[Federal Register Volume 88, Number 172 (Thursday, September 7, 2023)]
[Proposed Rules]
[Pages 61746-61804]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2023-18585]
[[Page 61745]]
Vol. 88
Thursday,
No. 172
September 7, 2023
Part III
Department of Transportation
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Pipeline and Hazardous Materials Safety Administration
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49 CFR Parts 191, 192, and 198
Pipeline Safety: Safety of Gas Distribution Pipelines and Other
Pipeline Safety Initiative; Proposed Rule
Federal Register / Vol. 88 , No. 172 / Thursday, September 7, 2023 /
Proposed Rules
[[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: https://www.regulations.gov. This site allows the public
to enter comments on any Federal Register notice issued by any agency.
Follow the online instructions for submitting comments.
Mail: Docket Management System: U.S. Department of Transportation,
1200 New Jersey Avenue SE, West Building Ground Floor, Room W12-140,
Washington, DC 20590-0001.
Hand Delivery: DOT Docket Management System: West Building Ground
Floor, Room W12-140, 1200 New Jersey Avenue SE, between 9:00 a.m. and
5:00 p.m. ET, Monday-Friday, except Federal holidays.
Fax: 202-493-2251
Instructions: Include the agency name and identify Docket No.
PHMSA-2021-0046 at the beginning of your comments. Note that all
comments received will be posted without change to https://www.regulations.gov including any personal information provided. If you
submit your comments by mail, submit two copies. If you wish to receive
confirmation that PHMSA received your comments, include a self-
addressed stamped postcard.
Confidential Business Information: Confidential Business
Information (CBI) is commercial or financial information that is both
customarily and actually treated as private by its owner. Under the
Freedom of Information Act (5 U.S.C. 552), CBI is exempt from public
disclosure. If your comments in response to this NPRM contain
commercial or financial information that is customarily treated as
private, that you actually treat as private, and that is relevant or
responsive to this NPRM, it is important that you clearly designate the
submitted comments as CBI. Pursuant to 49 Code of Federal Regulations
(CFR) 190.343, you may ask PHMSA to provide confidential treatment to
the information you give to the agency by taking the following steps:
(1) mark each page of the original document submission containing CBI
as ``Confidential;'' (2) send PHMSA a copy of the original document
with the CBI deleted along with the original, unaltered document; and
(3) explain why the information you are submitting is CBI. Submissions
containing CBI should be sent to Ashlin Bollacker, 1200 New Jersey
Avenue SE, DOT: PHMSA-PHP-30, Washington, DC 20590-0001. Any comment
PHMSA receives that is not explicitly designated as CBI will be placed
in the public docket.
Docket: To access the docket, which contains background documents
and any comments that PHMSA has received, go to https://www.regulations.gov. Follow the online instructions for accessing the
docket. Alternatively, you may review the documents in person at DOT's
Docket Management Office at the address listed above.
FOR FURTHER INFORMATION CONTACT: Ashlin Bollacker by phone at 202-680-
8303 or by email at [email protected].
SUPPLEMENTARY INFORMATION:
I. Executive Summary
A. Purpose of the Regulatory Action
B. Summary of the Proposed Regulatory Action
C. Costs and Benefits
II. Background
A. Gas Distribution Systems Overview
B. Gas Distribution Configurations
C. Merrimack Valley
D. Low-pressure Gas Distribution System in South Lawrence
E. Gas Main Replacement Project
F. Emergency Response to the Merrimack Valley Incident
III Recommendations, Advisory Bulletins, and Mandates
A. National Transportation Safety Board
B. Advisory Bulletins
C. Statutory Authority
IV. Proposed Amendments
A. Distribution Integrity Management Programs (Subpart P)
B. State Pipeline Safety Programs (Sections 198.3 and 198.13)
C. Emergency Response Plans (Section 192.615)
D. Operations and Maintenance Manuals (Section 192.605)--
Overpressurization
E. Operations and Maintenance Manuals (Section 192.605)--
Management of Change
F. Gas Distribution Recordkeeping Practices (Section 192.638)
G. Distribution Pipelines: Presence of Qualified Personnel
(Sections 192.640 and 192.605)
H. District Regulator Stations--Protections Against Accidental
Overpressurization (Sections 192.195 and 192.741)
I. Inspection: General (Section 192.305)
J. Records: Tests (Sections 192.517 and 192.725)
K. Miscellaneous Amendments Pertaining to Part 192--Regulated
Gas Gathering Pipelines (Sections 192.3 and 192.9)
V. Regulatory Analyses and Notices
I. Executive Summary
A. Purpose of the Regulatory Action
PHMSA proposes a series of revisions to the pipeline safety
regulations (49 CFR parts 190-199) in response to congressional
mandates and an NTSB recommendation, and to implement lessons learned
from a September 13, 2018, incident resulting from the
overpressurization of a low-pressure gas distribution pipeline operated
by Columbia Gas of Massachusetts (CMA) in the Merrimack Valley. That
incident resulted in one fatality, more than 20 people (including three
first responders) being hospitalized, damage to approximately 130
structures, and an evacuation request for more than 50,000
[[Page 61747]]
residents. PHMSA expects the proposals of this NPRM will address the
root causes and aggravating factors contributing to the severity of
that incident and help reduce the frequency and consequence of other
failure mechanisms on gas distribution pipeline systems. The proposals
include improved design standards for low-pressure gas distribution
systems; enhanced distribution integrity management program
requirements; strengthened recordkeeping, planning, and monitoring
practices for maintenance and construction activities on gas
distribution systems; and improved emergency response communication and
coordination protocols during emergency events for all 49 CFR part 192-
regulated gas pipelines.\1\ PHMSA also proposes codifying within the
pipeline safety regulations its State Inspection Calculation Tool
(SICT). The SICT is one of many factors used to help States determine
the base-level amount of time needed for administering adequate
pipeline safety programs, which PHMSA considers when awarding grants to
States supporting those programs. PHMSA anticipates these proposed
regulatory amendments will improve public safety, while also reducing
threats to the environment (including, but not limited to, reduction of
greenhouse gas emissions during incidents on gas pipelines), and
promoting environmental justice for minority populations, low-income
populations, or other underserved and disadvantaged communities, or
others who are particularly likely to live and work near higher-risk
gas distribution pipeline systems.
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\1\ Part 192--regulated pipelines refers to gas distribution,
transmission, and gathering pipelines, as applicable.
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A catalyst for this rulemaking is the 2018 Merrimack Valley
incident. The NTSB investigated the cause of this incident and issued a
full report on its findings and safety recommendations.\2\ The NTSB
found the cause to be CMA's weak engineering management that failed to
adequately plan and oversee a cast iron main replacement project.
Contributing to the incident was CMA's low-pressure gas distribution
system that was designed and operated without adequate overpressure
protection. The NTSB reviewed other incidents from the past 50 years
and found several previous incidents that involved high-pressure gas
entering low-pressure gas systems. The NTSB found that a common cause
of failure was an overpressure protection design scheme, common on
older low-pressure distribution systems, that can be defeated by a
single failure mode (e.g., operator error or equipment failure).
Currently, low-pressure gas systems are not required to have a device
at the service location that would prevent the overpressurization of a
customer's piping, fittings, and appliances, a required design feature
on high-pressure distribution systems. Instead, overpressure protection
on low-pressure distribution systems often is provided by a redundant
design scheme (i.e., worker and monitor regulators at the regulator
stations). While overpressurizations on distribution pipelines are
infrequent, they have the potential to be catastrophic given their
location within population centers. As a result of its investigation,
the NTSB recommended that PHMSA revise the pipeline safety regulations
to address overpressure protection failures like that which occurred on
CMA's low-pressure system.
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\2\ NTSB, Accident Report PAR-19/02, ``Overpressurization of
Natural Gas Distribution System, Explosions, and Fires in Merrimack
Valley, Massachusetts, September 13, 2018'' (Sept. 24, 2019),
https://www.ntsb.gov/investigations/AccidentReports/Reports/PAR1902.pdf.
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In 2020, the Leonel Rondon Pipeline Safety Act was enacted as
sections 202-206 of the Protecting our Infrastructure of Pipelines and
Enhancing Safety Act of 2020 (PIPES Act of 2020, Pub. L. N 116-260).
The law requires PHMSA to amend its regulations to ensure operators
evaluate the risks associated with the presence of cast iron piping and
the possibility of overpressurization on gas distribution systems
through updates to their distribution integrity management program
(DIMP). (49 U.S.C. 60109(e)(7)). The law further requires PHMSA to
amend its regulations to ensure operators' emergency response plans
include timely communications with first responders, public officials,
customers, and the general public. (49 U.S.C. 60102(r)). PHMSA was also
directed to amend its regulations to ensure operators' operations and
maintenance (O&M) manuals include procedures for responding to
overpressurization and a management of change (MOC) process with review
and certification by relevant qualified personnel. (49 U.S.C.
60102(s)). PHMSA must also amend its regulations to ensure operators
(1) keep ``traceable, reliable, and complete records;'' (2) monitor the
gas pressure at district regulator stations during construction; and
(3) assess and upgrade their district regulator stations to minimize
the risk of overpressurization. (49 U.S.C. 60102(t)).
Pursuant to its statutory authority and in furtherance of its
mission to protect people and the environment by advancing the safe
transportation of energy and other hazardous materials essential to our
daily lives, PHMSA proposes in this NPRM a number of regulatory
amendments to implement those statutory mandates and NTSB
recommendations arising from the 2018 CMA overpressure incident. PHMSA
expects the proposed regulatory amendments to reduce the likelihood of
another overpressure incident on low-pressure gas distribution systems
similar to that which occurred in Merrimack Valley. PHMSA also expects
the proposed amendments to reduce the frequency of, as well as public
and environmental consequences from, failure mechanisms on gas
distribution pipeline systems and other pipeline facilities.
Additionally, this rulemaking aligns with the Administration's efforts
to improve environmental justice and combat the climate crisis.\3\
Older cast-iron or bare-steel gas distribution pipelines--a type of gas
distribution pipeline particularly vulnerable to failure and
overpressurization--are disproportionately concentrated in older,
residential (often urban) areas with large minority, low- income, and
other historically underserved and disadvantaged populations.\4\ In
addition, the reduced frequency and severity of incidents on gas
pipelines anticipated from this rulemaking would have the benefit of
minimizing the release of greenhouse gases from pipeline incidents--in
particular methane--to the atmosphere.
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\3\ The White House Office of Domestic Climate Policy, ``U.S.
Methane Emissions Reduction Action Plan,'' (Nov. 2021), https://www.whitehouse.gov/wp-content/uploads/2021/11/US-Methane-Emissions-Reduction-Action-Plan-1.pdf. This and other PHMSA rulemakings are
identified in the U.S. Methane Emissions Reduction Action Plan as
critical elements in the Federal government's efforts to address the
climate crisis. Id. at 7-8 (listing PHMSA's Leak Detection and
Repair rulemaking (proposed in 88 FR 31890 (May 18, 2023) (Leak
Detection NPRM)), its Gas Gathering Final Rule (86 FR 63266 (Nov.
15, 2021)), its Valve Installation and Minimum Rupture Detection
Standards Final Rule (87 FR 20940 (Apr. 8, 2022) (Valve Rule)), and
its Gas Transmission Pipeline Safety Final Rule (87 FR 52224 (Aug.
24, 2022)).
\4\ See, e.g., Luna & Nicholas, ``An Environmental Justice
Analysis of Distribution-Level Natural Gas Leaks in Massachusetts,
USA,'' 162 Energy Policy 112778 (Mar. 2022); Weller et al.,
``Environmental Injustices of Leaks from Urban Natural Gas
Distribution Systems: Patterns Among and Within 13 U.S. Metro
Areas,'' Environ. Sci & Tech. (May 11, 2022).
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The proposed rule is consistent with the goals of a new grant
program established by the Bipartisan Infrastructure Law (BIL, enacted
as the Infrastructure Investment and Jobs Act, Pub. L. 117-58). The new
grant program, PHMSA's first ever Natural Gas Distribution
Infrastructure Safety
[[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.
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\10\ PHMSA, ``Annual Report Mileage for Gas Distribution
Systems'' (June 1, 2022), https://www.phmsa.dot.gov/data-and-statistics/pipeline/annual-report-mileage-gas-distribution-systems.
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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), https://primis.phmsa.dot.gov/meetings/FilGet.mtg?fil=1227. PHMSA consequently understands the proposed
revisions to 49 CFR parts 191 and 192 within this NPRM would apply
not only to natural gas pipelines but also to other gas pipeline
governed by 49 CFR parts 191 and 192.
\12\ U.S. Envtl. Prot. Agency, Global Methane Initiative:
Importance of Methane (last updated June 9, 2022), https://
www.epa.gov/gmi/importance-
methane#:~:text=Methane%20is%20more%20than%2025,due%20to%20human%2Dre
lated%20activities.
\13\ Serious incidents are those including a fatality or injury
requiring in-patient hospitalization, excluding incidents when
secondary ignition is involved, sometimes called ``fire first''
incidents. Between 2001 and 2020, gas distribution incidents
comprised 81 percent of all the serious incidents reported to PHMSA.
The three-year average incident count between 2018 and 2020 is 25,
down from an average of 28 serious incidents between 2001 and 2020.
``Pipeline Incident 20 Year Trends'' (Nov. 15, 2022), https://www.phmsa.dot.gov/data-and-statistics/pipeline/pipeline-incident-20-year-trends.
\14\ ``Pipeline Incident 20 Year Trends'' (Nov. 15, 2022),
https://www.phmsa.dot.gov/data-and-statistics/pipeline/pipeline-incident-20-year-trends.
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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),
https://www.phmsa.dot.gov/data-and-statistics/pipeline-replacement/decade-inventory.
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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), https://www.phmsa.dot.gov/sites/phmsa.dot.gov/files/docs/dot4111.pdf.
\17\ Cast iron or bare steel pipelines account for 95 percent of
corrosion leaks on mains, 92 percent of natural-force leaks on
mains, 91 percent of pipe/weld/joint failure leaks; 97 percent
``other cause'' leaks on mains; and 76 percent of all known leaks.
PHMSA, ``Cast and Wrought Iron Inventory'' (Apr. 26, 2021), https://www.phmsa.dot.gov/data-and-statistics/pipeline-replacement/cast-and-wrought-iron-inventory (``Cast and Wrought Iron Inventory'').
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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.
---------------------------------------------------------------------------
\18\ See Cast and Wrought Iron Inventory.
\19\ U.S. Dep't of Energy, ``Transforming U.S. Energy
Infrastructures in a Time of Rapid Change: The First Installment of
the Quadrennial Energy Review'' at S-5 (Apr. 2015) https://www.energy.gov/sites/prod/files/2015/08/f25/QER%20Summary%20for%20Policymakers%20April%202015.pdf.
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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.
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\20\ ``At the city gate the pressure of the gas is reduced, and
[this] is normally the location where odorant (typically mercaptan)
is added to the gas, giving it the characteristic smell of rotten
eggs so leaks can be detected.'' Pipeline Safety Trust, ``Pipeline
Basics & Specifics About Natural Gas Pipelines'' at 4 (Feb. 2019),
https://pstrust.org/wp-content/uploads/2019/03/2019-PST-Briefing-Paper-02-NatGasBasics.pdf.
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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.
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\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.
---------------------------------------------------------------------------
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), https://www.mass.gov/doc/independent-assessment-of-columbia-gas-of-massachusetts-merrimack-valley-restoration-program/download.
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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
https://www.ntsb.gov/investigations/AccidentReports/Reports/PAR1902.pdf.
\28\ These states were Alabama, Alaska, Arizona, Arkansas,
California, Colorado, Connecticut, Florida, Georgia, Idaho,
Illinois, Kentucky, Louisiana, Maine, Maryland, Mississippi,
Missouri, Montana, Nebraska, Nevada, New York, North Carolina,
Pennsylvania, South Carolina, South Dakota, Texas, Utah, Virginia,
and Wyoming. NTSB/PAR-19/02 at 50.
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[[Page 61755]]
In its accident report, the NTSB issued two safety recommendations
to PHMSA. The first, P-19-14, recommended that PHMSA require
overpressure protection for low-pressure natural gas distribution
systems that cannot be defeated by a single operator error or equipment
failure. The NTSB further clarified that to satisfy this
recommendation, PHMSA would not have to require that existing low-
pressure gas distribution systems be completely redesigned; rather,
PHMSA may satisfy this recommendation by requiring operators to add
additional protections, such as slam-shut or relief valves, to existing
district regulator stations or other appropriate locations in the
system.\29\ The second, P-19-15, recommended that PHMSA issue an
advisory bulletin to all low-pressure natural gas distribution system
operators of the possibility of a failure of overpressure protection.
Further, P-19-15 stated that the advisory bulletin should recommend
that operators use a failure modes and effects analysis or an
equivalent structured and systematic method to identify potential
failures and take action to mitigate those identified failures. In
developing this NPRM, PHMSA also reviewed additional recommendations
relating to the Merrimack Valley incident that NTSB made to states and
operators.
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\29\ NTSB clarified this in an official correspondence to PHMSA
on July 31, 2020. NTSB, ``Safety Recommendation P-19-014'' (July 31,
2020), https://data.ntsb.gov/carol-main-public/sr-details/P-19-014.
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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), https://www.phmsa.dot.gov/sites/phmsa.dot.gov/files/docs/RSPA%20Alert%20Notice%2091-02.pdf; RSPA,
ALN-92-02 (June 26, 1992), https://www.phmsa.dot.gov/sites/phmsa.dot.gov/files/docs/RSPA%20Alert%20Notice%2092-02.pdf
(supplementing ALN-91-02).
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1. Review current cast-iron replacement programs and consider
establishing mandated replacement programs;
2. Establish accelerated leakage survey frequencies or leak
testing;
3. Focus pipeline safety efforts on identifying the highest-risk
pipe;
4. Use rate adjustments to incentivize pipeline rehabilitation,
repair, and replacement programs;
5. Strengthen pipeline safety inspections, accident investigations,
and enforcement actions; and
6. Install interior/home methane gas alarms.
PHMSA reminded owners and operators of their responsibilities under
Sec. 192.617 to establish procedures for analyzing incidents and
failures to determine the causes of the failures and to minimize the
possibility of a reoccurrence.
Finally, the advisory bulletin notes that the DOT, in accordance
with the Pipeline Safety, Regulatory Certainty, and Job Creation Act of
2011 (Pub. L. 112-90), will continue to monitor the progress made by
operators to implement plans of safe management and replacement of
cast-iron gas pipelines and identify the total miles of cast iron
pipelines in the United States.
C. Statutory Authority
Title II of the PIPES Act of 2020, the ``Leonel Rondon Pipeline
Safety Act,'' included several mandates for PHMSA to update the
regulations governing operators of gas distribution systems. This NPRM
addresses mandates codified at 49 U.S.C. 60102(r)-(t), 60105(b), and
60109(e)(7). (See sections 202, 203, 204, and 206 of the PIPES Act of
2020). Additionally, PHMSA has general statutory authority to regulate
the safety of gas pipeline facilities subject to this rulemaking as
discussed in section V.A of this NPRM.
[[Page 61756]]
1. Distribution Integrity Management Program Plans and State Inspection
Calculation Tool (49 U.S.C. 60109(e)(7) and 49 U.S.C. 60105(b) and
60105 Note; PIPES Act of 2020 Section 202)
PHMSA is required to issue regulations ensuring that DIMP plans for
gas distribution operators include an evaluation of certain risks, such
as those posed by cast iron pipes and mains and low-pressure
distribution systems, as well as the possibility of future accidents to
better account for high-consequence but low-probability events. (49
U.S.C. 60109(e)(7)). Gas distribution operators were required make
their DIMP plans, emergency response plans, and O&M manuals available
to PHMSA or the relevant State regulatory agency no later than December
27, 2022. Gas distribution operators must also make these documents, in
updated form, available to PHMSA or the relevant State regulatory
agency: (1) two years after the promulgation of regulations as
required; and (2) every 5 years thereafter, as well as following any
significant change to the document. PHMSA must also update and codify
the use of the SICT, a tool used to help states determine the minimum
amount of time it must dedicate to inspections. (See 49 U.S.C. 60105(b)
and 60105 note).
2. Emergency Response Plans (49 U.S.C. 60102(r); PIPES Act of 2020
Section 203)
PHMSA is required to update its emergency response plan regulations
to ensure that each emergency response plan developed by a gas
distribution system operator includes written procedures for how to
handle communications with first responders, other relevant public
officials, and the general public after certain significant pipeline
emergencies (49 U.S.C. 60102(r)). Specifically, the updated regulations
would ensure that pipeline operators contact first responders and
public officials as soon as practicable after they know a release of
gas has occurred that resulted in a fire related to an unintended
release of gas, an explosion, one or more fatalities, or the
unscheduled release of gas and shutdown of gas service to a significant
number of customers. Similarly, the updated regulations would provide
for general public communication of pertinent emergencies as soon as
practicable and leverage communications methods facilitating rapid
notice to the general public.
3. Operation and Maintenance Manuals (49 U.S.C. 60102(s); PIPES Act of
2020 Section 204)
PHMSA is required to update the regulations for O&M manuals to
require distribution system operators to have a specific action plan to
respond to overpressurization events (49 U.S.C. 60102(s)).
Additionally, operators must develop written procedures for management
of change processes for significant technology, equipment, procedural,
and organizational changes to their distribution system and ensure that
relevant qualified personnel, such as an engineer with a professional
engineer (PE) license, reviews and certifies such changes (49 U.S.C.
60102(s)).
4. Pipeline Safety Practices (49 U.S.C. 60102(t); PIPES Act of 2020
Section 206)
PHMSA is required to issue regulations that require distribution
pipeline operators to identify and manage ``traceable, reliable, and
complete'' maps and records of critical pressure-control infrastructure
and update these records as appropriate. The records must be submitted
or made available to the relevant regulatory agency (i.e., PHMSA or the
State). These regulations must require records to be gathered on an
opportunistic basis. (49 U.S.C. 60102(t)(1)).
PHMSA must also issue regulations requiring a qualified employee of
a distribution system operator to monitor gas pressure at district
regulator stations and be able to shut off flow or limit gas pressure
during construction projects that have the potential to cause a
hazardous overpressurization. An exception to this requirement would be
made for a district regulator station that has a monitoring system and
capability for a remote or automatic shutoff (49 U.S.C. 60102(t)(2)).
PHMSA is further required to issue regulations on district regulator
stations to ensure that gas distribution system operators minimize the
risk of a common mode of failure at low-pressure district regulator
stations, monitor the gas pressure of low-pressure distribution
systems, and install overpressure protection safety technology at low-
pressure district regulator stations. If it is not operationally
possible to install such technology, this section would require the
operator to identify plans that would minimize the risk of
overpressurization (49 U.S.C. 60102(t)(3)).
IV. Proposed Amendments
A. Distribution Integrity Management Programs (Subpart P)
In 2009, PHMSA issued a final rule titled ``Pipeline Safety:
Integrity Management Program for Gas Distribution Pipelines,'' creating
49 CFR part 192, subpart P.\34\ As specified in Sec. 192.1003, subpart
P applies to operators of all gas distribution pipelines covered under
part 192, subject to certain exceptions, and prescribes minimum
requirements for integrity management programs for any such pipelines
(referred to in this rulemaking as DIMPs). Adherence to a DIMP is an
overall approach by operators to ensure the integrity of their
distribution systems. The purpose of DIMP is to enhance safety by
identifying and reducing pipeline integrity risks. DIMP regulations
require that operators develop an integrity management plan that they
must re-evaluate periodically; that integrity management plan
complements operator efforts in complying with prescriptive operating
and maintenance requirements elsewhere in part 192.
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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), https://www.phmsa.dot.gov/sites/phmsa.dot.gov/files/docs/DIMP_Enforcement_Guidance_12_7_2015.pdf (``DIMP Guidance'').
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The second step in developing and implementing a DIMP plan, as
required in Sec. 192.1007(b), is for operators to use the information
they have gathered in compliance with Sec. 192.1007(a) to identify
threats to the integrity of their gas distribution systems. Section
192.1007(b) currently requires that operators consider eight broad
categories of threats. These threats are corrosion (including
atmospheric corrosion), natural forces, excavation damage, other
outside force damage, material or welds, equipment failure, incorrect
operations, and other issues that could threaten the integrity of the
pipeline.\36\ Operators must consider reasonably available information
to identify existing and potential threats. Sources of data may include
incident and leak history, corrosion control records (including
atmospheric corrosion records), continuing surveillance records,
patrolling records, maintenance history, and excavation damage
experience (see Sec. 192.1007(b)).
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\36\ PHMSA, ``F 7100.1-1, Annual Report: Gas Distribution
System'' (May 2021), https://www.phmsa.dot.gov/sites/phmsa.dot.gov/files/2021-05/Current_GD_Annual_Report_Form_PHMSA%20F%207100.1-1_CY%202021%20and%20Beyond.pdf.
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Section 192.1007(b) requires operators to consider certain
categories of threats and consider reasonably available information to
identify other existing and potential threats not specifically listed.
PHMSA has clarified through guidance that operators should use sources
of information such as past O&M procedures, abnormal operating events,
purchase orders, material lists from old field orders or standards, and
information from industry sources (e.g., plastic pipe database
committee (PPDC),\37\ NTSB accident reports, or PHMSA advisory
bulletins) to help identify threats.\38\ PHMSA identified potential
threats that include, but are not limited to, non-leak events such as
near misses, overpressurizations, and material and appurtenance
failures. Even though certain potential threats may not have caused
system integrity issues on an operator's particular system in the past,
the fact that known industry or systemic risks exist requires operators
to account for the threat in their DIMP. Further, operators should not
eliminate any existing or potential threat to a system without an
adequate basis for doing so.\39\ PHMSA reiterated through guidance
material that operators should consider environmental conditions that
may be conducive to threats developing over time (e.g., atmospheric
corrosion, hurricanes, flooding, excavation damage, or materials with
known integrity issues), so that operators do not eliminate potential
threats without proper consideration.\40\ Prior to excluding a
potential threat, operators should perform an analysis of their records
to ensure that the pipeline has not experienced the threat to date.\41\
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\37\ The Plastic Pipe Database Committee, composed of
representatives of the American Gas Association (AGA), American
Public Gas Association (APGA), Plastics Pipe Institute (PPI),
National Association of Regulatory Utility Commissioners (NARUC),
NAPSR, NTSB, and PHMSA, coordinates the creation and maintenance of
a database to proactively monitor the performance of in-service
plastic piping system failures and leaks with the objective of
identifying possible performance issues.
\38\ PHMSA, ``Gas Distribution Pipeline Integrity Management
Enforcement Guidance'' at 19-23 (Dec. 7, 2015), https://www.phmsa.dot.gov/sites/phmsa.dot.gov/files/docs/DIMP_Enforcement_Guidance_12_7_2015.pdf (``DIMP Guidance'').
\39\ DIMP Guidance at 18-19.
\40\ DIMP Guidance at 19.
\41\ DIMP Guidance at 19.
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PHMSA clarified through enforcement guidance that to exclude a
threat from consideration, an operator should document the basis for
that conclusion and should not exclude a threat based on the
unavailability of information to support the existence of such a
threat.\42\ Where data is missing or insufficient, an operator should
use a conservative assumption in the risk assessment. Operators must
maintain records that identify how they use unsubstantiated data so
that operators and regulators can consider the impact on the
variability and accuracy of risk analysis results.\43\
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\42\ DIMP Guidance at 18-19.
\43\ DIMP Guidance at 19, 58. Section 192.1011 requires that
operators must maintain records demonstrating compliance with the
requirements of this subpart for at least 10 years. The records must
include copies of superseded integrity management plans developed
under this subpart.
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The third step in developing and implementing a DIMP plan, as
required in Sec. 192.1007(c), is to evaluate and rank risk. Risk is
the likelihood of an event occurring multiplied by the consequence of
that event. An event that is highly likely and has significant public
safety or environmental consequences constitutes an event of greatest
concern, while an unlikely event that has minimal consequences may not
justify any particular precautions. On the other hand, an unlikely
event that could have very high consequences may justify special
precautions. Incidents on gas distribution systems are generally low-
likelihood, but high-consequence, events.
Risk analysis is an ongoing process of understanding the risk each
identified threat presents to a pipeline. Operators use the threats
identified in Sec. 192.1007(b) and any knowledge gained when complying
with Sec. 192.1007(a) to evaluate the risks associated with their
pipelines. Operators then must rank the risks to determine their
relative importance. PHMSA has recommended that operators prioritize
and address the risks of greatest concern first.\44\
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\44\ DIMP Guidance at 22, 61.
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The fourth step in developing and implementing a DIMP plan, as
required in Sec. 192.1007(d), is for operators to determine and
implement measures designed to reduce the risks from failure of their
gas distribution pipelines. These measures include having an effective
leak management program (unless all leaks are repaired when found).\45\
PHMSA's enforcement guidance specifies that the process for identifying
risk reduction measures should be based on identified threats.\46\
Operators
[[Page 61758]]
should promptly identify the need for risk reduction measures if a new
risk is identified.
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\45\ PHMSA notes that it recently proposed in a separate
rulemaking a number of revisions to its prescriptive part 192 leak
detection requirements that would (inter alia) require gas
distribution to adopt advanced leak detection programs based on
commercially available, advanced leak detection equipment. See ``Gas
Pipeline Leak Detection and Repair,'' 88 FR 31890 (May 18, 2023).
\46\ DIMP Guidance at 28.
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Overall, DIMP requirements direct operators to identify conditions
that can result in hazardous leaks or other unintended consequences and
take actions to reduce the likelihood of the occurrence of a hazardous
condition and the consequences of a resulting failure. It is critical
for operators to identify threats that affect, or could potentially
affect, a distribution pipeline to ensure that pipeline's integrity.
Knowledge of applicable threats, whether actual or potential, allows
operators to evaluate the safety risks they pose and to rank those
risks, allowing the operator to apply safety resources where they will
be most effective. For the most effective results, operators should
break down these broad threat categories into more specific threats. An
operator must use the knowledge of their system gained as a result of
complying with Sec. 192.1007(a), combined with the threats identified
pursuant to Sec. 192.1007(b), to perform a risk analysis to evaluate
the likelihood and consequences of failures for those threats described
in Sec. 192.1007(c) for which risk-reduction measures are then
identified and implemented under Sec. 192.1007(d). The more accurately
and completely an operator characterizes their system, the more
accurate the risk analysis results will be. This in turn should inform
how an operator allocates resources to mitigate the risks associated
with its system.
Pipeline incidents since the promulgation of the DIMP rules in 2011
have demonstrated that some distribution operators whose systems are
subject to DIMP requirements are not adequately identifying (step 2),
evaluating (step 3), or mitigating (step 4) the threats that are
degrading and reducing the integrity of their pipeline systems. For
example, NTSB's report on the Merrimack Valley incident found that, by
at least September 2015, CMA employees knew of overpressure dangers
associated with maintenance on belowground control lines for low-
pressure system regulator stations: a faulty, damaged, or unaccounted
for control line could lead to overpressurization, resulting in fires
and explosions in a populated area.\47\ In September 2015, NiSource and
CMA internally disseminated Operational Notice (ON) 15-05, titled
``Below Grade Regulator Control Lines: Caution When Excavating Near
Regulator Stations or Regulator Buildings.'' \48\ The impetus for ON
15-05 was a ``near-miss'' experience involving another NiSource company
outside of Massachusetts where a construction crew that was excavating
to repair a gas leak near a regulator station came close to hitting a
control line and was unaware of its purpose and importance. The NTSB's
report concludes that even though NiSource had historically identified
overpressurization as a threat in at least some of its internal
procedures, NiSource had nevertheless failed to undertake a systemic
evaluation (e.g., a failure modes and effects analysis) of the risks
associated with that threat and the mitigating actions needed to manage
those risks.\49\
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\47\ NTSB/PAR-19/02 at 18.
\48\ NTSB/PAR-19/02 at 59-61.
\49\ NTSB/PAR-19/02 at 40.
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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.
---------------------------------------------------------------------------
\52\ NTSB, Accident Report PAR-21/01, ``Atmos Energy Corporation
Natural Gas-Fueled Explosion: Dallas, Texas: February 23, 2018''
(Jan. 12, 2021), https://www.ntsb.gov/investigations/AccidentReports/Reports/PAR2101.pdf.
\53\ NTSB/PAR-21/01 at 66.
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Following the Atmos incident, NTSB issued recommendation P-21-2 to
PHMSA.\54\ This recommendation requires PHMSA to evaluate industry's
implementation of DIMP requirements and to develop updated guidance for
improving the effectiveness of operator DIMP plans. The recommendation
goes on to say that the evaluation should ``specifically consider
factors that increase the likelihood of failure such as age, increase
the overall risk (including factors that simultaneously increase the
likelihood and consequence of failure), and limit the effectiveness of
leak management programs.''
---------------------------------------------------------------------------
\54\ NTSB/PAR-21/01 at 72.
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[[Page 61759]]
In this NPRM, PHMSA proposes to revise DIMP requirements so that
operators of gas distribution systems will improve their identification
of existing and potential threats to their pipelines' integrity,
improve the accuracy of their risk analyses, and take meaningful,
timely actions to remediate or mitigate the highest risks to their
infrastructure. When developing the proposals in this NPRM, PHMSA
considered applicable statutory mandates and the NTSB recommendations
that followed the CMA and Atmos incidents. The proposals described in
the paragraph's below apply to all gas distribution operators,
including individual service lines (also known as farm taps),\55\ but
excluding small LPG operators. PHMSA discusses the proposal to remove
small LPG operators from DIMP in IV.A.7.
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\55\ An individual gas service line directly connected to a gas
transmission, production, or gathering pipeline is commonly referred
to as a ``farm tap.'' Individual service lines have the option of
following either Sec. 192.740, for service lines that are not
operated as part of a distribution system, or DIMP (as detailed in
Sec. 192.1003(b)) for any portion of the individual service line
that is classified as a service line. This rule proposed no change
to this scope. The proposals apply to those individual service lines
(aka farm taps) that apply DIMP.
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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.
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\61\ AGA, ``Plastic Pipe Data Collection Initiative'', https://www.aga.org/natural-gas/safety/promoting-safety/plastic-pipe-data-collection-initiative/ (last visited March 10, 2023).
---------------------------------------------------------------------------
Once the threats are identified under Sec. 192.1007(b), operators
are also required to evaluate these risks under Sec. 192.1007(c) and
to ensure that risk reduction measures are identified and implemented
under Sec. 192.1007(d).
2. DIMP--Identify Threats (Sec. 192.1007(b))--Overpressurization
a. Current Requirements--DIMP--Identify Threats--Overpressurization
Section 192.1007(b) does not explicitly require operators to
consider the threat of overpressurization as a threat under their DIMP
plans. Instead, Sec. 192.1007(b) requires operators to consider the
general threat category of ``incorrect operations'' or ``other issues
that could threaten the integrity of [a] pipeline'' and requires
operators to consider whether those threats exist on their systems.
