. As a result of its investigation, 
the NTSB recommended that PHMSA revise the pipeline safety regulations 
to address overpressure protection failures like that which occurred on 
CMA's low-pressure system.
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    \2\ NTSB, Accident Report PAR-19/02, ``Overpressurization of 
Natural Gas Distribution System, Explosions, and Fires in Merrimack 
Valley, Massachusetts, September 13, 2018'' (Sept. 24, 2019), 
https://www.ntsb.gov/investigations/AccidentReports/Reports/PAR1902.pdf.
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    In 2020, the Leonel Rondon Pipeline Safety Act was enacted as 
sections 202-206 of the Protecting our Infrastructure of Pipelines and 
Enhancing Safety Act of 2020 (PIPES Act of 2020, Pub. L. N 116-260). 
The law requires PHMSA to amend its regulations to ensure operators 
evaluate the risks associated with the presence of cast iron piping and 
the possibility of overpressurization on gas distribution systems 
through updates to their distribution integrity management program 
(DIMP). (49 U.S.C. 60109(e)(7)). The law further requires PHMSA to 
amend its regulations to ensure operators' emergency response plans 
include timely communications with first responders, public officials, 
customers, and the general public. (49 U.S.C. 60102(r)). PHMSA was also 
directed to amend its regulations to ensure operators' operations and 
maintenance (O&M) manuals include procedures for responding to 
overpressurization and a management of change (MOC) process with review 
and certification by relevant qualified personnel. (49 U.S.C. 
60102(s)). PHMSA must also amend its regulations to ensure operators 
(1) keep ``traceable, reliable, and complete records;'' (2) monitor the 
gas pressure at district regulator stations during construction; and 
(3) assess and upgrade their district regulator stations to minimize 
the risk of overpressurization. (49 U.S.C. 60102(t)).
    Pursuant to its statutory authority and in furtherance of its 
mission to protect people and the environment by advancing the safe 
transportation of energy and other hazardous materials essential to our 
daily lives, PHMSA proposes in this NPRM a number of regulatory 
amendments to implement those statutory mandates and NTSB 
recommendations arising from the 2018 CMA overpressure incident. PHMSA 
expects the proposed regulatory amendments to reduce the likelihood of 
another overpressure incident on low-pressure gas distribution systems 
similar to that which occurred in Merrimack Valley. PHMSA also expects 
the proposed amendments to reduce the frequency of, as well as public 
and environmental consequences from, failure mechanisms on gas 
distribution pipeline systems and other pipeline facilities. 
Additionally, this rulemaking aligns with the Administration's efforts 
to improve environmental justice and combat the climate crisis.\3\ 
Older cast-iron or bare-steel gas distribution pipelines--a type of gas 
distribution pipeline particularly vulnerable to failure and 
overpressurization--are disproportionately concentrated in older, 
residential (often urban) areas with large minority, low- income, and 
other historically underserved and disadvantaged populations.\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.
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    \3\ The White House Office of Domestic Climate Policy, ``U.S. 
Methane Emissions Reduction Action Plan,'' (Nov. 2021), https://www.whitehouse.gov/wp-content/uploads/2021/11/US-Methane-Emissions-Reduction-Action-Plan-1.pdf. This and other PHMSA rulemakings are 
identified in the U.S. Methane Emissions Reduction Action Plan as 
critical elements in the Federal government's efforts to address the 
climate crisis. Id. at 7-8 (listing PHMSA's Leak Detection and 
Repair rulemaking (proposed in 88 FR 31890 (May 18, 2023) (Leak 
Detection NPRM)), its Gas Gathering Final Rule (86 FR 63266 (Nov. 
15, 2021)), its Valve Installation and Minimum Rupture Detection 
Standards Final Rule (87 FR 20940 (Apr. 8, 2022) (Valve Rule)), and 
its Gas Transmission Pipeline Safety Final Rule (87 FR 52224 (Aug. 
24, 2022)).
    \4\ See, e.g., Luna & Nicholas, ``An Environmental Justice 
Analysis of Distribution-Level Natural Gas Leaks in Massachusetts, 
USA,'' 162 Energy Policy 112778 (Mar. 2022); Weller et al., 
``Environmental Injustices of Leaks from Urban Natural Gas 
Distribution Systems: Patterns Among and Within 13 U.S. Metro 
Areas,'' Environ. Sci & Tech. (May 11, 2022).
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    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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and Modernization grant program, authorizes $200 million a year in 
grant funding with a total of $1 billion in grant funding over the next 
five years. The grant funding is to be made available to a municipality 
or community owned utility (not including for-profit entities) to 
repair, rehabilitate, or replace its natural gas distribution pipeline 
systems or portions thereof or to acquire equipment to (1) reduce 
incidents and fatalities and (2) to avoid economic losses. The new 
grant program authorized by BIL can, however, address only part of the 
universe of at-risk distribution pipeline systems. While the grant 
program would assist eligible entities who receive funding in making 
needed repairs to their pipeline systems, PHMSA's proposal would go 
further in ensuring that all gas distribution and other part-192 
regulated operators improve and maintain the safety of their systems 
and reduce the risk of public safety impacts and environmental damage 
from incidents on their pipeline systems.

B. Summary of the Proposed Regulatory Action

    In this rulemaking, PHMSA proposes amendments to 49 CFR parts 191, 
192, and 198. PHMSA also proposes compliance deadlines for each of the 
NPRM's regulatory amendments.
    1. Clarifications and Updates to DIMP Plans--Part 192, Subpart P. 
Pursuant to 49 U.S.C. 60109(e)(7), PHMSA proposes several revisions to 
its DIMP regulations at 49 CFR part 192, subpart P. PHMSA further 
proposes that, subject to certain exceptions at Sec.  192.1003, all gas 
distribution pipeline operators--including service lines--would need to 
update their DIMP plans in conformity with the amended requirements no 
later than one year after the publication of any final rule in this 
proceeding.
    First, PHMSA proposes to require all operators of gas distribution 
pipeline systems identify and minimize the risks to their systems from 
specific threats in their DIMP. These specific threats, where 
applicable, include: (1) the presence of certain materials, such as 
cast iron and other piping with known issues; (2) overpressurization of 
low-pressure systems; and (3) extreme weather and other geohazards. 
Operators must also consider the effect of age on those specific 
threats faced by a distribution pipeline.
    For operators of low-pressure gas distribution systems, PHMSA 
proposes that, when evaluating and ranking the above and other threats 
identified in their DIMP plans, operators must evaluate risks from: (1) 
abnormal operating conditions; and (2) potential consequences 
associated with low-probability events. If an operator can demonstrate 
through a documented engineering analysis, or an equivalent analysis 
incorporating operational knowledge, that no potential consequences are 
associated with a particular low-probability event, and therefore no 
potential risk exists, then the operator must notify PHMSA and state 
regulatory authorities of that determination within 30 days. 
Additionally, as part of the proposal to implement measures to minimize 
the risk of overpressurization, PHMSA would require operators of low-
pressure distribution systems to identify, maintain, and obtain 
pressure control records. PHMSA would also require operators to 
identify and implement preventive and mitigative measures based on the 
unique characteristics of their system. If operators choose to 
implement measures to minimize the risk of an overpressurization on a 
low-pressure system, then they must notify PHMSA and state regulatory 
authorities no later than 90 days in advance of implementing any 
alternative measures. As an alternative to implementing such preventive 
and mitigative measures, operators could choose to upgrade their 
systems to meet new proposed design requirements applicable to new 
systems.
    PHMSA is also proposing to omit operators of a liquefied petroleum 
gas (LPG) distribution pipeline system that serves fewer than 100 
customers (small LPG operators) from the DIMP requirements. Based on 
recommendations from the National Association of Pipeline Safety 
Representatives (NAPSR), a National Academies of Science (NAS) study, 
and PHMSA's incident data, current DIMP requirements do not provide a 
safety benefit warranting the compliance burdens those requirements 
impose on small LPG operators and the administrative burdens placed on 
PHMSA and state regulatory authorities. Instead, PHMSA proposes to add 
a requirement for small LPG operators to complete an annual report 
providing data that would support PHMSA's regulatory oversight of the 
safety of those facilities.
    2. Codifying in Regulation the Use of the State Inspection 
Calculation Tool--Sec. Sec.  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.
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    \5\ The SICT can be accessed on the PHMSA Portal by authorized 
users.
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    3. Updates to Emergency Response Communications--Sec.  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 Sec.  
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

[[Page 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--Sec.  
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 
Sec.  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--Sec.  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--Sec.  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--Sec. Sec.  192.195 and 
192.741. Pursuant to 49 U.S.C. 60102(t)(3), PHMSA proposes to require 
that

[[Page 61750]]

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--Sec.  192.305. PHMSA proposes to amend Sec.  
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\
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    \6\ ``Pipeline Safety: Miscellaneous Changes to Pipeline Safety 
Regulations,'' 80 FR 12762, 12779 (Mar. 11, 2015). PHMSA 
indefinitely stayed Sec.  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).
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    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--Sec. Sec.  192.517 and 192.725. PHMSA proposes to amend Sec.  
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 Sec.  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--Sec.  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 Sec.  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 
Sec.  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--Sec. Sec.  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 (Sec.  192.3) as well as--by way of 
removal of exceptions within the regulatory cross-references at Sec.  
192.9--emergency planning and response (Sec.  192.615) and protocols 
for notifications of potential ruptures (Sec.  192.635).
---------------------------------------------------------------------------

    \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).
---------------------------------------------------------------------------

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

[[Page 61751]]

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.
---------------------------------------------------------------------------

    \9\ 88 FR 21879 (Apr. 6, 2023); 58 FR 51735 (Oct. 4, 1993).
---------------------------------------------------------------------------

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

                   Table ES-1--Total Annualized Costs
                            [Millions, 2020$]
------------------------------------------------------------------------
                                                        3%         7%
             Proposed rule requirement               discount   discount
                                                       rate       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.
---------------------------------------------------------------------------

    \10\ PHMSA, ``Annual Report Mileage for Gas Distribution 
Systems'' (June 1, 2022), https://www.phmsa.dot.gov/data-and-statistics/pipeline/annual-report-mileage-gas-distribution-systems.
---------------------------------------------------------------------------

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

    \11\ This gas, regulated under 49 CFR parts 191 and 192, can be 
natural gas and any ``flammable gas, or gas which is toxic or 
corrosive.'' See Sec. Sec.  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.
    \12\ U.S. Envtl. Prot. Agency, Global Methane Initiative: 
Importance of Methane (last updated June 9, 2022), https://
www.epa.gov/gmi/importance-
methane#:~:text=Methane%20is%20more%20than%2025,due%20to%20human%2Dre
lated%20activities.
    \13\ Serious incidents are those including a fatality or injury 
requiring in-patient hospitalization, excluding incidents when 
secondary ignition is involved, sometimes called ``fire first'' 
incidents. Between 2001 and 2020, gas distribution incidents 
comprised 81 percent of all the serious incidents reported to PHMSA. 
The three-year average incident count between 2018 and 2020 is 25, 
down from an average of 28 serious incidents between 2001 and 2020. 
``Pipeline Incident 20 Year Trends'' (Nov. 15, 2022), https://www.phmsa.dot.gov/data-and-statistics/pipeline/pipeline-incident-20-year-trends.
    \14\ ``Pipeline Incident 20 Year Trends'' (Nov. 15, 2022), 
https://www.phmsa.dot.gov/data-and-statistics/pipeline/pipeline-incident-20-year-trends.
---------------------------------------------------------------------------

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

    \15\ PHMSA, ``By-Decade Inventory: Reports'' (Mar. 16, 2020), 
https://www.phmsa.dot.gov/data-and-statistics/pipeline-replacement/decade-inventory.
---------------------------------------------------------------------------

    On April 4, 2011, following a string of major gas pipeline 
incidents, the Secretary of Transportation announced a Pipeline Safety 
Action Plan (Action Plan) that was a vehicle for Federal and State 
cooperation to accelerate the repair, rehabilitation, and replacement 
of the highest-risk pipeline infrastructure.\16\ Efforts implementing 
the Action Plan focused on pipeline age and material as significant 
risk indicators. Pipelines constructed of cast- and wrought iron and 
bare steel were among those materials identified as posing the highest 
risk. In fact, operators of cast-iron and bare-steel distribution 
pipelines perform the vast majority of all leak repairs, despite these 
lines only making up about 21 percent of all distribution pipelines 
according to

[[Page 61752]]

PHMSA's distribution operators' annual report data.\17\
---------------------------------------------------------------------------

