Proposed Rule2023-18585
Pipeline Safety: Safety of Gas Distribution Pipelines and Other Pipeline Safety Initiatives
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Published
September 7, 2023
Issuing agencies
Transportation DepartmentPipeline and Hazardous Materials Safety Administration
Abstract
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.
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[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 [<a href="http://www.gpo.gov">www.gpo.gov</a>]
[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
[[Page 61746]]
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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: <a href="https://www.regulations.gov">https://www.regulations.gov</a>. This site allows the public
to enter comments on any Federal Register notice issued by any agency.
Follow the online instructions for submitting comments.
Mail: Docket Management System: U.S. Department of Transportation,
1200 New Jersey Avenue SE, West Building Ground Floor, Room W12-140,
Washington, DC 20590-0001.
Hand Delivery: 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 <a href="https://www.regulations.gov">https://www.regulations.gov</a> 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 <a href="https://www.regulations.gov">https://www.regulations.gov</a>. 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 <a href="/cdn-cgi/l/email-protection#b2d3c1dadedbdc9cd0dddeded3d1d9d7c0f2d6ddc69cd5ddc4"><span class="__cf_email__" data-cfemail="e283918a8e8b8ccc808d8e8e8381898790a2868d96cc858d94">[email protected]</span></a>.
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),
<a href="https://www.ntsb.gov/investigations/AccidentReports/Reports/PAR1902.pdf">https://www.ntsb.gov/investigations/AccidentReports/Reports/PAR1902.pdf</a>.
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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), <a href="https://www.whitehouse.gov/wp-content/uploads/2021/11/US-Methane-Emissions-Reduction-Action-Plan-1.pdf">https://www.whitehouse.gov/wp-content/uploads/2021/11/US-Methane-Emissions-Reduction-Action-Plan-1.pdf</a>. 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
[[Page 61748]]
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).
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\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).
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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.
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\9\ 88 FR 21879 (Apr. 6, 2023); 58 FR 51735 (Oct. 4, 1993).
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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), <a href="https://www.phmsa.dot.gov/data-and-statistics/pipeline/annual-report-mileage-gas-distribution-systems">https://www.phmsa.dot.gov/data-and-statistics/pipeline/annual-report-mileage-gas-distribution-systems</a>.
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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\
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\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), <a href="https://primis.phmsa.dot.gov/meetings/FilGet.mtg?fil=1227">https://primis.phmsa.dot.gov/meetings/FilGet.mtg?fil=1227</a>. 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), <a href="https://www.phmsa.dot.gov/data-and-statistics/pipeline/pipeline-incident-20-year-trends">https://www.phmsa.dot.gov/data-and-statistics/pipeline/pipeline-incident-20-year-trends</a>.
\14\ ``Pipeline Incident 20 Year Trends'' (Nov. 15, 2022),
<a href="https://www.phmsa.dot.gov/data-and-statistics/pipeline/pipeline-incident-20-year-trends">https://www.phmsa.dot.gov/data-and-statistics/pipeline/pipeline-incident-20-year-trends</a>.
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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),
<a href="https://www.phmsa.dot.gov/data-and-statistics/pipeline-replacement/decade-inventory">https://www.phmsa.dot.gov/data-and-statistics/pipeline-replacement/decade-inventory</a>.
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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\
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\16\ PHMSA, ``U.S. Transportation Secretary Ray LaHood Announces
Pipeline Safety Action Plan'' (Apr. 4, 2011), <a href="https://www.phmsa.dot.gov/sites/phmsa.dot.gov/files/docs/dot4111.pdf">https://www.phmsa.dot.gov/sites/phmsa.dot.gov/files/docs/dot4111.pdf</a>.
\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), <a href="https://www.phmsa.dot.gov/data-and-statistics/pipeline-replacement/cast-and-wrought-iron-inventory">https://www.phmsa.dot.gov/data-and-statistics/pipeline-replacement/cast-and-wrought-iron-inventory</a> (``Cast and Wrought Iron Inventory'').