However, overpressurization is a potential threat to gas distribution
systems. PHMSA has stated through previous enforcement guidance and an
advisory bulletin (ADB-2020-02) that overpressurization is a threat,
especially for low-pressure gas distribution systems, and recommended
that operators identify overpressurization as a threat in their DIMP
plans. Further, Sec. 192.195 provides design requirements for the
protection against accidental overpressurization, including additional
requirements for distribution systems.
b. Need for Change--DIMP--Identify Threats--Overpressurization
The threat of overpressurization, particularly on low-pressure gas
distribution systems, is a threat that PHMSA expects operators to
consider in their DIMP plans. PHMSA considers the threat of
overpressurization to fall under the threat categories of both
``incorrect operations'' and ``other issues that could threaten the
integrity of [a] pipeline'' in Sec. 192.1007(b). In enforcement
guidance, PHMSA lists ``overpressurization events'' as an example of
potential threats operators could experience on their pipelines.\62\
PHMSA also requires operators to have sufficient knowledge of their
systems, per Sec. 192.1007(a), to determine if overpressurization is a
threat on their specific systems and to develop and implement measures
to mitigate the consequences of a potential overpressurization. As
discussed earlier, PHMSA also issued an advisory bulletin (ADB-2020-02)
alerting operators of low-pressure gas distribution systems of the
increased risk of overpressurization on those systems and recommended
that operators consider the threat of overpressurization in their DIMP
plans.
---------------------------------------------------------------------------
\62\ DIMP Guidance at 19, 59.
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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\
---------------------------------------------------------------------------
\63\ NTSB/PAR-19/02 at 25.
---------------------------------------------------------------------------
On March 1, 2004, a system overpressurized when debris lodged at
the seat of the bypass valve in Lynchburg, VA.
On February 28, 2012, an operator error during an inspection
resulted in accidental overpressurization in Wellston, OH. 300
customers were without service for 14 hours.
On March 21, 2013, a segment of a pipe with an MAOP of 1 psig was
pressurized at over 2 psig in Pittsburgh, PA. A work crew, under the
direction of
[[Page 61761]]
the local NiSource subsidiary, was making a tie-in and failed to
monitor the pressure and flow of the existing low-pressure natural gas
distribution system during the tie-in process.
On August 11, 2014, a local NiSource crew in Frankfort, KY, was
excavating to repair a leak located on the outside of a regulator
station building. The crew uncovered and narrowly missed hitting the 1-
inch control line and tap located on the 8-inch outlet pipeline. The
crew was unaware of the purpose of the 1-inch line and called local
measurement and regulation (M&R) personnel. The M&R personnel advised
the crew of the purpose of a control line and what would have happened
had the line been broken. As discussed earlier, in 2015 NiSource issued
ON 15-05 in response to this near miss. ON 15-05 required that M&R
personnel be consulted on all future excavation work done within 25
feet of a regulator station with sensing lines, other communications
and/or electric lines critical to the operation of the regulator
station, or buried odorant lines. On September 13, 2018 (the date of
the Merrimack Valley incident), however, CMA did not follow those
procedures or implement any preventive or mitigative measures as they
should have if they were correctly following DIMP requirements.
On January 13, 2018, during the investigation of a service
complaint, an overpressurization was discovered on a natural gas
distribution system in Longmeadow, MA. The cause was associated with
debris accumulation on both the worker and monitor regulator seats at a
regulator station. Once the debris was removed, the pressure returned
to normal. This event illustrates that, in some cases, an
overpressurization can occur that does not cause a catastrophic failure
of the entire system, but if the operator takes timely, mitigative
action, the system can safely return to normal. Operators know debris
accumulation at regulator stations can cause an overpressurization and
can plan routine maintenance of regulator stations to remove debris or
install a device to prevent the debris from reaching the regulator
station. However, an operator must first recognize overpressurization
as a threat to ensure that they allocate resources to address this
threat.
While overpressurization is a threat that PHMSA expects operators
to consider in their DIMP plans, the pipeline safety regulations do not
explicitly state that operators must identify and evaluate the threat
of overpressurization in their DIMP plans. Following the Merrimack
Valley incident on September 13, 2018, PHMSA was required by law to
ensure that operators evaluate the risk of overpressurization in their
DIMP plans. PHMSA therefore proposes to amend Sec. 192.1007(b) to
explicitly require operators to identify overpressurization as a threat
to low-pressure distribution systems. The proposal is intended to
ensure that operators consider this risk on their system as required by
the risk analysis in Sec. 192.1007(c) and identify risk reduction
measures in accordance with Sec. 192.1007(d).
c. Proposal To Amend Sec. 192.1007(b)--DIMP--Identify Threats--
Overpressurization on Low-Systems
PHMSA proposes to amend Sec. 192.1007(b) to create a new threat
category of ``overpressurization on low-pressure systems.'' This change
would ensure that consideration of risks under the DIMP regulations
explicitly includes overpressurization of a low-pressure system as a
threat. Once identified as a threat under Sec. 192.1007(b), operators
would also have to evaluate the likelihood and the potential
consequences of such a failure, as required in Sec. 192.1007(c), and
ensure risk-reduction measures are identified and implemented under
Sec. 192.1007(d). PHMSA discusses the actions operators must take to
implement Sec. 192.1007(c) and Sec. 192.1007(d) in subsection IV.A.5
and 6 of this preamble.
3. DIMP--Identify Threats (Sec. 192.1007(b))--Natural Forces
a. Current Requirements--DIMP--Identify Threats--Natural Forces
Including Extreme Weather and Geohazards
Section 192.1007(b) requires operators to consider the general
threat category of ``natural forces,'' but the requirement does not
explicitly state what natural forces could pose a threat to the
integrity of the system. Natural force damage occurs as a result of
naturally occurring events, including: (1) earthquakes and landslides;
(2) heavy rains and flooding; (3) high winds, tornadoes, or hurricanes;
(4) temperature extremes; and (5) lightning.\64\ Further, PHMSA has
issued advisory bulletins alerting operators to threats related to
natural forces such as land movement (i.e., geological hazards or
``geohazards'' \65\) (ADB-2022-01 and ADB-2019-02), severe flooding
(ADB-2019-01), snow and ice build-up (ADB-2016-03), and extreme
temperatures (ADB-2012-03).\66\
---------------------------------------------------------------------------
\64\ PHMSA, ``Fact Sheet: Natural Force Damage'' (July 23,
2014), https://primis.phmsa.dot.gov/comm/FactSheets/FSNaturalForce.htm.
\65\ PHMSA also interprets natural hazards to include
geohazards.
\66\ ``Pipeline Safety: Potential for Damage to Pipeline
Facilities Caused by Earth Movement and Other Geological Hazards,''
ADB-2022-01, 87 FR 33576 (June 2, 2022); ``Pipeline Safety:
Potential for Damage to Pipeline Facilities Caused by Earth Movement
and Other Geological Hazards,'' ADB-2019-02, 84 FR 18919 (May 2,
2019); ``Pipeline Safety: Potential for Damage to Pipeline
Facilities Caused by Flooding, River Scour, and River Channel
Migration,'' ADB-2019-01, 84 FR 14715 (Apr. 11, 2019); ``Pipeline
Safety: Dangers of Abnormal Snow and Ice Build-Up on Gas
Distribution Systems,'' ADB-2016-03, 81 FR 7412 (Feb. 11, 2016);
``Notice to Operators of Driscopipe 8000 High Density Polyethylene
Pipe of the Potential for Material Degradation,''ADB-2012-03, 77 FR
13387 (Mar. 6, 2012). PHMSA notes that many of those advisory
bulletins identify resources maintained by other Federal agencies
that can assist pipeline operators in identifying and evaluating
integrity threats to their pipelines.
---------------------------------------------------------------------------
b. Need for Change--DIMP--Identify Threats--Natural Forces Including
Extreme Weather and Geohazards
A distribution pipeline system operates in a discrete environment
due to the limited geographic scope of each individual system. The
environment in which a system operates significantly affects the
threats to pipeline integrity that it faces. Factors such as weather
(dry or wet, hot or subject to freezing) can significantly shape the
threats affecting individual distribution operators and the actions
necessary to address those threats. Major climate trends, such as
elevated average surface temperatures, more intense storm events, and
flooding, can, independently and in combination, affect the reliability
and integrity of the United States' gas distribution infrastructure. As
climate change has made extreme weather more common, it is harder to
categorize what types of environmental factors facing distribution
pipelines are ``normal'' based on geography and historical averages
alone.
While freezing weather once seemed like a problem reserved for
northern regions of the United States, southern regions are also
experiencing unseasonable and extremely cold weather. For example, in
February of 2021, Texas experienced a winter storm that brought some of
the coldest temperatures in its history.\67\ Extremely cold weather can
cause thermal contraction stress or fractures of pipelines due to the
expansion of moisture trapped inside components. In addition, safety
relief devices can malfunction due to icing or freezing.
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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), https://www.ipcc.ch/site/assets/uploads/2018/03/SREX-Chap3_FINAL-1.pdf.
\72\ U.S. Envtl. Prot. Agency, ``What Climate Change Means for
Missouri'', EPA 430-F-16-027, at 1 (Aug. 2016), https://19january2017snapshot.epa.gov/sites/production/files/2016-09/documents/climate-change-mo.pdf (noting that over the last half
century, average annual precipitation in most of the Midwest has
increased by 5 to 10 percent).
\73\ See A. Park Williams et al., ``Rapid Intensification of the
Emerging Southwestern North American Megadrought in 2020-2021,'' 12
Nature Climate Change 232-234 (2022).
\74\ U.S. Envtl. Prot. Agency, ``What Climate Change Means for
Missouri,'' at 1.
\75\ U.S. Envtl. Prot. Agency, ``Climate Impacts in the
Midwest,'' Climate Change Impacts, https://climatechange.chicago.gov/climate-impacts/climate-impacts-midwest
(last visited Feb. 25, 2023).
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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.
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\76\ 77 FR at 13388.
\77\ Performance Pipe, ``Driscopipe[supreg] 8000 Pipe
Degradation in High Temperature Applications'' https://www.cpchem.com/sites/default/files/2020-05/DriscopipeDegradation.pdf
(last visited Mar. 1, 2023).
---------------------------------------------------------------------------
Following the Merrimack Valley incident, PHMSA reviewed its current
DIMP regulations for areas where additional clarification could improve
the safety of gas distribution pipelines. As climate change increases
the frequency of extreme weather events and natural forces that can
impact the integrity of pipelines, PHMSA proposes to add clarity to the
DIMP regulations to ensure that operators are considering these threats
when evaluating risks. Operators would, therefore, need to consider and
take appropriate action to address the impacts of extreme weather as a
threat, regardless of whether they had experienced such events in their
pipelines' history, while still recognizing regional differences. PHMSA
expects operators to continue evaluating reasonably available
information regarding changing operating environments (i.e., climate)
and the regional impacts of extreme weather on their pipeline.
c. PHMSA's Proposal To Amend Sec. 192.1007(b)--DIMP--Identify
Threats--Natural Forces Including Extreme Weather and Geohazards
PHMSA proposes to amend Sec. 192.1007(b) to specify that operators
must include the threat of extreme weather and geohazards as
subcategories under the threat category of ``natural forces.'' This
amendment would ensure that operators consider the threat of extreme
weather under the DIMP regulations. Once identified as a threat under
Sec. 192.1007(b), operators would be required to consider how
potential extreme weather events could increase the likelihood of
failure. They would also need to consider the potential consequences of
such a failure, as required in Sec. 192.1007(c), and ensure that they
identify risk-reduction measures and implement them under Sec.
192.1007(d). PHMSA expects that operators would not limit their
[[Page 61763]]
consideration of the threat of extreme weather solely on past normal
weather patterns but would also consider any anticipated increases in
extreme weather conditions and fluctuations. This proposed requirement
would improve safety by ensuring that operators address the impacts of
climate change and protect the reliability and integrity of their
pipeline systems, even if operators have yet to experience these issues
on their systems.
4. DIMP--Identify Threats (Sec. 192.1007(b))--Age of the System, Pipe,
and Components
a. Current Requirements--DIMP--Identify Threats--Age of the System,
Pipe, and Components
Section 192.1007(b) includes a generic threat category of ``other
issues that could threaten the integrity of [a] pipeline,'' which
operators should use to identify threats that do not fit into the other
threat categories. When performing their risk analysis, Sec.
192.1007(c) states that operators ``may subdivide [their] pipeline into
regions with similar characteristics.'' PHMSA has observed operators
using age as a method of subdividing their pipeline segments when
performing the risk analysis. Further, PHMSA's annual report form,
PHMSA F 7100.1-1, requires operators to identify the miles of pipeline
by decade of installation. Section 192.1007(b) does not, however,
specifically require that operators consider the age of a pipe or
components when identifying threats to pipeline integrity.
b. Need for Change--DIMP--Identify Threats--Age of the System, Pipe,
and Components
Over time, all pipeline systems are subject to time-dependent
degradation processes threatening pipeline integrity. Pipelines made
from ferrous materials (steel, wrought iron, cast iron, etc.) are all
susceptible to oxidation corrosion over time. Plastic and composite
materials used in pipelines are subject to photodegradation if exposed
to sunlight. Joints, fittings, and welds connecting various pipeline
components can be subject to dissimilar materials corrosion or chemical
degradation of bonding agents and sealants. And the longer the
timeline, the more any gas pipeline components are exposed to a variety
of phenomena--e.g., from internal mechanical stresses, changes in
temperature, changes in external loads (including external force
damage)--that threaten pipeline integrity, exacerbate existing material
weaknesses, or accelerate time-dependent degradation processes.
Age can impact and potentially modify each of the threats an
operator identifies in Sec. 192.1007(b). The potential threat to
pipeline integrity posed by age depends on the age of the pipeline
components of which it is comprised. PHMSA understands the cumulative
effect of those age-related threats to integrity across an entire
pipeline are not merely the sum of age-related, component-specific
threats; rather, those threats can magnify or exacerbate one another
when integrated within a pipeline system. For example, one component's
failure due to time-dependent degradation processes can strain other
components throughout the system (e.g., by releasing corrosion products
that can damage other, newer components within the system). PHMSA
further notes that trending failure rates by age can be a useful tool
for revealing degraded performance throughout a pipeline system.
Similarly, the overall age of the pipeline system can provide more
opportunities for safety-critical gaps in material records. Poor
recordkeeping with respect to a pipeline component dating from a
certain time period may threaten not only pipeline integrity on that
segment, but also other components of the same pipeline installed at a
different time period.
Age can also be expressed in terms of vintage of pipes or
components. Specific manufacturing techniques and materials used during
certain periods of time can result in similar characteristics among
pipes and components of a given vintage. The vintage of pipes or
components can interact with other threats, including materials,
equipment failures, or natural forces. For example, pipe installed
earlier than 1950 has disproportionately high susceptibility to
problems from cold weather and freezing, which could interact with the
threat of natural forces. The greater susceptibility of pre-1950 pipe
is thought to be due to inferior low-temperature ductility of the
steels of the era and the methods used to join pipe at the time (such
as electric arc welds, acetylene welds, couplings, and threaded
collars).\78\ Additionally, as described in section IV.A.1 (materials),
some of the early plastic piping products manufactured from the 1960s
and into the early 1980s are more susceptible to brittle-like cracking
(also known as slow-crack growth) than newer materials.\79\
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\78\ M.J. Rosenfeld, ``Cold Weather Can Play Havoc On Natural
Gas Systems'' 242 Pipeline & Gas J. 1 (Jan. 2015), https://pgjonline.com/magazine/2015/january-2015-vol-242-no-1/features/cold-weather-can-play-havoc-on-natural-gas-systems.
\79\ Brittle-like cracking failures occur under conditions of
stress intensification. Stress intensification is more common in
fittings and joints.
---------------------------------------------------------------------------
Even though time-dependent degradation processes are widely
understood threats to the integrity of pipeline systems, as discussed
earlier, Sec. 192.1007(b) does not specifically state that operators
must account for the age of the system, pipe, and components in
identifying threats. Increasing failure rates have been observed in
older gas distribution infrastructure that has certain attributes.\80\
The increasing failure rate typically occurs toward the end of life and
accelerates the rate by which the reliability decreases. This behavior
is typically attributed to cumulative degradation that occurs in the
system over its service period. Trending failure rates by system age
can reveal degrading performance.
---------------------------------------------------------------------------
\80\ PHMSA, ``Pipeline Replacement Background'' (Apr. 26, 2021),
https://www.phmsa.dot.gov/data-and-statistics/pipeline-replacement/pipeline-replacement-background.
---------------------------------------------------------------------------
Recent incidents have illustrated that operators may be
inadequately identifying and managing threats related to the age of
components on their systems. For example, in its risk analysis, Atmos
used a commercially available software that did not explicitly consider
the age of the pipeline segments, instead grouping them into failure
categories based on similar attributes, such as material and coating.
Although such an approach may have been compliant with current
regulations, this approach to risk analysis disregards how the age
could contribute to failures. Following the 2018 Atmos incidents, the
NTSB recommended that Gas Piping Technology Committee develop guidance
and identify steps operators can take to ensure that their gas
distribution IM programs appropriately consider threats that degrade a
system over time.\81\ By adopting such a practice, operators would
recognize the full threat based on the impact of age and prioritize
remediating or replacing segments of the pipe and components that pose
more acute threats. PHMSA therefore proposes to revise Sec.
192.1007(b) to explicitly identify age as a factor in addressing
threats to integrity.
---------------------------------------------------------------------------
\81\ NTSB/PAR-21/01 at 82.
---------------------------------------------------------------------------
c. Proposal To Amend Sec. 192.1007(b)--DIMP--Identify Threats--Age of
the System, Pipe, and Components
PHMSA proposes to amend Sec. 192.1007(b) to clarify that operators
[[Page 61764]]
must, when identifying the threats on its distribution system, also
consider the age of the system, piping, and components in identifying
threats.\82\ For example, once an operator identifies a time-dependent
threat exists on their pipeline, such as corrosion, the operator would
then consider how the age of the pipe, or the components, could
influence the severity of the threat. All things equal, an older pipe
or component exposed to the threat of corrosion could carry additional
risk compared to newer pipe. Similarly, for time-independent threats,
such as natural forces, the operator would consider how the age of the
pipeline or components would expose the pipeline to multiple threats
over its lifetime, a threat that may evolve or increase over time.
PHMSA's proposal would ensure that the DIMP regulations explicitly
account for how the age of the system, pipes, and components contribute
to a pipeline's integrity degrading over time.
---------------------------------------------------------------------------
\82\ See Am. Soc'y of Mech. Eng's, ANSI B31.8S-2004, ``Managing
System Integrity of Gas Pipelines,'' at sec. 2 (Jan. 14, 2005).
---------------------------------------------------------------------------
5. DIMP--Evaluate and Rank Risk (Section 192.1007(c))
a. Current Requirements--DIMP--Evaluate and Rank Risk
Section 192.1007(c) requires that operators evaluate and rank the
risks associated with their distribution pipeline systems. This
evaluation must consider each applicable current and potential threat,
the likelihood of failure associated with each threat, and the
potential consequences of such a failure. Operators may subdivide their
distribution systems into regions (areas within a distribution system
consisting of mains, services, and other appurtenances) that have
similar characteristics and reasonably consistent risks, and for which
similar actions would be effective in reducing risk.
Through enforcement guidance, PHMSA recommended that operators
develop weighted factors for each threat specific to their system
depending upon their unique operating environment.\83\ PHMSA has
further stressed that it may be inadequate for operators to conclude
that a pipeline is not subject to any particular threat based solely on
the fact that it has not experienced a pipeline failure attributed to
the threat.\84\ PHMSA has used enforcement guidance to clarify that if
operators conclude that a particular threat is not applicable to
sections of their pipeline, then operators should document the basis
for drawing that conclusion.\85\ This basis should consider the
pipeline's failure history, design, manufacturing, construction,
operation, and maintenance.
---------------------------------------------------------------------------
\83\ DIMP Guidance at 22.
\84\ DIMP Guidance at 23.
\85\ DIMP Guidance at 18, 57.
---------------------------------------------------------------------------
b. Need for Change--DIMP--Evaluate and Rank Risk
Recent incidents have demonstrated the importance of operators
adequately evaluating and ranking risks on their systems and in their
DIMP plans. For example, as demonstrated by the 2018 Merrimack Valley
and other incidents investigated by the NTSB, some operators have not
been adequately evaluating the risk of overpressurization, and thus not
taking appropriate mitigating measures to account for those risks.\86\
Overpressurization incidents--in particular on low-pressure gas
distribution systems--merit mitigation because they have a high-
consequence. As previously noted, CMA had knowledge of the risks of an
overpressurization, updated their procedures, and still did not take
appropriate action to mitigate the risks. Similarly, the Atmos incident
in Texas demonstrated how operators can underestimate the risks
associated with the presence of leak-prone materials.
---------------------------------------------------------------------------
\86\ NTSB/PAR-19/02 at 18-21, 39-40, 48.
---------------------------------------------------------------------------
PHMSA is required by law to ensure that operators' DIMP plans
evaluate the presence and risks associated with cast iron piping and
the threat of overpressurization on low-pressure gas distribution
systems (49 U.S.C. 60109(e)(7)). PHMSA is also required to prohibit
operators, when evaluating risks related to the operation of a low-
pressure gas distribution system, from determining that there are no
potential consequences associated with low-probability events unless
that determination is supported by ``engineering analysis or
operational knowledge.'' PHMSA must also ensure that operators of gas
distribution systems consider factors other than past observed
``abnormal operating conditions''--as that term is defined at Sec.
192.803--when ranking risks and identifying measures to mitigate those
risks.
c. PHMSA's Proposal To Amend Sec. 192.1007(c)--DIMP--Evaluate and Rank
Risk
PHMSA proposes to redesignate the general requirements of Sec.
192.1007(c) under a new paragraph (c)(1). These general requirements
still require operators to consider the identified threats proposed in
Sec. 192.1007(b) as they evaluate and rank risks.
i. Certain Pipe Materials With Known Issues
PHMSA proposes to amend Sec. 192.1007(c) by creating a new Sec.
192.1007(c)(2) to specify that operators must evaluate the risks
resulting from pipelines constructed with certain materials (including
cast iron, bare steel, unprotected steel, wrought iron, and historic
plastics with known issues) when such materials are present in their
pipeline systems. Overall, these proposed requirements would improve
safety by codifying in DIMP requirements some of the known, industry-
wide threats if the materials that have exhibited these threats are
present in the operator's systems, even if operators have not yet
experienced any of these issues on their systems.
ii. Evaluate and Rank Risk: Low-Pressure Distribution Systems
PHMSA also proposes to amend Sec. 192.1007(c) by creating a new
Sec. 192.1007(c)(3) applicable to low-pressure distribution systems.
Consistent with the mandate in 49 U.S.C. 60109(e)(7), PHMSA proposes to
require operators of low-pressure gas distribution systems to evaluate
``the risks that could lead to or result from the operation of a low-
pressure distribution system at a pressure that makes the operation of
any connected and properly adjusted low-pressure gas burning equipment
unsafe.'' For the purposes of this NPRM, PHMSA determines that
``unsafe'' in this context means that gas flowing into the downstream
equipment is at a pressure beyond the rated supply pressure specified
by the manufacturer of that equipment. This amendment would ensure that
operators are addressing the risks on their pipeline that could result
in an overpressurization.
In evaluating the risks to low-pressure distribution systems, the
mandate in 49 U.S.C. 60109(e)(7)(B) requires PHMSA to ensure that
operators consider ``factors other than past observed abnormal
operating conditions [. . .] in ranking risks.'' This includes any
abnormal operating conditions (AOCs) that operators have experienced
(i.e., observed) on their system and any unobserved AOCs that could
occur on their system (i.e., an overpressurization on a low-pressure
system), including any known industry threats, risks, or hazards, as
identified by an operator from available sources (e.g., PHMSA advisory
bulletins, PHMSA incident and accident reports, PHMSA and NTSB accident
reports, State pipeline safety regulatory actions, and operator
knowledge sharing). PHMSA proposes
[[Page 61765]]
in Sec. 192.1007(c)(3)(i) to require operators of low-pressure systems
to evaluate risks to their systems in accordance with the mandate. This
amendment would ensure that operators are reviewing their past observed
operational performance to evaluate the risks on their systems. This
amendment would also ensure that operators are considering risks even
if they have yet to experience those risks on their systems. For
example, if an operator has not experienced an overpressurization on
its system, that operator must still consider the risks of an
overpressurization on its system.
The mandate in 49 U.S.C. 60109(e)(7)(B) also states that operators
may not determine that low probability events have no potential
consequences without a supporting determination. PHMSA proposes
integrating this mandate by adding a new paragraph Sec.
192.1007(c)(3)(ii) that will direct operators to evaluate the potential
consequences associated with low-probability events, unless a
determination--supported and documented by an engineering analysis or
other equivalent analysis incorporating operational knowledge--
demonstrates that the event results in no potential consequences (and
therefore no potential risk).
An engineering analysis would include documentation of the
engineering principles used to calculate the flows, pressures, and
other parameters of the piping and systems to calculate the actual
downstream pressure. This engineering analysis would also include
documentation of the methods used to determine that the system cannot
fail and cause overpressurization, including any data and assumptions
(including mitigation and control measures) utilized by the operator.
This engineering analysis may necessarily include degrees of measurable
operational knowledge regarding specific pipeline characteristics and
evidence from that analysis combined with documentable known pipeline
characteristics. An operator that determines there are no potential
consequences from a low-probability event must document all these
reasons as part of its ``engineering analysis'' submitted to PHMSA
according to Sec. 192.18 with sufficient detail as listed in Sec.
192.1007(c)(3)(ii)(A)-(F).
Because the statute requires operators to make an affirmative
determination that there are no potential consequences associated with
low probability events and recognizing that some operators might not
have fully considered the risk of low-probability events based solely
on operational knowledge, PHMSA proposes that any operational knowledge
relied upon must include with it a quantifiable assessment and support
the operator's determination with a level of rigor equal to that of an
engineering analysis. This operational knowledge could be included as
part of the proposed regulatorily required ``engineering analysis, or
an equivalent analysis,'' as used in Sec. 192.1007(c)(3)(ii). For
example, should an operator determine that a release of gas from the
pipeline, such as a leak, has no potential consequences, the operator
should include documentation demonstrating that many scenarios were
considered (such as a leak with ignition or gas migration under nearby
pavement) and that no potential consequences were identified in any of
those potential scenarios. This amendment would ensure that operators
do not dismiss material risks without a meaningful evidentiary basis,
and PHMSA or pertinent State authorities would have the opportunity to
review and consider the validity of the operator's determination when
reviewing DIMP plans.
State regulatory authorities already review operators' DIMP plans
during regular inspections. Because incorrectly determining that a
potential threat has no consequences would have serious public safety
impacts, however, PHMSA understands there is a compelling policy reason
for an operator's determination that a low-frequency event entails zero
risk be reviewed by those State regulatory authorities as well as
PHMSA. Therefore, if operators choose to apply the proposed exception
in Sec. 192.1007(c)(3)(ii), they must notify PHMSA and the appropriate
State Authority in accordance with Sec. 192.18 within 30 days of
making this determination that there are no potential consequences
associated with the low-probability event. The notification must
include information such as the date the determination was made (to
ensure compliance with the proposed timeline), descriptions of the low-
probability events being considered, and a description of the logic
supporting the determination, including information from an engineering
analysis or an equivalent analysis incorporating operational knowledge.
Further, this notification should contain a description of any
preventive and mitigative measures, including any measures considered
but not taken, as determined through the engineering analysis or an
equivalent analysis incorporating operational knowledge. The
notification should also include a description of the low-pressure
system, including, at a minimum, miles of pipe, number of customers,
number of district regulators supplying the system, and other relevant
information. In addition, operators must provide a written statement
summarizing the documentation it evaluated and how the conclusion that
there would be no potential consequences associated with the low-
probability event was reached. This documentation could include the
inspection and maintenance history of the pipeline segment, incident
reports, any leak repair data, and any failure investigations or
abnormal operations records. Providing this information would be
critical in ensuring that operators robustly evaluated methods of
reducing risk and that the operator did not ignore any material factors
in their engineering analysis or an equivalent analysis incorporating
operational knowledge.
In a new Sec. 192.1007(c)(3)(iii), PHMSA proposes to require that
in evaluating and ranking risks in their DIMP plans, operators of low-
pressure gas distribution systems must evaluate the configuration of
their primary and any secondary overpressure protection installed at
the district regulator stations, the availability of gas pressure
monitoring at or near overpressure protection equipment, and the
likelihood of any single event that immediately or over time could
result in an overpressurization of the low-pressure system (see amended
Sec. 192.195(c)). Operators' overpressure protection configurations
vary--some include a combination of relief valves, monitoring
regulators, or automatic shutoff valves. Other operators have real-time
monitoring devices located at the district regulator station, while yet
others rely on telemetering devices. Some operators, as demonstrated by
the events of September 13, 2018, may have an overpressure protection
configuration that can be defeated by a single event, such as
excavation damage, natural forces, an equipment failure, or incorrect
operations. This amendment would ensure that operators are evaluating
their existing overpressure protection system for inadequacies or
additional risks that could result in an overpressurization of the
system.
[[Page 61766]]
6. DIMP--Identify and Implement Measures To Address Risks (Section
192.1007(d))
a. Current Requirements--DIMP--Identify and Implement Measures To
Address Risks
Section 192.1007(d) requires operators to determine and implement
measures designed to reduce the risks from failure of their gas
distribution pipeline systems following the identification of threats
(in accordance with Sec. 192.1007(b)) and the evaluation and ranking
of risks (in accordance with Sec. 192.1007(c)). Section 192.1007(d)
also requires that these risk mitigation measures include an effective
leak management program (unless all leaks are repaired when found).
Although the specific process is not defined in Sec. 192.1007(d),
PHMSA has issued guidance material to support the implementation of
these requirements.
In the guidance material, PHMSA states that operators should have a
documented list of measures to reduce risks identified on their
pipeline system.\87\ The process for identifying risk mitigation
measures must be based on identified threats to each pipeline segment
and the risk analysis. Operators should rank pipeline segments and
group segments that represent the highest risk as the most important
candidates for which measures are taken to reduce risk. The operator
should ensure that the highest priority measures for reducing risk are
for the highest-ranked segments as indicated by the risk analysis.
Because the design and operation of gas distribution systems are so
diverse, no single risk control method is appropriate in all cases.
Therefore, the objective of Sec. 192.1007(d) is to ensure that each
operator has documented and described existing and proposed measures to
address the unique risks to its system and that the operator has
evaluated and prioritized actions to reduce risks to pipeline
integrity.
---------------------------------------------------------------------------
\87\ DIMP Guidance at 28.
---------------------------------------------------------------------------
b. Need for Change--DIMP--Identify and Implement Measures To Address
Risks
Proper implementation of a DIMP plan should result in aggressive
oversight and replacement of higher-risk infrastructure. For example,
there are many benefits to replacing old, cast-iron, low-pressure
distribution pipes with newer materials, such as modern plastic pipe.
Replacement projects, however, entail their own risks to public safety
and the environment that need to be balanced against the risks
associated with leaving a pipeline segment undisturbed. Poorly managed
construction projects can result in property damage and personal
injury, and replacement activity can include blowdowns to the
atmosphere of methane gas that contribute to climate change. Work on
existing pipeline facilities can also cause a catastrophic
overpressurization, as was the case in CMA's 2018 incident. Operators
must manage those risks while still implementing preventive and
mitigative measures that would reduce the risk of identified threats.
In 2020, PHMSA issued an advisory bulletin to remind operators of
the possibility of failure due to an overpressurization on low-pressure
distribution systems.\88\ In that advisory bulletin, PHMSA reminded
operators of the existing DIMP regulations and recommended that per
Sec. 192.1007(d), operators take additional actions to reduce risks if
they found their current overpressure protection design to be
insufficient. PHMSA also identified for operators that ``[t]here are
several ways that operators can protect low-pressure distribution
systems from overpressure events,'' such as:
---------------------------------------------------------------------------
\88\ See ``Pipeline Safety: Overpressure Protection on Low-
Pressure Natural Gas Distribution Systems,'' ADB-2020-02, 85 FR
61097 (Sept. 29, 2020).
---------------------------------------------------------------------------
1. Installing a full-capacity relief valve downstream of the low-
pressure regulator station, including in applications where there is
only worker-monitor pressure control;
2. Installing a ``slam shut'' device;
3. Using telemetered pressure recordings at district regulator
stations to signal failures immediately to operators at control
centers; and
4. Completely and accurately documenting the location for all
control (i.e., sensing) lines on the system.
As discussed earlier, subsequent to the 2018 Merrimack Valley
incident, PHMSA was required by statute to ensure that operators of
low-pressure gas distribution systems evaluate the risk of
overpressurization in their DIMP plans. (49 U.S.C. 60109(e)(7)(A)(ii)).
For existing low-pressure systems, operators already have a mechanism
in place--their DIMP--to evaluate their systems to ensure they can
identify and implement measures to minimize the risk imposed by any
inadequate overpressure protection.
c. PHMSA's Proposal To Amend Sec. 192.1007(d)--DIMP--Identify and
Implement Measures To Address Risks
PHMSA proposes to amend Sec. 192.1007(d) to establish additional
criteria for operators to evaluate when identifying and implementing
measures to address risks identified in DIMP plans. PHMSA's proposal
would require operators--when identifying and implementing measures--to
specifically account for risks associated with the age of the pipe, the
age of the system, the presence of pipes with known issues, and
overpressurization of low-pressure distribution systems. PHMSA is
adding these specific risks to Sec. 192.1007(d) because they were the
subject of recent incidents, as discussed earlier. This amendment would
ensure that operators are not only identifying these specific threats
(in Sec. 192.1007(b)), but also implementing measures to address those
risks. In a new Sec. 192.1007(d)(2), PHMSA is proposing to explicitly
require operators of existing low-pressure systems to take certain
actions to prevent and mitigate the risk of an overpressurization that
could be the result of any single event or failure. These actions
include identifying, maintaining, and (if necessary) obtaining
traceable, verifiable, and complete records that document the
characteristics of the pipeline that are critical to ensuring proper
pressure controls for the system. PHMSA discusses the criteria for
these pressure control records in section IV.F of this NPRM.
In addition to this recordkeeping requirement, in a new Sec.
192.1007(d)(2), PHMSA proposes that operators must confirm and document
that each district regulator station meets the design standards in
Sec. 192.195(c)(1)-(3) or take the following actions: (1) identify
preventative and mitigative measures based on the unique
characteristics of their system to minimize the risk of
overpressurization on low-pressure systems, or (2) upgrade their
systems to meet design standards in Sec. 192.195(c)(1)-(3). PHMSA
discusses the criteria for this proposed upgrade in section IV.H of
this NPRM. Should an operator choose to identify preventative and
mitigative measures based on the unique characteristics of their system
to minimize the risk of overpressurization, PHMSA proposes that the
operator notify PHMSA and State or local pipeline authorities no later
than 90 days in advance of implementing any alternative measures. PHMSA
proposes that an operator must make this notification in accordance
with Sec. 192.18, which would include a description of the operator's
proposed alternative measures, identification, and location of
facilities to which the measures would be applied, and a description of
how the measures would
[[Page 61767]]
ensure the safety of the public, affected facilities, and environment.
This notification would ensure that operators are keeping PHMSA and
State authorities informed of alternative measures to address risk.
This amendment would apply to existing low-pressure systems that have
evaluated and identified inadequate overpressure protections in
accordance with Sec. 192.1007(c).
PHMSA has also proposed to amend Sec. 192.18 to reflect this
proposed change by including a reference to Sec. 192.1007. Should an
operator choose to implement an alternative method of minimizing
overpressurization, PHMSA proposes that the operator notify PHMSA and
State or local pipeline authorities no later than 90 days in advance of
implementing any alternative measures. PHMSA proposes that operators
must make this notification in accordance with Sec. 192.18, which
would include a description of the operators' proposed alternative
measures, identification, and location of facilities to which the
measures would be applied, and a description of how the measures would
ensure the safety of the public, affected facilities, and environment.