    \16\ PHMSA, ``U.S. Transportation Secretary Ray LaHood Announces 
Pipeline Safety Action Plan'' (Apr. 4, 2011), https://www.phmsa.dot.gov/sites/phmsa.dot.gov/files/docs/dot4111.pdf.
    \17\ Cast iron or bare steel pipelines account for 95 percent of 
corrosion leaks on mains, 92 percent of natural-force leaks on 
mains, 91 percent of pipe/weld/joint failure leaks; 97 percent 
``other cause'' leaks on mains; and 76 percent of all known leaks. 
PHMSA, ``Cast and Wrought Iron Inventory'' (Apr. 26, 2021), https://www.phmsa.dot.gov/data-and-statistics/pipeline-replacement/cast-and-wrought-iron-inventory (``Cast and Wrought Iron Inventory'').
---------------------------------------------------------------------------

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

    \18\ See Cast and Wrought Iron Inventory.
    \19\ U.S. Dep't of Energy, ``Transforming U.S. Energy 
Infrastructures in a Time of Rapid Change: The First Installment of 
the Quadrennial Energy Review'' at S-5 (Apr. 2015) https://www.energy.gov/sites/prod/files/2015/08/f25/QER%20Summary%20for%20Policymakers%20April%202015.pdf.
---------------------------------------------------------------------------

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

B. Gas Distribution Configurations

    In a distribution system, gas is sourced from a transmission 
pipeline operating at a high pressure and must be safely delivered to 
the customer at lower pressures that are safe for customer piping and 
appliances. There are multiple points along the system where operators 
can reduce the pressure to be more suitable for the needs of the 
customer. City gate stations are the first such reduction point, and 
district regulator stations are pressure-reducing facilities downstream 
of city gate stations that further reduce the pressure from the 
pipeline coming from the city gate.\20\ This lower pressure downstream 
of a district regulator station is more suitable for providing service 
to customers.
---------------------------------------------------------------------------

    \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/wp-content/uploads/2019/03/2019-PST-Briefing-Paper-02-NatGasBasics.pdf.
---------------------------------------------------------------------------

    Each gas distribution system must be designed to operate safely at 
or below a certain pressure, also known as its maximum allowable 
operating pressure (MAOP), as determined in accordance with Sec.  
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.
---------------------------------------------------------------------------

    \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).
---------------------------------------------------------------------------

    Many regulators require external control lines, which sense the 
outlet pressure of the regulator. Based on the pressure sensed through 
the control lines, the regulator valve will open or close to control 
the downstream pressure of the regulator. In some older installations, 
control lines are located farther downstream of the regulator station 
on the buried outlet piping based on either the manufacturer's 
recommendations or previous control-line standards and practices at the 
time of installation. However, a break in the control line (e.g., if it 
is damaged during an excavation) will make the regulator sense a lower 
downstream pressure and will cause the regulator valve to open wider 
automatically. This could result in overpressurization of the 
downstream piping, which could lead to a catastrophic event. The same 
result occurs if the flow through the control line is otherwise 
disrupted, for example if the control line valve is shut off or if the 
control line is isolated from the regulator it is controlling.
    In general, gas distribution pipeline systems can be classified as 
either low pressure or high pressure. In a high-pressure gas 
distribution system, the gas pressure in the main is substantially 
higher than what the customer requires, and a pressure regulator 
installed at each meter reduces the pressure from the main to a 
pressure that can be used by the customer's equipment and appliances. 
These regulators incorporate an overpressure-protection device to 
prevent overpressurization of the customer's piping and appliances 
should the regulator fail. Additionally, all new or replaced service 
lines connected to a high-pressure distribution system must have excess 
flow valves (see Sec.  192.383). Excess flow valves can reduce the flow 
of gas through the service line by minimizing unplanned, excessive gas 
flows.\22\
---------------------------------------------------------------------------

    \22\ An excess-flow valve is a mechanical safety device 
installed on a gas service line to a residence or small commercial 
gas customer. In the event of damage to the gas service line between 
the street and the meter, the excess-flow valve will minimize the 
flow of gas through the service line. The pipeline safety 
regulations require a gas distribution company to install such a 
device on new or replacement service lines for single-family 
residences and certain multifamily and commercial buildings where 
the service line pressure is above 10 pounds per square inch gauge 
(psig). See 49 CFR 192.383 for specific requirements.
---------------------------------------------------------------------------

    In a low-pressure distribution system, the gas pressure in the main 
is substantially the same as the pressure provided to the customer (see 
Sec.  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.

[[Page 61753]]

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.
---------------------------------------------------------------------------

    \23\ CMA transferred from NiSource, Inc. to Eversource Energy in 
November 2020.
---------------------------------------------------------------------------

    In response, fire departments from three municipalities were 
dispatched to the fires and explosions. First responders initiated the 
Massachusetts fire mobilization plan and received mutual aid from 
neighboring districts in Massachusetts, New Hampshire, and Maine. 
Emergency management officials had the electric utility shut off 
electrical power in the area. Additionally, CMA shut down its low-
pressure natural gas distribution system, affecting 10,894 customers, 
including some outside of the affected area who had their service shut 
off as a precaution.
    The NTSB on September 24, 2019, issued a final report of its 
investigation into the Merrimack Valley incident.\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.
---------------------------------------------------------------------------

    \24\ NTSB/PAR-19/02 at 49.
---------------------------------------------------------------------------

D. Low-Pressure Gas Distribution System in South Lawrence

    At the time of the incident, CMA owned and operated a network of 
gas pipeline systems for the transportation and delivery of natural gas 
that included approximately 25 different low-pressure gas distribution 
systems in Massachusetts. Among these systems, CMA owned and operated a 
low-pressure system in the area of South Lawrence, Massachusetts that 
served Lawrence, Andover, and North Andover, among other communities 
(South Lawrence system). The South Lawrence system was installed in the 
early 1900s and was constructed with cast iron and bare steel mains and 
used several regulator stations to control downstream pressure. The 
regulator stations were located below ground and contained regulators 
that monitored and controlled downstream pressure. Natural gas came 
into the South Lawrence system at a pressure of about 75 pounds per 
square inch, gauge (psig). The regulators reduced the pressure to about 
0.5 psig for delivery to customers.
    The South Lawrence system consisted of 14 regulator stations, 
wherein the regulator valves opened or closed based on the pressure the 
regulator sensed downstream to maintain the downstream pressure at a 
pre-set limit called a ``set point.'' This was to ensure the pressure 
in the system did not exceed the MAOP and become unsafe. Each regulator 
station in the South Lawrence system had at least two regulators in 
series--a ``worker regulator'' and a ``monitor regulator''--each with a 
control line that sensed downstream pressure and connected back to its 
regulator, thereby enabling the regulator station to regulate system 
pressure. The worker regulator was the primary regulator that 
maintained system pressure. The monitor regulator was the redundant 
backup in case the worker regulator was damaged or malfunctioned. If 
both control lines experienced a decrease in pressure, such as when the 
cast iron main was disconnected, the worker regulator and monitor 
regulator would automatically and continually increase the pressure, 
resulting in an overpressurization of the low-pressure system. That is 
precisely what occurred in CMA's gas main replacement project.

E. Gas Main Replacement Project

    Beginning in 2016, CMA began a pipe replacement project in the 
South Lawrence system called the South Union Street project. CMA's 
field engineering department initiated the project in part due to the 
pending City of Lawrence water main project that would encroach on two 
aging cast iron mains on South Union Street. The construction project 
was also part of CMA's Gas System Enhancement Plan that called for 
replacing existing low-pressure cast iron pipelines (both mains and the 
accompanying service lines) with higher-pressure modern plastic piping.
    The South Union Street project proposed replacing two low-pressure 
cast iron mains with one plastic high-pressure main. Once installed, 
the new plastic main would be ``tied-in'' to the distribution system 
and service lines supplying gas to customers. As is typical in pipe 
replacement projects, the two cast iron mains would be completely 
disconnected from the low-pressure system and abandoned in the ground 
upon completion.
    The scope of the South Union Street project included the 
replacement of the cast iron mains near a belowground regulator station 
located at the intersection of Winthrop Avenue and South Union Street 
(the Winthrop regulator station), one of the 14 regulator stations that 
monitored and controlled downstream pressure in the South Lawrence 
system. Up until the time of the incident, two control lines connected 
the Winthrop regulator station and the two cast iron and bare steel 
mains on South Union Street.
    CMA contracted with a pipeline services firm to complete the 
replacement project. CMA prepared a work package, which included 
materials such as isometric drawings and procedural details for 
disconnecting and connecting pipes, for each of the planned 
construction activities. However, CMA did not prepare a package for the 
relocation of the control lines serving the regulator station. The 
absence of a complete work package led to the contractor completing the 
installation of the plastic main with the regulator control lines at 
the regulator station still connected to the cast iron main that was 
being replaced.
    In 2016, the construction crew installed the new plastic main on 
South Union Street and began feeding the new plastic main with gas from 
the Winthrop regulator station. However, CMA put the work on hold due 
to a city-wide moratorium on all gas, water, and sewer projects in 
Lawrence. Consequently, the construction crew was unable to begin any 
of the tie-in and abandonment procedures to tie-in or connect the mains 
or services to the new plastic main and thus was also unable to abandon 
the cast iron mains on South Union Street. The regulator control lines 
at the Winthrop regulator station remained connected to the cast iron 
mains that would ultimately be decommissioned.
    The final stage of the South Union Street project involved the 
installation of tie-ins to the new plastic main, after which the legacy 
cast iron mains would be decommissioned and abandoned in

[[Page 61754]]

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.
---------------------------------------------------------------------------

    \25\ Operators use SCADA systems to monitor and control critical 
assets remotely. See Sec.  192.631. Here, the South Lawrence system 
was monitored by CMA's corporate owner at the time, NiSource.
---------------------------------------------------------------------------

    Following company protocol, at 4:06 p.m., the SCADA controller 
called the on-call technician in Lawrence, MA, and reported the high-
pressure event. The on-call technician dispatched 3 field technicians 
to perform field checks on the 14 regulators within the South Lawrence 
system. Not until about 4:30 p.m. did a CMA field technician at the 
Winthrop regulator station (the location of the control lines still 
connected to the cast iron main) hear a loud sound and recognize that a 
large quantity of natural gas was flowing through the Winthrop 
regulator station. The CMA field technician adjusted the set point on 
the two regulators to reduce flow and isolated them. The CMA field 
technician then noticed that the sound of the flowing natural gas began 
to decrease.
    Meanwhile, at 4:18 p.m., a CMA field engineer and a CMA field 
operations leader (FOL) were at another construction site when they 
received notice to respond to fire coming out of house chimneys. Due to 
traffic congestion, a police officer escorted the FOL to the 
construction site at Salem and South Union streets (location of the 
September 13 tie-in). When the FOL arrived at 5:08 p.m., crew members 
stated that they had confirmed the pressure in the entire low-pressure 
system was in the normal range before removing the bypass (i.e., 
disconnecting the cast iron main from the Winthrop regulator station 
and connecting the new plastic main). At 5:19 p.m. the FOL took 
pressure readings at a nearby house and found the pressure was 
elevated. The FOL then recommended to a supervisor that CMA shut down 
the low-pressure system.
    After being designated as the CMA Incident Commander by the 
Lawrence Operations Center manager, the FOL then called CMA's 
engineering department for the list of valves that needed closing to 
isolate and shut down the system. While waiting for this information, 
the FOL assigned crews to regulator stations and directed them to 
verify, with CMA's engineering department, the correct valve to close 
once they arrived at the regulator station. Once confirmed, they closed 
the valves. The FOL confirmed the closure of all valves at 7:24 p.m.
    At 7:43 p.m., almost 4 hours after the CMA SCADA system detected 
the overpressurization, the president of CMA declared a ``Level 1'' 
emergency, in accordance with CMA's emergency response plan. According 
to the NTSB's report, the operator's Emergency Response Manual defines 
a ``Level 1'' emergency as a ``catastrophic event'' that includes the 
loss of a major natural gas facility or the loss of critical natural 
gas infrastructure.
    Working through the night, CMA's engineering department worked 
under the FOL's direction to confirm that no gas was flowing into the 
regulator stations on the low-pressure system. On September 14, 2018, 
at 6:27 a.m., CMA confirmed the low-pressure distribution system was 
shut down for the 8,447 customers in the Lawrence, Andover, and North 
Andover areas. CMA shut down the natural gas to an additional 2,447 
customers outside the immediate area as a precaution.
    The following days required an unprecedented response effort. More 
than 50,000 residents were asked to evacuate from their homes following 
the overpressurization.\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 longer-term housing solutions as recovery efforts 
extended into the fall and winter months.
---------------------------------------------------------------------------

    \26\ Mass. Dep't of Pub. Utilities, ``Independent Assessment of 
Columbia Gas of Massachusetts' Merrimack Valley Restoration Program: 
Final Report,'' at A-2 (June 22, 2020), https://www.mass.gov/doc/independent-assessment-of-columbia-gas-of-massachusetts-merrimack-valley-restoration-program/download.
---------------------------------------------------------------------------

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

III. Recommendations, Advisory Bulletins, and Mandates

A. National Transportation Safety Board

    The NTSB investigates serious pipeline accidents, including those 
that occur on gas distribution pipeline systems. The NTSB investigated 
CMA's overpressurization incident and issued its final report,\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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    \27\ See NTSB, PAR-19/02. The full report is available at 
https://www.ntsb.gov/investigations/AccidentReports/Reports/PAR1902.pdf.
    \28\ These states were Alabama, Alaska, Arizona, Arkansas, 
California, Colorado, Connecticut, Florida, Georgia, Idaho, 
Illinois, Kentucky, Louisiana, Maine, Maryland, Mississippi, 
Missouri, Montana, Nebraska, Nevada, New York, North Carolina, 
Pennsylvania, South Carolina, South Dakota, Texas, Utah, Virginia, 
and Wyoming. NTSB/PAR-19/02 at 50.