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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.
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\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) <a href="https://www.energy.gov/sites/prod/files/2015/08/f25/QER%20Summary%20for%20Policymakers%20April%202015.pdf">https://www.energy.gov/sites/prod/files/2015/08/f25/QER%20Summary%20for%20Policymakers%20April%202015.pdf</a>.
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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),
<a href="https://pstrust.org/wp-content/uploads/2019/03/2019-PST-Briefing-Paper-02-NatGasBasics.pdf">https://pstrust.org/wp-content/uploads/2019/03/2019-PST-Briefing-Paper-02-NatGasBasics.pdf</a>.
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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.
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\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).
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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\
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\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.
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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.
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\23\ CMA transferred from NiSource, Inc. to Eversource Energy in
November 2020.
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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.
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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.
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\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.
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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.
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\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), <a href="https://www.mass.gov/doc/independent-assessment-of-columbia-gas-of-massachusetts-merrimack-valley-restoration-program/download">https://www.mass.gov/doc/independent-assessment-of-columbia-gas-of-massachusetts-merrimack-valley-restoration-program/download</a>.
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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
<a href="https://www.ntsb.gov/investigations/AccidentReports/Reports/PAR1902.pdf">https://www.ntsb.gov/investigations/AccidentReports/Reports/PAR1902.pdf</a>.
\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), <a href="https://data.ntsb.gov/carol-main-public/sr-details/P-19-014">https://data.ntsb.gov/carol-main-public/sr-details/P-19-014</a>.
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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), <a href="https://www.phmsa.dot.gov/sites/phmsa.dot.gov/files/docs/RSPA%20Alert%20Notice%2091-02.pdf">https://www.phmsa.dot.gov/sites/phmsa.dot.gov/files/docs/RSPA%20Alert%20Notice%2091-02.pdf</a>; RSPA,
ALN-92-02 (June 26, 1992), <a href="https://www.phmsa.dot.gov/sites/phmsa.dot.gov/files/docs/RSPA%20Alert%20Notice%2092-02.pdf">https://www.phmsa.dot.gov/sites/phmsa.dot.gov/files/docs/RSPA%20Alert%20Notice%2092-02.pdf</a>
(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.
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\34\ 74 FR 63906 (Dec. 4, 2009).
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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), <a href="https://www.phmsa.dot.gov/sites/phmsa.dot.gov/files/docs/DIMP_Enforcement_Guidance_12_7_2015.pdf">https://www.phmsa.dot.gov/sites/phmsa.dot.gov/files/docs/DIMP_Enforcement_Guidance_12_7_2015.pdf</a> (``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), <a href="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">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</a>.
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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), <a href="https://www.phmsa.dot.gov/sites/phmsa.dot.gov/files/docs/DIMP_Enforcement_Guidance_12_7_2015.pdf">https://www.phmsa.dot.gov/sites/phmsa.dot.gov/files/docs/DIMP_Enforcement_Guidance_12_7_2015.pdf</a> (``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.
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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.
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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).
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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.
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\52\ NTSB, Accident Report PAR-21/01, ``Atmos Energy Corporation
Natural Gas-Fueled Explosion: Dallas, Texas: February 23, 2018''
(Jan. 12, 2021), <a href="https://www.ntsb.gov/investigations/AccidentReports/Reports/PAR2101.pdf">https://www.ntsb.gov/investigations/AccidentReports/Reports/PAR2101.pdf</a>.
\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.''
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\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.
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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.
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\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).
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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.
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\58\ RSPA, ALN-92-02 (June 26, 1992); RSPA, ALN-91-02 (Oct. 11,
1991).
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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).
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\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.
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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'', <a href="https://www.aga.org/natural-gas/safety/promoting-safety/plastic-pipe-data-collection-initiative/">https://www.aga.org/natural-gas/safety/promoting-safety/plastic-pipe-data-collection-initiative/</a> (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.