This notification would ensure that operators are keeping PHMSA and
State authorities informed of alternative measures to address risk.
PHMSA proposes these amendments pursuant to 49 U.S.C. 60102(t) and
60109(e)(7). The proposed amendments would reinforce the recommended
actions from PHMSA's 2020 advisory bulletin in which PHMSA identified
for operators of low-pressure distribution systems the risks inherent
to those systems and the preventative or mitigative measures they
should implement to address the risk of overpressurization. PHMSA
expects that operators may already be complying with many of these
practices subsequent to issuance of the advisory bulletin, which set
forth PHMSA's existing policy and interpretation of the current DIMP
requirements. In this NPRM, PHMSA proposes to codify this existing
policy and interpretation in its regulations.
This amendment is also aligned with the NTSB's clarification to
recommendation P-19-14 that PHMSA would not have to require that
existing low-pressure gas distribution systems be completely
redesigned; rather, PHMSA may satisfy the recommendation by requiring
operators to add additional protections, such as slam-shut or relief
valves, to existing district regulator stations or other appropriate
locations in the system.\89\
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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), https://data.ntsb.gov/carol-main-public/sr-details/P-19-014.
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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.
---------------------------------------------------------------------------
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.
---------------------------------------------------------------------------
\92\ NPGA, Petition for Rulemaking: Small Liquefied Petroleum
Distribution Systems, Doc. No. PHMSA-2022-0102-001 (Dec. 17, 2021)
(``NPGA Petition'').
\93\ NPGA referenced the examples of: (1) PHMSA Gas Regulatory
Reform Final Rule, 86 FR 2210; (2) Nat'l Academies of Sciences,
Eng'g, and Med., ``Safety Regulation for Small LPG Distribution
Systems'' (2018), https://nap.edu/25245 (``NAS Study''); and (3)
NPGA, Comment Re: Pipeline Safety: Integrity Management Program for
Gas Distribution Pipelines, Doc. No. PHMSA-RSPA-2004-19854-0197
(Oct. 23, 2008).
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[[Page 61768]]
The basis of NPGA's petition is that small LPG system operators are
comparable to master meter systems, a set of operators that PHMSA
recently removed from the DIMP requirements through the 2021 Gas
Regulatory Reform Final Rule. As NPGA explained, master meter systems
tend to be operated by small entities with simple systems compared to
natural gas distribution operators. Master meters also often include
only one type of pipe, and the systems operate at a single operating
pressure. Similarly, as NPGA stated, the vast majority of small LPG
pipeline systems are single property systems that occupy a small,
overall footprint in size and generally operate at a single operating
pressure. Although such systems may be metered or non-metered, the
nature of their simplicity in size and application make them comparable
to master meter systems such that, owing to their ``nearly identical''
function and structure, ``the two systems should be categorized
together for the same treatment under the regulations'' exempting them
from DIMP requirements.\94\
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\94\ NPGA Petition at 3.
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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.
---------------------------------------------------------------------------
\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), https://www.phmsa.dot.gov/sites/phmsa.dot.gov/files/2020-07/2020-State-Guidelines-Revision-with-Appendices-2020-5-27.pdf.
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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 SICT. (49 U.S.C. 60105(b)).
PHMSA updates Guidelines and its evaluation process annually to ensure
that State agencies are meeting the certification requirements.\105\
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\105\ PHMSA anticipates issuing updated Guidance to reflect the
changes to the Pipeline Safety Grant Program.
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In certifying that the State has a ``sufficient number of
employees'', the State must use the SICT to account for:
1. The number of miles of gas and hazardous liquid pipelines in the
State, including the number of miles of cast iron and bare steel
pipelines;
2. The number of services in the State;
3. The age of the gas distribution systems in the State; and
4. Environmental factors that could impact the integrity of the
pipeline, including relevant geological issues.
Currently, the SICT accounts for the size (e.g., mileage, service
line count, etc.) of each operator's system; type of operator and
product being transported; risk factors of material composition,
including but not limited to, the presence of cast iron and bare steel;
and environmental factors that could impact the integrity of a
pipeline, including geological issues. Total miles of gas and hazardous
liquid pipelines in a State and the age of gas distribution systems
are, however, only implicitly considered. To comply with the mandate,
PHMSA proposes to codify within its regulations the use of the SICT for
establishing inspection person-days and update the SICT to explicitly
include the total gas or hazardous liquid pipeline mileage in the State
and the age of a gas distribution system as a factor for consideration.
3. PHMSA's Proposal To Codify the Use of the SICT in Pipeline Safety
Regulations
This NPRM proposes amendments to the pipeline safety regulations at
49 CFR part 198 to codify use of the SICT by all PHMSA's State partners
holding certifications or agreements per 49 U.S.C. 60105 or 60106.
Specifically, PHMSA proposes to revise Sec. 198.3 to add definitions
for ``inspection person-day'' and ``State Inspection Calculation Tool''
and by revising Sec. 198.13 to include the use of the SICT for
determining inspection person-days. PHMSA proposes to define
``inspection person-day'' to mean ``all or part of a day, including
travel, spent by State agency personnel in on-site or virtual
evaluation of a pipeline system to determine compliance with Federal or
State Pipeline Safety Regulations.'' PHMSA will continue to permit
travel to be included for inspection person-days even if travel
requires a full day before or after the inspection because some states
cover a large geographical area that requires substantial travel time
and a State agency's staffing requirement could be impacted if travel
is not considered. PHMSA will also continue to allow inspection person-
days to be counted for those individuals who have not completed
training requirements but who assist in inspections if they are
supervised by a qualified inspector. PHMSA proposes to define the term
``State Inspection Calculation Tool (SICT)'' to mean ``a tool used to
determine the required minimum number of annual inspection person-days
for a State agency.'' These proposed definitions are consistent with
those in the Guidelines.
PHMSA is required to promulgate regulations to require that a State
authority with a certification under 49 U.S.C. 60105 has a sufficient
number of qualified inspectors to ensure safe operations, as determined
by the SICT and other factors determined appropriate by the Secretary.
(49 U.S.C. 60105 note). Pursuant to this legal requirement, PHMSA
proposes revising Sec. 198.13(c)(6) to state that when allocating
funding and considering various performance factors, PHMSA considers
the number of State inspection person-days, ``as determined by the SICT
and other factors.'' These amendments would codify PHMSA's current
practice of using the SICT in the determination of the minimum number
of inspection person-days each State must dedicate to inspections in a
given calendar year.
C. Emergency Response Plans (Section 192.615)
The pipeline safety regulations require operators to have written
procedures for responding to emergencies involving their pipeline
systems to ensure a coordinated response to a pipeline emergency. This
response includes communicating with fire, police, and other public
officials promptly. Through a final rule issued on April 8, 2022,
titled ``Requirement of Valve Installation and Minimum Rupture
Detection Standards'', PHMSA extended that emergency communication for
all gas pipeline operators to include a public safety answering point
(PSAP; i.e., 9-1-1 emergency call center).\106\ Among other changes,
the Valve Rule amended Sec. 192.615(a) to ensure proper communication
with PSAPs, requiring operators to immediately and directly notify
PSAPs upon notification of a potential rupture. However, the Valve Rule
requirements were not in effect at the time of the Merrimack Valley
incident.
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\106\ 87 FR at 20940, 20973.
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Subsequent to the 2018 Merrimack Valley incident, 49 U.S.C. 60102
was amended to improve the emergency response and communications of gas
distribution operators during gas pipeline emergencies in several ways.
Specifically, 49 U.S.C. 60102(r) was added, which requires PHMSA to
promulgate regulations ensuring that gas distribution operators develop
written emergency response procedures for notifying and communicating
with emergency response officials as soon as practicable from the time
of confirmed discovery of certain gas pipeline emergencies; communicate
with the public during and after such a gas pipeline emergency; and
establish an opt-in system for operators to rapidly communicate with
customers. Gas distribution operators must make their updated emergency
response plans available to PHMSA or the relevant State regulatory
agency within 2 years after the final rule is issued, and every 5 years
thereafter (49 U.S.C. 60108(a)(3)).
PHMSA, in this NPRM, proposes building on the Valve Rule's changes
to emergency response plan requirements through additional changes to
ensure prompt and effective emergency response coordination. For all
gas pipeline operators subject to Sec. 192.615,\107\ PHMSA proposes to
expand the requirements to have procedures for a prompt and effective
response to include emergencies involving notification of potential
ruptures, a release of gas that results in a fatality, and any other
emergencies deemed significant by the operator, with similar
requirements to notify PSAPs in those instances. PHMSA understands
these proposed amendments of existing emergency response plan
requirements as applicable to all part 192-regulated pipelines would be
reasonable, technically feasible, cost-effective, and practicable. The
proposed changes are common-sense, incremental supplementation of
current requirements regarding the content and execution of emergency
response plans for gas pipeline operators.
[[Page 61771]]
Implementation of the proposed requirements should not require special
expertise or investment in expensive new equipment; PHMSA expects that
some operators may already comply with these proposed requirements
either voluntarily or due to similar requirements imposed by State
pipeline safety regulators. And insofar as these incremental proposed
additions to emergency planning requirements are consistent with
historical PHMSA guidance, industry operational experience, and the
lessons learned from incidents such as the Merrimack Valley incident,
they are precisely the sort of actions a reasonably prudent operator of
any gas pipeline facility would maintain in ordinary course given that
their systems transport commercially valuable, pressurized (natural
flammable, toxic, or corrosive) gasses. Viewed against those
considerations and the compliance costs estimated in the PRIA, PHMSA
expects its proposed amendments are a cost-effective approach to
achieving the commercial, public safety, and environmental benefits
discussed in this NPRM and its supporting documents. Lastly, PHMSA
understands that its proposed compliance timeline--one year after
publication of a final rule (which would necessarily be in addition to
the time since publication of this NPRM)--would provide operators ample
time to implement requisite changes to their procedures (and manage any
related compliance costs).
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\107\ PHMSA notes that Sec. 192.9(d) does not currently require
compliance with Sec. 192.615 for Type B gathering lines, however
PHMSA has proposed, in another rulemaking, to amend Sec. 192.9(d)
to require Type B gas gathering operators to comply with Sec.
192.615. See 88 FR at 31952-53, 31955-56.
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PHMSA proposes additional requirements for gas distribution
operators. First, those operators would be subject to an expanded list
of emergencies that includes unintentional releases of gas with
significant associated shutdown of customer services. Second, gas
distribution operators must establish written procedures for
communications with the general public during an emergency, and
continue communications through service restoration and recovery
efforts, to inform the public of the emergency and service restoration
and recovery efforts. Third, gas distribution operators would be
required to develop and implement for their customers an opt-in or opt-
out notification system to provide them with direct communications
during a gas pipeline emergency. PHMSA understands its proposed
amendments enhancing existing emergency response plan requirements
would be reasonable, technically feasible, cost-effective, and
practicable for affected gas distribution operators. PHMSA expects that
some gas distribution operators may already comply with these
requirements either voluntarily or due to similar requirements imposed
by State pipeline safety regulators. PHMSA also expects that operators
will already have (due to the need to bill their customers) the
requisite contact information needed to implement voluntary opt-in or
opt-out notification systems; as explained below, some operators may
also be able to leverage existing emergency notification systems
maintained by local and State government officials in satisfying this
proposed requirement. PHMSA further notes that its proposed
enhancements for emergency communications are precisely the sort of
minimal actions a reasonably prudent operator of gas distribution
pipeline facility would undertake in ordinary course to protect each of
(1) the public safety, given that their systems transport pressurized
(natural, flammable, toxic, or corrosive) gasses; and (2) their
customers, given the economic cost to those customers from interruption
of supply. Viewed against those considerations and the compliance costs
estimated in the PRIA, PHMSA expects its proposed amendments will be a
cost-effective approach to achieving the public safety and
environmental benefits discussed in this NPRM and its supporting
documents. Lastly, PHMSA understands that its proposed compliance
timeline--between 12 to 18 months after publication of a final rule
(which would necessarily be in addition to the time since publication
of this NPRM)--would provide operators ample time to implement
requisite changes to their procedures and procure necessary personnel
and vendor services (and manage any related compliance costs).
Finally, PHMSA is requesting comments on whether it should require
gas distribution operators to follow incident command systems (ICS)
during an emergency response. PHMSA may consider whether to include
this requirement in any final rule in this proceeding. The sections
below discuss each of these proposals in more detail.
1. Emergency Response Plans--First Responders
a. Current Requirements--Emergency Response Plans--Notifying PSAPs,
First Responders, and Public Officials
Section 192.615(a) requires that each gas pipeline operator have
written procedures for responding to gas pipeline emergencies,
including for how operators are expected to communicate with fire,
police, and other appropriate public officials before and during an
emergency. The Valve Rule revised Sec. 192.615(a)(2) to add direct
communication with PSAPs in response to gas pipeline emergencies and
required operators to establish and maintain an adequate means of
communication with PSAPs.\108\ Further, the Valve Rule revised Sec.
192.615(a)(8) to require operators to notify these entities and
coordinate with them during an emergency. This communication to the
appropriate PSAPs must occur immediately and directly upon receiving a
notification of potential rupture to coordinate and share information
to determine the location of any release.\109\ The Valve Rule also
revised Sec. 192.615(c) to require each operator establish and
maintain liaison with the appropriate PSAPs ``where direct access to a
9-1-1 emergency call center is available from the location of the
pipeline, as well as fire, police, and other public officials'' to
coordinate responses and preparedness planning.
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\108\ PHMSA expects that ``maintaining adequate means of
communication'' should include, but not be limited to, considering
the frequency of communication, changes to the nature of the
emergency, changes to previously liaised information, and updates to
other emergency response information, as determined by the operator.
\109\ 87 FR at 20983.
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Further, PHMSA issued an advisory bulletin in 2012 (ADB-2012-09)
regarding communications between pipeline operators and PSAPs.\110\ In
the advisory bulletin, PHMSA reminded operators that they should notify
PSAPs of indications of a pipeline facility emergency, including an
unexpected drop in pressure, an unanticipated loss of SCADA
communications, or reports from field personnel. In the advisory
bulletin, PHMSA recommended that pipeline operators immediately contact
the PSAPs of the communities in which such indications occur.
Furthermore, the advisory bulletin noted that operators should have the
ability to immediately contact PSAPs along their pipeline routes if
there is an indication of a pipeline emergency to determine if the PSAP
has information that may help the operator confirm whether a pipeline
emergency is occurring or to provide assistance and information to
public safety personnel who may be responding to the event. The
revisions to Sec. 192.615 in the Valve Rule essentially codified this
advisory.
[[Page 61772]]
PHMSA notes that indications of a gas pipeline emergency, including
unexpected pressure drops or reports from field personnel, might be a
notification of potential rupture under amended Sec. 192.615, which
would require the direct and immediate notification of the appropriate
PSAP.
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\110\ ``Pipeline Safety: Communication During Emergency
Situations,'' ADB-2012-09, 77 FR 61826 (Oct. 11, 2012). PHMSA also
issued draft FAQs on 9-1-1 notification on July 8, 2021.
``Frequently Asked Questions on 911 Notifications Following Possible
Pipeline Ruptures,'' 86 FR 36179 (July 8, 2021). If PHMSA were to
finalize the proposed revisions for these emergency plan provisions
in a subsequent final rule, PHMSA would withdraw the draft 9-1-1
notification FAQs as redundant.
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b. Need for Change--Emergency Response Plans--Notifying PSAPs, First
Responders, and Public Officials
During the initial response to the 2018 Merrimack Valley incident,
the three fire departments in the affected municipalities were
inundated with emergency calls from residents and businesses reporting
fires and explosions and requesting assistance shortly after 4 p.m. on
September 13, 2018. Around that same time, the CMA technician reported
smoke and explosions. However, it was not until nearly 4 hours later at
7:43 p.m. that the president of CMA declared a ``Level 1'' emergency
under CMA's emergency response plan. Lawrence's deputy fire chief told
NTSB investigators that, during the incident response, he attempted to
contact CMA through the station dispatch to get a status update to see
if CMA had the gas incident under control but did not receive updates
from the company until hours later. About 2 hours after the initial
fires, Lawrence's deputy fire chief assumed the gas company had
resolved the incident.\111\ The Andover fire chief recognized the
events occurring were gas-related and contacted CMA through a regular
dispatch number to provide status updates so the fire department could
relay information to the public. He told NTSB investigators that CMA
did call him back more than 4 hours later, while also acknowledging the
delay was likely caused by the number of emergency calls CMA received.
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\111\ NTSB, PLD18MR003, ``Interview of: Kevin Loughlin, Deputy
Chief Lawrence Fire Department,'' (Sept. 15, 2018), https://data.ntsb.gov/Docket/Document/docBLOB?ID=40476257&FileExtension=.PDF&FileName=Emergency%20Response%20-%20Interview%20of%20Lawrence%20Deputy%20Fire%20Chief-Master.PDF.
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The NTSB report noted that CMA had emergency response plans but did
not implement their plans in a manner that would allow them to
effectively respond to such a large incident, explaining that
ambiguities within the operator's emergency response plans could have
contributed to the poor emergency response in that incident.
Specifically, the NTSB pointed out that the operator's emergency
response plans suggested that notification could be discretionary, as
those procedures stated that when an overpressurization of the system
occurs, there ``may be a need'' to communicate with local government
officials and emergency management agencies, as well as with fire and
police departments.\112\ According to the NTSB report, the NiSource
emergency plan also stated that it is ``imperative for all entities
involved to remain informed of each other's activities,'' and that
CMA's Incident Commander (IC), (in this case, the field operations
leader (FOL)) was required to establish appropriate contacts for
communication purposes throughout the incident. However, during the
initial hours of the event, the IC did not establish these requisite
communication contacts because the IC was involved with shutting down
the natural gas system. And although CMA representatives went to
emergency responder staging areas and emergency operations centers, the
NTSB report noted that CMA representatives could not address many of
the questions from emergency responders because the representatives
were not prepared with thorough and actionable information. As a result
of the lack of timely, thorough, and actionable information on the
circumstances of the overpressurization event, emergency responders
unnecessarily evacuated areas, straining limited emergency response
resources, and creating confusion among the public. The NTSB concluded
that CMA was not adequately prepared with the resources necessary to
assist emergency management services with the emergency response.
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\112\ NTSB/PAR-19/02 at 46.
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Subsequent to the 2018 Merrimack Valley incident, PHMSA was
required by law to promulgate regulations to ensure that gas
distribution system operators include in their emergency response plans
written procedures for notifying ``first responders and other relevant
public officials as soon as practicable, beginning from the time of
confirmed discovery, as determined by [PHMSA], by the operator of a gas
pipeline emergency,'' and including gas distribution-specific
indications of what constitutes a gas pipeline emergency. (49 U.S.C.
60102(r)).
c. Proposal To Amend Sec. 192.615--Emergency Response Plans--Notifying
PSAPs, First Responders, and Public Officials
As discussed earlier, the Valve Rule revised the existing emergency
response regulations to require operators notify PSAPs in the event of
gas pipeline emergencies, and immediately and directly notify PSAPs
when receiving a notification of potential rupture. In this NPRM, PHMSA
proposes to revise the non-exclusive list at Sec. 192.615(a)(3) of gas
pipeline emergencies requiring all part 192-regulated gas pipeline
operators to undertake prompt, effective response on notification of
potential ruptures; a release of gas that results in one or more
fatalities; and any other emergency deemed significant by the operator.
PHMSA is also proposing that gas distribution pipeline operators would
need to undertake prompt, effective response on notification of the
unintentional release of gas and shutdown of gas service to either 50
or more customers or, if the operator has fewer than 100 customers, 50
percent of total customers. Additionally, PHMSA proposes to amend
existing requirements at Sec. 192.615(a)(8) to apply its requirement
for operators of all gas pipelines to establish written procedures for
immediately and directly notifying PSAPs, or other coordinating
agencies for the communities and jurisdictions in which the pipeline is
located, to include after a notification of these gas pipeline
emergencies. Gas distribution operators, moreover, would also have to
immediately and directly notify PSAPs on notification of an
unintentional release and shutdown of gas services where either 50 or
more customers lose service, or for operators with fewer than 100
customers, if 50 percent of all the operator's customers lose service.
i. What is a ``Gas Pipeline Emergency?''
PHMSA is revising the list of gas pipeline emergencies in Sec.
192.615(a)(3) to add: (1) for all part 192-regulated gas pipeline
operators, events involving 1 or more fatalities or any other emergency
deemed significant by the operator; and (2) for gas distribution
pipeline operators only, an unintentional release of gas resulting in a
shutdown of gas services affecting at least 50 customers, or for
operators with fewer than 100 customers, 50 percent of customers.\113\
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\113\ PHMSA also is adding, applicable to all part 192-regulated
gas pipeline operators, ``potential rupture'', consistent with the
amendment in the Valve Rule to Sec. 192.615(a)(8).
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The statutory language does not elaborate on the meaning of
``significant'' within its usage in the phrase ``the unscheduled
release of gas and shutdown of gas service to a significant number of
customers.'' Therefore, PHMSA proposes to establish the threshold for a
``significant number of customers'' to be 50 customers or, for
operators with fewer than 100 customers, 50 percent of all the
operator's customers. In determining this threshold, PHMSA reviewed the
[[Page 61773]]
data for all reportable gas distribution incidents from 2010 to 2021
and averaged the number of residential, commercial, and industrial
customers affected by those incidents.\114\
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\114\ See PHMSA, ``Distribution, Transmission & Gathering, LNG,
and Liquid Accident and Incident Data'' (Aug. 31, 2022), https://www.phmsa.dot.gov/data-and-statistics/pipeline/distribution-transmission-gathering-lng-and-liquid-accident-and-incident-data.
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PHMSA also proposes to add ``other emergency deemed significant by
the operator'' to the list of examples of a gas pipeline emergency to
allow operators to use their best professional judgment when
coordinating with first responders and other relevant public officials
and account for other system-specific circumstances, such as an outage
to a single customer that happens to be a hospital or other critical-
use facility, when complying with Sec. 192.615. This amendment would
specify a non-exclusive list of gas pipeline emergencies.
ii. When must operators communicate with PSAPs, first responders, and
other relevant public officials?
PHMSA proposes to adopt the aforementioned more-inclusive list of
gas pipeline emergencies into the Sec. 192.615(a)(8) notification
requirements established in the Valve Rule that required the immediate
and direct notification of PSAPs and other relevant emergency
responders and public officials after receiving notice of such an
emergency. Pursuant to 49 U.S.C. 60102(r), operator communications with
first responders and other relevant public officials must occur ``as
soon as practicable, beginning from the time of confirmed discovery, as
determined by the Secretary, by the operator of a gas pipeline
emergency.'' PHMSA, in Sec. Sec. 191.5 and 195.52, already uses the
term ``confirmed discovery'' \115\ to require operators to report
certain events to the National Response Center at the earliest
practicable moment following ``confirmed discovery;'' however, these
notifications may occur up to 1 hour after confirmation. Further, those
Sec. Sec. 191.5 and 195.52 reportable events may not always constitute
a gas pipeline emergency as proposed in Sec. 192.615. Because the 49
U.S.C. 60102(r) mandate directs PHMSA to improve and expand emergency
response efforts--distinct from operator notification of incidents/
accidents for reporting purposes--PHMSA determines that the timing of
local emergency communication must come immediately and directly upon
indication of such a gas pipeline emergency. PHMSA, therefore, does not
propose to interpret ``confirmed discovery'' in 49 U.S.C. 60102(r) to
apply in Sec. 192.615(a) in the same manner as the term is used in 49
CFR parts 191 and 195.\116\ Instead, PHMSA proposes ``confirmed
discovery'' in 49 U.S.C. 60102(r), for purposes of Sec. 192.615, to
mean immediately after receiving notice of a gas pipeline
emergency.\117\ This will bring local emergency services to bear as
near as possible to a gas pipeline emergency based on early
indications, rather than considering whether the gas pipeline emergency
is also a reportable event under Sec. 191.5 before initiating an
emergency response.
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\115\ The term ``confirmed discovery,'' defined at Sec. Sec.
191.3 and 195.3, ``means when it can be reasonably determined, based
on information available to the operator at the time a reportable
event has occurred, even if only based on a preliminary
evaluation.''
\116\ Relying on the same operative phrase (``confirmed
discovery'') that is already used to notify the National Response
Center of reportable incidents risks introducing confusion and
uncertainty with respect to what regulations to follow and how to
incorporate these regulations into response plans for when operators
must contact local emergency responders. In an emergency, clarity is
critical and PHMSA believes that utilizing distinct regulatory
phrases for these different duties will help distinguish and clarify
responsibilities in an emergency response.
\117\ PHMSA's proposal anticipates that an operator will alert
local emergency response officials upon earliest indications of gas
pipeline emergencies.
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PHMSA proposes that gas pipeline emergencies be immediately and
directly communicated to local emergency responders because any delays
in emergency response may make the emergency significantly more
difficult to contain. PHMSA expects that in no case should that
``immediate'' communication to PSAPs begin any later than 15 minutes
following initial notification to the operator of that emergency. This
expectation is consistent with certain criteria for ``notification of a
potential rupture'' adopted in the Valve Rule,\118\ and would ensure
the timely and effective implementation of the pipeline operator's
emergency response plan and coordinated response with local public
safety officials. PHMSA also expects that if a gas pipeline emergency
also meets the criteria of an incident in Sec. 191.3, operators would
report the incident to the National Response Center in accordance with
Sec. 191.5, as already required.
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\118\ See Sec. 192.635(a)(1) (specifying a 15-minute time
interval for evaluating significant pressure losses on gas pipelines
as an indicium of a rupture).
---------------------------------------------------------------------------
iii. What information should operators provide to first responders and
public officials?
As the emergency response to the Merrimack Valley incident
continued, public safety officials asked CMA for detailed information
on the locations of the overpressurized gas lines to aid in assessing
the scope and scale of the incident. Officials requested maps and lists
of impacted customers and impacted streets, but CMA did not provide
them in a timely manner. This significantly hampered the response to
the event and caused first responders to take unnecessary actions
during the immediate response efforts. For example, instead of
targeting specific residents based on the location of the affected
services, first responders needed to go door to door to evaluate safety
impacts and determine where the gas lines were overpressurized. To
prevent such delays from occurring in the future, PHMSA recommends
operators provide first responders and public officials with pertinent
information, as it becomes available, to support emergency
communications during a gas pipeline emergency, including: (1) the
operator's response efforts; (2) information on the gas service sites
impacted by the release; (3) the magnitude of the incident and its
expected impact; (4) the location(s) of the emergency and of affected
customers; (5) the specific hazard and the potential risks; and (6) the
operator point of contact responsible for addressing first responder
and public official questions and concerns. Procedures to provide such
information must be included in their emergency response plans and
should also comport with guidance by the Federal Emergency Management
Agency (FEMA) for State and local governments in developing effective
hazard mitigation planning and would help ensure that appropriate
instructions, directions, and information is provided to the right
people at the appropriate time.\119\
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\119\ FEMA, ``Lesson 3: Communicating in an Emergency'' (Feb.
2014), https://training.fema.gov/emiweb/is/is242b/instructor%20guide/ig_03.pdf.
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2. Emergency Response Plans--General Public
a. Current Requirements--Emergency Response Plans--General Public
Currently, there are no Federal regulations requiring gas
distribution operators to establish communications with the general
public during or following a gas pipeline emergency. Section 192.615
requires operator
[[Page 61774]]
coordination and communication with only fire, law enforcement,
emergency management, and other public safety officials. Section
192.616 contains requirements for public awareness but does not contain
provisions specific to communications with the public during or after
an emergency.\120\
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\120\ Section 192.616 requires operators to develop and
implement a written continuing public-education program that follows
the guidance provided in American Petroleum Institute's (API)
Recommended Practice (RP) 1162 (incorporated by reference, see Sec.
192.7). API RP 1162 is a consensus standard that establishes a
baseline public-awareness program for pipeline operators. It states
that operators should provide notice of, and information regarding,
their emergency response plans to appropriate local emergency
officials.
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b. Need for Change--Emergency Response Plans--General Public
In any gas pipeline emergency, communicating basic information and
a consistent message can be difficult. While communication with
emergency responders is important, so too is contemporaneously updating
affected members of the public, as both serve to reduce public safety
harms. CMA's failure to communicate promptly with its affected
customers throughout the 2018 Merrimack Valley incident showed
deficiencies in CMA's incident response planning. CMA first provided
the public with information regarding the incident at approximately
9:00 p.m. on September 13, 2018--nearly 5 hours after the onset of the
emergency at approximately 4:00 p.m. when the first 9-1-1 calls on the
incident were made. Although CMA was still gathering relevant
information during the first several hours following the incident and
did not have a complete understanding of the situation, it nevertheless
should have conveyed information to the public on the nature of the
incident and affected areas more quickly.
Subsequent to the 2018 Merrimack Valley incident, PHMSA was
directed in 49 U.S.C. 60102(r) to revise its regulations to ensure that
each gas distribution operator includes written procedures in its
emergency plan for ``establishing general public communication through
an appropriate channel'' as soon as practicable after a gas pipeline
emergency. In particular, operators should communicate to the public
information regarding the gas pipeline emergency and ``the status of
public safety.''
c. PHMSA's Proposal To Amend Sec. 192.615--Emergency Response Plans--
General Public
Gas distribution pipeline operators are not currently required to
communicate public safety or service interruption and restoration
information to the public during and following a gas pipeline
emergency. Therefore, PHMSA proposes that gas distribution operators
include procedures for establishing and maintaining communication with
the general public as soon as practicable during a gas pipeline
emergency on a gas distribution pipeline. Operators would need to
continue communications through service restoration and recovery
efforts. Operators would need to establish communication through one or
more channels appropriate for their communities, which could include
in-person events (e.g., press conferences or town hall-style events),
print media, broadcast media, the internet or social media, text
messages, phone apps, or any combination of these channels. Further,
PHMSA proposes that such communications must include the following
components:
1. Information regarding the gas pipeline emergency (which could
include the specific hazard and potential risks to the community, the
location of the incident and boundaries of the impacted area, the
magnitude of the event and the expected impact, protective actions the
public should take, and how long the public may be impacted),
2. The status of the emergency (e.g., have the condition causing
the emergency or the resulting public safety risks been resolved),
3. The status of pipeline operations affected by the gas pipeline
emergency and when possible, a timeline for expected service
restoration, and
4. Directions for the public to receive assistance (e.g., provide a
phone number for customers to call if they are without power for 24
hours, or directions to safe local shelters should temperatures drop
below freezing).
PHMSA believes that providing in its regulations a list of
information for operators to include in their procedures will help
streamline communications to the public during a gas pipeline emergency
and post-emergency efforts and ensure that members of the public have
information needed to understand the risks to public safety posed by a
gas pipeline emergency. In addition, by providing a list of minimum
requirements for public communications, operators can train personnel
on the type of information they should collect and share with the
public. Operators can require the communication of additional
information in their procedures, but should, at a minimum, inform the
public of the information listed above. During an emergency response,
an operator's resources may be strained such that not all the
information pertaining to the incident may be available at a given
time. Therefore, during a gas pipeline emergency on a distribution
line, operators should provide updates to the public on a reasonable
basis as this information becomes available or changes. This provision
allows for a common-sense approach to when an operator must provide
general public updates to an emergency. However, it would require
operators to provide these updates based on the circumstances of the
emergency such that the general public timely receives information that
could influence the public's response to the emergency or benefit
affected communities' understanding of recovery effort progress.
Further, PHMSA also proposes that when communicating this minimum
information with the general public, operators must ensure these
messages are issued in English and in other languages commonly
understood by a significant number and concentration of the non-English
speaking population in the operator's service area and are delivered in
a manner accessible to diverse populations in their service operators.
Operators should use clear and simple language in their communications.
The Merrimack Valley incident underscores the value of such broadly
accessible communications. The city of Lawrence, MA, is comprised of a
higher percentage of Spanish-speaking residents than other areas
affected by the Merrimack Valley incident. In the Massachusetts
Emergency Management Agency (MEMA) After Action Report, MEMA reported
that CMA did not fully account for the demographics of the impacted
communities when attempting to communicate with the public during and
following the incident, which in some cases delayed delivery of
appropriate information and services to impacted customers.\121\
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\121\ Mass. Emergency Mgmt. Agency & Mass. Nat'l Guard,
``Merrimack Valley Natural Gas Explosions After Action Report,'' at
49-50 (Jan. 2020), https://www.mass.gov/doc/merrimack-valley-natural-gas-explosions-after-action-report/download (``Merrimack
Valley After Action Report'').
---------------------------------------------------------------------------
Operators must prepare their public communication plans before a
gas pipeline emergency develops to ensure that the proper tools and
resources are available to assist limited English proficiency (LEP)
individuals in the communities they serve when an emergency arises.
PHMSA notes that, as required under Sec. 192.616(g), operators must
conduct their public awareness program in other languages commonly
understood by a significant number and
[[Page 61775]]
concentration of the non-English speaking population in the operator's
area. Therefore, operators should already be aware of the languages
used in their service areas and have this information readily
available. If operators do not already have this information, data from
the U.S. Census Bureau American Community Survey at the tract level--
including summarized information on English proficiency along with
mapping of critical infrastructure and locations of hospitals, long-
term care facilities, police, and fire stations--can help provide more
targeted and community-specific services.\122\ Operators can use this
information to understand the demographics of their communities and
build lists of common media sources for each language population in
their service area. More information on how to reach LEP communities in
emergency preparedness, response, and recovery is available through the
Department of Justice.\123\ Where appropriate, operators'
communications during pipeline emergencies should account for
disabilities that might make communication difficult by, for example,
having American Sign Language interpreters present during press
conferences to ensure that hearing-impaired residents can receive
communications during a pipeline emergency.
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\122\ Ltd. English Proficiency, ``Data and Language Maps,'' U.S.
DOJ, https://www.lep.gov/maps (last visited Feb. 27, 2023).
\123\ U.S. DOJ, ``Tips and Tools for Reaching Limited English
Proficiency in Emergency Preparedness, Response, and Recovery,''
(2016), https://www.justice.gov/crt/file/885391/download.
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3. Emergency Response Plans--Opt-in System for Customers
a. Current Requirements--Emergency Response Plans--Customers
As previously discussed, there are currently no Federal regulations
in place that would require gas distribution operators to establish
communications with customers throughout a gas pipeline emergency.
There are also no current Federal requirements in place requiring these
operators establish procedures for developing and implementing an opt-
in communication system whereby customers in their service area can
receive updates of pipeline emergencies on their cell phones or other
media.
b. Need for Change--Emergency Response Plans--Customers
As the incident unfolded and local leaders made decisions to ensure
the safety of citizens, each community sent their own evacuation
notifications targeting their residents by using 9-1-1 call location
data to estimate the locations of the affected services. Local
officials used this data to reach a consensus about which areas to
evacuate because they were unable to use more accurate data from CMA
regarding the number and location of impacted customers.\124\
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\124\ Merrimack Valley After Action Report at 46.
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Andover and North Andover used their existing emergency
notification systems to notify residents to evacuate. Authorities in
North Andover issued a voluntary evacuation for all occupied structures
with natural gas utility service, using local cable channels, the town
website, and a citizen alert telephone system that sends public service
messages. The alert system automatically called every landline.