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[[Page 61755]]

    In its accident report, the NTSB issued two safety recommendations 
to PHMSA. The first, P-19-14, recommended that PHMSA require 
overpressure protection for low-pressure natural gas distribution 
systems that cannot be defeated by a single operator error or equipment 
failure. The NTSB further clarified that to satisfy this 
recommendation, PHMSA would not have to require that existing low-
pressure gas distribution systems be completely redesigned; rather, 
PHMSA may satisfy this recommendation by requiring operators to add 
additional protections, such as slam-shut or relief valves, to existing 
district regulator stations or other appropriate locations in the 
system.\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.
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    \29\ NTSB clarified this in an official correspondence to PHMSA 
on July 31, 2020. NTSB, ``Safety Recommendation P-19-014'' (July 31, 
2020), https://data.ntsb.gov/carol-main-public/sr-details/P-19-014.
---------------------------------------------------------------------------

B. Advisory Bulletins

1. Possibility of Overpressurization of Low-Pressure Distribution 
Systems Advisory Bulletin
    On September 29, 2020, PHMSA issued an advisory bulletin (ADB-2020-
02) to urge owners and operators of gas distribution systems to conduct 
a comprehensive review of their systems for the possibility of a 
failure of overpressure protection on low-pressure distribution 
systems.\30\ The advisory bulletin addressed NTSB safety recommendation 
P-19-15, which underscored the elevated possibility of a common mode of 
failure on low-pressure distribution systems. Specifically, PHMSA 
requested owners and operators of low-pressure distribution systems to 
review the NTSB's report concerning the 2018 Merrimack Valley 
overpressurization event. PHMSA also recommended that operators review 
their current systems for a similar overpressure-protection 
configuration to that on the CMA pipeline involved in the incident. In 
the review of their systems, PHMSA urged operators to consider the 
possibility of a failure of overpressure-protection devices as a threat 
to their system's integrity. Additionally, PHMSA reminded owners and 
operators of their responsibilities under 49 CFR part 192, subpart P, 
to follow their DIMP and to revise their DIMP based on the new 
information provided in the NTSB's report and PHMSA's advisory 
bulletin. Finally, PHMSA recommended several ways that an operator can 
protect low-pressure distribution systems from an overpressurization 
event. Some examples include:
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    \30\ ``Pipeline Safety: Overpressure Protection on Low-Pressure 
Natural Gas Distribution Systems,'' ADB-2020-02, 85 FR 61097 (Sept. 
29, 2020).
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    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:
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    \31\ ``Pipeline Safety: Cast Iron Pipe (Supplementary Advisory 
Bulletin),'' ADB-2012-05, 77 FR 17119 (Mar. 23, 2012).
    \32\ On January 18, 2011, an explosion and fire caused the death 
of one gas utility employee and injuries to several other people 
while gas utility crews were responding to a natural gas leak in 
Philadelphia, Pennsylvania. On February 9, 2011, five people lost 
their lives, several homes were destroyed, and other properties were 
impacted by an explosion and subsequent fire in Allentown, 
Pennsylvania.
    \33\ Research and Special Programs Administration (RSPA), ALN-
91-02 (Oct. 11, 1991), https://www.phmsa.dot.gov/sites/phmsa.dot.gov/files/docs/RSPA%20Alert%20Notice%2091-02.pdf; RSPA, 
ALN-92-02 (June 26, 1992), https://www.phmsa.dot.gov/sites/phmsa.dot.gov/files/docs/RSPA%20Alert%20Notice%2092-02.pdf 
(supplementing ALN-91-02).
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    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 
Sec.  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.

[[Page 61756]]

1. Distribution Integrity Management Program Plans and State Inspection 
Calculation Tool (49 U.S.C. 60109(e)(7) and 49 U.S.C. 60105(b) and 
60105 Note; PIPES Act of 2020 Section 202)
    PHMSA is required to issue regulations ensuring that DIMP plans for 
gas distribution operators include an evaluation of certain risks, such 
as those posed by cast iron pipes and mains and low-pressure 
distribution systems, as well as the possibility of future accidents to 
better account for high-consequence but low-probability events. (49 
U.S.C. 60109(e)(7)). Gas distribution operators were required make 
their DIMP plans, emergency response plans, and O&M manuals available 
to PHMSA or the relevant State regulatory agency no later than December 
27, 2022. Gas distribution operators must also make these documents, in 
updated form, available to PHMSA or the relevant State regulatory 
agency: (1) two years after the promulgation of regulations as 
required; and (2) every 5 years thereafter, as well as following any 
significant change to the document. PHMSA must also update and codify 
the use of the SICT, a tool used to help states determine the minimum 
amount of time it must dedicate to inspections. (See 49 U.S.C. 60105(b) 
and 60105 note).
2. Emergency Response Plans (49 U.S.C. 60102(r); PIPES Act of 2020 
Section 203)
    PHMSA is required to update its emergency response plan regulations 
to ensure that each emergency response plan developed by a gas 
distribution system operator includes written procedures for how to 
handle communications with first responders, other relevant public 
officials, and the general public after certain significant pipeline 
emergencies (49 U.S.C. 60102(r)). Specifically, the updated regulations 
would ensure that pipeline operators contact first responders and 
public officials as soon as practicable after they know a release of 
gas has occurred that resulted in a fire related to an unintended 
release of gas, an explosion, one or more fatalities, or the 
unscheduled release of gas and shutdown of gas service to a significant 
number of customers. Similarly, the updated regulations would provide 
for general public communication of pertinent emergencies as soon as 
practicable and leverage communications methods facilitating rapid 
notice to the general public.
3. Operation and Maintenance Manuals (49 U.S.C. 60102(s); PIPES Act of 
2020 Section 204)
    PHMSA is required to update the regulations for O&M manuals to 
require distribution system operators to have a specific action plan to 
respond to overpressurization events (49 U.S.C. 60102(s)). 
Additionally, operators must develop written procedures for management 
of change processes for significant technology, equipment, procedural, 
and organizational changes to their distribution system and ensure that 
relevant qualified personnel, such as an engineer with a professional 
engineer (PE) license, reviews and certifies such changes (49 U.S.C. 
60102(s)).
4. Pipeline Safety Practices (49 U.S.C. 60102(t); PIPES Act of 2020 
Section 206)
    PHMSA is required to issue regulations that require distribution 
pipeline operators to identify and manage ``traceable, reliable, and 
complete'' maps and records of critical pressure-control infrastructure 
and update these records as appropriate. The records must be submitted 
or made available to the relevant regulatory agency (i.e., PHMSA or the 
State). These regulations must require records to be gathered on an 
opportunistic basis. (49 U.S.C. 60102(t)(1)).
    PHMSA must also issue regulations requiring a qualified employee of 
a distribution system operator to monitor gas pressure at district 
regulator stations and be able to shut off flow or limit gas pressure 
during construction projects that have the potential to cause a 
hazardous overpressurization. An exception to this requirement would be 
made for a district regulator station that has a monitoring system and 
capability for a remote or automatic shutoff (49 U.S.C. 60102(t)(2)). 
PHMSA is further required to issue regulations on district regulator 
stations to ensure that gas distribution system operators minimize the 
risk of a common mode of failure at low-pressure district regulator 
stations, monitor the gas pressure of low-pressure distribution 
systems, and install overpressure protection safety technology at low-
pressure district regulator stations. If it is not operationally 
possible to install such technology, this section would require the 
operator to identify plans that would minimize the risk of 
overpressurization (49 U.S.C. 60102(t)(3)).

IV. Proposed Amendments

A. Distribution Integrity Management Programs (Subpart P)

    In 2009, PHMSA issued a final rule titled ``Pipeline Safety: 
Integrity Management Program for Gas Distribution Pipelines,'' creating 
49 CFR part 192, subpart P.\34\ As specified in Sec.  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.
---------------------------------------------------------------------------

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

    Pursuant to Sec.  192.1007, DIMP regulations require operators 
implement the following steps in developing their DIMP plans:
    (1) Knowledge (Sec.  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 (Sec.  192.1007(b))--Requires operators to 
identify existing and potential threats to their pipeline systems;
    (3) Evaluate and Rank Risk (Sec.  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 (Sec.  
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 (Sec.  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 (Sec.  192.1007(f))--
Requires operators to periodically reevaluate threats and risks across 
the entire pipeline system; and

[[Page 61757]]

    (7) Report Results (Sec.  192.1007(g))--Requires operators to 
report their performance results to PHMSA and the applicable State 
agency through annual reports (required by Sec.  191.11).
    The first step in developing a robust DIMP plan, as required in 
Sec.  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.
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    \35\ PHMSA, ``Gas Distribution Pipeline Integrity Management 
Enforcement Guidance'' at 19-23 (Dec. 7, 2015), https://www.phmsa.dot.gov/sites/phmsa.dot.gov/files/docs/DIMP_Enforcement_Guidance_12_7_2015.pdf (``DIMP Guidance'').
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    The second step in developing and implementing a DIMP plan, as 
required in Sec.  192.1007(b), is for operators to use the information 
they have gathered in compliance with Sec.  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 Sec.  192.1007(b)).
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    \36\ PHMSA, ``F 7100.1-1, Annual Report: Gas Distribution 
System'' (May 2021), https://www.phmsa.dot.gov/sites/phmsa.dot.gov/files/2021-05/Current_GD_Annual_Report_Form_PHMSA%20F%207100.1-1_CY%202021%20and%20Beyond.pdf.
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    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\
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    \37\ The Plastic Pipe Database Committee, composed of 
representatives of the American Gas Association (AGA), American 
Public Gas Association (APGA), Plastics Pipe Institute (PPI), 
National Association of Regulatory Utility Commissioners (NARUC), 
NAPSR, NTSB, and PHMSA, coordinates the creation and maintenance of 
a database to proactively monitor the performance of in-service 
plastic piping system failures and leaks with the objective of 
identifying possible performance issues.
    \38\ PHMSA, ``Gas Distribution Pipeline Integrity Management 
Enforcement Guidance'' at 19-23 (Dec. 7, 2015), https://www.phmsa.dot.gov/sites/phmsa.dot.gov/files/docs/DIMP_Enforcement_Guidance_12_7_2015.pdf (``DIMP Guidance'').
    \39\ DIMP Guidance at 18-19.
    \40\ DIMP Guidance at 19.
    \41\ DIMP Guidance at 19.
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    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\
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    \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.
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    The third step in developing and implementing a DIMP plan, as 
required in Sec.  192.1007(c), is to evaluate and rank risk. Risk is 
the likelihood of an event occurring multiplied by the consequence of 
that event. An event that is highly likely and has significant public 
safety or environmental consequences constitutes an event of greatest 
concern, while an unlikely event that has minimal consequences may not 
justify any particular precautions. On the other hand, an unlikely 
event that could have very high consequences may justify special 
precautions. Incidents on gas distribution systems are generally low-
likelihood, but high-consequence, events.
    Risk analysis is an ongoing process of understanding the risk each 
identified threat presents to a pipeline. Operators use the threats 
identified in Sec.  192.1007(b) and any knowledge gained when complying 
with Sec.  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\
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    \44\ DIMP Guidance at 22, 61.
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    The fourth step in developing and implementing a DIMP plan, as 
required in Sec.  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

[[Page 61758]]

should promptly identify the need for risk reduction measures if a new 
risk is identified.
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    \45\ PHMSA notes that it recently proposed in a separate 
rulemaking a number of revisions to its prescriptive part 192 leak 
detection requirements that would (inter alia) require gas 
distribution to adopt advanced leak detection programs based on 
commercially available, advanced leak detection equipment. See ``Gas 
Pipeline Leak Detection and Repair,'' 88 FR 31890 (May 18, 2023).
    \46\ DIMP Guidance at 28.
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    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 Sec.  192.1007(a), combined with the threats identified 
pursuant to Sec.  192.1007(b), to perform a risk analysis to evaluate 
the likelihood and consequences of failures for those threats described 
in Sec.  192.1007(c) for which risk-reduction measures are then 
identified and implemented under Sec.  192.1007(d). The more accurately 
and completely an operator characterizes their system, the more 
accurate the risk analysis results will be. This in turn should inform 
how an operator allocates resources to mitigate the risks associated 
with its system.
    Pipeline incidents since the promulgation of the DIMP rules in 2011 
have demonstrated that some distribution operators whose systems are 
subject to DIMP requirements are not adequately identifying (step 2), 
evaluating (step 3), or mitigating (step 4) the threats that are 
degrading and reducing the integrity of their pipeline systems. For 
example, NTSB's report on the Merrimack Valley incident found that, by 
at least September 2015, CMA employees knew of overpressure dangers 
associated with maintenance on belowground control lines for low-
pressure system regulator stations: a faulty, damaged, or unaccounted 
for control line could lead to overpressurization, resulting in fires 
and explosions in a populated area.\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\
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    \47\ NTSB/PAR-19/02 at 18.
    \48\ NTSB/PAR-19/02 at 59-61.
    \49\ NTSB/PAR-19/02 at 40.
---------------------------------------------------------------------------