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\62\ DIMP Guidance at 19, 59.
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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\
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\63\ NTSB/PAR-19/02 at 25.
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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\
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\64\ PHMSA, ``Fact Sheet: Natural Force Damage'' (July 23,
2014), <a href="https://primis.phmsa.dot.gov/comm/FactSheets/FSNaturalForce.htm">https://primis.phmsa.dot.gov/comm/FactSheets/FSNaturalForce.htm</a>.
\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.
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\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\
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\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.
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\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), <a href="https://www.ipcc.ch/site/assets/uploads/2018/03/SREX-Chap3_FINAL-1.pdf">https://www.ipcc.ch/site/assets/uploads/2018/03/SREX-Chap3_FINAL-1.pdf</a>.
\72\ U.S. Envtl. Prot. Agency, ``What Climate Change Means for
Missouri'', EPA 430-F-16-027, at 1 (Aug. 2016), <a href="https://19january2017snapshot.epa.gov/sites/production/files/2016-09/documents/climate-change-mo.pdf">https://19january2017snapshot.epa.gov/sites/production/files/2016-09/documents/climate-change-mo.pdf</a> (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, <a href="https://climatechange.chicago.gov/climate-impacts/climate-impacts-midwest">https://climatechange.chicago.gov/climate-impacts/climate-impacts-midwest</a>
(last visited Feb. 25, 2023).
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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'' <a href="https://www.cpchem.com/sites/default/files/2020-05/DriscopipeDegradation.pdf">https://www.cpchem.com/sites/default/files/2020-05/DriscopipeDegradation.pdf</a>
(last visited Mar. 1, 2023).
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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\
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\78\ M.J. Rosenfeld, ``Cold Weather Can Play Havoc On Natural
Gas Systems'' 242 Pipeline & Gas J. 1 (Jan. 2015), <a href="https://pgjonline.com/magazine/2015/january-2015-vol-242-no-1/features/cold-weather-can-play-havoc-on-natural-gas-systems">https://pgjonline.com/magazine/2015/january-2015-vol-242-no-1/features/cold-weather-can-play-havoc-on-natural-gas-systems</a>.
\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),
<a href="https://www.phmsa.dot.gov/data-and-statistics/pipeline-replacement/pipeline-replacement-background">https://www.phmsa.dot.gov/data-and-statistics/pipeline-replacement/pipeline-replacement-background</a>.
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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.
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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.
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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.
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\87\ DIMP Guidance at 28.
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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\
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\89\ NTSB clarified this in an official correspondence to PHMSA
on July 31, 2020. NTSB, ``Safety Recommendation P-19-014'' (July 31,
2020), <a href="https://data.ntsb.gov/carol-main-public/sr-details/P-19-014">https://data.ntsb.gov/carol-main-public/sr-details/P-19-014</a>.
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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), <a href="https://nap.edu/25245">https://nap.edu/25245</a> (``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.
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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\
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\95\ NPGA Petition at 3-5. PHMSA notes that LPG releases are not
themselves generally considered to be releases of GHGs.
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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.
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\96\ NAS Study at 83.
\97\ NAS Study at 41, Table 3-4.
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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.
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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.
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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.
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\100\ PHMSA, ``Guidelines for States Participating in the
Pipeline Safety Program'' (Jan. 2022), <a href="https://www.phmsa.dot.gov/sites/phmsa.dot.gov/files/2020-07/2020-State-Guidelines-Revision-with-Appendices-2020-5-27.pdf">https://www.phmsa.dot.gov/sites/phmsa.dot.gov/files/2020-07/2020-State-Guidelines-Revision-with-Appendices-2020-5-27.pdf</a>.
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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.
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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 SI
[…truncated; see source link]Indexed from Federal Register on September 7, 2023.
This is legal information, not legal advice. Laws vary by jurisdiction and change frequently. Always verify current law with official sources and consult a licensed attorney in your jurisdiction for advice on your specific situation.