However, cell phones and private numbers had to be registered to
receive a call. The Andover fire chief called for an evacuation using a
citizen alert telephone system and social media. The wireless emergency
alerts to evacuate South Lawrence, and later to return home, were sent
out in both English and Spanish. The South Lawrence mayor's evacuation
order was issued as an alert over cell phones and media broadcasts to
residents in the area. In total, more than 50,000 residents were asked
to evacuate through a variety of methods.
While many municipalities have communication systems to rapidly
communicate with their constituents during an emergency, not all gas
distribution operators are using these tools to rapidly communicate
with their customers during a gas pipeline emergency. PHMSA believes
that operators could use these tools to provide customers with real-
time information during an emergency to protect public safety. The
Merrimack Valley incident underscored the need for operators to improve
their communication with customers when responding to an emergency on a
gas distribution pipeline. Subsequently, 49 U.S.C. 60102 was amended to
include a new mandate to expand the use of voluntary, opt-in customer
notifications during an emergency. Specifically, PHMSA was directed to
update its regulations to ensure that each emergency response plan
developed by an operator of a gas distribution system includes written
procedures for ``the development and implementation of a voluntary,
opt-in system that would allow operators of distribution systems to
rapidly communicate with customers in the event of an emergency.'' (49
U.S.C. 60102(r)(3)). PHMSA understands that a ``system'' to ``rapidly
communicate with customers'' could take many forms; however, in
practice, it is typically a ``reverse 9-1-1'' system that calls or
texts individual customers to notify them of significant, time-
sensitive events. Many cities and utilities already use such systems to
allow emergency officials to notify residents and businesses of
emergencies or outages by telephone, cell phone, text message, or
email.
c. Proposal To Amend Sec. 192.615--Emergency Response Plans--Customers
Pursuant to 49 U.S.C. 60102(r)(3), PHMSA proposes to add to Sec.
192.615 a new paragraph (d) that would require operators of gas
distribution pipelines to establish procedures for developing and
implementing a voluntary, opt-in customer notification system to
communicate with customers in the event of a gas pipeline emergency.
PHMSA understands the statutory mandate for a ``voluntary, opt-in
system'' to mean that the gas pipeline operators give the customers
they serve the opportunity to opt-in (or opt-out) to receiving
notifications from the operator's communication system, therefore
making the system voluntary for customers. Gas distribution operators
must notify all customers of the existence of such a communications
tool and their ability to elect to receive such emergency
notifications.
PHMSA does not expect that a voluntary, opt-in emergency
notification system would impose a significant burden on operators.
PHMSA notes that operators will often already have from their billing
activities much of the information (customer phone numbers, email and
postal addresses, and preferred language) needed to implement such a
system. And because an iteration of a voluntary, opt-in or opt-out
emergency notification systems may already be in place in some local
communities,\125\ PHMSA concludes that operators could comply with this
proposed requirement by coordinating with cities and townships to
utilize those existing systems. Where coordination with an existing
communication system is not possible, operators may choose to utilize a
third-party vendor or build such a service in-house. Regardless of who
administers the notification system proposed in Sec. 192.615(d),
operators would need to provide a basic description of the system and
describe the operation of the system in their procedures. Operators
[[Page 61776]]
must also include in their procedures a description of the protocols
for activating the system and notifying customers (i.e., who initiates
the notification and when). PHMSA notes that such a voluntary opt-in or
opt-out system could have additional benefits outside of gas pipeline
emergencies, as operators could use such a system to communicate with
their customers during non-emergencies (such as service outages or
planned maintenance) or for billing purposes.
---------------------------------------------------------------------------
\125\ PHMSA further understands that some utilities (e.g.,
electric utilities) may have similar notification systems for their
customers and the public within their service areas.
---------------------------------------------------------------------------
Because periodic testing is essential for ensuring proper operation
of such an emergency customer notification system, PHMSA includes
within its proposed Sec. 192.615(d) that operators' procedures must
describe system testing protocols and (at least) annual testing.
Operators would need to maintain the results of their testing and
operations history for at least 5 years. If an operator does not
control the testing protocol (e.g., because they rely on an emergency
notification system administered by a local government), they should
describe in their procedures the frequency of testing performed by
partnered municipality and arrange to receive confirmation of those
tests after they occur.
Similar to the requirements discussed earlier for public
communications during and following gas pipeline emergencies, PHMSA is
also proposing that an operator's written procedures for this opt-in
notification system include a description of how the system's messages
will be accessible to English-speaking and LEP customers alike.
Operators should describe the process for identifying any LEP or other
pertinent demographic information for the areas they serve. These
procedures should include a description of any non-English languages
required in standardized emergency communications that would be
provided in an operator's system. Because there may be LEP individuals
who need to receive these messages, operators should be prepared to
translate messages about public safety into the required non-English
language(s).
PHMSA also proposes to require operators' procedures include
cybersecurity measures to protect the notification system and customer
information. As with any system that interfaces with operators'
information technology assets or customers private information,
operators should protect against cybersecurity vulnerabilities and
insider threats. Operators should, for example, include protocols aimed
at protecting their infrastructure from malicious attacks, false
notifications being sent to customers, and theft of customers'
information. If the communication system is operated by a third party,
operators should document the cybersecurity measures managed by the
vendor.\126\
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\126\ As discussed in Section I.A. of the preamble, the BIL
provides funding for the Natural Gas Distribution Infrastructure
Safety and Modernization Grant Program. Each applicant selected for
grant funding under this notice must demonstrate, prior to the
signing of the grant agreement, effort to consider and address
physical and cyber security risks relevant to their natural gas
distribution system and the type and scale of the project. Projects
that have not appropriately considered and addressed physical and
cyber security and resilience in their planning, design, and project
oversight, as determined by the Department of Transportation and the
Department of Homeland Security, will be required to do so before
receiving funds for construction, consistent with Presidential
Policy Directive 21--Critical Infrastructure Security and Resilience
and the National Security Presidential Memorandum on Improving
Cybersecurity for Critical Infrastructure Control Systems.
---------------------------------------------------------------------------
PHMSA proposes that operators of gas distribution systems must
implement such a voluntary, opt-in notification system in accordance
with their procedures (i.e., ensure that the system is ready for use
during a gas pipeline emergency) no later than 18 months after the
publication of the final rule.\127\ PHMSA proposes that 18 months after
the publication of the final rule in this proceeding is a reasonable
timeframe to implement these new procedures and seeks comment on this
conclusion.
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\127\ While 49 U.S.C. 60109(e)(7)(C)(i)(II) directs gas
distribution operators to make their updated emergency response
procedures available to PHMSA or the relevant State regulatory
agency no later than 2 years after issuing a final rule, it does not
specify a deadline for operators to have implemented their customer
notification systems.
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4. Emergency Response--Incident Command Systems
a. Background
Communication during a pipeline emergency is complex and includes
communication between the pipeline operator, other pipeline companies,
non-pipeline utilities, emergency responders, elected officials, PSAPs,
and the public. Effective communication between and within each of
these entities is crucial to the successful response to a gas pipeline
emergency. For this reason, some gas distribution pipeline operators
and other utilities use an Incident Command System (ICS) to coordinate
emergency response actions.
An ICS is a standardized approach to the command, control, and
coordination of on-scene management of emergencies and other incidents,
providing a common hierarchy within which personnel from multiple
organizations can be effective.\128\ An ICS is the combination of
procedures, personnel, facilities, equipment, and communications
operating within a common organizational structure, designed to aid in
the management of on-scene resources. It can be applied to incidents
(including emergencies and planned events alike) of any size.
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\128\ FEMA, ``Glossary of Related Terms, E/L/G 0300 Intermediate
Incident Command System for Expanding Incidents, ICS 300'' at 6
(Mar. 2018), https://training.fema.gov/emiweb/is/icsresource/assets/glossary%20of%20related%20terms.pdf.
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The National Incident Management System (NIMS), a system commonly
used in the public and private sectors of incident management, uses ICS
principles. As stated in the American Gas Association's (AGA) Emergency
Preparedness Handbook, ``[u]tilities across our nation are increasingly
integrating [NIMS] into their planning and incident management
structure.'' \129\ Additionally, API in API RP 1174 recommends the use
of NIMS for responding to accidents on hazardous liquid pipelines.\130\
FEMA has also indirectly recommended the use of NIMS through its
recommendation of National Fire Protection Association (NFPA) Standard
1600 for emergency preparedness, a standard which recommends the use of
NIMS.\131\
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\129\ AGA, ``Emergency Preparedness Handbook for Natural Gas
Utilities'' at 10, https://www.aga.org/wp-content/uploads/2022/12/aga-emergency-preparedness-handbook-2018.pdf.
\130\ API Recommended Practice 1174, ``Recommended Practice for
Onshore Hazardous Liquid Pipeline Emergency Preparedness and
Response'' at 26 (1st ed. Dec. 2015).
\131\ NFPA, ``NFPA 1600: Standard on Continuity, Emergency, and
Crisis Management'' (2019); FEMA, ``Fact Sheet: NIMS Recommended
Standards'' (Jan. 4, 2007), https://www.fema.gov/pdf/emergency/nims/fs_standards_010407.pdf.
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Typically, local authorities handle most incidents using the
communications systems, dispatch centers, and incident personnel within
their jurisdiction. For larger and more complex incidents, however,
response efforts may rapidly expand to multi-jurisdictional or multi-
disciplinary efforts requiring outside resources and support.
Widespread use of ICSs could allow the efficient integration of outside
resources and enable personnel from anywhere in the Nation to
participate in the incident-management structure. Regardless of the
size, complexity, or scope of the incident, the use of an ICS could
benefit pipeline operators.
PHMSA is considering an ICS-based system in this rulemaking to
provide safety benefits. However, PHMSA has preliminarily determined
further input from the public would be beneficial in assessing the
feasibility of doing so, as well as the best practices that would
[[Page 61777]]
inform such a regulatory standard. Specifically, PHMSA is considering
requirements under Sec. 192.615 for operators of gas distribution
pipelines to follow ICS procedures in response to gas pipeline
emergencies. For example, PHMSA could require that operators of gas
distribution pipelines develop written procedures in accordance with
ICS tools and practices. An example of an ICS practice would be to
identify the roles and responsibilities of emergency responders and
communicate those responsibilities to designated personnel, which would
be similar to the current requirements in Sec. 192.615(c). PHMSA
recognizes the benefit of pipeline operators using ICS for gas pipeline
emergencies, as such an approach can help hone and maintain skills
needed to coordinate response efforts effectively, even as poor
implementation of an ICS may hinder effectiveness. For example, in the
Merrimack Valley incident, both the operator and emergency responders
had an ICS in their respective emergency response manuals; however, the
ICS procedures were implemented with mixed results. While State and
local emergency responders were able to effectively manage, organize,
and coordinate the activities of multiple agencies serving in the
emergency response by following the ICS, the NTSB concluded that CMA's
Incident Commander (IC) struggled to manage the multiple competing
priorities, such as communicating with affected municipalities,
updating emergency responders, and shutting down the natural gas
distribution system, which adversely affected the IC's ability to
complete tasks in a timely manner.\132\ The Merrimack Valley incident
underscores that effective execution of an ICS is still dependent upon
each operator's ability to implement the practices during a crisis.
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\132\ NTSB/PAR-19/02 at 45-47, 48-49.
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PHMSA is also considering, if it determines to adopt requirements
for operators of gas distribution pipelines to follow ICS procedures in
response to gas pipeline emergencies, requiring operators to train
personnel on ICS tools and practices. PHMSA expects that to develop an
ICS for a response to gas pipeline emergencies, operator personnel
would need to undergo extensive training and coordination exercises
with first responders, and local and State public safety officials.
FEMA provides free resources for implementing and training on ICS on
their website.\133\ Because this training is free, PHMSA expects there
should be no upfront costs to provide training, however, there would be
a burden in terms of time for operators to (1) take these trainings and
(2) incorporate ICS tools and practices into their training and
emergency response procedures. Further, the ICS tools and guidance are
designed to be integrated into an organization's existing
infrastructure, so PHMSA would not expect operators to have to hire
additional personnel to meet a new requirement in its regulations for
an ICS. PHMSA seeks comment on these assumptions.
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\133\ FEMA, ``National Incident Management System'' (May 24,
2022), https://www.fema.gov/emergency-managers/nims.
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b. Request for Input on the Adoption of ICS Requirements in PHMSA
Regulations
PHMSA is seeking public comments regarding the potential adoption
within the pipeline safety regulations of a requirement at Sec.
192.615 that each operator employ an ICS for gas pipeline emergencies
to include the following topics that could inform the specifics of any
such requirement:
1. Should PHMSA promulgate new regulations requiring ICS for all
gas distribution systems? Any other pipeline facilities?
2. If PHMSA were to adopt ICS requirements, should there be any
exceptions from the ICS requirements?
3. Should PHMSA develop a standard for ICS or incorporate by
reference an existing industry-based standard for ICS?
4. What are current sources of ICS training?
5. How long does it take, or would it take, for operators to train
an employee on ICS tools and practices?
6. How often should qualified employees receive periodic training
on ICS tools and practices?
7. What is an appropriate timeline for operators to incorporate ICS
practices into their procedures if PHMSA were to promulgate an ICS
standard?
PHMSA requests that commenters provide specific proposals for what
provisions should be adopted or changes that should be made to the
regulations related to the questions listed above.
In addition to the questions above, PHMSA requests commenters to
provide information and supporting data related to:
1. The number of gas distribution operators that have currently
adopted an ICS in their emergency procedures.
2. The technical feasibility, cost-effectiveness, and
practicability of implementing any requirement for operators to adopt
ICS.
3. The potential quantifiable safety and societal benefits of
adopting ICS.
4. The potential impacts on small businesses adopting ICS.
5. The potential environmental impacts of adopting ICS.
D. Operations and Maintenance Manuals (Section 192.605)--
Overpressurization
1. Current Requirements--O&M Manuals--Overpressurization
Section 192.605 includes minimum requirements for gas pipeline
operators' procedural manuals for operations, maintenance, and
emergencies. Section 192.605(a) requires gas pipeline operators to have
``a manual of written procedures for conducting operations and
maintenance activities and for emergency response,'' otherwise known as
an O&M manual. Operators must review and update this manual at
intervals that do not exceed 15 months and at least once each calendar
year. Appropriate parts of the manual must be kept where operations and
maintenance activities take place.
Section 192.605(b) lists various procedures that each gas pipeline
operator must include in the manual to provide safety during operation
and maintenance. Among other requirements, Sec. 192.605(b)(5) requires
that the O&M manual include a procedure for ``[s]tarting up and
shutting down any part of the pipeline in a manner designed to assure
operation within the MAOP limits prescribed in this part, plus the
build-up allowed for operation of pressure-limiting and control
devices'' in order ``to provide safety during maintenance and
operations.''
Subpart L also requires an operator to ``keep records necessary to
administer the procedures established under Sec. 192.605.'' \134\
Among the records required to be kept and made available to operating
personnel are ``construction records, maps and operating history,'' per
Sec. 192.605(b)(3). Sections 192.605(d)-(e) require an O&M manual to
include procedures for both reporting safety-related conditions and for
surveillance, emergency response, and accident investigations,
respectively.
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\134\ 49 CFR 192.603(b).
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2. Need for Change--O&M Manuals--Overpressurization
Clearly written procedures aid in the successful execution of tasks
and processes necessary to ensure a gas distribution pipeline system is
operated and maintained in a safe manner. Overpressurizations, while
rare, can cause a pipeline failure if not addressed in a timely manner.
Including measures
[[Page 61778]]
in O&M manuals to respond to indications of an overpressurization can
help ensure a timely, effective response.
As demonstrated by the Merrimack Valley incident, operators of gas
distribution pipelines must be prepared to recognize and respond to
overpressurization indications, as these events can have significant
consequences for public safety and the environment. PHMSA regulations
have a requirement in Sec. 192.605(b)(5) for operators to have
procedures for ``starting up and shutting down any part of the pipeline
in a manner designed to assure operation within the MAOP limits
prescribed by this part, plus the build-up allowed for operation of
pressure-limiting and control devices.'' To further reduce the
likelihood of future incidents like the 2018 Merrimack Valley incident,
however, PHMSA proposes to amend Sec. 192.605 to ensure that operators
explicitly account for overpressurization in their O&M procedures.
Subsequent to the 2018 Merrimack Valley incident, 49 U.S.C. 60102
was amended to require PHMSA to undertake a new rulemaking that would
require operators of gas distribution systems to update their
operations, maintenance, and emergency plans to include procedures for
specific actions to be taken on receipt of an indication of an
overpressurization on their systems. Those actions include an order of
operations for immediately reducing pressure in, or shutting down
portions of, the gas distribution system, if necessary. (49 U.S.C.
60102(s)). Amendments to 49 U.S.C. 60108 require gas distribution
operators to make their updated O&M manuals available to PHMSA or the
relevant State regulatory agency within 2 years after any final rule is
issued and every 5 years thereafter.
3. Proposal To Amend Sec. 192.605--O&M Manuals--Overpressurization
In this NPRM, PHMSA proposes to amend Sec. 192.605 to require that
operators of gas distribution pipelines establish procedures for
responding to, investigating, and correcting the cause of
overpressurization indications as soon as practicable. This will
include specific actions to take and an order of operations for
immediately reducing pressure in portions of the gas distribution
system affected by the overpressurization, shutting down that portion,
or taking other actions as necessary.
A timely response to an overpressurization event will require
operators to promptly recognize overpressurization indications.
Operator procedures would need to document potential overpressurization
indications based on the design and operating characteristics of their
systems. For example, a common indication of an overpressure condition
would be an increase in pressure or flow rate outside of normal
operating limits--but precisely how much a pressure change outside
normal conditions would exceed MAOP will depend on the characteristics
of that system.
PHMSA also proposes to require that an operator's procedures must
document specific actions and the sequence of events various personnel
must follow in response to an overpressurization indication. Those
procedures should contain clear statements of authority for relevant
operator personnel to undertake particular actions both on initial
receipt of notification of an overpressurization indication and
subsequent confirmation that an overpressurization condition exists or
is imminent.\135\ An example would include the actions a controller in
the monitoring center (i.e., SCADA system) would take and the protocols
to follow when in receipt of a pressure alarm indicating an
overpressurization. Similarly, field personnel may witness
overpressurization indications such as fires, explosions, control lines
damage during excavation, instrumentation or valve failures, or the
activation of safety valves. Operators must develop procedures for
those personnel to recognize the signs of an overpressurization as well
as identify the steps they should take in response (such as applying a
stop-work authority, reducing the pressure, isolating portions of the
gas distribution system, and notifying emergency responders). The
operator must also provide training on these procedures to ensure that
personnel--including field personnel and construction workers--are able
to recognize the indications of an overpressurization and respond
appropriately.\136\
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\135\ Although PHMSA expects that among the immediate actions
that operators will take in response to an overpressurization
indication would be confirming as soon as practicable whether an
overpressurization exists or is imminent, operators may not delay
other immediate actions necessary to protect hazards to public
safety and the environment while they obtain such confirmation.
\136\ PHMSA also notes that pipeline employees and contractors
who raise concerns that a pipeline operator is not complying with
pertinent PHMSA safety requirements or the pipeline's implementing
procedures may have statutory whistleblower protections pursuant to
49 U.S.C. 60129. Pipeline employees and contractors who are
concerned that they have been retaliated against for raising safety
concerns should be raised with Department of Labor (via the
Occupational Health and Safety Administration). See OHSA, ``Fact
Sheet: Whistleblower Protection for Pipeline Facility Workers,''
(Feb. 2022), https://www.osha.gov/sites/default/files/publications/OSHA4072.pdf.
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Operators must also develop and document procedures for, as soon as
practicable, investigating and correcting the cause of an
overpressurization or an overpressurization indication. While the
amendments proposed throughout this NPRM, if adopted, are expected to
prevent or reduce the frequency of future overpressurizations, they may
still occur. If an operator experiences an overpressurization or any
indication that an overpressurization could occur, PHMSA proposes to
require operators to investigate and correct the cause(s) of the
overpressurization or overpressurization indication. During their
investigation, operators could find a mode of failure common to other
parts of their systems and take action to prevent or mitigate a
potential overpressurization, such as promptly repairing or replacing
parts of the system.
PHMSA proposes the requirements described above to ensure operators
have clear direction as to what procedures are necessary to prevent
catastrophic overpressurizations similar to that of the Merrimack
Valley incident and to improve the safety of gas distribution systems
generally. PHMSA also expects this proposed amendment of subpart L
requiring distribution operators to update O&M manuals to address
overpressure scenarios would reinforce the updates to DIMP plans
proposed elsewhere in this NPRM. PHMSA expects that this amendment
would improve pipeline safety by bringing additional awareness to gas
distribution pipeline operators and personnel regarding
overpressurization indications. This amendment would also ensure
operators establish procedures for monitoring and controlling gas
pressure should they detect an indication of an overpressurization.
PHMSA further proposes to respond to the risk of overpressurization in
an operator's O&M manuals through adopting an MOC process, as discussed
below.
PHMSA understands these proposed requirements for enhancements of
gas distribution operators' O&M manuals to address a well-understood
threat to pipeline integrity would be reasonable, technically feasible,
cost-effective, and practicable for gas distribution operators. PHMSA
expects that some gas distribution operators may already be complying
with these requirements either voluntarily (e.g., in response to the
Merrimack Valley incident), as a result of similar requirements imposed
[[Page 61779]]
by State pipeline safety regulators, or pursuant to their DIMPs. PHMSA
further notes that its proposed enhancements of baseline expectations
for O&M manual contents are precisely the sort of minimal actions a
reasonably prudent operator of gas distribution pipeline facility would
adopt in ordinary course to protect public safety given that their
systems transport pressurized (natural, flammable, toxic, or corrosive)
gasses typically within or in close proximity to population centers.
Viewed against those considerations and the compliance costs estimated
in the PRIA, PHMSA expects its proposed amendments will be a cost-
effective approach to achieving the public safety and environmental
benefits discussed in this NPRM and its supporting documents. Lastly,
PHMSA understands that its proposed compliance timeline--one year after
publication of a final rule (which would necessarily be in addition to
the time since publication of this NPRM)--would provide operators ample
time to implement requisite changes to their O&M manuals (and manage
any related compliance costs).
E. Operations and Maintenance Manuals (Section 192.605)--Management of
Change
1. Current Requirements--O&M Manuals--Management of Change (MOC)
There are no current requirements in the pipeline safety
regulations for operators of gas distribution pipelines to follow
management of change (or MOC) processes in their operations and
maintenance activity. While not specifically an MOC process, the
operator qualification provisions in Sec. 192.805(f) require that
changes that affect covered tasks be communicated to individuals
performing these tasks. As such, operators may have in place some type
of process for reviewing changes, including whether such changes will
impact O&M procedures and those performing the procedures. Further, gas
transmission pipelines located in a high consequence area have an MOC
requirement in Sec. 192.911(k), which adopts an MOC process outlined
in the American Society of Mechanical Engineers/American National
Standards Institute (ASME/ANSI) standard B31.8S, section 11.\137\ The
192.911(k) requirement, however, applies only to operators of gas
transmission pipelines subject to subpart O integrity management
requirements (i.e., high-consequence areas, which are not applicable to
gas distribution pipelines).
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\137\ Am. Soc'y of Mech. Eng's, ANSI B31.8S-2004, ``Managing
System Integrity of Gas Pipelines'' (Jan. 14, 2005).
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2. Need for Change--O&M Manuals--MOC
Inadequately reviewed or documented design, construction,
maintenance, or operational changes can seriously impact pipeline
integrity. MOC procedures are designed to prevent such impacts. In the
Merrimack Valley incident, NTSB investigators discovered omissions in
CMA's engineering work package and construction documentation for the
South Union Street project and that the work package was completed
without a proper constructability review. NTSB investigators reviewed
the engineering plans that CMA used during the construction work and
found that the CMA engineers did not document the location of regulator
control lines.\138\ Had CMA accurately documented the regulator control
lines, engineers and work crews would have been able to relocate them
prior to abandoning the pipeline main.
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\138\ NTSB/PAR-19/02 at 16.
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CMA did not employ MOC processes for its maintenance and
construction operations. Instead, CMA's engineering department relied
on simple checklists in its workflow documentation. The NTSB determined
that if NiSource had adequately employed a MOC process, it could have
identified potential risk of overpressurization of its system from a
common mode of failure as a result of the South Union Street project
construction activity and employed control measures to prevent or
mitigate the Merrimack Valley incident. As a result, the NTSB
recommended in P-18-8 that NiSource apply an MOC process to all changes
to adequately identify system threats that could result in a common
mode of failure.\139\
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\139\ NTSB/PAR-19/02 at 51.
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NTSB also stated that CMA did not identify the omission of
regulator control lines from its engineering work package during its
constructability review of that documentation. Constructability
reviews--an element of MOC processes--are recognized and accepted as a
necessary engineering practice for the execution of construction
services. If properly implemented, constructability reviews provide
structured reviews of construction plans and specifications to ensure
functionality, sustainability, and safety, thus reducing the potential
for shortcomings, omissions, inefficiencies, conflicts, or errors. The
NTSB concluded that the CMA constructability review process was not
sufficiently robust to detect the omission of a work order to relocate
the sensing lines. The NTSB identified that part of the failure of the
process was likely due to the absence of a review by a critical
department (CMA's measurement and regulation or M&R department).
Despite there being at least two constructability reviews for the South
Union Street project, the M&R department did not participate. The NTSB
stated that a comprehensive constructability review, which would
require all pertinent departments to review each project, along with
the endorsement by a professional engineer (PE), would likely have
identified the omission of the regulator control lines, thereby
preventing the error that led to the Merrimack Valley incident. As a
result of its investigation, the NTSB recommended that NiSource revise
its constructability review process to ensure that all pertinent
departments review construction documents for accuracy and
completeness, and that the documents or plans be endorsed by a PE prior
to commencing work.
Subsequent to the 2018 Merrimack Valley incident, PHMSA was
required by statute to update its regulations to require gas
distribution operators to include in their O&M manuals an MOC process
which must apply to ``significant technology, equipment, procedural,
and organizational changes to the distribution system[.]'' (49 U.S.C.
60102(s)(2)). This provision also requires that operators ``ensure that
relevant qualified personnel, such as an engineer with a professional
engineer licensure, subject matter expert, or other employee who
possesses the necessary knowledge, experience, and skills regarding
natural gas distribution systems, review and certify construction plans
for accuracy, completeness, and correctness.'' In addition, 49 U.S.C.
60108 requires gas distribution operators to make their updated O&M
manuals available to PHMSA or the relevant State regulatory agency
within 2 years after the final rule is issued in this proceeding and
every 5 years thereafter.
3. Proposal To Amend Sec. 192.605 To Require an MOC Process
Pursuant to 49 U.S.C. 60102(s), PHMSA proposes to require that gas
distribution operators update their O&M manuals to include a detailed
MOC process.\140\ Under this proposal,
[[Page 61780]]
operators would be required to apply an MOC process to technology,
equipment, procedural, and organizational changes that may impact the
integrity or safety of the gas distribution system. Specifically,
operators must apply an MOC process to changes to their pipeline
systems, organization, and O&M procedures in connection with the (1)
installation, modification, or replacement of, or upgrades to,
regulators, pressure monitoring locations, or overpressure protection
devices; (2) modifications to alarm set points or upper/lower trigger
limits on monitoring equipment; (3) introduction of new technologies
for overpressure protection into the system; (4) revisions, changes to,
or introduction of new standard operating procedures for design,
construction, installation, maintenance, and emergency response; and
(5) other changes that may impact the integrity or safety of the gas
distribution system. PHMSA notes that although most of the occasions
for changes to operator pipelines and procedures listed above are
directed toward reducing the potential for overpressurization, it
expects that MOC processes will also help reduce the risk of other
incidents on gas distribution pipelines. Towards that end, PHMSA
proposes savings language (``other changes that may impact the
integrity or safety of the gas distribution systems'') that would
require operators to employ a MOC process in connection with changes to
their systems and procedures in connection with high-risk activities.
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\140\ PHMSA has not included its proposed MOC requirements for
distribution pipeline operators within integrity management
regulations at 49 CFR part 192, subpart P (as it did for gas
transmission pipelines within subpart O) because 49 U.S.C. 60102(s)
explicitly required update of regulations governing ``procedural
manuals for operations, maintenance, and emergencies''--located at
Sec. 192.605.
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PHMSA also proposes to require that the MOC process must ensure
that qualified personnel review and certify construction plans
associated with installations, modifications, replacements, or upgrades
for accuracy and completeness before the work begins. These personnel
must be qualified to perform these tasks under subpart N of 49 CFR part
192.\141\ Qualified personnel could include an engineer with a
professional engineer (PE) license, a subject matter expert, or any
other employee who possesses the necessary knowledge, experience, and
skills regarding gas distribution systems. This proposal would ensure
that personnel who work on planning construction projects have the
appropriate qualifications and training necessary to ensure these tasks
are performed safely.
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\141\ ``Qualified'' under Sec. 192.803 means that an individual
has been evaluated pursuant to the requirements of Subpart N and can
perform assigned covered tasks and recognize and react to abnormal
operating conditions.
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In developing this proposed requirement, PHMSA reviewed NTSB
recommendation P-19-16, which called on states to require that all
future gas infrastructure projects require licensed PE approval and
stamping.\142\ This NPRM in no way prohibits states from applying a
higher standard than that provided in the Federal regulations.
Additionally, PHMSA acknowledges that a PE could provide the best
assurance of high-quality review of construction plans. PHMSA is
uncertain as to the availability of those personnel resources in all
states or for all gas distribution operators, however, and any shortage
of licensed PEs could cause delays in the construction or remediation
of integrity issues. Other qualified professionals, such as experienced
engineers or subject matter experts, may have an equivalent level of
experience or skills without holding the licensure. PHMSA is proposing
this amendment pursuant to 49 U.S.C. 60102(s), which contemplates a
larger pool of personnel qualified to perform these reviews and
certifications than just licensed PEs. Nevertheless, PHMSA expects that
when operators evaluate construction projects, operators consider
assigning qualified personnel with experience commensurate to the
complexity of each project and its potential impacts on public safety
and the environment. The most complex and riskiest projects should be
reviewed by a licensed PE, if available, while less complex or routine
construction projects may be suitable for review by qualified personnel
who do not hold such a credential. PHMSA welcomes comments on the
availability of PE licensure in various jurisdictions and the
appropriateness of review by other, non-licensed qualified individuals.
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\142\ NTSB/PAR-19/02 at 50.
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Finally, PHMSA proposes to require that operators' MOC process must
ensure that any hazards introduced by a change are identified,
analyzed, and controlled before resuming operations. Quality originates
at the planning stages of a pipeline project. When pipeline facilities
are designed or modified, operators intend for these changes to provide
decades of safe and reliable operation. But any change to a pipeline
system can also introduce potential hazards. Operators can manage risks
introduced by changes to the system through a robust MOC process. It is
a standard practice in any MOC process or system to analyze and control
for risks. PHMSA is proposing this general requirement for operators to
identify any hazards they are introducing as the result of a change, to
analyze those risks, and to control for those hazards and risks through
preventive and mitigative measures. These steps are necessary to
establish appropriate preventive and mitigative measures to reduce the
likelihood and consequences of failure on a gas distribution system
should an accident occur. PHMSA, therefore, proposes this requirement
to ensure that operators incorporate these steps into their MOC
process.
PHMSA understands this proposed requirement for gas distribution
operators' O&M manuals to incorporate a MOC process would be
reasonable, technically feasible cost-effective, and practicable. PHMSA
expects that some gas distribution operators may already comply with
these requirements either voluntarily (e.g., to minimize losses of
commercially valuable commodities, in response to the Merrimack Valley
incident and NTSB recommendations, or consistent with broadly
applicable, consensus industry standards such as ASME/ANSI B31.8S
\143\), as a result of similar requirements imposed by State pipeline
safety regulators, or as risk mitigation measures pursuant to their
DIMPs. PHMSA further notes that the proposed construction plans
certification requirement within those MOC procedures is consistent
with longstanding industry best practices and NTSB recommendations;
PHMSA's proposal also affords operators optionality to use either their
own or contractor personnel when implementing this requirement on a
going-forward basis. Indeed, PHMSA submits that its proposed
enhancements of baseline expectations for O&M manual contents are
precisely the sort of minimal actions a reasonably prudent operator of
gas distribution pipeline facility would adopt in ordinary course to
protect public safety given that their systems transport pressurized
(natural, flammable, toxic, or corrosive) gasses typically within or in
close proximity to population centers. Viewed against those
considerations and the compliance costs estimated in the PRIA, PHMSA
expects its proposed amendments will be a cost-effective approach to
achieving the commercial, public safety, and environmental benefits
discussed in this NPRM and its supporting documents. Lastly, PHMSA
understands that its proposed compliance timeline--one year after
publication of a final rule (which would
[[Page 61781]]
necessarily be in addition to the time since publication of this
NPRM)--would provide operators ample time to implement requisite
changes to their O&M manuals and identify or procure personnel
resources needed to comply with the new certification requirement (and
manage any related compliance costs).
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\143\ ASME/ANSI, B31.8S-2004, ``Managing System Integrity of Gas
Pipelines, Supplement to B31.8'' (Jan. 14, 2005) (incorporated by
reference under Sec. 192.7).
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PHMSA is also requesting comments on whether it should promulgate
the MOC requirement described above, adopt the industry standard ASME/
ANSI B31.8S for gas distribution operators, or both.\144\ PHMSA has
adopted ASME/ANSI B31.8S for gas transmission operators subject to 49
CFR, part 192, subpart O integrity management requirements.
Specifically, PHMSA at Sec. 192.911(k) requires operators of certain
gas transmission pipelines to develop and follow an MOC process, as
outlined in ASME/ANSI B31.8S, section 11, that addresses technical,
design, physical, environmental, procedural, operational, maintenance,
and organizational changes to the pipeline or processes, whether
permanent or temporary. While provisions in section 11 of ASME/ANSI
B31.8S outline formal elements of an MOC process resembling the
elements within the regulatory text proposed in this NPRM, other
provisions of ASME/ANSI B31.8S section 11, such as (b)(1), are specific
to changes in population that may be more appropriate for gas
transmission operators required to identify high consequence areas
(HCAs) along their pipeline. But the HCA concept does not apply to gas
distribution operators, and as noted above, PHMSA expects it can
capture the public safety and environmental benefits from MOC processes
by adopting the regulatory text proposed in this NPRM without
incorporating by reference ASME/ANSI B31.8S directly. Nevertheless,
PHMSA requests comments on whether adoption within a final rule of a
similar approach for gas distribution operators would provide better
protection for public safety and the environment, and otherwise be
technically feasible, cost-effective, and practicable.
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\144\ On January 15, 2021, PHMSA issued the NPRM, ``Periodic
Updates of Regulatory References to Technical Standards and
Miscellaneous Amendments,'' which included a proposal to replace the
incorporated by reference ASME/ANSI B31.8S 2004 edition to the 2016
edition. 86 FR 3938, 3944 (Jan. 15, 2021). PHMSA reviewed both 2004
and 2016 editions for consideration in this rulemaking.