    More robust risk management was also needed in the planning of the 
South Union Street project, particularly with respect to the threat of 
overpressurization. NTSB concluded that NiSource's engineering package 
for that construction project failed to identify, and control for the 
vulnerability of its system to, a common mode of failure during the 
construction project that could result in an overpressurization. After 
the incident in the Merrimack Valley, NiSource worked to improve its 
risk management processes and installed automatic pressure-control 
equipment.\50\ Therefore, the NTSB concluded that NiSource's 
engineering risk management processes were deficient.
---------------------------------------------------------------------------

    \50\ NTSB/PAR-19/02 at 43.
---------------------------------------------------------------------------

    Subsequent to the Merrimack Valley incident, 49 U.S.C. 60109(e)(7) 
was amended to require PHMSA to add more specificity to the DIMP 
requirements to ensure that operators consider specific threats to 
their systems. Specifically, PHMSA must update its regulations to 
ensure DIMP plans for distribution operators include an evaluation of 
certain risks, such as those posed by cast iron pipes and mains and 
low-pressure distribution systems, as well as the possibility of future 
accidents, to better account for high-consequence but low-probability 
events. Distribution operators must make their updated DIMP plans 
available to PHMSA or the relevant State regulatory agency two years 
after any final rule in this proceeding is issued and every 5 years 
thereafter, as well as following any significant change to an 
operator's DIMP plan or distribution system.\51\
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    \51\ This provision also requires that operators make their 
current DIMP plans, emergency response plans, and O&M manuals 
available to PHMSA or the relevant State regulatory agency no later 
than December 27, 2022, which PHMSA intends to continue to review as 
appropriate in the course of inspection. See 49 U.S.C. 60109(e)(7).
---------------------------------------------------------------------------

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

    \52\ NTSB, Accident Report PAR-21/01, ``Atmos Energy Corporation 
Natural Gas-Fueled Explosion: Dallas, Texas: February 23, 2018'' 
(Jan. 12, 2021), https://www.ntsb.gov/investigations/AccidentReports/Reports/PAR2101.pdf.
    \53\ NTSB/PAR-21/01 at 66.
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    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.''
---------------------------------------------------------------------------

    \54\ NTSB/PAR-21/01 at 72.

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[[Page 61759]]

    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.
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    \55\ An individual gas service line directly connected to a gas 
transmission, production, or gathering pipeline is commonly referred 
to as a ``farm tap.'' Individual service lines have the option of 
following either Sec.  192.740, for service lines that are not 
operated as part of a distribution system, or DIMP (as detailed in 
Sec.  192.1003(b)) for any portion of the individual service line 
that is classified as a service line. This rule proposed no change 
to this scope. The proposals apply to those individual service lines 
(aka farm taps) that apply DIMP.
---------------------------------------------------------------------------

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

    \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[supreg] 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[hyphen]Like Cracking of Older 
Plastic Pipe,'' ADB-07-02, 72 FR 51301 (Sept. 6, 2007).
---------------------------------------------------------------------------

b. Need for Change--DIMP--Identify Threats--Materials
    Different piping materials could pose different threats to gas 
distribution systems and should be identified prior to conducting a 
risk analysis of those threats. All things equal, pipelines that are 
made of certain materials, like cast iron, wrought iron, bare steel, 
unprotected steel, and certain plastic pipelines, are more susceptible 
to leaks and other pipeline integrity issues. In particular, cast-iron 
pipe was the subject of an advisory bulletin (ADB-2012-05) that 
reiterated two alert notices previously issued by PHMSA that addressed 
the continued use of cast- and wrought-iron pipe in gas distribution 
pipeline systems and reminded owners and operators and State pipeline 
safety representatives of the need to maintain an effective cast-iron 
management program.\58\ Similar to cast- and wrought-iron piping, steel 
pipelines without corrosion protection coating--also known as bare-
steel or unprotected pipelines--are made of a material that could be a 
threat to a gas distribution system, as that material is more 
susceptible to corrosion than coated steel.
---------------------------------------------------------------------------

    \58\ RSPA, ALN-92-02 (June 26, 1992); RSPA, ALN-91-02 (Oct. 11, 
1991).
---------------------------------------------------------------------------

    Certain vintages and types of plastic piping are also known 
throughout the industry to present acute threats to pipeline integrity. 
For example, susceptibility to premature brittle[hyphen]like cracking 
of certain Aldyl ``A'' pipe, along with other vintages and 
manufacturers' products, is a well[hyphen]documented problem in the 
industry and the subject of the advisory bulletin ADB-07-02. In this 
advisory bulletin, PHMSA recommended that operators consider the threat 
of brittle-like cracking applicable to any Aldyl ``A'' pipe in service 
(under the general category of ``material''), regardless of whether the 
threat had resulted in leakage to date. Similarly, PHMSA also alerted 
operators to the risks of material degradation on Driscopipe8000 
(Driscopipe Series 8000 high-density poly-ethylene (HDPE)) pipe in 
Arizona and Nevada in ADB-2012-03.
    While many of these pipelines have been taken out of service, some 
of them continue to operate today. As discussed earlier, the Merrimack 
Valley incident involved the replacement of cast-iron and bare-steel 
pipelines with modern plastic piping. This was part of CMA's pipeline 
replacement program, which called for the replacement of leak-prone 
low-pressure cast iron pipelines (both mains and services) with modern 
plastic pipe. Many operators are also engaged in pipeline replacement 
projects in response to PHMSA's Action Plan; managing the reduction in 
cast- and wrought-iron inventory has been a priority and in progress 
for many years.
    Following the Merrimack Valley incident, PHMSA was required by

[[Page 61760]]

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 
Sec.  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 Sec.  192.1007(c).
---------------------------------------------------------------------------

    \59\ PHMSA notes, however, the threats to pipeline integrity 
posed by other materials. Specifically, 49 U.S.C. 60108 (Section 114 
of PIPES Act of 2020) imposes a self-executing mandate on gas 
transmission, distribution, and part-192 regulated gas gathering 
pipeline operators to update their inspection and maintenance 
procedures to provide for replacement or remediation of pipelines 
``known to leak based on their material (including cast iron, 
unprotected steel, wrought iron, and historic plastics with known 
issues) . . . .'' PHMSA is considering within a separate rulemaking 
(under RIN 2137-AF54) whether to incorporate that self-executing 
statutory mandate within its 49 CFR part 192 regulations. See ``Gas 
Pipeline Leak Detection and Repair,'' 88 FR 31890 (May 18, 2023). 
PHMSA submits that this NPRM's amendments to DIMP requirements at 
subpart P would complement any revisions to prescriptive regulations 
elsewhere in 49 CFR part 192 that PHMSA may adopt in that parallel 
rulemaking.
    \60\ Operators are already subcategorizing their pipeline 
segments by material type (i.e., cast iron, wrought iron, bare 
steel, and certain plastics with known issues) in their annual 
report form, PHMSA F 7100.1-1. See supra note 36.
---------------------------------------------------------------------------

c. Proposal To Amend Sec.  192.1007(b)--DIMP--Identify Threats--
Materials
    PHMSA proposes to revise Sec.  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.
---------------------------------------------------------------------------

    \61\ AGA, ``Plastic Pipe Data Collection Initiative'', https://www.aga.org/natural-gas/safety/promoting-safety/plastic-pipe-data-collection-initiative/ (last visited March 10, 2023).
---------------------------------------------------------------------------

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

    \62\ DIMP Guidance at 19, 59.
---------------------------------------------------------------------------

    Recent incidents underscore the importance of operators adequately 
identifying the risk of overpressurization on distribution systems. 
Prior to the Merrimack Valley incident on September 13, 2018, the 
operator experienced four other overpressurizations and one ``near-
miss'' within its network of distribution systems.\63\
---------------------------------------------------------------------------

    \63\ NTSB/PAR-19/02 at 25.
---------------------------------------------------------------------------

    On March 1, 2004, a system overpressurized when debris lodged at 
the seat of the bypass valve in Lynchburg, VA.
    On February 28, 2012, an operator error during an inspection 
resulted in accidental overpressurization in Wellston, OH. 300 
customers were without service for 14 hours.
    On March 21, 2013, a segment of a pipe with an MAOP of 1 psig was 
pressurized at over 2 psig in Pittsburgh, PA. A work crew, under the 
direction of

[[Page 61761]]

the local NiSource subsidiary, was making a tie-in and failed to 
monitor the pressure and flow of the existing low-pressure natural gas 
distribution system during the tie-in process.
    On August 11, 2014, a local NiSource crew in Frankfort, KY, was 
excavating to repair a leak located on the outside of a regulator 
station building. The crew uncovered and narrowly missed hitting the 1-
inch control line and tap located on the 8-inch outlet pipeline. The 
crew was unaware of the purpose of the 1-inch line and called local 
measurement and regulation (M&R) personnel. The M&R personnel advised 
the crew of the purpose of a control line and what would have happened 
had the line been broken. As discussed earlier, in 2015 NiSource issued 
ON 15-05 in response to this near miss. ON 15-05 required that M&R 
personnel be consulted on all future excavation work done within 25 
feet of a regulator station with sensing lines, other communications 
and/or electric lines critical to the operation of the regulator 
station, or buried odorant lines. On September 13, 2018 (the date of 
the Merrimack Valley incident), however, CMA did not follow those 
procedures or implement any preventive or mitigative measures as they 
should have if they were correctly following DIMP requirements.
    On January 13, 2018, during the investigation of a service 
complaint, an overpressurization was discovered on a natural gas 
distribution system in Longmeadow, MA. The cause was associated with 
debris accumulation on both the worker and monitor regulator seats at a 
regulator station. Once the debris was removed, the pressure returned 
to normal. This event illustrates that, in some cases, an 
overpressurization can occur that does not cause a catastrophic failure 
of the entire system, but if the operator takes timely, mitigative 
action, the system can safely return to normal. Operators know debris 
accumulation at regulator stations can cause an overpressurization and 
can plan routine maintenance of regulator stations to remove debris or 
install a device to prevent the debris from reaching the regulator 
station. However, an operator must first recognize overpressurization 
as a threat to ensure that they allocate resources to address this 
threat.
    While overpressurization is a threat that PHMSA expects operators 
to consider in their DIMP plans, the pipeline safety regulations do not 
explicitly state that operators must identify and evaluate the threat 
of overpressurization in their DIMP plans. Following the Merrimack 
Valley incident on September 13, 2018, PHMSA was required by law to 
ensure that operators evaluate the risk of overpressurization in their 
DIMP plans. PHMSA therefore proposes to amend Sec.  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 Sec.  192.1007(c) and identify risk reduction 
measures in accordance with Sec.  192.1007(d).
c. Proposal To Amend Sec.  192.1007(b)--DIMP--Identify Threats--
Overpressurization on Low-Systems
    PHMSA proposes to amend Sec.  192.1007(b) to create a new threat 
category of ``overpressurization on low-pressure systems.'' This change 
would ensure that consideration of risks under the DIMP regulations 
explicitly includes overpressurization of a low-pressure system as a 
threat. Once identified as a threat under Sec.  192.1007(b), operators 
would also have to evaluate the likelihood and the potential 
consequences of such a failure, as required in Sec.  192.1007(c), and 
ensure risk-reduction measures are identified and implemented under 
Sec.  192.1007(d). PHMSA discusses the actions operators must take to 
implement Sec.  192.1007(c) and Sec.  192.1007(d) in subsection IV.A.5 
and 6 of this preamble.
3. DIMP--Identify Threats (Sec.  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\
---------------------------------------------------------------------------

    \64\ PHMSA, ``Fact Sheet: Natural Force Damage'' (July 23, 
2014), https://primis.phmsa.dot.gov/comm/FactSheets/FSNaturalForce.htm.
    \65\ PHMSA 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.
---------------------------------------------------------------------------

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.
---------------------------------------------------------------------------

    \67\ On February 16, 2021, Dallas, TX recorded temperatures as 
low as -2 [deg]F.
---------------------------------------------------------------------------

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

[[Page 61762]]

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\
---------------------------------------------------------------------------

    \68\ Regulators must be adequately protected from obstructions 
such as dirt, insects, and ice. If the vent on a regulator becomes 
completely obstructed, then the regulator can either shut off the 
flow of gas to a customer or increase the pressure to the upstream 
pressure, causing possible failures.
    \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 Build-Up 
on Gas Distribution Systems,'' ADB-08-03, 73 FR 12796 (Mar. 10, 
2008); ``Potential Damage to Pipelines by Impact of Snowfall, and 
Actions Taken by Homeowners and Others to Protect Gas Systems from 
Abnormal Snow Build-up,'' ADB-97-01 (Jan. 24, 1997); ``Pipeline 
Safety Advisory Bulletin; Snow Accumulation on Gas Pipeline 
Facilities,'' ADB-93-01, 58 FR 7034 (Feb. 3, 1993).
---------------------------------------------------------------------------

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

    \70\ See, e.g., ``Pipeline Safety: Potential for Damage to 
Pipeline Facilities Caused by Flooding, River Scour, and River 
Channel Migration,'' ADB-2016-01, 81 FR 2943 (Jan. 19, 2016); 
``Pipeline Safety: Potential for Damage to Pipeline Facilities 
Caused by the Passage of Hurricanes,'' ADB-2015-02, 80 FR 36042 
(June 23, 2015); ``Pipeline Safety: Potential for Damage to Pipeline 
Facilities Caused by Flooding, River Scour, and River Channel 
Migration,'' ADB-2015-01, 80 FR 19114 (Apr. 9, 2015); ``Pipeline 
Safety: Potential for Damage to Pipeline Facilities Caused by 
Flooding,'' ADB-2013-02, 78 FR 41991 (July 12, 2013); ``Pipeline 
Safety: Potential for Damage to Pipeline Facilities Caused by 
Flooding,'' ADB-11-04, 76 FR 44985 (July 27, 2011).
    \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.
    \72\ U.S. Envtl. Prot. Agency, ``What Climate Change Means for 
Missouri'', EPA 430-F-16-027, at 1 (Aug. 2016), https://19january2017snapshot.epa.gov/sites/production/files/2016-09/documents/climate-change-mo.pdf (noting that over the last half 
century, average annual precipitation in most of the Midwest has 
increased by 5 to 10 percent).
    \73\ See A. Park Williams et al., ``Rapid Intensification of the 
Emerging Southwestern North American Megadrought in 2020-2021,'' 12 
Nature Climate Change 232-234 (2022).
    \74\ U.S. Envtl. Prot. Agency, ``What Climate Change Means for 
Missouri,'' at 1.
    \75\ U.S. Envtl. Prot. Agency, ``Climate Impacts in the 
Midwest,'' Climate Change Impacts, https://climatechange.chicago.gov/climate-impacts/climate-impacts-midwest 
(last visited Feb. 25, 2023).
---------------------------------------------------------------------------

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

    \76\ 77 FR at 13388.
    \77\ Performance Pipe, ``Driscopipe[supreg] 8000 Pipe 
Degradation in High Temperature Applications'' https://www.cpchem.com/sites/default/files/2020-05/DriscopipeDegradation.pdf 
(last visited Mar. 1, 2023).
---------------------------------------------------------------------------

    Following the Merrimack Valley incident, PHMSA reviewed its current 
DIMP regulations for areas where additional clarification could improve 
the safety of gas distribution pipelines. As climate change increases 
the frequency of extreme weather events and natural forces that can 
impact the integrity of pipelines, PHMSA proposes to add clarity to the 
DIMP regulations to ensure that operators are considering these threats 
when evaluating risks. Operators would, therefore, need to consider and 
take appropriate action to address the impacts of extreme weather as a 
threat, regardless of whether they had experienced such events in their 
pipelines' history, while still recognizing regional differences. PHMSA 
expects operators to continue evaluating reasonably available 
information regarding changing operating environments (i.e., climate) 
and the regional impacts of extreme weather on their pipeline.
c. PHMSA's Proposal To Amend Sec.  192.1007(b)--DIMP--Identify 
Threats--Natural Forces Including Extreme Weather and Geohazards
    PHMSA proposes to amend Sec.  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 
Sec.  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 Sec.  192.1007(c), and ensure that they 
identify risk-reduction measures and implement them under Sec.  
192.1007(d). PHMSA expects that operators would not limit their

[[Page 61763]]

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 (Sec.  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, Sec.  
192.1007(c) states that operators ``may subdivide [their] pipeline into 
regions with similar characteristics.'' PHMSA has observed operators 
using age as a method of subdividing their pipeline segments when 
performing the risk analysis. Further, PHMSA's annual report form, 
PHMSA F 7100.1-1, requires operators to identify the miles of pipeline 
by decade of installation. Section 192.1007(b) does not, however, 
specifically require that operators consider the age of a pipe or 
components when identifying threats to pipeline integrity.
b. Need for Change--DIMP--Identify Threats--Age of the System, Pipe, 
and Components
    Over time, all pipeline systems are subject to time-dependent 
degradation processes threatening pipeline integrity. Pipelines made 
from ferrous materials (steel, wrought iron, cast iron, etc.) are all 
susceptible to oxidation corrosion over time. Plastic and composite 
materials used in pipelines are subject to photodegradation if exposed 
to sunlight. Joints, fittings, and welds connecting various pipeline 
components can be subject to dissimilar materials corrosion or chemical 
degradation of bonding agents and sealants. And the longer the 
timeline, the more any gas pipeline components are exposed to a variety 
of phenomena--e.g., from internal mechanical stresses, changes in 
temperature, changes in external loads (including external force 
damage)--that threaten pipeline integrity, exacerbate existing material 
weaknesses, or accelerate time-dependent degradation processes.
    Age can impact and potentially modify each of the threats an 
operator identifies in Sec.  192.1007(b). The potential threat to 
pipeline integrity posed by age depends on the age of the pipeline 
components of which it is comprised. PHMSA understands the cumulative 
effect of those age-related threats to integrity across an entire 
pipeline are not merely the sum of age-related, component-specific 
threats; rather, those threats can magnify or exacerbate one another 
when integrated within a pipeline system. For example, one component's 
failure due to time-dependent degradation processes can strain other 
components throughout the system (e.g., by releasing corrosion products 
that can damage other, newer components within the system). PHMSA 
further notes that trending failure rates by age can be a useful tool 
for revealing degraded performance throughout a pipeline system.
    Similarly, the overall age of the pipeline system can provide more 
opportunities for safety-critical gaps in material records. Poor 
recordkeeping with respect to a pipeline component dating from a 
certain time period may threaten not only pipeline integrity on that 
segment, but also other components of the same pipeline installed at a 
different time period.
    Age can also be expressed in terms of vintage of pipes or 
components. Specific manufacturing techniques and materials used during 
certain periods of time can result in similar characteristics among 
pipes and components of a given vintage. The vintage of pipes or 
components can interact with other threats, including materials, 
equipment failures, or natural forces. For example, pipe installed 
earlier than 1950 has disproportionately high susceptibility to 
problems from cold weather and freezing, which could interact with the 
threat of natural forces. The greater susceptibility of pre-1950 pipe 
is thought to be due to inferior low-temperature ductility of the 
steels of the era and the methods used to join pipe at the time (such 
as electric arc welds, acetylene welds, couplings, and threaded 
collars).\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\
---------------------------------------------------------------------------

    \78\ M.J. Rosenfeld, ``Cold Weather Can Play Havoc On Natural 
Gas Systems'' 242 Pipeline & Gas J. 1 (Jan. 2015), https://pgjonline.com/magazine/2015/january-2015-vol-242-no-1/features/cold-weather-can-play-havoc-on-natural-gas-systems.
    \79\ Brittle-like cracking failures occur under conditions of 
stress intensification. Stress intensification is more common in 
fittings and joints.
---------------------------------------------------------------------------

    Even though time-dependent degradation processes are widely 
understood threats to the integrity of pipeline systems, as discussed 
earlier, Sec.  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.
---------------------------------------------------------------------------

    \80\ PHMSA, ``Pipeline Replacement Background'' (Apr. 26, 2021), 
https://www.phmsa.dot.gov/data-and-statistics/pipeline-replacement/pipeline-replacement-background.
---------------------------------------------------------------------------

    Recent incidents have illustrated that operators may be 
inadequately identifying and managing threats related to the age of 
components on their systems. For example, in its risk analysis, Atmos 
used a commercially available software that did not explicitly consider 
the age of the pipeline segments, instead grouping them into failure 
categories based on similar attributes, such as material and coating. 
Although such an approach may have been compliant with current 
regulations, this approach to risk analysis disregards how the age 
could contribute to failures. Following the 2018 Atmos incidents, the 
NTSB recommended that Gas Piping Technology Committee develop guidance 
and identify steps operators can take to ensure that their gas 
distribution IM programs appropriately consider threats that degrade a 
system over time.\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 Sec.  
192.1007(b) to explicitly identify age as a factor in addressing 
threats to integrity.
---------------------------------------------------------------------------

    \81\ NTSB/PAR-21/01 at 82.
---------------------------------------------------------------------------

c. Proposal To Amend Sec.  192.1007(b)--DIMP--Identify Threats--Age of 
the System, Pipe, and Components
    PHMSA proposes to amend Sec.  192.1007(b) to clarify that operators

[[Page 61764]]

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.
---------------------------------------------------------------------------

    \82\ See Am. Soc'y of Mech. Eng's, ANSI B31.8S-2004, ``Managing 
System Integrity of Gas Pipelines,'' at sec. 2 (Jan. 14, 2005).
---------------------------------------------------------------------------

5. DIMP--Evaluate and Rank Risk (Section 192.1007(c))
a. Current Requirements--DIMP--Evaluate and Rank Risk
    Section 192.1007(c) requires that operators evaluate and rank the 
risks associated with their distribution pipeline systems. This 
evaluation must consider each applicable current and potential threat, 
the likelihood of failure associated with each threat, and the 
potential consequences of such a failure. Operators may subdivide their 
distribution systems into regions (areas within a distribution system 
consisting of mains, services, and other appurtenances) that have 
similar characteristics and reasonably consistent risks, and for which 
similar actions would be effective in reducing risk.
    Through enforcement guidance, PHMSA recommended that operators 
develop weighted factors for each threat specific to their system 
depending upon their unique operating environment.\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.
---------------------------------------------------------------------------

    \83\ DIMP Guidance at 22.
    \84\ DIMP Guidance at 23.
    \85\ DIMP Guidance at 18, 57.
---------------------------------------------------------------------------

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

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

    PHMSA is required by law to ensure that operators' DIMP plans 
evaluate the presence and risks associated with cast iron piping and 
the threat of overpressurization on low-pressure gas distribution 
systems (49 U.S.C. 60109(e)(7)). PHMSA is also required to prohibit 
operators, when evaluating risks related to the operation of a low-
pressure gas distribution system, from determining that there are no 
potential consequences associated with low-probability events unless 
that determination is supported by ``engineering analysis or 
operational knowledge.'' PHMSA must also ensure that operators of gas 
distribution systems consider factors other than past observed 
``abnormal operating conditions''--as that term is defined at Sec.  
192.803--when ranking risks and identifying measures to mitigate those 
risks.
c. PHMSA's Proposal To Amend Sec.  192.1007(c)--DIMP--Evaluate and Rank 
Risk
    PHMSA proposes to redesignate the general requirements of Sec.  
192.1007(c) under a new paragraph (c)(1). These general requirements 
still require operators to consider the identified threats proposed in 
Sec.  192.1007(b) as they evaluate and rank risks.
i. Certain Pipe Materials With Known Issues
    PHMSA proposes to amend Sec.  192.1007(c) by creating a new Sec.  
192.1007(c)(2) to specify that operators must evaluate the risks 
resulting from pipelines constructed with certain materials (including 
cast iron, bare steel, unprotected steel, wrought iron, and historic 
plastics with known issues) when such materials are present in their 
pipeline systems. Overall, these proposed requirements would improve 
safety by codifying in DIMP requirements some of the known, industry-
wide threats if the materials that have exhibited these threats are 
present in the operator's systems, even if operators have not yet 
experienced any of these issues on their systems.
ii. Evaluate and Rank Risk: Low-Pressure Distribution Systems
    PHMSA also proposes to amend Sec.  192.1007(c) by creating a new 
Sec.  192.1007(c)(3) applicable to low-pressure distribution systems. 
Consistent with the mandate in 49 U.S.C. 60109(e)(7), PHMSA proposes to 
require operators of low-pressure gas distribution systems to evaluate 
``the risks that could lead to or result from the operation of a low-
pressure distribution system at a pressure that makes the operation of 
any connected and properly adjusted low-pressure gas burning equipment 
unsafe.'' For the purposes of this NPRM, PHMSA determines that 
``unsafe'' in this context means that gas flowing into the downstream 
equipment is at a pressure beyond the rated supply pressure specified 
by the manufacturer of that equipment. This amendment would ensure that 
operators are addressing the risks on their pipeline that could result 
in an overpressurization.
    In evaluating the risks to low-pressure distribution systems, the 
mandate in 49 U.S.C. 60109(e)(7)(B) requires PHMSA to ensure that 
operators consider ``factors other than past observed abnormal 
operating conditions [. . .] in ranking risks.'' This includes any 
abnormal operating conditions (AOCs) that operators have experienced 
(i.e., observed) on their system and any unobserved AOCs that could 
occur on their system (i.e., an overpressurization on a low-pressure 
system), including any known industry threats, risks, or hazards, as 
identified by an operator from available sources (e.g., PHMSA advisory 
bulletins, PHMSA incident and accident reports, PHMSA and NTSB accident 
reports, State pipeline safety regulatory actions, and operator 
knowledge sharing). PHMSA proposes