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F. Gas Distribution Recordkeeping Practices (Section 192.638)
1. Current Requirements--Recordkeeping
Operators must collect and maintain records about their gas
distribution pipelines in compliance with requirements of 49 CFR part
192, including those governing DIMPs. Section 192.1007(a) requires
operators to identify reasonably available information necessary to
develop an understanding of the characteristics of their pipelines,
identify applicable threats, and analyze the risk associated with the
threats. Section 192.1007(a)(3) requires that operators have a plan to
collect information needed to conduct the risk analysis required in
DIMP. Section 192.1007(a)(5) requires operators to capture and retain
information on any new pipeline installed, including, at a minimum, the
location of the pipeline and the material of which it is constructed.
In addition to keeping records as part of complying with DIMP
requirements, an operator must also consider the data it needs to
comply with the various recordkeeping requirements in 49 CFR part 192,
such as those for pipeline design, testing and construction (Sec.
192.517); corrosion control (Sec. 192.491); customer notification
(Sec. 192.16); uprating (Sec. 192.553); surveying, patrolling,
monitoring, inspections, operations, maintenance, and emergencies
(Sec. Sec. 192.603 and 192.605); and operator qualification (Sec.
192.807). Sections 192.603(b) and 192.605 further require that each
operator establish a written operating and maintenance plan that meets
the requirements of the pipeline safety regulations and keep records
necessary to administer the plan. Sections 192.603(b) and 192.605(e)
require operators to maintain current records and maps of the location
of their facilities for use in operations, maintenance, and emergency
response activities (e.g., surveillance, leak surveys, cathodic
protection, etc.). Further, Sec. 192.605 requires that operators make
construction records, maps, and the pipeline's operating history
available to appropriate operating personnel. Therefore, if an operator
requires maps as a record to properly administer its O&M procedures
consistent with Federal safety requirements, these maps must be
maintained by the operator.
Additionally, operators must keep records related to the design and
installation of their pipeline components, including protection against
overpressurization under 49 CFR part 192, subparts L and M.\145\ These
records would include valve failure position and capacity records,
which include information operators used when designing the system to
ensure sufficient overpressure protection.
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\145\ See Sec. Sec. 192.603(b), 192.605(b)(1), and subpart M
(incorporating Sec. Sec. 192.199 and 192.201).
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2. Need for Change--Recordkeeping
Maintaining accurate and reliable records is critical for safe
operation, maintenance, pipeline integrity management, and emergency
response. Records of the physical components on a gas distribution
system, such as regulators, valves, and underground piping (including
control lines), are necessary for an operator to have the basic
knowledge of its system needed to maintain control of system pressure.
Mapping of all gas systems enables proper planning of system upgrade
activities, maintenance, and protection of the system from excavation
damage. Knowing the location of control lines is critically important
to preventing incidents on low-pressure distribution systems because
they can be easily damaged during excavation activities or
inadvertently taken out of service, as demonstrated by the Merrimack
Valley incident. Further, mapping of all gas systems, such as
documenting the location of shutoff valves, could improve the response
time during an emergency. In the event of an incident or other
emergency, being able to locate and operate valves is critical to
achieving the effective shutdown and isolation of any sections of a gas
distribution system. Incomplete, inaccurate, unreliable, or
inaccessible records hinder the safe operation of a pipeline, reduce
the effectiveness of the integrity assessment (as required under DIMP
regulations), and impede timely emergency response.
The 2018 Merrimack Valley incident illustrated how incomplete
records of gas distribution systems can lead to or exacerbate safety
issues. One of the issues identified in the NTSB's report was that the
engineers responsible for developing CMA's construction plan did not
have all the records necessary to plan the construction project
correctly, such as control line drawings and location information.
Further, the CMA engineers knew that even if they had access to the
records regarding the location of the control lines, the records CMA
maintained were often outdated, and thus potentially inaccurate and
incomplete.\146\ For example, for the Winthrop regulator station, the
records had the location of the control lines as
[[Page 61782]]
they existed around May 2010; however, CMA installed a new control line
around September 2015 and never updated its records to reflect the
change. Without access to accurate maps and drawings of the system, CMA
did not include control line maps or procedures for handling control
line removal in the construction plan. CMA then passed along an
inaccurate and incomplete construction plan to the contractor doing the
work. As a result, NTSB recommended that NiSource review and ensure
that all records and documentation of its natural gas systems are
traceable, reliable, and complete.
---------------------------------------------------------------------------
\146\ NTSB/PAR-19/02 at 16-17.
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The Merrimack Valley incident further illustrated how the lack of
accurate maps of pipeline systems can inhibit effective emergency
response. During the emergency response to the overpressurization, the
operator took too long to provide maps of the low-pressure system to
emergency response officials, who needed street maps showing the layout
of the natural gas distribution system to understand where the affected
customers were located. CMA did not provide the information requested
until hours after the overpressurization began. The emergency
responders emphasized to the NTSB that the absence of this information
impeded their emergency response and public safety decision-making.
Without maps of the low-pressure system, the ICs managing emergency
response had to evacuate thousands of people from their homes,
including people in unaffected areas, out of an abundance of caution.
Subsequent to the 2018 Merrimack Valley incident, 49 U.S.C. 60102
was amended to ensure that operators keep better, more complete records
(such as maps that include the location of control lines and other
critical infrastructure) and make those available to the emergency
responders and public officials who need them. Specifically, 49 U.S.C.
60102(t)(1) directs PHMSA to issue regulations that require
distribution pipeline operators to identify and manage ``traceable,
reliable, and complete'' maps and records of critical pressure-control
infrastructure, and update other records needed for risk analysis.
Operators must update their records ``on an opportunistic basis.''
These records must be accessible to all personnel responsible for
performing or overseeing relevant construction or engineering work.
Pursuant to 49 U.S.C. 60102(t)(1), PHMSA proposes to amend its
regulations to supplement existing requirements pertaining to gas
distribution operators' recordkeeping critical to pressure control on
their systems. The proposal would require operators to collect or
generate complete, reliable, and accurate records if they are not
available, and make the records accessible to the personnel who need
them.
3. Proposal To Add a New Sec. 192.638--Records: Distribution System
Pressure Controls
PHMSA proposes a new Sec. 192.638 to specify that an operator of a
gas distribution system must identify and maintain traceable,
verifiable, and complete records documenting the characteristics of the
pipeline critical to ensuring proper pressure controls.\147\
---------------------------------------------------------------------------
\147\ As discussed elsewhere in the preamble, PHMSA also
proposes to introduce a cross-reference to this new Sec. 192.638
within its existing DIMP plan knowledge management requirements at
Sec. 192.1007(a)(3).
---------------------------------------------------------------------------
In 2019, PHMSA introduced a regulatory amendment requiring gas
transmission records pertaining to MAOP to be ``traceable, verifiable,
and complete.'' \148\ 49 U.S.C. 60102(t)(1) similarly requires PHMSA to
require operators to identify and manage ``traceable, reliable, and
complete'' records. PHMSA understands that the phrase ``traceable,
reliable, and complete,'' as used in 49 U.S.C. 60102(t)(1) is
substantively the same standard with respect to the quality and
accessibility of records maintained as the ``traceable, verifiable, and
complete'' language adopted in the 2019 final rule for gas transmission
pipelines.\149\ PHMSA interprets ``reliable'' as used in 49 U.S.C.
60102(t)(1) to mean the same as ``verifiable'' as used in the 2019 rule
because both verifiable and reliable would mean to prove that a record
is trustworthy and authentic. A record is considered reliable if it is
verifiable and vice versa. PHMSA's proposed Sec. 192.638 recordkeeping
requirement is intended to encompass any records essential to pressure
control on a system and not just pertain to MAOP or material property
and attribute verification activities. PHMSA would require operators to
identify what records they currently have that document the
characteristics of the pipeline that are ``critical to ensuring proper
pressure controls'' for the system.
---------------------------------------------------------------------------
\148\ ``Pipeline Safety: Safety of Gas Transmission Pipelines:
MAOP Reconfirmation, Expansion of Assessment Requirements, and Other
Related Amendments,'' 84 FR 52180 (Oct. 1, 2019).
\149\ Compare 192.607 (requiring ``traceable, verifiable, and
complete records'' of certain material properties and attributes)
and 192.624 (requiring ``traceable, verifiable, and complete
records'' for MAOP confirmation) with 49 U.S.C. 60102(t) (requiring
gas distribution operators identify and manage ``traceable,
reliable, and complete records . . . critical to ensuring proper
pressure controls for a gas distribution system . . . .'').
---------------------------------------------------------------------------
In Sec. 192.638(a), PHMSA identifies the types of records that it
proposes are critical to ensuring proper pressure control for a gas
distribution system. These records include: (1) current location
information (including maps and schematics) for regulators, valves, and
underground piping (including control lines); (2) attributes of the
regulator(s), such as set points, design capacity, and the valve
failure position (open/closed); (3) the overpressure protection
configuration; and (4) other records deemed critical by the operator.
Regarding item (1), operators generally keep records, such as maps
and schematics, when designing their system and district regulator
stations. Operators should also have records of selected regulators,
valves, and other gas pressure control equipment based on several
factors, for the purpose of determining, for example, the overall
capacity and future flow requirements of the system.
Regarding item (2), records related to the attributes of the
regulators' set points, design capacity, and valve failure position are
necessary to ensure that the design of the district regulator station
can protect the distribution system from overpressurization. For
example, demands on the system may change over time due to customer
usage, weather, or maintenance requirements. Operators can use design
capacity records to validate and revalidate that their systems are
capable of meeting changing customer demands and weather dynamics.
Regarding item (3), maintaining records for the overpressure
protection configuration are necessary for the safe operation of the
pipeline and for performing a robust risk analysis required under DIMP
regulations. As demonstrated by the 2018 Merrimack Valley incident,
certain overpressure protection configurations on low-pressure
distribution systems (i.e., redundant worker-monitor regulators) alone
are inadequate for preventing an overpressurization. Requiring
operators to keep records of their systems' overpressure configurations
will ensure that operators will be able to identify any higher-risk
configurations in their systems. Once identified, operators can
properly assess the overall risk to their systems and take preventive
or mitigative actions to reduce the likelihood or consequences of a
potential failure.
Regarding item (4), PHMSA proposes that operators must have
traceable, verifiable, and complete records for any records they deem
critical but that were
[[Page 61783]]
not mentioned in the list provided by PHMSA. This general requirement
would ensure that operators keep records based on the unique
characteristics of their system.
When taking inventory of the records described above, operators
must identify if those records are traceable (e.g., can be clearly
linked to original information about, or changes to, a pipeline
segment, facility, or district regulator station), verifiable (e.g.,
their information is confirmed by other complementary but separate
documentation), and complete (e.g., as evidenced by a signature, date,
or other appropriate marking such as a corporate stamp or seal). This
amendment would improve the completeness and accuracy of the records
needed during normal operations, emergency response activities, and
risk analyses.
In Sec. 192.638(b), PHMSA proposes to require that if an operator
does not yet have traceable, verifiable, and complete records, then the
operator must develop a plan for collecting those records. PHMSA also
proposes to revise Sec. 192.605 to ensure that operators have
procedures for implementing the new recordkeeping requirements proposed
in Sec. 192.638. Because the availability and form of records, as well
as records retention practices, will vary among operators, PHMSA
proposes that operators must identify what records they need to collect
under this requirement.
In Sec. 192.638(c), PHMSA proposes that operators must collect
records needed to meet this standard on an opportunistic basis, which
is defined as occurring during normal operations conducted on the
pipeline including (but not limited to) design, construction,
operations, or maintenance activities. PHMSA notes that its proposed
language in paragraph (c) mirrors the language at Sec. 192.1007(a)(3)
governing operator knowledge management in connection with a
performance of the risk analysis within their DIMPs. PHMSA expects this
approach will minimize compliance burdens on operators, as they would
be able to collect or generate records through existing regulatory
mechanisms such as DIMPs or annual inspections. PHMSA also proposes to
revise Sec. 192.1007(a)(3) so that it references Sec. 192.638(c).
This would require operators to identify records specified in Sec.
192.638(c) that they could collect as part of their DIMP plan.
In Sec. 192.638(d), PHMSA proposes to require that operators
ensure the records required in this section are accessible to personnel
performing or overseeing design, construction, operations, and
maintenance activities. In the 2018 Merrimack Valley incident, the
engineering staff did not have access to the maps containing control
line information and were unaware if the department had access to such
records. This lack of access and awareness resulted in the omission of
critical information that should have been considered through a proper
risk analysis under their DIMPs. Therefore, PHMSA proposes to add a
requirement for operators to provide the personnel responsible for
planning and performing work on critical infrastructure with the
records they need to perform their work safely and effectively.
Operators should note that access would extend to the qualified
employees monitoring the gas pressure (as proposed in Sec. 192.640).
PHMSA expects that during a construction activity, these qualified
personnel may need records such as maps of control lines to effectively
monitor the safety of excavation activities around gas distribution
systems.
In Sec. 192.638(e), PHMSA proposes to require that once a record
is generated or collected under this section, that operators must keep
the record for the life of the pipeline. This will help facilitate
traceability of records as required by 49 U.S.C. 60102(t).
In Sec. 192.638(f), PHMSA specifies that the requirements in this
section would not apply to master meter systems, liquefied petroleum
gas (LPG) distribution pipeline systems that serve fewer than 100
customers from a single source, or any individual service line directly
connected to a transmission, gathering, or production pipeline that is
not operated as part of a distribution system. As discussed above,
small LPG operators are relatively simple, low-risk systems affecting a
finite (generally small) number of customers such that the public
safety and environmental benefits from imposing new requirements on
these systems would be limited. Similar reasoning applies to master
meter systems. PHMSA understands that compliance costs generally are
felt more acutely by small LPG operators and master meter system
operators. PHMSA does not expect that these operators would have the
means (e.g., access to detailed maps and GIS tools) to be able to
comply with the recordkeeping requirements proposed in this NPRM. For
individual service lines, the consequences of an overpressurization are
smaller relative to a district regulator station. Given the relatively
low public safety and environmental benefits from extending the new
Sec. 192.638 recordkeeping requirements to those operators, PHMSA
proposes to except those systems from the new recordkeeping requirement
at Sec. 192.638. Nevertheless, PHMSA does encourage these excepted
operators to, where applicable, follow the recordkeeping specifications
proposed in this NPRM.
Overall, PHMSA expects that its proposed new Sec. 192.638 would
ensure that operators are documenting and maintaining records of how
their critical pressure controlling facilities operate so that they can
review and assess their performance over time. Keeping complete and
accurate records for the life of these assets could help improve
operators' risk analyses, as required by DIMP regulations, and thus
improve the overall integrity of gas distribution pipelines.
PHMSA also understands this proposed requirement for gas
distribution operators to identify and maintain traceable, accurate,
and complete records documenting system characteristics pertinent to
pressure control would be reasonable, technically feasible, cost-
effective, and practicable. As explained above, the proposed
requirement is analogous to material property documentation
requirements elsewhere in PHMSA regulations (e.g., Sec. 192.607) for
gas transmission systems. And PHMSA understands that some gas
distribution operators may already comply with this proposed
requirement either voluntarily (e.g., to minimize losses of
commercially valuable commodities, in response to the Merrimack Valley
incident and NTSB recommendations, or consistent with broadly
applicable, consensus industry standards such as ASME/ANSI B31.8S
\150\), as a result of similar requirements imposed by State pipeline
safety regulators, or as risk mitigation measures pursuant to their
DIMPs. Indeed, the sort of records subject to this proposed requirement
are precisely the sort of records that a reasonably prudent operator of
gas distribution pipeline facility would in ordinary course already
have identified and be maintaining to protect the public given that
their systems transport pressurized (natural, flammable, toxic, or
corrosive) gasses typically within or in close proximity to population
centers. Viewed against those considerations and the compliance costs
estimated in the PRIA, PHMSA expects its proposed amendments will be a
cost-effective approach to achieving the commercial, public safety, and
environmental benefits discussed in this NPRM and its
[[Page 61784]]
supporting documents. Lastly, PHMSA understands that its proposed
compliance timeline--one year after publication of a final rule (which
would necessarily be in addition to the time since publication of this
NPRM)--would provide operators ample time to review and compile
pertinent existing records and develop and implement procedures to
generate or obtain missing records on a going-forward basis (and manage
any related compliance costs).
---------------------------------------------------------------------------
\150\ ASME/ANSI, B31.8S-2004, ``Managing System Integrity of Gas
Pipelines, Supplement to B31.8'' (Jan. 14, 2005) (incorporated by
reference under Sec. 192.7).
---------------------------------------------------------------------------
G. Distribution Pipelines: Presence of Qualified Personnel (Sections
192.640 and 192.605)
1. Current Requirements--Procedures for Qualified Personnel Monitoring
Gas Pressure
Currently, PHMSA does not require operators to have procedures for
monitoring gas pressure with qualified persons and equipment capable of
ensuring pressure control and having the ability to shut off the flow
of gas. There are other provisions related to personnel qualification
included in 49 CFR part 192, subpart N, which contain requirements for
operators of gas pipelines to develop a qualification program to
qualify employees for certain covered tasks. Covered tasks include
those activities that affect the operation or integrity of the
pipeline. PHMSA defines ``Qualified'' in Sec. 192.803 to mean that
``an individual has been evaluated and can: (a) [p]erform assigned
covered tasks; and (b) [r]ecognize and react to abnormal operating
conditions.''
2. Need for Change--Distribution Pipelines: Presence of Qualified
Personnel
Gas pipelines are often monitored in a control room by controllers
using computer-based equipment, such as a SCADA system, that records
and displays operational information about the pipeline system, such as
pressures, flow rates, and valve positions. Some SCADA systems are used
by controllers to operate pipeline equipment remotely or automatically;
in other cases, controllers may dispatch other personnel to operate
equipment in the field. For those operators whose systems are not
capable of remote or automatic shut down or pressure control, control
room operators may have to respond to overpressure indications by
communicating to field personnel to go to the location of the suspected
event, gather additional information to determine if there is an
emergency, and initiate response actions, if needed. This process
creates delays in identifying and responding to overpressurization
indications on gas distribution systems.
During the Merrimack Valley incident, the SCADA controller
responded to a high-pressure alarm by contacting the field technician
who could adjust the flow of gas at the Winthrop regulator station.
CMA's system had remote pressure monitoring but no remote or automatic
shutoff. It took 30 minutes from the time CMA's SCADA controller
noticed an alarm to the time when the field technician began to adjust
the flow of gas. NTSB investigators learned that, at one time, CMA
required that a technician monitor any gas main revision work that
required depressurizing the main.\151\ Per those historical procedures,
the technician would use a gauge to monitor the pressure readings on
the impacted main and would communicate directly with the crew
performing the work. If a pressure anomaly occurred, the technician
could quickly act to prevent an overpressurization event. CMA offered
no explanation to the NTSB as to why this procedure was phased out.
---------------------------------------------------------------------------
\151\ NTSB, Safety Recommendation Report PSR-18-02, ``Natural
Gas Distribution System Project Development and Review (Urgent)'' at
6 (Nov. 24, 2018), https://www.ntsb.gov/investigations/AccidentReports/Reports/PSR1802.pdf.
---------------------------------------------------------------------------
As a result of the incident, the NTSB recommended in P-18-9 that
NiSource, Inc., develop and implement control procedures during
modifications to gas distribution mains to mitigate the risks
identified during MOC operations, and stated that gas main pressures
should be continually monitored during these modifications and that
assets should be placed at critical locations to immediately shut down
the system if abnormal operations are detected. PHMSA agrees with
NTSB's recommendation and concludes that requiring these procedures
could benefit safety for all gas distribution operators. Further, PHMSA
believes that operators can mitigate the consequences of the
overpressurization by requiring qualified personnel capable of shutting
off the gas to monitor the gas pressure during construction associated
with installations, modifications, replacements, or upgrades on gas
distribution mains that could result in overpressurization.
Subsequent to the 2018 Merrimack Valley incident, PHMSA was
directed to issue regulations requiring qualified personnel of a gas
distribution system operator, with the ability to ensure proper
pressure control and shut off, or limit gas pressure should
overpressurization occur, monitor gas pressure at district regulator
stations during certain times. (49 U.S.C. 60102(t)(2)). The mandate
specifies that those times are during any construction project that has
the potential to cause an overpressurization, including projects such
as tie-ins or abandonment of distribution mains. These requirements do
not apply if a district regulator station has a monitoring system and
the capability of remote or automatic shutoff. Further, amendments to
49 U.S.C. 60108 now require gas distribution operators to make their
updated O&M manuals available to PHMSA or the relevant State regulatory
agency within 2 years after any final rule is issued and every 5 years
thereafter.
3. Proposal To Add a New Sec. 192.640 Distribution Pipelines: Presence
of Qualified Personnel
In a new Sec. 192.640, PHMSA proposes an additional layer of
safety at district regulator stations during construction projects by
requiring qualified personnel to be present, monitor the gas pressure,
and have the capability to shut off the flow of gas during an
overpressurization event. This provision, including each of the below
proposed parts, would not apply if an operator already has equipped
that district regulator station with a remote pressure monitoring
system that has the capability for remote or automatic shutoff.\152\
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\152\ This exception will be reflected by addition of new
paragraph (d).
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In paragraph (a), PHMSA proposes that operators of a distribution
system must conduct an evaluation of planned and future installation,
modification, or replacement of, or upgrade construction projects and
identify any potential for an overpressurization to occur at a district
regulator station. Operators must perform this evaluation before
performing activities that could result in an overpressurization. PHMSA
recognizes that not every construction project performed on a gas
distribution system has the same risk profile and not all would require
on-site gas monitoring by a qualified employee. However, the pre-
construction evaluation must occur regardless to assess the probability
of an overpressurization. Some construction projects clearly entail a
potential for overpressurization, such as tie-ins and abandonment of
distribution pipelines and mains, because work is done while part of
the gas system remains active. Similarly, the consequences of
overpressurization during construction projects may increase when that
work is on low-pressure gas distribution systems where customers do not
have
[[Page 61785]]
secondary pressure regulation at their individual meter.
In paragraph (b), PHMSA proposes that once the evaluation is
complete, if an operator has determined that a construction project
activity presents a potential for overpressurization, then the operator
must ensure that at least one qualified employee or contractor with the
capability to shut off the flow of gas is present at that district
regulator station to monitor the gas pressure during the construction
project activity. This will result in safer construction activities on
gas distribution pipelines by requiring operators to ensure that
resources have been deployed to effectively mitigate risks the operator
had determined exist.
Under this proposal, the employee or contractor must be qualified
to monitor the gas pressure in accordance with 49 CFR, part 192,
subpart N. Subpart N already requires that operators ensure on-site
personnel, such as maintenance crew members and inspectors, are
qualified by training and experience to perform covered tasks. Further,
subpart N requires that operators qualify these individuals to ensure
that covered tasks are conducted in a safe, reliable manner in
compliance with regulatory standards. In complying with this new
proposal, operators would need to qualify employees and contractors
responsible for monitoring the gas pressure during construction to
perform various tasks, such as reading and understanding gas monitoring
equipment; responding to abnormal operating conditions (see Sec.
192.805), including overpressurization indications; shutting off or
reducing the pressure to the system; implementing any stop-work
authority granted by the operator; and notifying appropriate emergency
response personnel should an incident occur. They should also be
qualified on the relevant proposed new O&M requirements discussed in
subsection IV.D and E.
In paragraph (c), PHMSA proposes to require that, when monitoring
the system as described in this section, the qualified personnel should
be provided, at a minimum, information regarding the location of all
valves necessary for isolating the pipeline system and pressure control
records (see Sec. 192.638). Providing access to this information could
be essential to an employee or contractor performing their gas
monitoring responsibilities effectively and help shorten the response
time to emergency indications. For example, a qualified employee
responsible for monitoring the gas pressure may need to access valves
on the system so that they can shut off the flow of gas, isolate the
pipeline system, or otherwise mitigate the consequences of an incident.
Similarly, a qualified employee responsible for monitoring the gas
pressure may need to have more extensive maps of the entire gas system
to identify an affected area and detailed information--such as a
specific regulator's set point--to determine if a system is operating
abnormally. The records proposed in Sec. 192.638 would provide this
information and must be accessible to qualified personnel who monitor
gas pressure.
Further, under paragraph (c), PHMSA proposes that operators must
also ensure that qualified employees monitoring the gas pressure have
information regarding emergency response procedures. PHMSA expects such
information would include the contact information of the appropriate
emergency response personnel. Should field personnel recognize an
emergency condition, it is critical for those personnel to have updated
emergency contacts and to know what to do and how to respond in an
emergency. PHMSA expects operators would already have general emergency
contact information in an emergency response plan under Sec. 192.615;
however, given that these qualified personnel may be the first to
witness overpressurization indications, PHMSA believes it is essential
they have immediate access to this information on site during their
activities.
Some operators may already provide qualified employees with ``stop-
work authority'' to halt work that does not conform to specifications
or if they observe unsafe activities on the job site. Although this
authority is not required to be given to all qualified employees under
proposed Sec. 192.640, it is recommended. Where operators have granted
this authority to these qualified personnel monitoring the gas
pressure, operators should ensure these employees are trained to
recognize unsafe, abnormal conditions that are consistent with an
overpressurization.
Overall, the proposals in Sec. 192.640 would reduce the time to
respond to an overpressurization by ensuring qualified employees are on
site or at an alternative location, and that they are capable of
actively monitoring the gas pressure during certain construction
project activities. Should an overpressurization occur, these qualified
employees would be able to respond (i.e., shutting off or reducing the
flow of gas) and thereby mitigate the impact. Under PHMSA's proposal,
the qualified employees would be trained to recognize
overpressurization indications and be able to respond more quickly.
This should mitigate some of the impact of an overpressurization and
improve the response time of the operator.
PHMSA also understands that this proposed new requirement would be
reasonable, technically feasible, cost-effective, and practicable for
gas distribution operators. That operators should evaluate construction
projects on their systems to determine whether they could result in an
overpressurization at a district regulator station and then ensure that
personnel are present who can monitor pressure and prevent such a
condition during the work is a common-sense, best practice within
industry--whose value was underscored by the Merrick Valley incident
and subsequent NTSB recommendation P-18-9. Indeed, PHMSA understands
that some operators may already employ compliant maintenance and
construction protocols in ordinary course. For other operators,
integration of this new requirement within their procedures could be
accomplished via supplementation rather than material revisions; the
proposed new staffing requirements for construction activity would not
require unique skills or equipment to which operators would not have
access. Viewed against those considerations and the compliance costs
estimated in the PRIA, PHMSA expects its proposed amendments will be a
cost-effective approach to achieving the public safety and
environmental benefits discussed in this NPRM and its supporting
documents. Lastly, PHMSA understands that its proposed compliance
timeline--one year after publication of a final rule (which would
necessarily be in addition to the time since publication of this
NPRM)--would provide operators ample time to develop procedures
implementing this new regulatory requirement (and manage any related
compliance costs).
4. Proposal To Amend Sec. 192.605 Procedures for Qualified Personnel
Monitoring Gas Pressure
PHMSA proposes to revise Sec. 192.605, by adding paragraph
(b)(13), to ensure gas distribution operators have procedures for
implementing the monitoring requirements in the proposed Sec. 192.640.
During construction projects on a gas distribution system, qualified
personnel may need to perform their monitoring or shutdown activities
in a specific sequence. Doing work out of sequence may result in an
overpressurization or exacerbate an emergency. For this reason, it is
critical to pipeline safety that operators have written procedures for
personnel performing the construction activity monitoring requirements
proposed in
[[Page 61786]]
Sec. 192.640 to follow. This amendment would ensure that operators
must provide qualified personnel with clear procedures for how to
perform their responsibilities in a safe manner, and specifically how
to monitor for abnormal operating conditions that could lead to an
overpressurization.
PHMSA also understands that this proposed new requirement would be
reasonable, technically feasible, cost-effective, and practicable for
gas distribution operators. As noted above, many operators may already
have compliant procedures; those operators lacking such procedures
should be able to develop new procedures (or supplement existing
procedures) with relatively little difficulty. Viewed against those
considerations and the compliance costs estimated in the PRIA, PHMSA
expects its proposed amendments are a cost-effective approach to
achieving the public safety and environmental benefits discussed in
this NPRM and its supporting documents. Lastly, PHMSA understands that
its proposed compliance timeline--one year after publication of a final
rule (which would necessarily be in addition to the time since
publication of this NPRM)--would provide operators ample time to
develop procedures implementing this new regulatory requirement (and
manage any related compliance costs).
H. District Regulator Stations--Protections Against Accidental
Overpressurization (Sections 192.195 and 192.741)
1. Background--Overpressure Protection
Gas distribution systems are designed to operate at or below an
MAOP. As discussed earlier, a district regulator station is a pressure-
reducing facility that receives gas from a high-pressure source (such
as a transmission line) and delivers it to a distribution system at a
pressure suitable for the demands on the system. An overpressurization
occurs when the pressure of the system rises above the set point of the
devices controlling its pressure. Pressure regulating and control
devices (housed in these district regulator stations) keep the systems'
pressure under their MAOP and at or below the desired set point. These
devices act as overpressure protection. Because of varying conditions
and requirements, there are no standard designs for distribution
systems or overpressure protection on such systems. However, among the
common approaches to overpressure protection in use today are the
following: (1) pressure relief valves, (2) a worker and monitor
regulator system, and (3) automatic or remote shutoff (or ``slam-
shut'') valves.
Pressure relief valves provide overpressure protection by venting
excess gas into the atmosphere and can be used alone or in combination
with other methods of overpressure protection. If the relief valve
senses that the downstream pressure has exceeded a set point, then the
relief valve automatically begins to open to relieve excess gas
pressure in the system. If activated, the relief valve protects from
overpressurization while allowing gas to flow at a safe pressure,
maintaining normal service to customers. In general, the relief valve
is a highly reliable device for overpressure protection. Relief valves
also provide benefits with respect to alerting or warning operator
personnel or the public that an emergency has occurred because (1)
these devices are loud if operated at or near a full discharge of
excess gas pressure, and (2) the smell of the odorized gas that is
vented is also noticeable. However, pressure relief valves entail their
own potential public safety harms through their release of gas--which
can sometimes ignite--into the atmosphere when activated. Venting of
gas to the atmosphere by a relief valve also entails environmental
risks: a primary component of natural gas is methane, an ignitable,
potent greenhouse gas. For these reasons, section 114 of the PIPES Act
of 2020 (codified at 49 U.S.C. 60108(a)(2)(D)(ii)) contains a self-
executing requirement for operators of gas distribution pipelines to
have a written plan to minimize releases of natural gas--such as by
venting from relief valves--from their systems.\153\
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\153\ See ``Pipeline Safety: Statutory Mandate to Update
Inspection and Maintenance Plans to Address Eliminating Hazardous
Leaks and Minimizing Releases of Natural Gas from Pipeline
Facilities,'' ADB-2021-01, 86 FR 31002 (June 10, 2021).
---------------------------------------------------------------------------
A worker and monitor regulator system is a type of pressure control
and overpressure protection configuration that involves two pressure
reducing valves (e.g., control or pilot valves) installed in a
series.\154\ One regulator valve controls the pressure of gas to the
downstream system. The second regulator valve remains on standby with a
slightly higher set point and only begins operating in the event of a
malfunction of the first regulator or another failure results in
pressure exceeding the set point of the first regulator. If the first,
primary regulator (the ``worker'' regulator) cannot control the
pressure, the second regulator (the ``monitor''), which senses the
rising downstream pressure, automatically begins to operate to maintain
the pressure downstream at a gas pressure slightly higher than normal,
albeit still within safe operation. Sometimes an operator will also
install a small relief valve downstream to act as a ``token relief'' or
an alarm to alert the operator that the regulator has failed.
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\154\ There are a few types of monitor regulating, all of which
operate substantially similarly as described herein: working
monitor, series regulation, and relief monitoring.
---------------------------------------------------------------------------
When working properly, a worker and monitor regulator system should
not interrupt service if an overpressurization occurs. An advantage of
the worker and monitor regulator system is that it does not result in
venting large volumes of gas to the atmosphere, thereby reducing public
safety and environmental harms. Unlike with pressure relief valves, the
pressure reducing valves used in the worker and monitor regulator
system described above are not self-operated; instead, control lines
are installed in this type of system. Control lines (often called
``sensing'' or ``impulse'' lines) are small-diameter pipes that
transmit the signal pressure from the tie-in point on the downstream
piping line to the pressure regulating device. When the downstream
pressure decreases, the regulator opens wider to allow more gas to
flow. The regulator valve remains open until it senses an increase in
pressure or the demand of the downstream pressure has been met. Control
lines must be protected against breakage because the regulator will
open wide if the control lines are cut or damaged because the regulator
will not detect that the demand has been met, it will remain open,
allowing gas to flow freely. This could result in full upstream
pressure being forced into the low-pressure system, resulting in a
catastrophic situation as seen in the Merrimack Valley incident.
A third type of overpressure protection is automatic shutoff
devices. In the event of an overpressurization indication or event, an
automatic shutoff device completely shuts off the gas flow to the
system until the operator determines the cause of the malfunction and
resets the device. In many cases, an automatic shutoff device is used
as a secondary form of overpressure protection.
2. Current Requirements--Overpressure Protection
Section 192.195 describes the minimum requirements for protection
against accidental overpressurization. Section 192.195(a) requires that
``each pipeline that is connected to a gas
[[Page 61787]]
source so that the [MAOP] could be exceeded as the result of pressure
control failure or of some other type of failure, must have pressure
relieving or pressure limiting devices that meet the requirements of
Sec. Sec. 192.199 and 192.201.'' \155\ Section 192.195(b) adds that
``[e]ach distribution system that is supplied from a source of gas that
is at a higher pressure than the [MAOP] for the system must--(1) [h]ave
pressure regulation devices capable of meeting the pressure, load, and
other service conditions that will be experienced in normal operation
of the system, and that could be activated in the event of failure of
some portion of the system; and (2) [b]e designed so as to prevent
accidental overpressuring.'' This pipeline safety regulation has
existed in 49 CFR part 192 since its inception.\156\
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\155\ Except as provided in Sec. 192.197, which only applies to
high-pressure gas distribution systems.
\156\ See ``Establishment of Minimum Standards,'' 35 FR 13248,
13264 (Aug. 19, 1970).
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Section 192.199 describes the minimum requirements for the design
of pressure relief and limiting devices. Section 192.199(g) states that
``[w]here installed at a district regulator station to protect a
pipeline system from overpressuring, [the pressure relief or pressure-
limiting device must] be designed and installed to prevent any single
incident such as an explosion in a vault or damage by a vehicle from
affecting the operation of both the overpressure protective device and
the district regulator[.]''
Section 192.201 describes the minimum requirements for the required
capacity of pressure-relieving and -limiting stations. Section
192.201(a)(1) requires that ``[i]n a low-pressure distribution system,
the pressure may not cause the unsafe operation of any connected and
properly adjusted gas utilization equipment.'' Section 192.201(c)
requires that ``[r]elief valves or other pressure limiting devices must
be installed at or near each regulator station in a low-pressure
distribution system, with a capacity to limit the maximum pressure in
the main to a pressure that will not exceed the safe operating pressure
for any connected and properly adjusted gas utilization equipment.''
Section 192.203(b)(9) adds that ``[e]ach control line must be protected
from anticipated causes of damage and must be designed and installed to
prevent damage to any one control line from making both the regulator
and the over-pressure protective device inoperative.'' PHMSA has
clarified through its enforcement guidance that an occurrence of
overpressurization may be indicative of an equipment failure or design
flaw.\157\
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\157\ PHMSA, ``Operations & Maintenance Enforcement Guidance
Part 192 Subparts L and M'' at 149 (July 21, 2017), https://www.phmsa.dot.gov/sites/phmsa.dot.gov/files/docs/regulatory-compliance/pipeline/enforcement/5776/o-m-enforcement-guidance-part-192-7-21-2017.pdf.
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In addition, Sec. 192.739 describes the minimum requirements for
the inspection and testing of pressure-limiting and regulating
stations. Section 192.739 requires annual inspection and testing of
each pressure limiting or regulating stations, including relief
devices. The inspection and tests should determine that the station is:
(1) in good mechanical condition; (2) adequate from the standpoint of
capacity and reliability of operation for the service in which it is
employed; (3) except as provided in Sec. 192.739(b) applicable to
certain steel pipelines, set to control or relieve at the correct
pressure consistent with the pressure limits of Sec. 192.201(a); and
(4) properly installed and protected from dirt, liquids, or other
conditions that might prevent proper operation. These requirements are
intended to address inspection and testing of pressure-limiting and
regulator stations necessary to maintain safe pressures on the gas
distribution system.
Section 192.741 describes minimum requirements for the telemetering
or recording gauges on pressure-limiting and regulating stations.
Section 192.741(a) states that ``[e]ach distribution system supplied by
more than one district pressure regulating station must be equipped
with telemetering or recording pressure gauges to indicate the gas
pressure in the district.'' Section 192.741(b) requires that, ``[o]n
distribution systems supplied by a single district pressure regulating
station, the operator shall determine the necessity of installing
telemetering or recording gauges in the district, taking into
consideration the number of customers supplied, the operating
pressures, the capacity of the installation, and other operating
conditions.''
3. Need for Change--Overpressure Protection
The pipeline safety regulations governing overpressure protection
of low-pressure distribution systems have not changed since their
inception in the 1970s. For years, low-pressure gas distribution
systems, like CMA's system in the Merrimack Valley, have relied on
overpressure protection systems like the redundant worker and monitor
regulators to regulate and control the pressure and flow of gas. While
these overpressure protection methods are safe under normal operating
conditions, this method of overpressure protection on low-pressure
distribution systems can be too easily defeated, as recent events with
a common mode of failure have demonstrated. PHMSA's proposed change to
regulations governing overpressure protection is intended to facilitate
the operation of gas distribution systems to avoid catastrophic
overpressurization.
According to the NTSB's report, the low-pressure system in
Merrimack Valley met the requirements for overpressure protection
contained in Sec. 192.195 (Protection Against Accidental
Overpressuring) and Sec. 192.197 (Control of the Pressure of Gas
Delivered from High-pressure Distribution Systems). ``At each of the 14
regulator stations feeding natural gas into [CMA's] low-pressure
system, there were two regulators [(i.e., a worker and monitor
regulator system)] installed in a series to control the natural gas
flow from the high-pressure [. . .] system.'' \158\ The worker
regulator and the monitor regulator were set to limit the pressure to a
maximum safe value to the customer. But the system nonetheless failed.
After reviewing accidents investigated by the NTSB over the past 50
years, as well as prior NiSource incidents, the NTSB found that this
scheme for overpressure protection can be defeated by a common mode of
failure, like operator error or equipment failure.\159\
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\158\ NTSB/PAR-19/02 at 39.
\159\ NTSB/PAR-19/02 at 39-40.
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CMA's overpressurization was not an isolated event. For example, on
January 28, 1982, in Centralia, MO, high-pressure natural gas entered a
low-pressure natural gas distribution system after a backhoe damaged
the regulator control line at the Missouri Power and Light Company's
district regulator station.\160\ Because the regulator no longer sensed
system pressure, the regulator opened, and high-pressure natural gas
entered customer piping systems. In some cases, this resulted in high
pilot-light flames that ignited fires in buildings. In other cases, the
pilot-light flames were blown out, allowing natural gas to escape
within the buildings. Of the 167 buildings affected by the
overpressurization, 12 were destroyed and 32 sustained moderate to
heavy damage. Five occupants suffered minor injuries.
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\160\ NTSB, Accident Report PAR-82/03, ``Missouri Power and
Light Company Natural Gas Fires, Centralia, Missouri, January 28,
1982'' (Aug. 24, 1982).
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The NTSB investigated one other incident in 1977 that was nearly
identical to the 2018 incident in
[[Page 61788]]
Merrimack Valley. Both incidents occurred when a cast-iron main with
control lines attached was isolated as part of a pipe replacement
project. On August 9, 1977, natural gas under high pressure entered a
Southern Union Gas Company's low-pressure natural gas distribution
pipeline and overpressurized a system serving more than 750 customers
in a 7-block area in El Paso, TX. The gas company was replacing a
section of 10-inch cast-iron low-pressure natural gas main containing
the pressure-sensing control lines for a nearby upstream regulator
station and its monitor and isolated it between two valves with a
temporary bypass installed. Southern Union Gas Company was aware that
the isolated section contained the control lines but did not realize
the potential hazard of isolating the pressure-sensing control lines,
which would make the two regulators inoperative. Without the ability to
sense the actual pressure in the gas main, the regulators allowed the
pressure to build up and overpressurized the rest of the affected
system. The problem was corrected before causing any fatalities or
major injuries.\161\
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\161\ NTSB, Safety Recommendation(s) P-77-43 (Dec. 9, 1977),
https://www.ntsb.gov/safety/safety-recs/RecLetters/P77_43.pdf.
---------------------------------------------------------------------------
As a result of its investigation of the CMA overpressurization
event, as well as a review of multiple overpressurizations that
occurred as the result of a common mode of failure, the NTSB
recommended in P-19-14 that PHMSA revise 49 CFR part 192 to require
additional overpressure protection for low-pressure natural gas
distribution systems that cannot be defeated by a single operator error
or equipment failure. NiSource also took action to remove this
vulnerable design on their systems. On December 14, 2018, the CEO of
NiSource committed to the NTSB that they would install automatic
pressure control equipment, referred to as ``slam-shut'' devices, on
every low-pressure system throughout their operating area.\162\ These
devices provide another level of control and protection, as they
immediately shut off gas to the system when they sense operating
pressure that is too high or too low. That measure exceeds current
Federal requirements.
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\162\ Sec. and Exch. Comm'n, Form 10-Q Quarterly Report,
``NiSource, Inc.'' at 42 (Oct. 30, 2019), https://www.sec.gov/Archives/edgar/data/1111711/000111171119000041/ni-2019930x10q.htm.
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Subsequent to the 2018 CMA incident, PHMSA was required by statute
to issue regulations ensuring that distribution system operators
minimize the risk of a common mode of failure at low-pressure district
regulator stations, monitor the gas pressure of a low-pressure system,
and install overpressure protection safety technology at low-pressure
district regulator stations. (49 U.S.C. 60102(t)(3)). The mandate also
provides that if it is not operationally possible to install such
technology, PHMSA's regulations must provide that operators would have
to develop and follow plans that would minimize the risk of an
overpressurization.
After reviewing NTSB's recommendations, the CMA and other related
incidents, and the requirements of 49 U.S.C. 60102(t)(3), PHMSA
proposes additional requirements to improve the design standard for
overpressure protection on low-pressure distribution systems. Gas
distribution systems that use only regulators and control lines as the
means to prevent overpressurization are not sufficient protection from
overpressurization events. Therefore, PHMSA is proposing additional
layers of protection specific to low-pressure distribution systems to
set a safer design standard for these systems.
4. Proposal To Amend Sec. 192.195--Overpressure Protection
Consistent with 49 U.S.C. 60102(t)(3), PHMSA proposes to amend
Sec. 192.195 to impose three additional requirements for each district
regulator station that serves a low-pressure distribution system.
First, each district regulator station must consist of at least two
methods of overpressure protection (such as a relief valve, monitoring
regulator, or automatic shutoff valve) appropriate for the
configuration and location of the station. Under this proposal,
operators have options for meeting the new requirements for
overpressure protection. For example, one option is for operators of
low-pressure distribution systems to install a full relief valve
downstream of existing overpressure protections. Another option is to
install an automatic shutoff valve. In that case, for operators with
the worker and monitor regulator set up, the addition of an automatic
shutoff valve downstream of the existing setup would stop the flow of
gas if an overpressurization occurred and both regulators failed.
Further, some automatic shutoff valves have the capability to activate
if the system experiences an underpressurization.\163\ PHMSA discussed
these additional options in the overpressure protection advisory
bulletin (ADB-2020-02), but there are other configurations that would
be suitable as well.
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\163\ An underpressurization could occur if there is a pipeline
rupture downstream, which is a risk during excavation.
---------------------------------------------------------------------------
PHMSA proposes this two-method requirement as mandatory for
district regulator stations that are new, replaced, relocated, or
otherwise changed after the effective date of the final rule. For all
other systems, PHMSA proposes to amend Sec. 192.1007(d)(2)(ii) to
require operators to ensure district regulator stations have two
methods of overpressure protection consistent with proposed Sec.
192.195(c)(1), or identify and notify PHMSA of alternative preventive
and mitigative measures. PHMSA finds that this approach meets the
mandate found at 49 U.S.C. 60102(t)(3)(iii) and (iv) for all district
regulator stations to have at least two methods of overpressure
protection technology appropriate for the configuration and siting of
the station, while allowing for alternate action where PHMSA determines
it is not operationally possible to have such secondary relief. PHMSA
concludes that it is operationally possible for operators to include at
least two methods of overpressure protection in new, replaced,
relocated, or otherwise changed district regulator stations. And, for
existing district regulator stations, PHMSA recognizes that there may
be unique cases where it is not operationally possible to have a second
measure, in which circumstance an operator may notify PHMSA under Sec.
192.1007(d)(2)(ii)(B) of the alternative measures to minimize the risk
of an overpressure event.
Second, PHMSA proposes that each district regulator station that
services a low-pressure system must minimize the risk of
overpressurization that could be caused by any single event (such as
excavation damage, natural forces, equipment failure, or incorrect
operations) that either immediately or over time affects the safe
operation of more than one overpressure protection device. PHMSA notes
that 49 U.S.C. 60102(t)(3) requires the promulgation of regulations
that minimize the risk of gas pressure exceeding the MAOP from a common
mode of failure. PHMSA interprets the statutory term ``common mode of
failure'' to mean a failure where a single common cause could
immediately or over time cause multiple failures that result in an
overpressurization on a downstream distribution system. PHMSA's
interpretation of ``common mode of failure'' is intended to ensure that
operators are identifying as many potential failure modes in their
systems as possible.
[[Page 61789]]
This practice of identifying potential common modes of failure will
be particularly important for operators of low-pressure gas
distribution systems, whose designs make them more vulnerable to
overpressurization. For example, hydrotesting upstream of the district
regulator station could cause moisture to be injected into the gas
system, which then could cause the working and monitor regulators to
freeze up before the gas distribution operator responds. Construction
work upstream of the district regulator station could cause
contaminants like metal shavings to be introduced into the gas system,
which then could damage the working and monitor regulator diaphragms
before the gas distribution operator could respond. Oil, hydrates, or
high sulfides that enter the gas system could affect both the working
and monitoring regulators before the gas distribution operator could
respond. A contractor or third party could damage both downstream
control lines at the same time. And, as seen in the 2018 Merrimack
Valley incident, connecting a new main to the district regulator
station without connecting the control lines to the new piping could
result in an overpressurization. In its proposed Sec. 192.195(c)(2),
PHMSA provides examples of single events that could cause a common mode
of failure, such as excavation damage, natural forces, equipment
failure, or incorrect operations. While operators are best positioned
to identify other scenarios that could introduce a common mode of
failure on their unique gas distribution systems, applying any of the
design standards described in this proposed amendment could eliminate
most of the common modes of failure described in this paragraph and in
Sec. 192.195(c)(2) by providing additional redundancy in the gas
distribution system.
Third, pursuant to 49 U.S.C. 61012(t)(3), PHMSA proposes in Sec.
192.195(c)(3) to require that low-pressure distribution systems have
remote monitoring of gas pressure at or near the location of
overpressure protection devices. Remote monitoring in this context
means that the device is capable of monitoring the gas pressure near
the location of overpressure protection devices and remotely displaying
the gas pressure to operator personnel in real time. Low-pressure gas
distribution operators are already required to have devices such as
telemetering or recording gauges that record gas pressure (see
Sec. Sec. 192.199 and 192.201). However, the current telemetering and
recording device requirements in Sec. 192.741 do not require active
monitoring and some of these devices employed under Sec. Sec. 192.199,
192.201, and 192.741 are not designed to provide real-time awareness or
notification of potential overpressurizations. Installing these real-
time monitoring devices will improve an operator's ability to receive
timely overpressurization indications, thereby giving operator
personnel an opportunity to avoid or mitigate adverse consequences.
Accordingly, PHMSA also proposes a conforming change in a new Sec.
192.741(d) to specify that operators of low-pressure distribution
systems that are new, replaced, relocated, or otherwise changed
beginning one year after the publication of any final rule in this
proceeding must monitor the gas pressure in accordance with Sec.
192.195(c)(3).
These three new design standards would be applicable to low-
pressure distribution systems that are new, replaced, relocated, or
otherwise changed beginning one year after the publication of any final
rule in this proceeding. A modification to either the low-pressure
system or the district regulator station made on or after the
compliance date above would require an operator to meet the proposed
new design standards described in this section. For example, as
operators upgrade their low-pressure systems as part of the cast iron
replacement program or implement mitigating measures to address the
risk of overpressurization through the DIMP requirements in Sec.
192.1007, they would be required to ensure those upgrades meet the
proposed design standard in Sec. 192.195(c). PHMSA would not expect
operators performing routine maintenance to upgrade their systems to
meet the proposed design standard.
PHMSA understands this proposed requirement for gas distribution
operators to incorporate in their design of low-pressure distribution
systems the overpressure protection measures described above would be
reasonable, technically feasible, cost-effective, and practicable.
These proposed enhanced design and installation requirements would be
applicable only to certain gas distribution operators--those with
district regulators serving low-pressure systems--and then only when
components within their systems are new, replaced, relocated, or
otherwise changed. Affected operators would therefore be able to
integrate these common-sense, proposed safety enhancements within
larger construction, installation, and replacement projects. Indeed,
some low-pressure gas distribution system operators may already be
complying with this proposed requirement either as a voluntarily for
commercial reasons (to minimize the loss of a valuable commodity), as a
safety practice (implementing lessons learned from the Merrimack Valley
incident and NTSB recommendation P-19-14) or as a mitigation measure
pursuant to their DIMP. Viewed against those considerations and the
compliance costs estimated in the PRIA, PHMSA expects its proposed
amendments will be a cost-effective approach to achieving the
commercial, public safety, and environmental benefits discussed in this
NPRM and its supporting documents. Lastly, PHMSA understands that its
proposed compliance timeline--one year after publication of a final
rule (which would necessarily be in addition to the time since
publication of this NPRM)--would provide operators ample time to
incorporate these requirements in plans for new, replaced, relocated,
or otherwise changed low pressure distribution systems (and manage any
related compliance costs).
I. Inspection: General (Section 192.305)
1. Current Requirements--Inspections
Section 192.305 (Inspection: General) states that ``[e]ach
transmission line or main must be inspected to ensure that it is
constructed in accordance with this part.''
2. Need for Change--Inspections
On November 29, 2011, PHMSA issued an NPRM that included a proposal
to modify the requirements contained in Sec. 192.305 to specify that a
gas transmission pipeline or distribution main cannot be inspected by
someone who participated in its construction.\164\ This addressed
concerns expressed by State and Federal regulators and was based in
part on a 2011 NAPSR resolution calling for revisions to Sec. 192.305
to provide that contractors who install a transmission pipeline or
distribution main should be prohibited from inspecting their own work
for compliance purposes.\165\ At the time, Sec. 192.305 had simply
provided that each transmission pipeline or distribution main must be
inspected to ensure that it was constructed in accordance with 49 CFR
part 192. In a final rule issued on March 11, 2015, PHMSA amended Sec.
192.305 to specify that a pipeline operator may not use the same
operator personnel to perform a required
[[Page 61790]]
inspection who also performed the construction task that required
inspection.\166\
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\164\ ``Pipeline Safety: Miscellaneous Changes to Pipeline
Safety Regulations,'' 76 FR 73570 (Nov. 29, 2011). On July 11, 2012,
the Gas Pipeline Advisory Committee (GPAC) recommended that PHMSA
adopt this amendment.
\165\ NAPSR, Resolution CR-1-02, Doc. No. PHMSA-2010-0026-0002
(Dec. 15, 2011).
\166\ ``Pipeline Safety: Miscellaneous Changes to Pipeline
Safety Regulations,'' 80 FR 12762, 12779 (Mar. 11, 2015).
---------------------------------------------------------------------------
PHMSA received petitions for reconsideration of various elements of
the March 2015 final rule, including petitions from the American Public
Gas Association (APGA) and other stakeholders raising concern about the
construction inspection requirement in Sec. 192.305 for smaller
operators for whom it may be particularly difficult to have different
personnel perform construction and inspection activities.\167\ The APGA
petition noted that utilities with only one qualified crew who work
together to construct distribution mains would not have anyone working
for the utility available and qualified to perform the inspection under
the amended language, which could significantly increase the costs for
those utilities by requiring small utilities to contract with third
parties for such inspections.\168\ In 2015, according to the APGA, 585
municipal gas utilities had 5 or fewer employees. The APGA stated that
its concerns would be alleviated by a clarification stating a two-man
utility crew may inspect each other's work and comply with the
amendment to Sec. 192.305.
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\167\ APGA, ``Petition for Clarification or in the Alternative
Reconsideration of the American Public Gas Association,'' Doc. No.
PHMSA-2010-0026-0055, at 4 (Apr. 10, 2015); American Gas
Association, ``Request for Effective Date Extension for Construction
Inspection Changes and Petition for Reconsideration of `Pipeline
Safety: Miscellaneous Changes to Pipeline Safety Regulations,'' Doc.
No. PHMSA-2010-0026-0056 (Apr. 10, 2015); NAPSR, ``NAPSR Request for
Delay in the Effective Date of Amended Rule 192.305 on Construction
Inspection,'' Doc. No. PHMSA-2010-0026-0059 (July 28, 2015).
\168\ APGA, ``Petition for Clarification or in the Alternative
Reconsideration of the American Public Gas Association,'' Doc. No.
PHMSA-2010-0026-0055, at 4 (Apr. 10, 2015).
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NAPSR, on the other hand, submitted a petition criticizing the
March 2015 final rule for not limiting the Sec. 192.305 prohibition to
contractor personnel inspecting the work performed by their own
company's crews, contending that such an approach would not resolve the
potential conflict of interest that had been the occasion for its 2011
resolution.\169\ NAPSR added that prohibition should not apply to an
operator's own construction personnel as NAPSR believed they would have
less of an incentive to accept poor quality work when conducting an
inspection than a contractor inspecting his colleagues' work. NAPSR
asked for a delay in the effective date of the final rule relative to
Sec. 192.305 until PHMSA had reviewed the rule and worked with NAPSR
to address its concerns.
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\169\ NAPSR, ``NAPSR Request for Delay in the Effective Date of
Amended Rule 192.305 on Construction Inspection,'' Doc. No. PHMSA-
2010-0026-0059 (July 28, 2015).
---------------------------------------------------------------------------
PHMSA responded to the petitions for reconsideration of the March
2015 final rule on September 30, 2015, and, in recognition of the
concerns expressed, indefinitely delayed the effective date of the
Sec. 192.305 amendment.\170\ Because other proposed amendments in this
NPRM may impact the number of inspections and construction activities
on gas distribution mains, PHMSA believes it is appropriate to re-
examine this issue.
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\170\ ``Pipeline Safety: Miscellaneous Changes to Pipeline
Safety Regulations: Response to Petitions for Reconsideration,'' 80
FR 58633, 58634 (Sept. 30, 2015).
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3. Proposal To Amend Sec. 192.305--Inspections
In this NPRM, PHMSA proposes to remove the existing suspension of
Sec. 192.305, relocate the existing regulatory language adopted in the
March 2015 final rule to a new paragraph (a), and add a new paragraph
(b) addressing concerns raised in APGA's petition for reconsideration
pertaining to the potential impact on small operators.
If adopted, PHMSA's proposed Sec. 192.305(a) would require each
gas transmission pipeline (along with each offshore gas gathering, and
Types A, B, and C gathering pipelines pursuant to Sec. 192.9) and
distribution main that is newly installed, replaced, relocated, or
otherwise changed beginning one year after the publication of a final
rule to be inspected to ensure that it is constructed in accordance
with the requirements of this subpart, using different personnel to
conduct the inspection than had performed the construction activity.
This requirement--which would lift the suspension of the regulatory
amendments adopted in the March 2015 final rule--was the subject of
extensive consideration in PHMSA's earlier notice and comment
rulemaking (including during a meeting of the Gas Pipeline Advisory
Committee (GPAC)).\171\
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\171\ PHMSA incorporates by reference in this proceeding
pertinent materials from the administrative record in the earlier
proceeding. Those materials can be found in Doc. No. PHMSA-2010-
0026.
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PHMSA understands that the public safety and environmental risks
associated with releases from Type C gathering pipelines, a category
created in a final rule issued in November 2021 \172\ and thus not
included in the 2015 assessment of cost-effectiveness, technical
feasibility, and practicability, are similar to the risks associated
with other part 192-regulated gas gathering pipelines (which generally
transport unprocessed natural gas containing higher percentages of
volatile organic compounds, corrosives, and hazardous airborne
pollutants than processed natural gas transported in other pipelines).
PHMSA therefore proposes to subject Type C gathering pipelines to the
inspection requirements at Sec. 192.305(a). PHMSA expects to have
operator-reported data after the reporting cycle completes in spring of
2023 for these newly regulated gathering lines.\173\ To address this
uncertainty, PHMSA estimates that most Type C lines are operated by
operators of other part 192-regulated gathering pipelines such that
they are already included in the 2015 assessment of this regulatory
requirement for other lines.\174\ PHMSA explains this estimate in
greater length in the associated preliminary regulatory impact
analysis.
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\172\ ``Pipeline Safety: Safety of Gas Gathering Pipelines:
Extension of Reporting Requirements, Regulation of Large, High-
Pressure Lines, and Other Related Amendments,'' 86 FR 63266 (Nov.
15, 2021).
\173\ PHMSA's preliminary review of the incoming reported data
supports its estimates in the PRIA for Type C lines.
\174\ See Preliminary Regulatory Impact Analysis, available in
the docket for this rulemaking.
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Additionally, PHMSA has evaluated concerns raised in APGA and other
petitioners' reconsideration petitions, and PHMSA proposes to add a
paragraph (b) that would provide an exception to the construction
inspection requirement for gas distribution mains for small gas
distribution operators for whom complying with paragraph (a) may prove
difficult due to their limited staffing. Specifically, PHMSA proposes
to allow operator personnel involved in the same construction task to
inspect each other's work on mains when the operator could otherwise
comply with the construction inspection requirement in paragraph (a) of
this section only by using a third-party inspector. This justification
must be documented and retained for the life of the pipeline. This
exception is in acknowledgment that, as highlighted by APGA, there are
times when only one or two people are available to perform a task and
the current requirements may be overly burdensome for smaller gas
distribution operators. PHMSA proposes to limit this exception to
distribution operators because it understands that: (1) many of these
operators are likely to have a limited number of employees, thereby
necessitating reliance on contractor personnel; and (2) the public
safety risks from delays in undertaking safety-improving construction
projects
[[Page 61791]]
(because of a lack of qualified inspection personnel) on these
pipelines would be particularly compelling given their (typical)
location near or within population centers. PHMSA believes this
proposed amendment addresses concerns raised in APGA's petitions for
reconsideration regarding the unintended burdens of the March 2015
rulemaking on small operators.
PHMSA acknowledges that NAPSR, in its 2011 resolution and petition
for reconsideration of the March 2015 final rule, called for limiting
the prohibition to contractor personnel inspecting the work of their
own crew, as NAPSR does not view an ``inherent conflict of interest''
arising from operator-employed personnel doing the same.\175\ PHMSA
agrees with NAPSR that a lack of independence in inspection activity
raises public safety concerns but disagrees that there is a material
distinction in risk between those personnel directly employed by the
operator and those third-party personnel contracted by the operator.
Further, creating such a distinction could diminish the scope of the
safety benefit while placing burden on smaller operators who rely on
contractors for a large portion of their construction work. Therefore,
PHMSA does not see a reasoned basis to discriminate between operator
personnel and contracted personnel for the purposes of this inspection.
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\175\ See NAPSR, Res. 2015-01, ``A Resolution Seeking Suspension
of the Effective Date of a Recently Adopted Federal Final Rule, and
Reconsideration of that Rule,'' at 2 (Sept. 3, 2015), https://www.napsr.org/resolutions.html.
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PHMSA understands this proposed amendment to restore a previously
approved (but now suspended) requirement that post-construction
inspections be performed by personnel other than those who performed
the construction work being inspected would be reasonable, technically
feasible, cost-effective, and practicable for all affected operators.
That requirement reflects the proposition--reflected in industry best
practice--that an independent second set of eyes inspecting a
construction project provides more robust assurance of work product
quality than allowing construction personnel to inspect their own work.
Although PHMSA acknowledges that this proposed requirement could entail
additional compliance burdens (in terms of costs and stretching limited
personnel resources) for some operators, PHMSA believes those burdens
would be manageable because (1) all operators could account for them at
the project planning phase in a way that allows them to control costs
or secure requisite supplemental personnel (or contractors), and (2)
small gas distribution system operators whose limited personnel
resources would make them dependent on (potentially expensive)
contractors would be excepted from this requirement. Viewed against
those considerations and the compliance costs estimated in the PRIA,
PHMSA expects its proposed amendments will be a cost-effective approach
to achieving the commercial, public safety, and environmental benefits
discussed in this NPRM and its supporting documents. Lastly, PHMSA
understands that its proposed compliance timeline--one year after
publication of a final rule (which would necessarily be in addition to
the time since publication of this NPRM)--would provide operators ample
time to implement requisite changes to their procedures and obtain
access to inspection personnel for near-term installation projects (as
well as manage any resulting compliance costs).
J. Records: Tests (Sections 192.517 and 192.725)
1. Current Requirements--Records: Tests
Section 192.517(b) applies to all gas pipeline operators and states
that ``[e]ach operator must maintain a record of each test required by
Sec. Sec. 192.509 [pipelines operating below 100 psig], 192.511
[service lines], and 192.513 [plastic pipelines], respectively, for at
least 5 years.'' Section 192.725(a) states that ``each disconnected
service line must be tested in the same manner as a new service line,
before being reinstated.'' \176\
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\176\ Paragraph (b) provides an exception to paragraph (a) for
any part of the original service line used to maintain continuous
service during testing if provisions are made to maintain continuous
service.
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2. Need for Change--Records: Tests
On October 7, 2021, NAPSR submitted a resolution seeking that PHMSA
amend Sec. 192.517(b) in several ways. NAPSR recommended PHMSA amend
its regulations to require operators to retain test documentation under
Sec. 192.517(b) for the life of the corresponding pipeline segment as
opposed to the current 5 years.\177\ The resolution also requested that
PHMSA require operators to retain for the life of the pipeline ``the
test pressure documentation created within the five years prior'' to
any such amendment. Additionally, NAPSR requested that PHMSA require
additional, more detailed, information be documented as part of these
test records. PHMSA agrees that the detailed recordkeeping content and
retention requirements suggested by NAPSR will improve consistency and
promote public safety and protection of the environment.
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\177\ NAPSR, Res. 2021-02, ``A Resolution Seeking a Modification
of 49 CFR 192.517(b) to Require Certain Distribution Pipeline
Pressure Test Information Be Documented and to Require the Retention
of Test Documentation for Distribution Pipelines for the Lifetime of
the Corresponding Pipeline Segment,'' Doc. No. PHMSA-2021-0046-0005
(Oct. 7, 2021). This extended retention period would include records
of tests establishing an MAOP, as NAPSR explains in its petition:
``PHMSA has set forth regulations requiring the availability and use
of pipeline pressure documentation to establish the maximum
allowable operating pressure (MAOP) of pipelines, including short
segments of replaced or relocated pipe, prior to placing them in
service within Subpart L of 49 CFR 192, specifically 49 CFR
192.619.''
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NAPSR also requested that PHMSA add Sec. 192.725 (``Test
requirements for reinstating service lines'') to the list of required
test records in Sec. 192.517(b). It reasoned that Sec. 192.603(b),
which requires operators to keep records necessary to administer the
procedures established under Sec. 192.605, is potentially in conflict
with Sec. 192.517. PHMSA clarifies that the requirement in Sec.
192.725 to perform a test ``in the same manner as a new service line''
is meant to direct an operator to conduct a test required for a new
service line in accordance with 49 CFR part 192, subpart J. A test
performed to meet Sec. 192.725 does not constitute a new type of test
for purposes of identifying recordkeeping requirements for such a test.
PHMSA expects an operator to select the appropriate test in subpart J
to meet the testing requirement of Sec. 192.725, which includes
meeting the corresponding recordkeeping requirements of Sec. 192.517.
For that reason, PHMSA does not propose to include Sec. 192.725 in the
list of tests identified within Sec. 192.517.
3. Proposal To Amend Sec. 192.517--Records: Tests
PHMSA proposes to amend Sec. 192.517 to require that records of
tests covered by Sec. 192.517(b) (i.e., tests performed according to
Sec. 192.509, 192.511, and 192.513) be retained for the life of the
pipeline. This amendment would be applicable to all gas pipeline
operators. PHMSA would require operators to retain the records for all
tests presently being retained under the existing language of Sec.
192.517(b) from the preceding five years, which under the proposal
would then be retained for the life of the pipeline. PHMSA also
proposes to require that the records of these tests include, at a
minimum, sufficient information to document the test, including
information about the
[[Page 61792]]
operator, the individual or any company used to perform the test,
pipeline segment being tested, test date, medium, pressure, duration,
and any leaks or failures noted and their disposition. Retaining tests
for the life of the pipeline, instead of the current retention period
of 5 years, ensures that records are available whenever repairs are
necessary, or should an incident occur, records are available to
support an operator's inspection and investigation into the root cause
of a failure. Further, PHMSA currently requires (per Sec. 192.603(b)
and Sec. 192.605) operators to keep MAOP records for life of facility
but MAOP records established by Sec. 192.517(b) tests are just 5
years. PHMSA believes that these changes will improve the quality and
availability of test records, including records of leaks occurring
during testing activities and MAOP establishment records.
PHMSA understands this proposed amendment of an existing record
retention requirement to be reasonable, technically feasible, cost-
effective, and practicable. The proposed changes are incremental
supplementation of current requirements regarding recording and
retaining record of pressure tests operators are already required to
conduct. The proposed amendments require operators to document
information they may already be obtaining through the required tests
under this current requirement, more clearly states that information
which operators should record from the tests and extends the retention
period; PHMSA expects some operators may already be in their
substantial compliance with this proposed requirement. Viewed against
those considerations and the compliance costs estimated in the PRIA,
PHMSA expects its proposed amendments will be a cost-effective approach
to achieving the commercial, public safety, and environmental benefits
discussed in this NPRM and its supporting documents. Lastly, PHMSA
understands that its proposed compliance timeline--one year after
publication of a final rule (which would necessarily be in addition to
the time since publication of this NPRM)--would provide operators ample
time to implement requisite changes to their procedures to ensure
identification or generation of pertinent records (and manage any
related compliance costs).
4. Proposal To Amend Sec. 192.725--Test Requirements for Reinstating
Service Lines
PHMSA proposes to revise Sec. 192.725 to clarify that ``tested in
the same manner as a new service line'' in the existing regulation
means ``tested in accordance with subpart J of this part'', by
inserting that clarifying language within a parenthetical. PHMSA
understands that this proposed revision merely clarifies an existing
requirement and is therefore technically feasible and practicable.
PHMSA further notes that its proposed compliance timeline--one year
after publication of a final rule (which would necessarily be in
addition to the time since publication of this NPRM)--would provide
operators ample time to implement updates, if any are needed, to their
procedures.
K. Miscellaneous Amendments Pertaining to Part 192--Regulated Gas
Gathering Pipelines (Sections 192.3 and 192.9)
1. Current Requirements--Gas Gathering
Among the regulatory amendments adopted in the April 2022 Valve
Rule were enhanced emergency planning and notification requirements
applicable to all part 192-regulated gas pipeline operators subject to
Sec. 192.615, to include new references to public safety answering
points (such as 9-1-1 call centers) and a requirement for those
operators to update their written procedures to provide for timely
rupture identification; certain new, implementing definitions at Sec.
192.3 applicable to all part 192-regulated gas pipelines; and within a
new Sec. 192.635, a definition of the term ``notification of potential
rupture'' applicable to those part 192-regulated pipelines subject to
that provision.
The D.C. Circuit, however, vacated those new requirements as to gas
gathering pipelines in a decision issued in May 2023.\178\ PHMSA
subsequently issued a Technical Correction codifying the court's
decision by introducing exceptions to the above provisions restricting
their application to the part-192 regulated gas gathering pipelines to
which they had applied.\179\ Specifically, the Technical Correction
introduced language in each of the Sec. 192.3 definitions adopted in
the Valve Rule (``entirely replaced onshore transmission pipeline
segments''; ``notification of potential rupture''; and ``rupture-
mitigation valve (RMV)'') excepting all part 192-regulated gas
gathering pipelines from those definitions. The Technical Correction
also introduced a series of exceptions within the regulatory cross-
reference provision at Sec. 192.9 preventing application of the Valve
Rule's amendments at Sec. Sec. 192.615 and 192.635 regarding emergency
response and notification and rupture identification procedures to each
of offshore gas gathering pipelines (Sec. 192.9(b)) as well as onshore
Types A (Sec. 192.9(c)) and C (Sec. 192.9(e)) gas gathering
pipelines.
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\178\ GPA Midstream Assn. v. Dep't of Transp., 67 F.4th 1188,
1201 (D.C. Cir. 2023).
\179\ 88 FR at 50058, 50060-61 (Aug. 1, 2023).
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2. Need for Change--Gas Gathering
Written emergency planning and notification procedures are critical
tools for the safe operation of any gas pipeline. Offshore, Type A, and
Type C gas gathering pipelines had--consistent with the risks to public
safety and the environment posed by an emergency involving those high-
pressure, gas pipeline facilities \180\--been subject to extensive
emergency planning and notification requirements before issuance of the
Valve Rule in April 2022. Those long-standing safety standards include
requirements for operators to have written emergency procedures for
notifying, establishing, and maintaining communications with fire,
police, and other public officials (Sec. 192.615(a)(2) and (8); Sec.
192.615(c)); taking actions necessary to minimize hazards to public
safety from the emergency (Sec. 192.615(a)(6)); and directing operator
control room response actions in an emergency (Sec. 192.615(a)(11)).
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\180\ See, e.g., ``Gas Gathering Line Definition; Alternative
Definition for Onshore Lines and New Safety Standards--Final Rule,''
71 FR 13292, 13296-97 (Mar. 15, 2006) (discussing safety basis for
broadly extending part 192 requirements for gas transmission lines
to Type A gas gathering pipelines); 86 FR at 63284-85 (discussing
safety basis for extending Sec. 192.615 requirements to high-
pressure, large-diameter Type C gas gathering pipelines).