[[Page 61765]]

in Sec.  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 Sec.  
192.1007(c)(3)(ii) that will direct operators to evaluate the potential 
consequences associated with low-probability events, unless a 
determination--supported and documented by an engineering analysis or 
other equivalent analysis incorporating operational knowledge--
demonstrates that the event results in no potential consequences (and 
therefore no potential risk).
    An engineering analysis would include documentation of the 
engineering principles used to calculate the flows, pressures, and 
other parameters of the piping and systems to calculate the actual 
downstream pressure. This engineering analysis would also include 
documentation of the methods used to determine that the system cannot 
fail and cause overpressurization, including any data and assumptions 
(including mitigation and control measures) utilized by the operator. 
This engineering analysis may necessarily include degrees of measurable 
operational knowledge regarding specific pipeline characteristics and 
evidence from that analysis combined with documentable known pipeline 
characteristics. An operator that determines there are no potential 
consequences from a low-probability event must document all these 
reasons as part of its ``engineering analysis'' submitted to PHMSA 
according to Sec.  192.18 with sufficient detail as listed in Sec.  
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 Sec.  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 Sec.  192.1007(c)(3)(ii), they must notify PHMSA and the appropriate 
State Authority in accordance with Sec.  192.18 within 30 days of 
making this determination that there are no potential consequences 
associated with the low-probability event. The notification must 
include information such as the date the determination was made (to 
ensure compliance with the proposed timeline), descriptions of the low-
probability events being considered, and a description of the logic 
supporting the determination, including information from an engineering 
analysis or an equivalent analysis incorporating operational knowledge. 
Further, this notification should contain a description of any 
preventive and mitigative measures, including any measures considered 
but not taken, as determined through the engineering analysis or an 
equivalent analysis incorporating operational knowledge. The 
notification should also include a description of the low-pressure 
system, including, at a minimum, miles of pipe, number of customers, 
number of district regulators supplying the system, and other relevant 
information. In addition, operators must provide a written statement 
summarizing the documentation it evaluated and how the conclusion that 
there would be no potential consequences associated with the low-
probability event was reached. This documentation could include the 
inspection and maintenance history of the pipeline segment, incident 
reports, any leak repair data, and any failure investigations or 
abnormal operations records. Providing this information would be 
critical in ensuring that operators robustly evaluated methods of 
reducing risk and that the operator did not ignore any material factors 
in their engineering analysis or an equivalent analysis incorporating 
operational knowledge.
    In a new Sec.  192.1007(c)(3)(iii), PHMSA proposes to require that 
in evaluating and ranking risks in their DIMP plans, operators of low-
pressure gas distribution systems must evaluate the configuration of 
their primary and any secondary overpressure protection installed at 
the district regulator stations, the availability of gas pressure 
monitoring at or near overpressure protection equipment, and the 
likelihood of any single event that immediately or over time could 
result in an overpressurization of the low-pressure system (see amended 
Sec.  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.

[[Page 61766]]

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 Sec.  192.1007(b)) and the evaluation and ranking 
of risks (in accordance with Sec.  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 Sec.  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 Sec.  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.
---------------------------------------------------------------------------

    \87\ DIMP Guidance at 28.
---------------------------------------------------------------------------

b. Need for Change--DIMP--Identify and Implement Measures To Address 
Risks
    Proper implementation of a DIMP plan should result in aggressive 
oversight and replacement of higher-risk infrastructure. For example, 
there are many benefits to replacing old, cast-iron, low-pressure 
distribution pipes with newer materials, such as modern plastic pipe. 
Replacement projects, however, entail their own risks to public safety 
and the environment that need to be balanced against the risks 
associated with leaving a pipeline segment undisturbed. Poorly managed 
construction projects can result in property damage and personal 
injury, and replacement activity can include blowdowns to the 
atmosphere of methane gas that contribute to climate change. Work on 
existing pipeline facilities can also cause a catastrophic 
overpressurization, as was the case in CMA's 2018 incident. Operators 
must manage those risks while still implementing preventive and 
mitigative measures that would reduce the risk of identified threats.
    In 2020, PHMSA issued an advisory bulletin to remind operators of 
the possibility of failure due to an overpressurization on low-pressure 
distribution systems.\88\ In that advisory bulletin, PHMSA reminded 
operators of the existing DIMP regulations and recommended that per 
Sec.  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:
---------------------------------------------------------------------------

    \88\ See ``Pipeline Safety: Overpressure Protection on Low-
Pressure Natural Gas Distribution Systems,'' ADB-2020-02, 85 FR 
61097 (Sept. 29, 2020).
---------------------------------------------------------------------------

    1. Installing a full-capacity relief valve downstream of the low-
pressure regulator station, including in applications where there is 
only worker-monitor pressure control;
    2. Installing a ``slam shut'' device;
    3. Using telemetered pressure recordings at district regulator 
stations to signal failures immediately to operators at control 
centers; and
    4. Completely and accurately documenting the location for all 
control (i.e., sensing) lines on the system.
    As discussed earlier, subsequent to the 2018 Merrimack Valley 
incident, PHMSA was required by statute to ensure that operators of 
low-pressure gas distribution systems evaluate the risk of 
overpressurization in their DIMP plans. (49 U.S.C. 60109(e)(7)(A)(ii)). 
For existing low-pressure systems, operators already have a mechanism 
in place--their DIMP--to evaluate their systems to ensure they can 
identify and implement measures to minimize the risk imposed by any 
inadequate overpressure protection.
c. PHMSA's Proposal To Amend Sec.  192.1007(d)--DIMP--Identify and 
Implement Measures To Address Risks
    PHMSA proposes to amend Sec.  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 Sec.  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 Sec.  192.1007(b)), but also implementing measures to address those 
risks. In a new Sec.  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 Sec.  
192.1007(d)(2), PHMSA proposes that operators must confirm and document 
that each district regulator station meets the design standards in 
Sec.  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 Sec.  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 Sec.  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

[[Page 61767]]

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 Sec.  192.1007(c).
    PHMSA has also proposed to amend Sec.  192.18 to reflect this 
proposed change by including a reference to Sec.  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 Sec.  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\
---------------------------------------------------------------------------

    \89\ NTSB clarified this in an official correspondence to PHMSA 
on July 31, 2020. NTSB, ``Safety Recommendation P-19-014'' (July 31, 
2020), https://data.ntsb.gov/carol-main-public/sr-details/P-19-014.
---------------------------------------------------------------------------

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 Sec.  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 
Sec.  192.1015 that reflect the relative simplicity of these pipeline 
systems. The current DIMP requirements for small LPG operators in Sec.  
192.1015 are less extensive than for other gas distribution systems, 
but still provide operator personnel direction for implementing their 
DIMP plans. Currently, under Sec.  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 Sec.  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 Sec.  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\
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    \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.
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    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 Sec.  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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    \92\ NPGA, Petition for Rulemaking: Small Liquefied Petroleum 
Distribution Systems, Doc. No. PHMSA-2022-0102-001 (Dec. 17, 2021) 
(``NPGA Petition'').
    \93\ NPGA 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).

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[[Page 61768]]

    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 non-metered, 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\
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    \94\ NPGA Petition at 3.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \95\ NPGA Petition at 3-5. PHMSA notes that LPG releases are not 
themselves generally considered to be releases of GHGs.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \96\ NAS Study at 83.
    \97\ NAS Study at 41, Table 3-4.
---------------------------------------------------------------------------

    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\
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    \98\ The NAS Study identified as a source of much of that 
regulatory uncertainty the varied interpretations of ``public 
place'' used at Sec.  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.
---------------------------------------------------------------------------

    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 Sec.  192.1003(b)(4) and delete 
existing Sec.  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 
Sec.  192.1015, the definition of small LPG operators in Sec.  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 Sec.  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.
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    \99\ Nor 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.
---------------------------------------------------------------------------

    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

[[Page 61769]]

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 Sec.  
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, cost-effective, 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.
---------------------------------------------------------------------------

    \100\ PHMSA, ``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-with-Appendices-2020-5-27.pdf.
---------------------------------------------------------------------------

    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.
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    \101\ PHMSA 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.''
    \102\ The 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.
    \104\ This 85-day requirement is not tied to each individual 
inspector. It is an 85-day average over all inspectors.
---------------------------------------------------------------------------

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

[[Page 61770]]

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\
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    \105\ PHMSA anticipates issuing updated Guidance to reflect the 
changes to the Pipeline Safety Grant Program.
---------------------------------------------------------------------------

    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 person-days 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 Sec.  198.3 to add definitions 
for ``inspection person-day'' and ``State Inspection Calculation Tool'' 
and by revising Sec.  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 person-days 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 person-
days 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 Sec.  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 Sec.  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.
---------------------------------------------------------------------------

    \106\ 87 FR at 20940, 20973.
---------------------------------------------------------------------------

    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 Sec.  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.

[[Page 61771]]

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 cost-effective approach to 
achieving the commercial, public safety, and environmental benefits 
discussed in this NPRM and its supporting documents. Lastly, PHMSA 
understands that its proposed compliance timeline--one year after 
publication of a final rule (which would necessarily be in addition to 
the time since publication of this NPRM)--would provide operators ample 
time to implement requisite changes to their procedures (and manage any 
related compliance costs).
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    \107\ PHMSA notes that Sec.  192.9(d) does not currently require 
compliance with Sec.  192.615 for Type B gathering lines, however 
PHMSA has proposed, in another rulemaking, to amend Sec.  192.9(d) 
to require Type B gas gathering operators to comply with Sec.  
192.615. See 88 FR at 31952-53, 31955-56.
---------------------------------------------------------------------------

    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 
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--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 Sec.  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 Sec.  
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 Sec.  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.
---------------------------------------------------------------------------

    \108\ PHMSA 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.
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    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 Sec.  192.615 in the Valve Rule essentially codified this 
advisory.

[[Page 61772]]

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 Sec.  192.615, which 
would require the direct and immediate notification of the appropriate 
PSAP.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

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.
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    \111\ NTSB, 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.
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    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.
---------------------------------------------------------------------------

    \112\ NTSB/PAR-19/02 at 46.
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    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 Sec.  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 Sec.  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 Sec.  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 Sec.  
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\
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    \113\ PHMSA also is adding, applicable to all part 192-regulated 
gas pipeline operators, ``potential rupture'', consistent with the 
amendment in the Valve Rule to Sec.  192.615(a)(8).
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    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

[[Page 61773]]

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\
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    \114\ See PHMSA, ``Distribution, Transmission & Gathering, LNG, 
and Liquid Accident and Incident Data'' (Aug. 31, 2022), https://www.phmsa.dot.gov/data-and-statistics/pipeline/distribution-transmission-gathering-lng-and-liquid-accident-and-incident-data.
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    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 Sec.  192.615. This amendment would 
specify a non-exclusive 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 Sec.  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 Sec. Sec.  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 
Sec. Sec.  191.5 and 195.52 reportable events may not always constitute 
a gas pipeline emergency as proposed in Sec.  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 Sec.  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 Sec.  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 Sec.  191.5 before initiating an 
emergency response.
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    \115\ The term ``confirmed discovery,'' defined at Sec. Sec.  
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.''
    \116\ Relying 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.
    \117\ PHMSA's proposal anticipates that an operator will alert 
local emergency response officials upon earliest indications of gas 
pipeline emergencies.
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    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 Sec.  191.3, operators would 
report the incident to the National Response Center in accordance with 
Sec.  191.5, as already required.
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    \118\ See Sec.  192.635(a)(1) (specifying a 15-minute time 
interval for evaluating significant pressure losses on gas pipelines 
as an indicium of a rupture).
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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\
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    \119\ FEMA, ``Lesson 3: Communicating in an Emergency'' (Feb. 
2014), https://training.fema.gov/emiweb/is/is242b/instructor%20guide/ig_03.pdf.
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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

[[Page 61774]]

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\
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    \120\ Section 192.616 requires operators to develop and 
implement a written continuing public-education program that follows 
the guidance provided in American Petroleum Institute's (API) 
Recommended Practice (RP) 1162 (incorporated by reference, see Sec.  
192.7). API RP 1162 is a consensus standard that establishes a 
baseline public-awareness program for pipeline operators. It states 
that operators should provide notice of, and information regarding, 
their emergency response plans to appropriate local emergency 
officials.
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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 Sec.  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 
in-person 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\
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    \121\ Mass. 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-gas-explosions-after-action-report/download (``Merrimack 
Valley After Action Report'').
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    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 Sec.  192.616(g), operators must 
conduct their public awareness program in other languages commonly 
understood by a significant number and