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The amendments to Sec. 192.615 introduced in the Valve Rule were
modest refinements to those long-standing emergencies response planning
and notification requirements. The Valve Rule explained its amendments
to Sec. 192.615(a)(2), (a)(8), and (c) adding language requiring
notification of, and communication with, public safety answering points
(PSAPs) or emergency coordination agencies ensure notifications of
pipeline emergencies are channeled to resources best positioned to
alert first responders and coordinate response efforts across multiple
jurisdictions that may be affected by a pipeline emergency.\181\ The
Valve Rule also made a pair of incremental changes to Sec.
192.615(a)(6)'s requirement that operator procedures provide for taking
certain actions--emergency shutdown or pressure reduction--to minimize
public safety risks. The first change was to add language (``including,
but not limited to . . .'') clarifying that operator procedures could
provide for actions
[[Page 61793]]
other than system shutdown or pressure reduction in an emergency,
thereby granting operators greater flexibility in designing response
actions best capable of minimizing hazards in a pipeline emergency;
this includes the additionally enumerated action of valve shut-off. The
second change included a reference to environmental hazards. Among
those hazards operator procedures must minimize, reflecting the fact
that the mechanism for public safety and environmental harms (namely,
the release of gas from a pipeline) is identical.
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\181\ 87 FR at 20969-70, 20973.
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The Valve Rule also made several regulatory amendments to address
the time-dependent \182\ risks to public safety and the environment
posed by ruptures on gas pipelines. First, the Valve Rule added at
Sec. 192.3 (which in turn references a new Sec. 192.935) the new term
``notification of potential rupture'' codifying commonly-understood
indicia of a rupture.\183\ The Valve Rule also added a pair of
requirements ensuring timely identification of, and response to, this
particular emergency in which every second lost can increase public
safety and environmental consequences: a new Sec. 192.615(a)(12)
requiring operators develop procedures for confirming actual ruptures
following reports of the indicia listed in the new definition of
``notification of potential rupture'', as well as language at Sec.
192.615(a)(8) introducing a new requirement for immediate and direct
notification of PSAPs on an operator's notification of a potential
rupture.\184\ Similarly, PHMSA enhanced a longstanding requirement at
Sec. 192.615(a)(11) governing emergency procedures for control room
personnel by adding a cross-reference to newly-adopted provisions
pertaining to rupture mitigation valves at Sec. Sec. 192.634 and
192.636.
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\182\ The severity of harms to public safety and the environment
from a rupture on a gas pipeline depend (inter alia) on the volume
of gas released, the duration of the release, and the time before
mitigation/response actions are initiated and completed.
\183\ 87 FR at 20949-52, 20972, 20972.
\184\ 87 FR 20952-53.
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Lastly, the Valve Rule adopted certain other definitions of terms
(``entirely replaced onshore transmission segment''; and ``rupture-
mitigation valve'') employed in its regulatory amendments.
3. Proposal To Amend Sec. Sec. 192.3 and 192.9--Emergency Procedures
and Notification; Rupture Identification Procedures
PHMSA proposes several amendments to restore certain emergency
planning, notification, and rupture identification procedures vacated
by the D.C. Circuit with respect to gas gathering pipelines. First,
PHMSA proposes to delete from each of the Sec. 192.3 definitions
introduced in the Technical Correction language disclaiming application
of those terms to any part 192-regulated gas gathering line.\185\
Second, PHMSA proposes to delete from Sec. 192.9 similar language
excluding application of the Valve Rule's amendments to Sec. 192.615
discussed in section IV.K.2 above to offshore gas gathering (Sec.
192.9(b)), Type A (Sec. 192.9(c)), and Type C (Sec. 192.9(e)) gas
gathering lines. This proposal is focused on application of these
emergency response provisions to gathering lines; PHMSA is not,
however, proposing in this rulemaking to restore application to part
192-regulated gas gathering lines of other regulatory amendments
adopted in the Valve Rule pertaining to rupture mitigation valve
installation, operation, and maintenance.
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\185\ PHMSA understands that in so doing, the Sec. 192.635
definition of ``notification of potential rupture'' referenced
within Sec. 192.3 would apply to all part 192-regulated gas
gathering pipelines as well.
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As explained in section IV.K.2 above, the Valve Rule's amendments
to Sec. 192.615 are incremental improvements on existing requirements
applicable to offshore, Type A, and Type C gas gathering pipelines.
Some of those amendments are broad in scope and are applicable to any
emergency on those gas gathering pipelines; others are specific to
ruptures on those pipelines. And each of those amendments is a common-
sense, baseline expectation ensuring operator emergency planning and
notification procedures are directed toward timely and effective
response and mitigation of risks to public safety and the environment.
PHMSA understands these proposed amendments would be reasonable,
technically feasible, cost-effective and practicable for affected gas
gathering pipeline operators. The restoration of definitions at Sec.
192.3 are not themselves operative provisions entailing compliance
burdens for operators; several of those definitions, moreover, are used
in operative provisions inapplicable to gas gathering pipelines. And
although the restored applicability of the Valve Rule's revisions to
Sec. 192.615 could entail additional compliance burdens for affected
gas gathering operators, some operators may already incorporate the
required content in their pipelines' emergency planning and
notification procedures; indeed, such procedures are precisely the sort
of procedures a reasonably prudent operator of any gas pipeline
facility would maintain in ordinary course given that their systems
transport commercially valuable, pressurized (natural flammable, toxic,
or corrosive) gasses. Viewed against those considerations and the
compliance costs estimated in the PRIA, PHMSA expects its proposed
amendments will be a cost-effective approach to achieving the public
safety, and environmental benefits discussed in this NPRM and its
supporting documents. Lastly, PHMSA understands that its proposed
compliance timeline--one year after publication of a final rule (which
would necessarily be in addition to the time since publication of this
NPRM)--would provide operators ample time to implement requisite
changes to their procedures (as well as manage any resulting compliance
costs).
V. Regulatory Analyses and Notices
A. Authority for This Rule
This proposed rule is published under the authority of the
Secretary of Transportation delegated to the PHMSA Administrator
pursuant to 49 CFR 1.97. Among the statutory authorities delegated to
PHMSA are those set forth in the Federal Pipeline Safety Statutes (49
U.S.C. 60101 et seq.). 49 U.S.C. 60102 grants authority to issue
standards for the transportation of gas via any part 192-regulated
gathering pipelines to protect public safety and the environment; and
49 U.S.C. 60102(b)(5) specifies that PHMSA must consider both public
safety and environmental benefits.
This NPRM proposes to implement several provisions of the PIPES Act
of 2020, including those codified at 49 U.S.C. 60102, 60105, 60106, and
60109. Section 60102 authorizes the Secretary of Transportation to
issue regulations governing the design, installation, inspection,
emergency plans and procedures, testing, construction, extension,
operation, replacement, and maintenance of gas pipeline facilities,
including gas transmission, gas distribution, offshore gas gathering,
and Types A, B, and C gas gathering pipelines, each of which would be
subject to various proposed requirements in this NPRM. Sections 60105
and 60106 permit States to assume safety authority over intrastate
pipelines, including gas and hazardous liquid pipelines, and
underground natural gas storage facilities through certifications or
agreements with PHMSA, while section 60107 authorizes the Secretary to
establish requirements governing award of grants supporting
[[Page 61794]]
State pipeline safety programs. Additionally, 49 U.S.C. 60117
authorizes the Secretary of Transportation to direct operators of those
gas pipeline facilities to submit reports to PHMSA to inform PHMSA's
regulatory oversight activities. As described above, 49 U.S.C. 60102,
60105, and 60109 also require the Secretary to issue regulations
updating PHMSA regulations in 49 CFR parts 192 and 198.
B. Executive Orders 12866 and 14094; DOT Regulatory Policies and
Procedures
Executive Order 12866 (``Regulatory Planning and Review''), as
amended by Executive Order 14094 (``Modernizing Regulatory Review''),
requires that agencies ``should assess all costs and benefits of
available regulatory alternatives, including the alternative of not
regulating.'' \186\ Agencies should consider quantifiable measures and
qualitative measures of costs and benefits that are difficult to
quantify. Further, Executive Order 12866 requires that agencies
maximize net benefits (including potential economic, environmental,
public health and safety, and other advantages; distributive impacts;
and equity), unless a statute requires another regulatory approach.
Similarly, DOT Order 2100.6A (``Rulemaking and Guidance Procedures'')
requires that regulations issued by PHMSA and other DOT Operating
Administrations should consider an assessment of the potential
benefits, costs, and other important impacts of the proposed action and
should quantify (to the extent practicable) the benefits, costs, and
any significant distributional impacts, including any environmental
impacts.
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\186\ E.O. 12866 is available at 58 FR 51735 (Oct. 4, 1993);
E.O. 14094 is available at 88 FR 21879 (Apr. 6, 2023).
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Executive Order 12866 (as amended by Executive Order 14094) and DOT
Order 2100.6A require that PHMSA submit ``significant regulatory
actions'' to the Office of Management and Budget (OMB) for review. The
proposed rule has been determined to be significant under section 3(f)
of Executive Order 12866 (as amended by section 1(b) of Executive Order
14094) and DOT Order 2100.6A and was reviewed by the Office of
Information and Regulatory Affairs (OIRA) within OMB.
Consistent with Executive Order 12866 (as amended by Executive
Order 14094) and DOT Order 2100.6A, PHMSA has prepared a PRIA assessing
the benefits and costs of the proposed rule as well as reasonable
alternatives. PHMSA estimates the proposed rule will result in
unquantified public safety and environmental benefits associated with
preventing and mitigating incidents on gas distribution and other part
192-regulated gas pipeline facilities. PHMSA estimates annualized costs
of $110 million per year (using a 3 percent discount rate) due to costs
associated with the proposed requirements for updating emergency
response plans, updating O&M manuals, keeping records, gas monitoring
by qualified employees, and assessing and upgrading district regulator
stations. For the full cost/benefit analysis, please see the PRIA in
the rulemaking docket. PHMSA seeks comment on the PRIA, its approach,
and the accuracy of its estimated costs and benefits.
C. Environmental Justice
Executive Order 12898 (``Federal Actions to Address Environmental
Justice in Minority Populations and Low-Income Populations''),\187\
directs Federal agencies to take appropriate and necessary steps to
identify and address disproportionately high and adverse effects of
Federal actions on the health or environment of minority and low-income
populations to the greatest extent practicable and permitted by law.
DOT Order 5610.2C (``U.S. Department of Transportation Actions to
Address Environmental Justice in Minority Populations and Low-Income
Populations'') establishes departmental procedures for effectuating
Executive Order 12898 promoting the principles of environmental justice
through full consideration of environmental justice principles
throughout planning and decision-making processes in the development of
programs, policies, and activities--including PHMSA rulemaking.
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\187\ 59 FR 7629 (Feb. 16, 1994).
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PHMSA has evaluated this NPRM under DOT Order 5610.2C and Executive
Order 12898 and has preliminarily determined it will not cause
disproportionately high and adverse human health and environmental
effects on minority and low-income populations. The proposed rule is
facially neutral and national in scope; it is neither directed toward a
particular population, region, or community, nor is it expected to
result in any adverse environmental or health impact any particular
population, region, or community. Rather, PHMSA anticipates the
rulemaking will reduce the safety and environmental risks associated
with losses of integrity on gas pipeline facilities--particularly gas
distribution pipelines in urban or rural areas posing higher risks due
to their vintage, material, and proximity to minority and low-income
communities in the vicinity of those pipelines.\188\ Lastly, as
explained in the draft environmental assessment in the rulemaking
docket, PHMSA anticipates that the regulatory amendments in this
proposed rule will yield greenhouse gas emissions reductions, thereby
reducing the risks posed by anthropogenic climate change to minority
and low-income, populations, underserved and other disadvantaged
communities. This finding is consistent with the most recent
Environmental Justice Executive Order 14096--Revitalizing Our Nation's
Commitment to Environmental Justice for All, by achieving several goals
including continuing to deepen the Administration's whole of government
approach to environmental justice and to better protect overburden
communities from pollution and environmental harms.
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\188\ See, e.g., Luna & Nicholas, ``An Environmental Justice
Analysis of Distribution-Level Natural Gas Leaks in Massachusetts,
USA,'' 162 Energy Policy 112778 (Mar. 2022); Weller et al.,
``Environmental Injustices of Leaks from Urban Natural Gas
Distribution Systems: Patterns Among and Within 13 U.S. Metro
Areas,'' Environ. Sci & Tech. (May 11, 2022).
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D. Regulatory Flexibility Act
The Regulatory Flexibility Act, as amended by the Small Business
Regulatory Flexibility Fairness Act of 1996 (5 U.S.C. 601 et seq.),
generally requires Federal agencies to prepare an initial regulatory
flexibility analysis (IRFA) for a proposed rule subject to notice-and-
comment rulemaking under the Administrative Procedure Act. 5 U.S.C.
603(a).\189\ Executive Order 13272 (``Proper Consideration of Small
Entities in Agency Rulemaking'') \190\ obliges agencies to establish
procedures promoting compliance with the Regulatory Flexibility Act;
DOT's implementing guidance is available on its website.\191\
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\189\ Agencies are not required to conduct an IRFA if the head
of the agency certifies that the proposed rule will not have a
significant impact on a substantial number of small entities. 5
U.S.C. 605.
\190\ 67 FR 53461 (Aug. 16, 2002).
\191\ DOT, ``Rulemaking Requirements Concerning Small
Entities'', https://www.transportation.gov/regulations/rulemaking-requirements-concerning-small-entities (last updated May 18. 2012).
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This NPRM was developed in accordance with Executive Order 13272
and DOT guidance to ensure compliance with the Regulatory Flexibility
Act and provide appropriate consideration of the potential impacts of
the rulemaking on small entities. PHMSA conducted an IRFA, which has
been made available in the docket for this rulemaking and is summarized
below. A description of the reasons why
[[Page 61795]]
PHMSA is considering this action and a succinct statement of the
objectives of, and legal basis for, the proposed rule are described
elsewhere in the preamble for this rule and not repeated here. PHMSA
seeks comment on whether the proposed rule, if adopted, would have a
significant economic impact on a significant number of small entities.
Description and Estimate of the Number of Small Entities to Which the
Proposed Rule Would Apply
PHMSA analyzed privately owned entities (inclusive of investor-
owned entities) that could be impacted by the rule, which include
companies with natural gas extraction, pipeline transportation, and
natural gas distribution businesses, as well as entities with another
primary business. PHMSA determined whether these entities were small
entities based on the size of the parent entity and using the relevant
SBA size standards set out in Table 43 of the PRIA. PHMSA also analyzed
publicly owned entities that could be impacted by the rule, including
State, municipal, and other political subdivision entities. Publicly
owned entities with population less than 50,000 are considered small.
PHMSA identified 1,239 gas distribution parent entities and
determined that of these parent entities, 92 percent (1,135 parent
entities) are classified as ``small'' based on the relevant criteria
listed above. PHMSA also identified 831 gas transmission and gathering
parent entities in this analysis that do not also operate distribution
systems. Of these gas transmission and gas gathering parent entities,
82 percent are classified as ``small'' (681 parent entities). Because
PHMSA did not have sufficient information to individually categorize
master meter operators or operators of small LPGs by size, PHMSA
conservatively made the over-inclusive decision to consider all master
meter operators and operators of small LPGs to be small entities for
purposes of its analysis.
Description of Projected Reporting, Recordkeeping, and Other Compliance
Requirements of the Proposed Rule, Including an Estimate of the Classes
of Small Entities Which Would Be Subject to the Requirement and the
Type of Professional Skills Necessary for Preparation of the Report or
Record
PHMSA analyzed the costs of compliance for the small gas
distribution, gas transmission and gathering, and master meter and
small LPG operators. PHMSA assessed the annualized cost for gas
distribution operators based on the number of services, and provided a
minimum, average, and maximum annualized cost estimate for each size
category. For small gas distribution operators with 100,000 or fewer
services, PHMSA calculated annualized estimated compliance costs that
ranged from $8,051 to $10,528 depending on the cost scenario and
discount rate.\192\ For gas transmission and gathering operators, PHMSA
calculated minimum, average, and maximum annualized estimated
compliance costs that ranged from $44 to $52,029 depending on the cost
scenario, industry type (transmission or gathering), and discount rate.
For small master meter systems, PHMSA estimated pre-tax annualized
compliance costs for individual operators from $4,421 to $4,590,
depending on the discount rate. For small LPG systems, PHMSA estimated
pre-tax annualized compliance costs for individual operators from
$4,764 to $4,928, again depending on the discount rate.
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\192\ See PRIA Table 45.
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PHMSA then calculated cost-to-revenue ratios using the calculated
compliance costs of each small parent entity. PHMSA estimated that 98
percent of small gas distribution parent entities will face after-tax
compliance costs of less than 1 percent of revenue under all evaluated
cost scenarios. PHMSA estimated that 80 to 82 percent of small gas
transmission parent entities operators will incur after-tax compliance
costs of less than 1 percent of revenue. Under the maximum cost
scenario, PHMSA estimates that 1 percent of small parent entities will
incur compliance costs above 1 percent but below 3 percent of revenue.
Under this maximum cost scenario, PHMSA also estimates that one small
parent entity will incur compliance costs above 3 percent of revenue.
However, PHMSA believes the maximum cost scenario is unlikely, as it
assumes the entirety of estimated new and replaced lines are
attributable to a single operator.\193\ For master meter operators and
operators of small LPGs, PHMSA calculated the break-even value of
annual revenue that would be required for their calculated after-tax
compliance costs to be 1 percent and 3 percent of revenue. For master
meter operators, PHMSA estimated that revenue would need to be $442,122
or less for compliance costs to be 1 percent of revenue and that
revenue would need to be $147,374 or less for compliance costs to be 3
percent of revenue. For operators of small LPGs, PHMSA estimated that
revenue would need to be $476,357 or less for compliance costs to be 1
percent of revenue and that revenue would need to be $158,786 or less
for compliance costs to be 3 percent of revenue.
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\193\ For the other 18% of operators, PHMSA did not have
sufficient data to calculate the revenue percentage for the
compliance costs of the rule at this time. PHMSA seeks comment on
compliance costs generally, but in particular for transmission and
gathering operators for which sufficient data was not available.
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Relevant Federal Rules Which May Duplicate, Overlap or Conflict With
the Proposed Rule
PHMSA did not identify any Federal rules that may duplicate,
overlap, or conflict with the proposed rule. In Section 7.6 of the PRIA
accompanying this NPRM, PHMSA provides details on other Federal
regulations that may impact operators of gas pipelines.
Description and Analysis of Significant Alternatives to the Proposed
Rule Considered
PHMSA analyzed a number of alternatives to the NPRM, which are
described in detail in Section 2 of the PRIA accompanying this NPRM. In
addition to retaining the status quo and not issuing the proposal,
which PHMSA determined would fail to satisfy PIPES Act mandates to
improve safety and update PHMSA regulations, PHMSA also analyzed:
1. Retaining DIMP requirements for small LPG operators and imposing
the updated DIMP requirements of this NPRM on those same operators.
2. Extending to all part 192-regulated pipelines an exception that
currently allows, for distribution mains only, distribution operator
personnel involved in the same construction task to inspect each
other's work.
3. An alternative compliance date.
4. Imposing an ICS requirement for emergency response.
5. Requiring all future construction projects associated with
installations, modifications, replacements, or system upgrades on gas
distribution pipelines to have licensed professional engineer approval
and stamping.
6. Requiring gas distribution operators to develop and follow an
MOC process as outlined in ASME/ANSI B31.8S.
PHMSA did not identify any viable alternative that could accomplish
the stated objectives of applicable statutes while further minimizing
any significant economic impact of the proposed rule on small entities.
As discussed in more detail elsewhere in this preamble and in Section 2
of the PRIA for this NPRM, PHMSA determined that these requirements
could result in reductions in safety benefits that were not justified
by any potential cost savings (e.g., the proposal
[[Page 61796]]
to extend the exception for distribution mains that allows distribution
operator personnel to inspect each other's work on the same
construction task to all part-192 regulated pipelines) or impose costs
on small entities that were not justified by any increased safety
benefits. PHMSA therefore declined to propose these alternatives but
seeks comment on them in this proposed rule.
E. Executive Order 13175: Consultation and Coordination With Indian
Tribal Governments
PHMSA analyzed this proposed rule in accordance with the principles
and criteria contained in Executive Order 13175 (``Consultation and
Coordination with Indian Tribal Governments'') \194\ and DOT Order
5301.1A (``Department of Transportation Programs, Policies, and
Procedures Affecting American Indians, Alaska Natives, and Tribes'').
Executive Order 13175 requires agencies to ensure meaningful and timely
input from Tribal government representatives in the development of
rules that significantly or uniquely affect Tribal communities by
imposing ``substantial direct compliance costs'' or ``substantial
direct effects'' on such communities, or the relationship or
distribution of power between the Federal Government and Tribes.
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\194\ 65 FR 67249 (Nov. 6, 2000).
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PHMSA assessed the impact of the proposed rule and does not expect
it will significantly or uniquely affect Tribal communities or Indian
Tribal governments. The proposed rule's regulatory amendments are
facially neutral and will have broad, national scope. PHMSA, therefore,
does not expect this rule to significantly or uniquely affect Tribal
communities, impose substantial compliance costs on Native American
Tribal governments, or mandate Tribal action. And insofar as PHMSA
expects the NPRM will improve safety and reduce environmental risks
associated with gas distribution pipelines, PHMSA expects it will not
entail disproportionately high adverse risks for Tribal communities.
Therefore, PHMSA concludes that the funding and consultation
requirements of Executive Order 13175 and DOT Order 5301.1A do not
apply to this proposed rule.
While PHMSA is not aware of specific Tribal-owned business entities
that operate part 192-regulated gas pipelines, any such business
entities could be subject to direct compliance costs as a result of
this proposed rule. PHMSA seeks comment on the applicability of
Executive Order 13175 to this proposed rule and the existence of any
Tribal-owned business entities operating pipelines affected by the
proposed rule (along with the extent of such potential impacts).
F. Paperwork Reduction Act
Pursuant to 5 CFR 1320.8(d), PHMSA is required to provide
interested members of the public and affected agencies with an
opportunity to comment on information collection and recordkeeping
requests. If adopted, the proposals in this rulemaking would impose new
notification and recordkeeping requirements for all part 192-regulated
pipelines, including gas distribution, gas transmission and gathering
pipelines.
PHMSA proposes to require gas distribution operators to review
their integrity management plans to ensure that the plans identify
specific threats such as: (1) certain materials, such as cast iron and
other piping with known issues, (2) the age of each component of the
operator's pipelines along with the overall age of its system, (3)
overpressurization of low-pressure systems, and (4) extreme weather and
geohazards. PHMSA also proposes that, when identifying and implementing
measures to address those risks, operators must address (at a minimum)
the risks associated with each of the following: the presence of known
issues, the age of each part of a pipeline along with the overall age
of the system, and (for operators of low-pressure gas distribution
systems) overpressurization. PHMSA plans to revise the ``Pipeline
Safety: Integrity Management Program for Gas Distribution Pipelines''
information collection that is currently approved under OMB Control No.
2137-0625 to include this new requirement. Since pipeline operators are
already required to review and update their integrity management plans
on a regular basis, PHMSA expects operators to incur minimal burden in
complying with this information collection request.
PHMSA also proposes to repeal the requirement for operators of
small LPGs to participate in the distribution integrity management
program. Based on a recent study, PHMSA estimates there are as many as
4,492 small LPG operators. PHMSA proposes to create a new form, PHMSA
Form 7100.1-2, to collect limited data from these operators of small
LPGs on an annual basis. As a result, PHMSA expects the burden of the
``Pipeline Safety: Integrity Management Program for Gas Distribution
Pipelines'' information collection under OMB Control No. 2137-0625 to
be reduced and the burden for information collection under OMB Control
No. 2137-0522 for the collection of annual and incident report data to
increase due to the creation of the new form. Specifically, PHMSA
expects each small LPG operator to spend 6 hours, annually, completing
the new report form, resulting in an increase of 4,492 responses and
26,952 hours to the overall burden for the information collection under
OMB Control No. 2137-0522. For the information collection under OMB
Control No. 2137-0625, PHMSA previously estimated there were 2,539
operators of small LPG systems. Consequently, PHMSA expects the burden
of that currently approved collection to be reduced by 2,539 responses
and 66,014 hours due to the removal of small LPG operators. PHMSA also
plans to revise the ``Gas Distribution Annual Report Form F7100.1-1''
information collection currently approved under OMB Control No. 2137-
0629 to include the newly proposed requirements. For gas distribution
pipelines, PHMSA proposes to collect additional information such as the
number and miles of low-pressure service pipelines, including their
overpressure protection methods.
PHMSA proposes codifying within the pipeline safety regulations its
State Inspection Calculation Tool (SICT). The SICT is one of many
factors used to help states determine the base level amount of time
needed for administering adequate pipeline safety programs and is a
consideration when PHMSA awards grants to states supporting those
programs. PHMSA plans to revise the ``Gas Pipeline Safety Program
Performance Progress Report'' and ``Hazardous Liquid Pipeline Safety
Program Performance Progress Report'' information collection currently
approved under OMB Control No. 2137-0584 to account for the burden
incurred by state representatives to report data via the SICT.
Operators are required to maintain records pertaining to various
aspects of their pipeline systems. Under the proposals in this
rulemaking, PHMSA would expand the recordkeeping requirements for all
gas pipeline operators. Operators would be required to revise their
emergency response plans to include procedures ensuring prompt and
effective response by adding emergencies involving a release of gas
that results in a fatality, as well as any other emergency deemed
significant by the operator. In the event of a release of gas resulting
in one or more fatalities, all operators would also be required to
immediately and directly notify emergency response officials upon
receiving notice of the same. For distribution pipeline operators only,
[[Page 61797]]
PHMSA's proposed expansion of the list of emergencies discussed above
would also include the unintentional release of gas and shutdown of gas
service to 50 or more customers (or 50 percent of its customers if it
has fewer than 100 total customers). Operators would need to
immediately and directly notify emergency response officials on
receiving notice of the same.
PHMSA also proposes a series of regulatory amendments requiring gas
distribution operators to update their emergency response plans to
improve communications with the public during an emergency. First,
PHMSA proposes to introduce a new requirement for gas distribution
operators to establish and maintain communications with the general
public as soon as practicable during an emergency. Second, PHMSA
proposes to add a new requirement for gas distribution pipeline
operators to develop and implement, no later than 18 months after the
publication of any final rule in this proceeding, an opt-in system to
keep their customers informed of the status of pipeline safety in their
communities should an emergency occur. PHMSA also proposes a new
requirement for gas distribution operators to notify their customers
and public officials in certain instances. PHMSA plans to create a new
information collection to cover these notification requirements for gas
distribution operators. PHMSA will request a new Control Number from
OMB for these information collections. PHMSA will submit these
information collection requests to OMB for approval based on the
proposed requirements in this rule.
Operators would also be required to review and update their O&M
manuals as needed pursuant to the proposal. Gas distribution operators
would also be required to document and maintain records on their MOC
processes and additional safety procedures. Further, PHMSA proposes
that all gas distribution pipeline operators identify and maintain
traceable, verifiable, and complete maps and records documenting the
characteristics of their systems that are critical to ensuring proper
pressure controls for their gas distribution pipeline systems and to
ensure that those records are accessible to anyone performing or
supervising design, construction, and maintenance activities on their
systems. PHMSA proposes to specify that these required records include
(1) the maps, location, and schematics related to underground piping,
regulators, valves, and control lines; (2) regulator set points, design
capacity, and valve-failure mode (open/closed); (3) the system's
overpressure-protection configuration; and (4) any other records deemed
critical by the operator. PHMSA proposes to require that the operator
maintain these integrity-critical records for the life of the pipeline
because these records are critical to the safe operation and pressure
control of a gas distribution system. PHMSA plans to revise the
``Recordkeeping Requirements for Gas Pipeline Operators'' information
collection currently approved under OMB Control No. 2137-0049 to
include the newly proposed recordkeeping requirements. PHMSA expects
the impact to be minimal and absorbed by the currently approved burden
for this information collection.
The information collections in this proposed rule would be required
through the proposed amendments to the pipeline safety regulations, 49
CFR 190-199. The following information is provided for each information
collection: (1) Title of the information collection; (2) OMB control
number; (3) Current expiration date; (4) Type of request; (5) Abstract
of the information collection activity; (6) Description of affected
public; (7) Estimate of total annual reporting and recordkeeping
burden; and (8) Frequency of collection. The information collection
burden under the proposed rule is estimated as follows:
1. Title: Pipeline Safety: Integrity Management Program for Gas
Distribution Pipelines.
OMB Control Number: 2137-0625.
Current Expiration Date: 5/31/2024.
Abstract: The pipeline safety regulations require operators of gas
distribution pipelines to develop and implement integrity management
(IM) programs. The purpose of these programs is to enhance safety by
identifying and reducing pipeline integrity risks. PHMSA requires
operators to maintain records demonstrating compliance with this
information collection for 10 years. PHMSA uses the information to
evaluate the overall effectiveness of gas distribution Integrity
Management requirements.
PHMSA proposes to repeal the requirement for operators of small
LPGs to participate in the distribution IM program. PHMSA previously
estimated that there were 2,539 operators of small LPG systems.
Consequently, PHMSA expects the burden of this information collection
to be reduced by 2,539 responses and 66,014 hours due to the removal of
small LPG operators.
Affected Public: Owners and operators of gas distribution
pipelines.
Annual Reporting Burden:
Total Annual Responses: 1,343.
Total Annual Burden Hours: 657,178.
Frequency of Collection: On occasion.
2. Title: Recordkeeping Requirements for Gas Pipeline Operators.
OMB Control Number: 2137-0049.
Current Expiration Date: 3/31/2025.
Abstract: This mandatory information collection request would
require owners and/or operators of gas pipeline systems to make and
maintain records in accordance with the requirements prescribed in 49
CFR part 192 and to provide information to the Secretary of
Transportation at the Secretary's request. Certain records are
maintained for a specific length of time while others are required to
be maintained for the life of the pipeline. PHMSA uses these records to
verify compliance with regulated safety standards and to inform the
agency on possible safety risks.
Affected Public: Operators of gas pipeline systems.
Annual Reporting Burden:
Total Annual Responses: 4,056,052.
Total Annual Burden Hours: 5,031,086.
Frequency of Collection: On occasion.
3. Title: Emergency Notification Requirements for Gas Operators.
OMB Control Number: Will Request from OMB.
Current Expiration Date: TBD.
Abstract: This information collection covers the requirement for
owners and operators of gas distribution pipelines to notify their
customers and public officials in the event of certain instances
pertaining to pipeline safety. PHMSA estimates there will be an average
of 75 incidents per year where gas distribution operators will need to
make such notifications. PHMSA expects gas distribution operators will
spend approximately 8 hours notifying the public in each instance,
resulting in an annual burden of 600 hours. PHMSA expects gas
distribution operators to spend an additional 2 hours per incident
notifying their customers, resulting in an added burden of 150 hours.
PHMSA also requires operators of all gas pipelines to notify and
communicate with emergency responders if gas is detected inside or near
a building; fire is located near or directly involving a pipeline
facility; and explosion occurs near or directly involving a pipeline
facility; or in the event of a natural disaster. Based on incident
report trends, PHMSA expects there to be 44 incidents (1 gas gathering,
16 gas transmission, 27 gas distribution) annually, which would require
gas operators to notify emergency responders. PHMSA estimates each
notification will take 2 hours per incident resulting in an annual
burden of 88 hours.
[[Page 61798]]
Affected Public: Owners and operators of gas pipelines.
Annual Reporting Burden:
Total Annual Responses: 194.
Total Annual Burden Hours: 838.
Frequency of Collection: On occasion.
4. Title: Annual and Incident Report for Gas Pipeline Operators.
OMB Control Number: 2137-0522.
Current Expiration Date: 03/31/2026.
Abstract: This mandatory information collection covers the
collection of data from operators of natural gas pipelines, underground
natural gas storage facilities, and liquefied natural gas (LNG)
facilities for annual reports. 49 CFR 191.17 requires operators of
underground natural gas storage facilities, gas transmission systems,
and gas gathering systems to submit an annual report by March 15 for
the preceding calendar year. The Gas Distribution NPRM proposes to
collect limited data from operators of small LPGs. PHMSA proposes to
create Form F7100.1-2. to collect this data, ``Small LPG Annual Report
Form F7100.1-2.'' The burden for this information collection is being
revised to account for this new data collection. PHMSA estimates that
4,492 small LPG operators will spend 6 hours annually completing this
new report resulting in an increase of 4,492 responses and 26,952 hours
to the currently approved burden for this information collection.
Affected Public: Owners and operators of gas distribution
pipelines.
Annual Reporting Burden:
Total Annual Responses: 7,813.
Total Annual Burden Hours: 122,763.
Frequency of Collection: Annually.
5. Title: Gas Pipeline Safety Program Performance Progress Report
and Hazardous Liquid Pipeline Safety Program Performance Progress
Report.
OMB Control Number: 2137-0584.
Current Expiration Date: 5/31/2025.
Abstract: 49 U.S.C. 60105 sets forth specific requirements a State
must meet to qualify for certification status to assume regulatory and
enforcement responsibility for intrastate pipelines, i.e., state
adoption of minimum Federal safety standards, state inspection of
pipeline operators to determine compliance with the standards, and
state provision for enforcement sanctions substantially the same as
those authorized by Chapter 601, Title 49 of the U.S. Code. A State
must submit an annual certification to assume responsibility for
regulating intrastate pipelines, and states who receive Federal grant
funding must have adequate damage prevention plans and associated
records in place. PHMSA uses this information to evaluate a State's
eligibility for Federal grants and to enforce regulatory compliance.
This information collection request requires a participating State to
annually submit a Gas Pipeline Safety Program Performance Progress
Report and Hazardous Liquid Pipeline Safety Program Performance
Progress Report to PHMSA's Office of Pipeline Safety (OPS) signifying
compliance with the terms of the certification and to maintain records
detailing a damage prevention plan for PHMSA inspectors whenever
requested. The purpose of the collection is to exercise oversight of
the grant program and to ensure that States are compliant with Federal
pipeline safety regulations. PHMSA is revising this information
collection to include the reporting of inspection data via the State
Inspection Calculation Tool (SICT). PHMSA expects 66 State
representatives to submit data pertaining to the number of safety
inspectors employed in their pipeline safety programs via the SICT.
PHMSA estimates that, on average, State representatives will spend 8
hours annually compiling and submitting SICT data.
Affected Public: Pipeline operators applying for State grants.
Annual Reporting Burden:
Total Annual Responses: 183.
Total Annual Burden Hours: 5,001.
Frequency of Collection: Annual.
6. Title: Annual for Gas Distribution Operators.
OMB Control Number: 2137-0629.
Current Expiration Date: 06/30/2026.
Abstract: This mandatory information collection request would
require operators of gas distribution pipeline systems to submit annual
report data to the Office of Pipeline Safety in accordance with the
regulations stipulated in 49 CFR part 191 by way of form PHMSA F
7100.1-1. The form is to be submitted once for each calendar year. The
annual report form collects data about the pipe material, size, and
age. The form also collects data on leaks from these systems as well as
excavation damages. PHMSA uses the information to track the extent of
gas distribution systems and normalize incident and leak rates.
The Gas Distribution NPRM proposes to revise the Annual Report for
Gas Distribution Operators, form PHMSA F 7100.1-1, to collect
additional information on gas distribution systems such as the number
and miles of low-pressure service pipelines, including their
overpressure protection methods.