[[Page 61775]]

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.
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    \122\ Ltd. English Proficiency, ``Data and Language Maps,'' U.S. 
DOJ, https://www.lep.gov/maps (last visited Feb. 27, 2023).
    \123\ U.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.
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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\
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    \124\ Merrimack Valley After Action Report at 46.
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    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, time-
sensitive 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 Sec.  192.615--Emergency Response Plans--Customers
    Pursuant to 49 U.S.C. 60102(r)(3), PHMSA proposes to add to Sec.  
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 opt-out 
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 
third-party vendor or build such a service in-house. Regardless of who 
administers the notification system proposed in Sec.  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

[[Page 61776]]

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.
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    \125\ PHMSA further understands that some utilities (e.g., 
electric utilities) may have similar notification systems for their 
customers and the public within their service areas.
---------------------------------------------------------------------------

    Because periodic testing is essential for ensuring proper operation 
of such an emergency customer notification system, PHMSA includes 
within its proposed Sec.  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 English-speaking 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\
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    \126\ As 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.
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    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.
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    \127\ While 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.
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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.
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    \128\ FEMA, ``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.
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    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\
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    \129\ AGA, ``Emergency Preparedness Handbook for Natural Gas 
Utilities'' at 10, https://www.aga.org/wp-content/uploads/2022/12/aga-emergency-preparedness-handbook-2018.pdf.
    \130\ API Recommended Practice 1174, ``Recommended Practice for 
Onshore Hazardous Liquid Pipeline Emergency Preparedness and 
Response'' at 26 (1st ed. Dec. 2015).
    \131\ NFPA, ``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.
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    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 multi-jurisdictional 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

[[Page 61777]]

inform such a regulatory standard. Specifically, PHMSA is considering 
requirements under Sec.  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 Sec.  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.
---------------------------------------------------------------------------

    \132\ NTSB/PAR-19/02 at 45-47, 48-49.
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    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.
---------------------------------------------------------------------------

    \133\ FEMA, ``National Incident Management System'' (May 24, 
2022), https://www.fema.gov/emergency-managers/nims.
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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 Sec.  
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, cost-effectiveness, 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, Sec.  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 
build-up allowed for operation of pressure-limiting 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 Sec.  192.605.'' \134\ 
Among the records required to be kept and made available to operating 
personnel are ``construction records, maps and operating history,'' per 
Sec.  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.
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    \134\ 49 CFR 192.603(b).
---------------------------------------------------------------------------

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

[[Page 61778]]

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 Sec.  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 Sec.  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 Sec.  192.605--O&M Manuals--Overpressurization
    In this NPRM, PHMSA proposes to amend Sec.  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\
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    \135\ Although 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.
    \136\ PHMSA 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.
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    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

[[Page 61779]]

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 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 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 Sec.  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 Sec.  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., high-consequence areas, which are not applicable to 
gas distribution pipelines).
---------------------------------------------------------------------------

    \137\ Am. Soc'y of Mech. Eng's, ANSI B31.8S-2004, ``Managing 
System Integrity of Gas Pipelines'' (Jan. 14, 2005).
---------------------------------------------------------------------------

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.
---------------------------------------------------------------------------

    \138\ NTSB/PAR-19/02 at 16.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \139\ NTSB/PAR-19/02 at 51.
---------------------------------------------------------------------------

    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 Sec.  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,

[[Page 61780]]

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.
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    \140\ PHMSA 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. 60102(s) 
explicitly required update of regulations governing ``procedural 
manuals for operations, maintenance, and emergencies''--located at 
Sec.  192.605.
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    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.
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    \141\ ``Qualified'' under Sec.  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.
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    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.
---------------------------------------------------------------------------

    \142\ NTSB/PAR-19/02 at 50.
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    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

[[Page 61781]]

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).
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    \143\ ASME/ANSI, B31.8S-2004, ``Managing System Integrity of Gas 
Pipelines, Supplement to B31.8'' (Jan. 14, 2005) (incorporated by 
reference under Sec.  192.7).
---------------------------------------------------------------------------

    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 Sec.  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.
---------------------------------------------------------------------------

    \144\ On 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.
---------------------------------------------------------------------------

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 (Sec.  
192.517); corrosion control (Sec.  192.491); customer notification 
(Sec.  192.16); uprating (Sec.  192.553); surveying, patrolling, 
monitoring, inspections, operations, maintenance, and emergencies 
(Sec. Sec.  192.603 and 192.605); and operator qualification (Sec.  
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, Sec.  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.
---------------------------------------------------------------------------

    \145\ See Sec. Sec.  192.603(b), 192.605(b)(1), and subpart M 
(incorporating Sec. Sec.  192.199 and 192.201).
---------------------------------------------------------------------------

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

[[Page 61782]]

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.
---------------------------------------------------------------------------

    \146\ NTSB/PAR-19/02 at 16-17.
---------------------------------------------------------------------------

    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 low-pressure 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 decision-making. 
Without maps of the low-pressure 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 Sec.  192.638--Records: Distribution System 
Pressure Controls
    PHMSA proposes a new Sec.  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\
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    \147\ As discussed elsewhere in the preamble, PHMSA also 
proposes to introduce a cross-reference to this new Sec.  192.638 
within its existing DIMP plan knowledge management requirements at 
Sec.  192.1007(a)(3).
---------------------------------------------------------------------------

    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 Sec.  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.
---------------------------------------------------------------------------

    \148\ ``Pipeline Safety: Safety of Gas Transmission Pipelines: 
MAOP Reconfirmation, Expansion of Assessment Requirements, and Other 
Related Amendments,'' 84 FR 52180 (Oct. 1, 2019).
    \149\ Compare 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 . . . .'').
---------------------------------------------------------------------------

    In Sec.  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 low-pressure 
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

[[Page 61783]]

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 Sec.  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 Sec.  192.605 to ensure that operators have 
procedures for implementing the new recordkeeping requirements proposed 
in Sec.  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 Sec.  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 Sec.  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 Sec.  192.1007(a)(3) so that it references Sec.  192.638(c). 
This would require operators to identify records specified in Sec.  
192.638(c) that they could collect as part of their DIMP plan.
    In Sec.  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 Sec.  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 Sec.  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 Sec.  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 
Sec.  192.638 recordkeeping requirements to those operators, PHMSA 
proposes to except those systems from the new recordkeeping requirement 
at Sec.  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 Sec.  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., Sec.  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

[[Page 61784]]

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).
---------------------------------------------------------------------------

    \150\ ASME/ANSI, B31.8S-2004, ``Managing System Integrity of Gas 
Pipelines, Supplement to B31.8'' (Jan. 14, 2005) (incorporated by 
reference under Sec.  192.7).
---------------------------------------------------------------------------

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 Sec.  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.
---------------------------------------------------------------------------

    \151\ NTSB, 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.
---------------------------------------------------------------------------

    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 Sec.  192.640 Distribution Pipelines: Presence 
of Qualified Personnel
    In a new Sec.  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\
---------------------------------------------------------------------------

    \152\ This exception will be reflected by addition of new 
paragraph (d).
---------------------------------------------------------------------------

    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

[[Page 61785]]

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 Sec.  
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 Sec.  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 Sec.  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 Sec.  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 Sec.  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 Sec.  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, cost-effective, 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 
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).
4. Proposal To Amend Sec.  192.605 Procedures for Qualified Personnel 
Monitoring Gas Pressure
    PHMSA proposes to revise Sec.  192.605, by adding paragraph 
(b)(13), to ensure gas distribution operators have procedures for 
implementing the monitoring requirements in the proposed Sec.  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

[[Page 61786]]

Sec.  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, cost-effective, 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\
---------------------------------------------------------------------------

    \153\ See ``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).
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \154\ There are a few types of monitor regulating, all of which 
operate substantially similarly as described herein: working 
monitor, series regulation, and relief monitoring.
---------------------------------------------------------------------------

    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 small-diameter 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 low-pressure 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

[[Page 61787]]

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 
Sec. Sec.  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\
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    \155\ Except as provided in Sec.  192.197, which only applies to 
high-pressure gas distribution systems.
    \156\ See ``Establishment of Minimum Standards,'' 35 FR 13248, 
13264 (Aug. 19, 1970).
---------------------------------------------------------------------------

    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\
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    \157\ PHMSA, ``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/regulatory-compliance/pipeline/enforcement/5776/o-m-enforcement-guidance-part-192-7-21-2017.pdf.
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    In addition, Sec.  192.739 describes the minimum requirements for 
the inspection and testing of pressure-limiting 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 Sec.  192.739(b) applicable to 
certain steel pipelines, set to control or relieve at the correct 
pressure consistent with the pressure limits of Sec.  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 Sec.  192.195 (Protection Against Accidental 
Overpressuring) and Sec.  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\
---------------------------------------------------------------------------

    \158\ NTSB/PAR-19/02 at 39.
    \159\ NTSB/PAR-19/02 at 39-40.
---------------------------------------------------------------------------

    CMA's overpressurization was not an isolated event. For example, on 
January 28, 1982, in Centralia, MO, high-pressure natural gas entered a 
low-pressure 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 
pilot-light 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.
---------------------------------------------------------------------------

    \160\ NTSB, Accident Report PAR-82/03, ``Missouri Power and 
Light Company Natural Gas Fires, Centralia, Missouri, January 28, 
1982'' (Aug. 24, 1982).
---------------------------------------------------------------------------

    The NTSB investigated one other incident in 1977 that was nearly 
identical to the 2018 incident in

[[Page 61788]]

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\
---------------------------------------------------------------------------

    \161\ NTSB, Safety Recommendation(s) P-77-43 (Dec. 9, 1977), 
https://www.ntsb.gov/safety/safety-recs/RecLetters/P77_43.pdf.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \162\ Sec. 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.
---------------------------------------------------------------------------

    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 low-pressure 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 Sec.  192.195--Overpressure Protection
    Consistent with 49 U.S.C. 60102(t)(3), PHMSA proposes to amend 
Sec.  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 
low-pressure 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.
---------------------------------------------------------------------------

    \163\ An underpressurization could occur if there is a pipeline 
rupture downstream, which is a risk during excavation.
---------------------------------------------------------------------------

    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 Sec.  192.1007(d)(2)(ii) to 
require operators to ensure district regulator stations have two 
methods of overpressure protection consistent with proposed Sec.  
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 Sec.  
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.

[[Page 61789]]

    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 Sec.  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 
Sec.  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 Sec.  
192.195(c)(3) to require that low-pressure 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 
Sec. Sec.  192.199 and 192.201). However, the current telemetering and 
recording device requirements in Sec.  192.741 do not require active 
monitoring and some of these devices employed under Sec. Sec.  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 Sec.  
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 Sec.  
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 Sec.  
192.1007, they would be required to ensure those upgrades meet the 
proposed design standard in Sec.  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 low-pressure 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 cost-effective approach to achieving the 
commercial, public safety, and environmental benefits discussed in this 
NPRM and its supporting documents. Lastly, PHMSA understands that its 
proposed compliance timeline--one year after publication of a final 
rule (which would necessarily be in addition to the time since 
publication of this NPRM)--would provide operators ample time to 
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 Sec.  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 Sec.  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, Sec.  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 Sec.  
192.305 to specify that a pipeline operator may not use the same 
operator personnel to perform a required

[[Page 61790]]

inspection who also performed the construction task that required 
inspection.\166\
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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.
    \165\ NAPSR, Resolution CR-1-02, Doc. No. PHMSA-2010-0026-0002 
(Dec. 15, 2011).
    \166\ ``Pipeline Safety: Miscellaneous Changes to Pipeline 
Safety Regulations,'' 80 FR 12762, 12779 (Mar. 11, 2015).
---------------------------------------------------------------------------

    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 Sec.  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 Sec.  192.305.
---------------------------------------------------------------------------

    \167\ APGA, ``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).
    \168\ APGA, ``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).
---------------------------------------------------------------------------

    NAPSR, on the other hand, submitted a petition criticizing the 
March 2015 final rule for not limiting the Sec.  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 
Sec.  192.305 until PHMSA had reviewed the rule and worked with NAPSR 
to address its concerns.
---------------------------------------------------------------------------

    \169\ 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).
---------------------------------------------------------------------------

    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 
Sec.  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.
---------------------------------------------------------------------------

    \170\ ``Pipeline Safety: Miscellaneous Changes to Pipeline 
Safety Regulations: Response to Petitions for Reconsideration,'' 80 
FR 58633, 58634 (Sept. 30, 2015).
---------------------------------------------------------------------------

3. Proposal To Amend Sec.  192.305--Inspections
    In this NPRM, PHMSA proposes to remove the existing suspension of 
Sec.  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 Sec.  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 Sec.  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\
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    \171\ PHMSA 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.
---------------------------------------------------------------------------