The current approved burden for gas distribution operators to
complete this report is 20 hours, annually. As a result of the proposed
change, the burden for completing PHMSA F 7100.1-collection is being
increased by 6 hours annually, resulting in an overall burden of 26
hours, per annual report, for gas distribution operators.
Affected Public: Owners and operators of gas distribution
pipelines.
Annual Reporting Burden:
Total Annual Responses: 1,446.
Total Annual Burden Hours: 37,596.
Frequency of Collection: Annually.
Requests for a copy of these information collections should be
directed to Angela Hill via email at [email protected] or via
telephone (202) 366-4595.
Comments are invited on:
(a) The need for the proposed collection of information for the
proper performance of the functions of the agency, including whether
the information will have practical utility;
(b) The accuracy of the agency's estimate of the burden of the
revised collection of information, including the validity of the
methodology and assumptions used;
(c) Ways to enhance the quality, utility, and clarity of the
information to be collected;
(d) Ways to minimize the burden of the collection of information on
those who are to respond, including the use of appropriate automated,
electronic, mechanical, or other technological collection techniques;
and
(e) Ways the collection of this information is beneficial or not
beneficial to public safety.
Send comments directly to the Office of Management and Budget,
Office of Information and Regulatory Affairs, Attn: Desk Officer for
the Department of Transportation, 725 17th Street NW, Washington, DC
20503.
G. Unfunded Mandates Reform Act of 1995
The Unfunded Mandates Reform Act (UMRA, 2 U.S.C. 1501 et seq.)
requires agencies to assess the effects of Federal regulatory actions
on State, local, and Tribal governments, and the private sector. For
any NPRM or final rule that includes a Federal mandate that may result
in the expenditure by State, local, and Tribal governments, in the
aggregate of $100 million or more (in 1996 dollars) in any given year,
the agency must prepare, amongst other things, a written statement that
qualitatively and quantitatively assesses the costs and benefits of the
Federal mandate.
As explained further in the PRIA, PHMSA does not expect that the
proposed rule will impose enforceable duties on State, local, or Tribal
governments or on the private sector of $100 million or more (in 1996
dollars) in any one year. A copy of the PRIA is
[[Page 61799]]
available for review in the docket. Therefore, the requirement to
prepare a statement pursuant to UMRA does not apply.
H. National Environmental Policy Act
The National Environmental Policy Act of 1969 (NEPA, 42 U.S.C. 4321
et seq.) requires Federal agencies to prepare a detailed statement on
major Federal actions significantly affecting the quality of the human
environment. The Council on Environmental Quality's implementing
regulations (40 CFR parts 1500-1508) require Federal agencies to
conduct an environmental review considering (1) the need for the
action, (2) alternatives to the action, (3) probable environmental
impacts of the action and alternatives, and (4) the agencies and
persons consulted during the consideration process. DOT Order 5610.1C
(``Procedures for Considering Environmental Impacts'') establishes
departmental procedures for evaluation of environmental impacts under
NEPA and its implementing regulations.
PHMSA has completed a draft environmental assessment and expects
that an environmental impact statement will not be required for this
rulemaking because it will not have a significant impact on the human
environment. To the extent that the proposed rule could impact the
environment, PHMSA expects those impacts will be primarily beneficial
impacts from reducing the likelihood and consequences of incidents on
gas distribution pipelines and other part 192-regulated gas pipelines.
A copy of the draft environmental assessment is available in the
docket. PHMSA invites comment on the potential environmental impacts of
this proposed rule.
I. Executive Order 13132: Federalism
PHMSA has analyzed this proposed rule in accordance with the
principles and criteria contained in Executive Order 13132
(``Federalism'') \195\ and the Presidential Memorandum titled
``Preemption.'' \196\ Executive Order 13132 requires agencies to ensure
meaningful and timely input by State and local officials in the
development of regulatory policies that may have ``substantial direct
effects on the states, on the relationship between the national
government and the states, or on the distribution of power and
responsibilities among the various levels of government.''
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\195\ 64 FR 43255 (Aug. 10, 1999).
\196\ 74 FR 24693 (May 22, 2009).
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PHMSA does not expect this proposed rule will have a substantial
direct effect on State and local governments, the relationship between
the Federal Government and the States, or the distribution of power and
responsibilities among the various levels of government. The provisions
proposed involving SICT codify in regulation existing practice and do
not impose any noteworthy additional direct compliance costs on State
and local governments.
States are generally prohibited by 49 U.S.C. 60104(c) from
regulating the safety of interstate pipelines. States that have
submitted a current certification under 49 U.S.C. 60105(a) can augment
Federal pipeline safety requirements for intrastate pipelines regulated
by PHMSA but may not approve safety requirements less stringent than
those required by Federal law. A State may also regulate an intrastate
pipeline facility that PHMSA does not regulate.
In this instance, the preemptive effect of the proposed rule would
be limited to the minimum level necessary to achieve the objectives of
the statutory authority under which the proposed rule is promulgated.
While the 49 CFR part 192 safety requirements in this proposed rule
may, if adopted in a final rule, preempt some State requirements,
preemption arises by operation of 49 U.S.C. 60104, and this proposed
rule would not impose any regulation that has substantial direct
effects on the states, the relationship between the national government
and the states, or the distribution of power and responsibilities among
the various levels of government. Therefore, the PHMSA has determined
that the consultation and funding requirements of Executive Order 13132
do not apply to this proposed rule.
J. Executive Order 13211: Significant Energy Actions
Executive Order 13211 (``Actions Concerning Regulations That
Significantly Affect Energy Supply, Distribution, or Use'') \197\
requires Federal agencies to prepare a Statement of Energy Effects for
any ``significant energy action.'' Executive Order 13211 defines a
``significant energy action'' as any action by an agency (normally
published in the Federal Register) that promulgates or is expected to
lead to the promulgation of a final rule or regulation that (1)(i) is a
significant regulatory action under Executive Order 12866 or any
successor order, and (ii) is likely to have a significant adverse
effect on the supply, distribution, or use of energy; or (2) is
designated by OIRA as a significant energy action.
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\197\ 66 FR 28355 (May 22, 2001).
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This proposed rule is not anticipated to be a ``significant energy
action'' under Executive Order 13211. It is not likely to have a
significant adverse effect on the supply, distribution, or use of
energy. Further, the OIRA has not designated this proposed rule as a
significant energy action.
K. Privacy Act Statement
In accordance with 5 U.S.C. 553(c), DOT solicits comments from the
public to better inform its rulemaking process. DOT posts these
comments without edit, including any personal information the commenter
provides, to https://www.regulations.gov, as described in the system of
records notice (DOT/ALL-14 FDMS), which can be reviewed at https://www.dot.gov/privacy.
L. Regulation Identifier Number
A regulation identifier number (RIN) is assigned to each regulatory
action listed in the Unified Agenda of Regulatory and Deregulatory
Actions (Unified Agenda). The RIN contained in the heading of this
document can be used to cross-reference this action with the Unified
Agenda.
M. Executive Order 13609 and International Trade Analysis
Executive Order 13609 (``Promoting International Regulatory
Cooperation'') \198\ requires agencies to consider whether the impacts
associated with significant variations between domestic and
international regulatory approaches are unnecessary or may impair the
ability of American business to export and compete internationally. In
meeting shared challenges involving health, safety, labor, security,
environmental, and other issues, international regulatory cooperation
can identify approaches that are at least as protective as those that
are or would be adopted in the absence of such cooperation.
International regulatory cooperation can also reduce, eliminate, or
prevent unnecessary differences in regulatory requirements.
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\198\ 77 FR 26413 (May 4, 2012).
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Similarly, the Trade Agreements Act of 1979 (Pub. L. 96-39), as
amended by the Uruguay Round Agreements Act (Pub. L. 103-465),
prohibits Federal agencies from establishing any standards or engaging
in related activities that create unnecessary obstacles to the foreign
commerce of the United States. For purposes of these requirements,
Federal agencies may participate in the establishment of international
standards so long as the standards have a legitimate domestic
objective, such as providing for safety,
[[Page 61800]]
and do not operate to exclude imports that meet this objective. The
statute also requires consideration of international standards and,
where appropriate, that they serve as the basis for U.S. standards.
PHMSA participates in the establishment of international standards to
protect the safety of the American public.
PHMSA assessed the effects of the proposed rule and expects that it
will not cause unnecessary obstacles to foreign trade.
N. Cybersecurity and Executive Order 14028
Executive Order 14028 (``Improving the Nation's Cybersecurity'')
\199\ directed the Federal government to improve its efforts to
identify, deter, and respond to ``persistent and increasingly
sophisticated malicious cyber campaigns.'' Accordingly, PHMSA has
assessed the effects of this NPRM to determine what impact the proposed
regulatory amendments may have on cybersecurity risks for pipeline
facilities and has preliminarily determined that this NPRM will not
materially affect the cybersecurity risk profile for pipeline
facilities.
---------------------------------------------------------------------------
\199\ 86 FR 26633 (May 17, 2021).
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Operator DIMPs, O&M manuals and procedures, and facility design
standards are largely static materials; because those materials are not
means of manipulating pipeline operations in real-time, PHMSA's
proposed amendments of requirements governing those materials are
therefore unlikely to increase the risk of cybersecurity incidents.
Although other proposals within the NPRM--in particular, real-time
overpressurization monitoring and customer opt-in/opt-out emergency
communication systems--may offer more attractive targets for
cybersecurity incidents, PHMSA understands the incremental additional
risk from the NPRM's proposed regulatory amendments to be minimal.
Operator compliance strategies for these proposed requirements will be
subject to current Transportation Security Agency (TSA) pipeline
cybersecurity directives; \200\ PHMSA further understands Cybersecurity
& Infrastructure Security Agency (CISA) and the Pipeline Cybersecurity
Initiative (PCI) of the U.S. Department of Homeland Security conduct
ongoing activities to address cybersecurity risks to U.S. pipeline
infrastructure and may introduce other cybersecurity requirements and
guidance for gas pipeline operators.\201\ Lastly, because PHMSA expects
that this NPRM's proposed regulatory amendments (notably those
regarding emergency response planning) will reduce the severity of any
gas pipeline incidents that occur, this rulemaking could reduce the
public safety and the environmental consequences in the event of a
cybersecurity incident on a gas pipeline.
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\200\ E.g., TSA, ``Ratification of Security Directive,'' 86 FR
38209 (July 20, 2021) (ratifying TSA Security Directive Pipeline-
2012-01, which requires certain pipeline owners and operators to
conduct actions to enhance pipeline cybersecurity).
\201\ See, e.g., CISA, National Cyber Awareness System Alerts,
https://www.cisa.gov/uscert/ncas/alerts (last accessed Feb. 1,
2023).
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M. Severability
The purpose of this proposed rule is to operate holistically in
addressing a panoply of issues necessary to ensure safe operation of
regulate pipelines, with a focus on gas distribution pipelines'
protection against overpressurization events. However, PHMSA recognizes
that certain provisions focus on unique topics. Therefore, PHMSA
preliminarily finds that the various provisions of this proposed rule
are severable and able to function independently if severed from each
other. In the event a court were to invalidate one or more of the
unique provisions of any final rule issued in this proceeding, the
remaining provisions should stand, thus allowing their continued
effect.
List of Subjects
49 CFR Part 191
Liquefied petroleum gas, Pipeline reporting requirements.
49 CFR Part 192
District regulator stations, Emergency response, Gas monitoring,
Integrity management, Inspections, Gas, Overpressure protection,
Pipeline safety, Reporting and recordkeeping requirements.
49 CFR Part 198
State inspector staffing requirements.
For the reasons provided in the preamble, PHMSA proposes to amend
49 CFR parts 191, 192, and 198 as follows:
PART 191--TRANSPORTATION OF NATURAL AND OTHER GAS BY PIPELINE;
ANNUAL, INCIDENT, AND OTHER REPORTING
0
1. The authority citation for 49 CFR part 191 continues to read as
follows:
Authority: 30 U.S.C. 185(w)(3); 49 U.S.C. 5121, 60101 et seq.,
and 49 CFR 1.97.
0
2. Revise Sec. 191.11 to read as follows:
Sec. 191.11 Distribution system: Annual report.
(a) General. Except as provided in paragraph (b) of this section,
each operator of a distribution pipeline system, excluding a liquefied
petroleum gas system that serves fewer than 100 customers from a single
source, must submit an annual report for that system on DOT Form PHMSA
F 7100.1-1. Each operator of a liquefied petroleum gas system that
serves fewer than 100 customers from a single source must submit an
annual report for that system on DOT Form PHMSA F 7100.1-2. Reports
must be submitted each year, not later than March 15, for the preceding
calendar year.
(b) Not required. The annual report requirement in this section
does not apply to a master meter system, a petroleum gas system
excepted from part 192 in accordance with Sec. 192.1(b)(5), or an
individual service line directly connected to a production pipeline or
a gathering line other than a regulated gathering line as determined in
Sec. 192.8.
PART 192--TRANSPORTATION OF NATURAL AND OTHER GAS BY PIPELINE:
MINIMUM FEDERAL SAFETY STANDARDS
0
3. The authority citation for 49 CFR part 192 continues to read as
follows:
Authority: 30 U.S.C. 185(w)(3), 49 U.S.C. 5103, 60101 et seq.,
and 49 CFR 1.97.
Sec. 192.3 [Amended]
0
4. Amend Sec. 192.3, by removing the last sentence ``This definition
does not apply to any gathering line.'' from the definitions of
``Entirely replaced onshore transmission pipeline segments'',
``Notification of potential rupture'' and ``Rupture-mitigation valve
(RMV)''.
Sec. 192.9 [Amended]
0
5. Amend Sec. 192.9 by:
0
a. Removing from paragraph (b) the last sentence;
0
b. Removing from paragraph (c) the last sentence; and
0
c. Removing from paragraph (e)(1)(iv) the words ``effective as of
October 4, 2022.''
0
6. Amend Sec. 192.18 by revising paragraph (c) to read as follows:
Sec. 192.18 How to notify PHMSA.
* * * * *
(c) Unless otherwise specified, if an operator submits, pursuant to
Sec. Sec. 192.8, 192.9, 192.13, 192.179, 192.319, 192.506, 192.607,
192.619, 192.624, 192.632, 192.634, 192.636, 192.710, 192.712, 192.714,
192.745, 192.917, 192.921, 192.927, 192.933, 192.937, or
[[Page 61801]]
192.1007, a notification for use of a different integrity assessment
method, analytical method, compliance period, sampling approach,
pipeline material, or technique (e.g., ``other technology'' or
``alternative equivalent technology'') than otherwise prescribed in
those sections, that notification must be submitted to PHMSA for review
at least 90 days in advance of using the other method, approach,
compliance timeline, or technique. An operator may proceed to use the
other method, approach, compliance timeline, or technique 91 days after
submitting the notification unless it receives a letter from the
Associate Administrator for Pipeline Safety, or his or her delegate,
informing the operator that PHMSA objects to the proposal or that PHMSA
requires additional time and/or more information to conduct its review.
0
7. Amend Sec. 192.195 by adding paragraph (c) to read as follows:
Sec. 192.195 Protection against accidental overpressuring.
* * * * *
(c) Additional requirements for low-pressure distribution systems.
Each regulator station, serving a low-pressure distribution system,
that is new, replaced, relocated, or otherwise changed after [ONE YEAR
AFTER THE PUBLICATION DATE OF THE RULE] must include:
(1) At least two methods of overpressure protection (such as a
relief valve, monitoring regulator, or automatic shutoff valve)
appropriate for the configuration and siting of the station;
(2) Measures to minimize the risk of overpressurization of the low-
pressure distribution system that could be caused by any single event
(such as excavation damage, natural forces, equipment failure, or
incorrect operations), that either immediately or over time affects the
safe operation of more than one overpressure protection device; and
(3) Remote monitoring of gas pressure at or near the location of
overpressure protection devices.
0
8. Amend Sec. 192.305 by:
0
a. Lifting the stay of the section; and
0
b. Revising the section.
The revision reads as follows:
Sec. 192.305 Inspections: General.
(a) Each transmission pipeline and main that is new, replaced,
relocated, or otherwise changed after [ONE YEAR AFTER THE PUBLICATION
DATE OF THE RULE] must be inspected to ensure that it is constructed in
accordance with this subpart. Except as provided in paragraph (b) of
this section, an operator must not use operator personnel to perform a
required inspection if the operator personnel performed the
construction task requiring inspection. Nothing in this section
prohibits the operator from inspecting construction tasks with operator
personnel who are involved in other construction tasks.
(b) For the construction inspection of a main that is new,
replaced, relocated, or otherwise changed after [ONE YEAR AFTER THE
PUBLICATION DATE OF THE RULE], operator personnel involved in the same
construction task may inspect each other's work in situations where the
operator could otherwise only comply with the construction inspection
requirement in paragraph (a) of this section by using a third-party
inspector. This justification must be documented and retained for the
life of the pipeline.
0
9. Amend Sec. 192.517 by revising paragraph (b) to read as follows:
Sec. 192.517 Records.
* * * * *
(b) Each operator must maintain a record of each test required by
Sec. Sec. 192.509, 192.511, and 192.513 for the life of the pipeline.
(1) For tests performed before [ONE YEAR AFTER THE PUBLICATION DATE
OF THE FINAL RULE] for which records are maintained, the record must
continue to be maintained for the life of the pipeline.
(2) For tests performed on or after [ONE YEAR AFTER THE PUBLICATION
DATE OF THE FINAL RULE], the records must contain at least the
following information:
(i) The operator's name, the name of the employee responsible for
making the test, and the name of the company or contractor used to
perform the test.
(ii) Pipeline segment pressure tested.
(iii) Test date.
(iv) Test medium used.
(v) Test pressure.
(vi) Test duration.
(vii) Leaks and failures noted and their disposition.
0
10. Amend Sec. 192.605 by adding paragraphs (b)(13), (f), and (g) to
read as follows:
Sec. 192.605 Procedural manual for operations, maintenance, and
emergencies.
* * * * *
(b) * * *
(13) Implementing the applicable requirements for distribution
systems in paragraphs (f) and (g) of this section, Sec. 192.638, and
Sec. 192.640.
* * * * *
(f) Overpressurization. For distribution lines, the manual required
by paragraph (a) of this section must, no later than [ONE YEAR AFTER
THE PUBLICATION DATE OF THE RULE], include procedures for responding
to, investigating, and correcting, as soon as practicable, the cause of
overpressurization indications. The procedures must include the
specific actions and an order of operations for immediately reducing
pressure in or shutting down portions of the distribution system
affected by an overpressurization.
(g) Management of Change (MOC) Process. For distribution lines, the
manual required by paragraph (a) of this section must, no later than
[ONE YEAR AFTER THE PUBLICATION DATE OF THE RULE], include a detailed
MOC process for the following:
(1) Technology, equipment, procedural, and organizational changes,
including:
(i) Installations, modifications, replacements, or upgrades to
regulators, pressure monitoring locations, or overpressure protection
devices;
(ii) Modifications to alarm set points or upper/lower trigger
limits on monitoring equipment;
(iii) The introduction of new technologies for overpressure
protection into the system;
(iv) Revisions, changes, or the introduction of new standard
operating procedures for design, construction, installation,
maintenance, and emergency response;
(v) Other changes that may impact the integrity or safety of the
gas distribution system.
(2) Ensuring that personnel--such as an engineer with a
professional engineer license, a subject matter expert, or another
person who possesses the necessary knowledge, experience, and skills
regarding gas distribution systems--review and certify construction
plans associated with installations, modifications, replacements, or
system upgrades for accuracy and completeness before the work begins.
These personnel must be qualified to perform these tasks under subpart
N of this part.
(3) Ensuring that any hazards introduced by a change are
identified, analyzed, and controlled before resuming operations.
0
11. Amend Sec. 192.615 by:
0
a. Adding paragraphs (a)(3)(v) through (viii);
0
b. Revising paragraph (a)(8); and
0
c. Adding paragraphs (a)(13) and paragraph (d).
The additions and revision read as follows:
Sec. 192.615 Emergency plans.
(a) * * *
(3) * * *
[[Page 61802]]
(v) Notification of potential rupture (see Sec. 192.635).
(vi) Beginning no later than [ONE YEAR AFTER THE PUBLICATION DATE
OF THE FINAL RULE], release of gas that results in one or more
fatalities.
(vii) Beginning no later than [ONE YEAR AFTER THE PUBLICATION DATE
OF THE FINAL RULE], for distribution line operators only, unintentional
release of gas and shutdown of gas service to 50 or more customers or,
if the operator has fewer than 100 customers, 50 percent or more of its
total customers.
(viii) Beginning no later than [ONE YEAR AFTER THE PUBLICATION DATE
OF THE FINAL RULE], any other emergency deemed significant by the
operator.
* * * * *
(8) Notifying the appropriate public safety answering point (i.e.,
9-1-1 emergency call center) where direct access to a 9-1-1 emergency
call center is available from the location of the pipeline, and fire,
police, and other public officials, of gas pipeline emergencies to
coordinate and share information to determine the location of the
emergency, including both planned responses and actual responses during
an emergency. The operator must immediately and directly notify the
appropriate public safety answering point or other coordinating agency
for the communities and jurisdictions in which the pipeline is located
after receiving notice of a gas pipeline emergency under paragraph
(a)(3) of this section. The operator must coordinate and share
information to determine the location of any release, regardless of
whether the segment is subject to the requirements of Sec. Sec.
192.179, 192.634, or 192.636.
* * * * *
(13) For distribution line operators, beginning no later than [ONE
YEAR AFTER THE PUBLICATION DATE OF THE FINAL RULE], establishing and
maintaining communication with the general public in the operator's
service area as soon as practicable during a gas pipeline emergency on
a distribution line. The communication(s) must be in English, and any
other languages commonly understood by a significant number and
concentration of the non-English speaking population in the operator's
service area; be in one or more formats or media accessible to the
population in the operator's service area; continue through service
restoration and recovery efforts; and provide the following:
(i) Information regarding the gas pipeline emergency;
(ii) The status of the emergency (e.g., have the condition causing
the emergency or the resulting public safety risks been resolved);
(iii) Status of pipeline operations affected by the gas pipeline
emergency, and when possible, a timeline for expected service
restoration; and
(iv) Directions for the public to receive assistance.
The operator must provide updates when the information in Sec.
192.615(a)(13)(i) through (iv) changes.
* * * * *
(d) No later than [DATE 18 MONTHS AFTER THE PUBLICATION DATE OF THE
RULE], each distribution line operator must develop and implement a
system, including written procedures, that allows operators to rapidly
communicate with customers in the event of a gas pipeline emergency
under this section. The notification system must be voluntary for the
public, allowing customers to opt-in (or opt-out) to receiving
notifications from the system. The written procedures must provide for
the following:
(i) A description of the notification system and how it will be
used to notify customers of a gas pipeline emergency;
(ii) Who is responsible for the development, operation, and
maintenance of the system;
(iii) How information on the system is delivered to customers,
ensuring that all customers are notified of the existence of the system
and necessary steps if they wish to opt-in (or opt-out);
(iv) Description of the system-wide testing protocol, including the
testing interval (which must not be less than once per calendar year),
to ensure the system is functioning properly and performing
notifications as designed;
(v) Maintenance of the results of testing and operations history
for at least 5 years;
(vi) Details regarding how the operator ensures messages are
accessible in other languages commonly understood by a significant
number and concentration of the non-English speaking population in the
operator's area;
(vii) Message content, including updates as emergency conditions
change;
(viii) A process to initiate, conduct, and complete notifications;
and
(ix) Cybersecurity measures to protect the system and customer
information.
0
12. Add Sec. 192.638 to read as follows:
Sec. 192.638 Distribution lines: Records for pressure controls.
(a) An operator of a distribution system, except those identified
in paragraph (f) of this section, must, no later than [ONE YEAR AFTER
THE PUBLICATION DATE OF THE RULE], identify and maintain traceable,
verifiable, and complete records that document the characteristics of
its pipeline system that are critical to ensuring proper pressure
control. These records must include:
(1) Current location information (including maps and schematics)
for regulators, valves, and underground piping (including control
lines);
(2) Attributes of the regulator(s), such as set points, design
capacity, and the valve failure position (open/closed);
(3) The overpressure protection configuration; and
(4) Other records deemed critical.
(b) If an operator does not have traceable, verifiable, and
complete records as required by paragraph (a) of this section, the
operator must, no later than [ONE YEAR AFTER THE PUBLICATION DATE OF
THE RULE], identify and document those records needed and develop and
implement procedures for collecting those records.
(c) The records identified in paragraph (a) of this section must be
collected, generated, or updated on an opportunistic basis, as
specified in Sec. 192.1007(a)(3).
(d) An operator must ensure the records required by this section
are accessible to all personnel responsible for performing or
supervising design, construction, operations, and maintenance
activities.
(e) An operator must retain the records required in this section
for the life of the pipeline.
(f) Exception. This section does not apply to master meter systems,
liquefied petroleum gas (LPG) distribution pipeline systems that serve
fewer than 100 customers from a single source, or any individual
service line directly connected to a transmission, gathering, or
production pipeline that is not operated as part of a distribution
system.
0
13. Add Sec. 192.640 to read as follows:
Sec. 192.640 Distribution lines: Presence of qualified personnel.
(a) An operator of a distribution system must conduct a documented
evaluation of each construction project that begins after [ONE YEAR
AFTER THE PUBLICATION DATE OF THE RULE] to identify any potential
project activities during which an overpressurization could occur at a
district regulator station. This evaluation must occur before such
activities begin. Activities that may present a potential for
overpressurization include, but are not limited to, tie-ins,
abandonment of
[[Page 61803]]
distribution lines, and equipment replacement.
(b) If the evaluation in paragraph (a) of this section results in a
determination that a potential for overpressurization exists during
construction project activity, the operator must:
(1) Ensure that at least one person qualified according to subpart
N of this part is present at that district regulator station, or at an
alternative site, during the construction project activity that could
cause an overpressurization;
(2) Monitor gas pressure with equipment capable of ensuring proper
pressure controls; and
(3) Have the capability to promptly shut off the flow of gas or
control overpressurization at a district regulator station.
(c) When monitoring the system as described in this section, the
qualified personnel must be provided, at a minimum: information
regarding the location of all valves necessary for isolating the
pipeline system; pressure control records (see Sec. 192.638); the
authority to stop work (unless prohibited by operator procedures);
operations procedures under Sec. 192.605; and emergency response
procedures under Sec. 192.615.
(d) Exception. Distribution systems with a remote monitoring system
in effect with the capability for remote or automatic shutoff need not
comply with the requirements in paragraphs (a) through (c) of this
section.
0
14. Amend Sec. 192.725 by revising paragraph (a) to read as follows:
Sec. 192.725 Test requirements for reinstating service lines.
(a) Except as provided in paragraph (b) of this section, each
disconnected service line being restored to service on or after [ONE
YEAR AFTER THE PUBLICATION DATE OF THE RULE] must be tested in the same
manner as a new service line (i.e., tested in accordance with subpart J
of this part) before being restored to service.
* * * * *
0
15. Amend Sec. 192.741 by:
0
a. Revising the title of the section, and
0
b. Adding paragraph (d).
The revision and addition read as follows:
Sec. 192.741 Pressure limiting and regulating stations: Telemetering,
recording gauges, and other monitoring devices.
* * * * *
(d) On low-pressure distribution systems that are new, replaced,
relocated, or otherwise changed after [ONE YEAR AFTER THE PUBLICATION
DATE OF THE RULE], the operator must monitor the gas pressure in
accordance with Sec. 192.195(c)(3).
Sec. 192.1001 [AMENDED]
0
16. Amend Sec. 192.1001 by removing the definition of ``Small LPG
Operator.''
0
17. Amend Sec. 192.1003 by adding paragraph (b)(4) to read as follows:
Sec. 192.1003 What do the regulations in this subpart cover?
* * * * *
(b) * * *
(4) A system of a liquefied petroleum gas (LPG) distribution
pipeline that serves fewer than 100 customers from a single source.
0
18. Amend Sec. 192.1005 by revising the title of the section to read
as follows:
Sec. 192.1005 What must a gas distribution operator do to implement
this subpart?
0
19. Amend Sec. 192.1007 by revising paragraphs (a)(3), (b), (c), and
(d) to read as follows:
Sec. 192.1007 What are the required elements of an integrity
management plan?
* * * * *
(a) * * *
(3) Identify additional information needed and provide a plan for
obtaining that information over time (including the records specified
in Sec. 192.638(c)) through normal activities conducted on the
pipeline (for example, design, construction, operations, or maintenance
activities).
* * * * *
(b) Identify threats. The operator must consider the following
categories of threats to each gas distribution pipeline: corrosion
(including atmospheric corrosion); natural forces (including extreme
weather, land movement, and other geological hazards); excavation
damage; other outside force damage; material (including the presence
and age of pipes such as cast iron, bare steel, unprotected steel,
wrought iron, and historic plastics with known issues) or welds;
equipment failure; incorrect operations; overpressurization of low-
pressure distribution systems; and other threats that pose a risk to
the integrity of a pipeline. An operator must also consider the age of
the system, pipe, and components in identifying threats. An operator
must consider reasonably available information to identify existing and
potential threats. Sources of data may include, but are not limited to,
incident and leak history, corrosion control records (including
atmospheric corrosion records), continuing surveillance records,
patrolling records, maintenance history, and excavation damage
experience.
(c) Evaluate and rank risk.
(1) General. An operator must evaluate the risks associated with
its distribution pipeline. In this evaluation, the operator must
determine the relative importance of each threat and estimate and rank
the risks posed to its pipeline. This evaluation must consider each
applicable current and potential threat, the likelihood of failure
associated with each threat, and the potential consequences of such a
failure. An operator may subdivide its pipeline into regions with
similar characteristics (e.g., contiguous areas within a distribution
pipeline consisting of mains, services and other appurtenances, areas
with common materials, age, or environmental factors), and for which
similar actions likely would be effective in reducing risk.
(2) Certain pipe with known issues. An operator must, no later than
[ONE YEAR AFTER THE PUBLICATION DATE OF THE RULE], evaluate the risks
in the distribution system resulting from pipelines with known issues
based on the material (including, cast iron, bare steel, unprotected
steel, wrought iron, and historic plastics with known issues), design,
age, or past operating and maintenance history.
(3) Low-pressure Distribution Systems. An operator must, no later
than [ONE YEAR AFTER THE PUBLICATION DATE OF THE RULE], evaluate the
risks that could lead to or result from the operation of a low-pressure
distribution system at a pressure that makes the operation of any
connected and properly adjusted low-pressure gas burning equipment
unsafe. In the evaluation of risks, an operator must:
(i) Evaluate factors other than past observed abnormal operating
conditions (as defined in Sec. 192.803) in ranking risks, including
any known industry threats, risks, or hazards to public safety that
could occur on its system based on knowledge gained from available
sources;
(ii) Evaluate potential consequences associated with low-
probability events unless a determination, supported and documented by
an engineering analysis, or an equivalent analysis incorporating
operational knowledge, demonstrates that the event results in no
potential consequences and therefore no potential risk. An operator
must notify PHMSA and State or local pipeline safety authorities, as
applicable, in accordance with Sec. 192.18 within 30 days of making
such a determination. The notification must include the following:
(A) Date the determination was made;
(B) Description of the low-probability event being considered;
(C) Logic supporting the determination, including information
[[Page 61804]]
from an engineering analysis, or an equivalent analysis incorporating
operational knowledge;
(D) Description of any preventive and mitigative measures,
including any measures considered but not taken;
(E) Details of the low-pressure system applicable to the event that
results in no potential consequence and risk, including, at a minimum,
the miles of pipe, number of customers, number of district regulators
supplying the system, and other relevant information; and
(F) Written statement summarizing the documentation provided in the
notification.
(iii) Evaluation of the configuration of primary and any secondary
overpressure protection installed at district regulator stations (such
as a relief valves, monitoring regulators, or automatic shutoff
valves), the availability of gas pressure monitoring at or near
overpressure protection equipment, and the likelihood of any single
event (such as excavation damage, natural forces, equipment failure, or
incorrect operations), that either immediately or over time, could
result in an overpressurization of the low-pressure distribution
system.
(d) Identify and implement measures to address risks.
(1) General. An operator must identify and implement measures to
reduce the risks of failure of its distribution pipeline system. The
measures identified and implemented must address, at a minimum, risks
associated with the age of pipeline components, the overall age of the
system and components, the presence of pipes with known issues, and
overpressurization of low-pressure distribution systems. The measures
must also include an effective leak management program (unless all
leaks are repaired when found).
(2) Minimization of Overpressurization of Low-Pressure Distribution
Systems. An operator must, no later than [ONE YEAR AFTER THE
PUBLICATION DATE OF THE RULE], implement the following preventive and
mitigative measures to minimize the risk of overpressurization of a
low-pressure distribution system that could be the result of any single
event or failure:
(i) Identify, maintain, and obtain, if necessary, pressure control
records in accordance with Sec. Sec. 192.638 and 192.1007(a)(3).
(ii) Confirm and document that each district regulator station
meets the requirements of Sec. 192.195(c)(1) through (3). If an
operator determines that a district regulator station does not meet the
requirements of Sec. 192.195(c)(1) through (3), then by [ONE YEAR
AFTER THE PUBLICATION DATE OF THE RULE], the operator must take either
of the following actions:
(A) Upgrade the district regulator station to meet the requirements
of Sec. 192.195(c)(1) through (3), or
(B) Identify alternative preventive and mitigative measures based
on the unique characteristics of its system to minimize the risk of
overpressurization of a low-pressure distribution system. The operator
must notify PHMSA and State or local pipeline safety authorities, as
applicable, no later than 90 days in advance of implementing any
alternative measures. The notification must be made in accordance with
Sec. 192.18(c) and must include a description of proposed alternative
measures, identification and location of facilities to which the
measures would be applied, and a description of how the measures would
ensure the safety of the public, affected facilities, and environment.
* * * * *
Sec. 192.1015 [Removed]
0
20. Remove Sec. 192.1015.
PART 198--REGULATIONS FOR GRANTS TO AID STATE PIPELINE SAFETY
PROGRAMS
0
21. The authority citation for part 198 continues to read as follows:
Authority: 49 U.S.C. 60101 et seq.; 49 CFR 1.97.
0
22. Amend Sec. 198.3 by adding the definitions for ``Inspection
person-day'' and ``State Inspection Calculation Tool (SICT)'' in
alphabetical order to read as follows:
Sec. 198.3 Definitions.
* * * * *
Inspection person-day means all or part of a day, including travel,
spent by State agency personnel in on-site or virtual evaluation of a
pipeline system to determine compliance with Federal or State pipeline
safety regulations.
* * * * *
State Inspection Calculation Tool (SICT) means a tool used to
determine the required number of annual inspection person-days for a
State agency.
* * * * *
0
23. Amend Sec. 198.13 by revising paragraph (c)(6) to read as follows:
Sec. 198.13 Grant-allocation formula.
* * * * *
(c) * * *
(6) Number of state inspection person-days, as determined by the
SICT and other factors;
* * * * *
Issued in Washington, DC, on August 23, 2023, under authority
delegated in 49 CFR 1.97.
Alan K. Mayberry,
Associate Administrator for Pipeline Safety.
[FR Doc. 2023-18585 Filed 9-6-23; 8:45 am]
BILLING CODE 4910-60-P