    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 Sec.  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.
---------------------------------------------------------------------------

    \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).
    \173\ PHMSA's preliminary review of the incoming reported data 
supports its estimates in the PRIA for Type C lines.
    \174\ See Preliminary Regulatory Impact Analysis, available in 
the docket for this rulemaking.
---------------------------------------------------------------------------

    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 safety-improving construction 
projects

[[Page 61791]]

(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 operator-employed 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.
---------------------------------------------------------------------------

    \175\ See 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.
---------------------------------------------------------------------------

    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 cost-effective approach 
to achieving the commercial, public safety, and environmental benefits 
discussed in this NPRM and its supporting documents. Lastly, PHMSA 
understands that its proposed compliance timeline--one year after 
publication of a final rule (which would necessarily be in addition to 
the time since publication of this NPRM)--would provide operators ample 
time to implement requisite changes to their procedures and obtain 
access to inspection personnel for near-term 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 
Sec. Sec.  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\
---------------------------------------------------------------------------

    \176\ Paragraph (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.
---------------------------------------------------------------------------

2. Need for Change--Records: Tests
    On October 7, 2021, NAPSR submitted a resolution seeking that PHMSA 
amend Sec.  192.517(b) in several ways. NAPSR recommended PHMSA amend 
its regulations to require operators to retain test documentation under 
Sec.  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.
---------------------------------------------------------------------------

    \177\ NAPSR, 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.''
---------------------------------------------------------------------------

    NAPSR also requested that PHMSA add Sec.  192.725 (``Test 
requirements for reinstating service lines'') to the list of required 
test records in Sec.  192.517(b). It reasoned that Sec.  192.603(b), 
which requires operators to keep records necessary to administer the 
procedures established under Sec.  192.605, is potentially in conflict 
with Sec.  192.517. PHMSA clarifies that the requirement in Sec.  
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 Sec.  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 Sec.  192.725, which includes 
meeting the corresponding recordkeeping requirements of Sec.  192.517. 
For that reason, PHMSA does not propose to include Sec.  192.725 in the 
list of tests identified within Sec.  192.517.
3. Proposal To Amend Sec.  192.517--Records: Tests
    PHMSA proposes to amend Sec.  192.517 to require that records of 
tests covered by Sec.  192.517(b) (i.e., tests performed according to 
Sec.  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 Sec.  
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

[[Page 61792]]

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 Sec.  192.603(b) 
and Sec.  192.605) operators to keep MAOP records for life of facility 
but MAOP records established by Sec.  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 cost-effective approach 
to achieving the commercial, public safety, and environmental benefits 
discussed in this NPRM and its supporting documents. Lastly, PHMSA 
understands that its proposed compliance timeline--one year after 
publication of a final rule (which would necessarily be in addition to 
the time since publication of this NPRM)--would provide operators ample 
time to implement requisite changes to their procedures to ensure 
identification or generation of pertinent records (and manage any 
related compliance costs).
4. Proposal To Amend Sec.  192.725--Test Requirements for Reinstating 
Service Lines
    PHMSA proposes to revise Sec.  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 
Sec.  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 Sec.  
192.3 applicable to all part 192-regulated gas pipelines; and within a 
new Sec.  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 part-192 regulated gas gathering pipelines to 
which they had applied.\179\ Specifically, the Technical Correction 
introduced language in each of the Sec.  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 Sec.  192.9 preventing application of the Valve 
Rule's amendments at Sec. Sec.  192.615 and 192.635 regarding emergency 
response and notification and rupture identification procedures to each 
of offshore gas gathering pipelines (Sec.  192.9(b)) as well as onshore 
Types A (Sec.  192.9(c)) and C (Sec.  192.9(e)) gas gathering 
pipelines.
---------------------------------------------------------------------------

    \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).
---------------------------------------------------------------------------

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 (Sec.  192.615(a)(2) and (8); Sec.  
192.615(c)); taking actions necessary to minimize hazards to public 
safety from the emergency (Sec.  192.615(a)(6)); and directing operator 
control room response actions in an emergency (Sec.  192.615(a)(11)).
---------------------------------------------------------------------------

    \180\ See, 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 Sec.  192.615 requirements to high-
pressure, large-diameter Type C gas gathering pipelines).
---------------------------------------------------------------------------

    The amendments to Sec.  192.615 introduced in the Valve Rule were 
modest refinements to those long-standing emergencies response planning 
and notification requirements. The Valve Rule explained its amendments 
to Sec.  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 Sec.  
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

[[Page 61793]]

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.
---------------------------------------------------------------------------

    \181\ 87 FR at 20969-70, 20973.
---------------------------------------------------------------------------

    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 
Sec.  192.3 (which in turn references a new Sec.  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 Sec.  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 Sec.  
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 
Sec.  192.615(a)(11) governing emergency procedures for control room 
personnel by adding a cross-reference to newly-adopted provisions 
pertaining to rupture mitigation valves at Sec. Sec.  192.634 and 
192.636.
---------------------------------------------------------------------------

    \182\ The 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.
---------------------------------------------------------------------------

    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 Sec. Sec.  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 Sec.  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 Sec.  192.9 similar language 
excluding application of the Valve Rule's amendments to Sec.  192.615 
discussed in section IV.K.2 above to offshore gas gathering (Sec.  
192.9(b)), Type A (Sec.  192.9(c)), and Type C (Sec.  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.
---------------------------------------------------------------------------

    \185\ PHMSA understands that in so doing, the Sec.  192.635 
definition of ``notification of potential rupture'' referenced 
within Sec.  192.3 would apply to all part 192-regulated gas 
gathering pipelines as well.
---------------------------------------------------------------------------

    As explained in section IV.K.2 above, the Valve Rule's amendments 
to Sec.  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 Sec.  
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 
Sec.  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 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 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

[[Page 61794]]

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.
---------------------------------------------------------------------------

    \186\ E.O. 12866 is available at 58 FR 51735 (Oct. 4, 1993); 
E.O. 14094 is available at 88 FR 21879 (Apr. 6, 2023).
---------------------------------------------------------------------------

    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 low-income 
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.
---------------------------------------------------------------------------

    \187\ 59 FR 7629 (Feb. 16, 1994).
---------------------------------------------------------------------------

    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 low-income, 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.
---------------------------------------------------------------------------

    \188\ See, e.g., Luna & Nicholas, ``An Environmental Justice 
Analysis of Distribution-Level Natural Gas Leaks in Massachusetts, 
USA,'' 162 Energy Policy 112778 (Mar. 2022); Weller et al., 
``Environmental Injustices of Leaks from Urban Natural Gas 
Distribution Systems: Patterns Among and Within 13 U.S. Metro 
Areas,'' Environ. Sci & Tech. (May 11, 2022).
---------------------------------------------------------------------------

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\
---------------------------------------------------------------------------

    \189\ Agencies 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-concerning-small-entities (last updated May 18. 2012).
---------------------------------------------------------------------------

    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

[[Page 61795]]

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.
---------------------------------------------------------------------------

    \192\ See PRIA Table 45.
---------------------------------------------------------------------------

    PHMSA then calculated cost-to-revenue 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.
---------------------------------------------------------------------------

    \193\ For 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.
---------------------------------------------------------------------------

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

[[Page 61796]]

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.
---------------------------------------------------------------------------

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

    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 
Tribal-owned 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,

[[Page 61797]]

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 
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. 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.

[[Page 61798]]

    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 low-pressure 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 [email protected] 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

[[Page 61799]]

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.''
---------------------------------------------------------------------------

    \195\ 64 FR 43255 (Aug. 10, 1999).
    \196\ 74 FR 24693 (May 22, 2009).
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \197\ 66 FR 28355 (May 22, 2001).
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \198\ 77 FR 26413 (May 4, 2012).
---------------------------------------------------------------------------

    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,

[[Page 61800]]

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.
---------------------------------------------------------------------------

    \199\ 86 FR 26633 (May 17, 2021).
---------------------------------------------------------------------------

    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, real-time 
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.
---------------------------------------------------------------------------

    \200\ E.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).
    \201\ See, e.g., CISA, National Cyber Awareness System Alerts, 
https://www.cisa.gov/uscert/ncas/alerts (last accessed Feb. 1, 
2023).
---------------------------------------------------------------------------

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

0
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.

0
2. Revise Sec.  191.11 to read as follows:


Sec.  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 Sec.  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 
Sec.  192.8.

PART 192--TRANSPORTATION OF NATURAL AND OTHER GAS BY PIPELINE: 
MINIMUM FEDERAL SAFETY STANDARDS

0
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.


Sec.  192.3  [Amended]

0
4. Amend Sec.  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)''.


Sec.  192.9  [Amended]

0
5. Amend Sec.  192.9 by:
0
a. Removing from paragraph (b) the last sentence;
0
b. Removing from paragraph (c) the last sentence; and
0
c. Removing from paragraph (e)(1)(iv) the words ``effective as of 
October 4, 2022.''
0
6. Amend Sec.  192.18 by revising paragraph (c) to read as follows:


Sec.  192.18  How to notify PHMSA.

* * * * *
    (c) Unless otherwise specified, if an operator submits, pursuant to 
Sec. Sec.  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

[[Page 61801]]

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.
0
7. Amend Sec.  192.195 by adding paragraph (c) to read as follows:


Sec.  192.195  Protection against accidental overpressuring.

* * * * *
    (c) Additional requirements for low-pressure 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.
0
8. Amend Sec.  192.305 by:
0
a. Lifting the stay of the section; and
0
b. Revising the section.
    The revision reads as follows:


Sec.  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.
0
9. Amend Sec.  192.517 by revising paragraph (b) to read as follows:


Sec.  192.517  Records.

* * * * *
    (b) Each operator must maintain a record of each test required by 
Sec. Sec.  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.
0
10. Amend Sec.  192.605 by adding paragraphs (b)(13), (f), and (g) to 
read as follows:


Sec.  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, Sec.  192.638, and 
Sec.  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.
0
11. Amend Sec.  192.615 by:
0
a. Adding paragraphs (a)(3)(v) through (viii);
0
b. Revising paragraph (a)(8); and
0
c. Adding paragraphs (a)(13) and paragraph (d).
    The additions and revision read as follows:


Sec.  192.615  Emergency plans.

    (a) * * *
    (3) * * *

[[Page 61802]]

    (v) Notification of potential rupture (see Sec.  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 Sec. Sec.  
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 non-English 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 Sec.  
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.
0
12. Add Sec.  192.638 to read as follows:


Sec.  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 Sec.  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.
0
13. Add Sec.  192.640 to read as follows:


Sec.  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

[[Page 61803]]

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 Sec.  192.638); the 
authority to stop work (unless prohibited by operator procedures); 
operations procedures under Sec.  192.605; and emergency response 
procedures under Sec.  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.
0
14. Amend Sec.  192.725 by revising paragraph (a) to read as follows:


Sec.  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.
* * * * *
0
15. Amend Sec.  192.741 by:
0
a. Revising the title of the section, and
0
b. Adding paragraph (d).
    The revision and addition read as follows:


Sec.  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 Sec.  192.195(c)(3).


Sec.  192.1001  [AMENDED]

0
16. Amend Sec.  192.1001 by removing the definition of ``Small LPG 
Operator.''
0
17. Amend Sec.  192.1003 by adding paragraph (b)(4) to read as follows:


Sec.  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.
0
18. Amend Sec.  192.1005 by revising the title of the section to read 
as follows:


Sec.  192.1005  What must a gas distribution operator do to implement 
this subpart?

0
19. Amend Sec.  192.1007 by revising paragraphs (a)(3), (b), (c), and 
(d) to read as follows:


Sec.  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 Sec.  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 low-
pressure 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 Sec.  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 Sec.  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

[[Page 61804]]

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 
low-pressure 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 Sec. Sec.  192.638 and 192.1007(a)(3).
    (ii) Confirm and document that each district regulator station 
meets the requirements of Sec.  192.195(c)(1) through (3). If an 
operator determines that a district regulator station does not meet the 
requirements of Sec.  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 Sec.  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 
Sec.  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.
* * * * *


Sec.  192.1015  [Removed]

0
20. Remove Sec.  192.1015.

PART 198--REGULATIONS FOR GRANTS TO AID STATE PIPELINE SAFETY 
PROGRAMS

0
21. The authority citation for part 198 continues to read as follows:

    Authority:  49 U.S.C. 60101 et seq.; 49 CFR 1.97.

0
22. Amend Sec.  198.3 by adding the definitions for ``Inspection 
person-day'' and ``State Inspection Calculation Tool (SICT)'' in 
alphabetical order to read as follows:


Sec.  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.
* * * * *
0
23. Amend Sec.  198.13 by revising paragraph (c)(6) to read as follows:


Sec.  198.13  Grant-allocation formula.

* * * * *
    (c) * * *
    (6) Number of state inspection person-days, 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


