Pipeline Safety: Safety of Gas Distribution Pipelines and Other Pipeline Safety Initiatives, 61746-61804 [2023-18585]
Download as PDF
<![CDATA[
61746
Federal Register / Vol. 88, No. 172 / Thursday, September 7, 2023 / Proposed Rules
DEPARTMENT OF TRANSPORTATION
Pipeline and Hazardous Materials
Safety Administration
49 CFR Parts 191, 192, and 198
[Docket No. PHMSA–2021–0046]
RIN 2137–AF53
Pipeline Safety: Safety of Gas
Distribution Pipelines and Other
Pipeline Safety Initiatives
Pipeline and Hazardous
Materials Safety Administration
(PHMSA), Department of Transportation
(DOT).
ACTION: Notice of proposed rulemaking
(NPRM).
AGENCY:
PHMSA proposes revisions to
the pipeline safety regulations to require
operators of gas distribution pipelines to
update their distribution integrity
management programs (DIMP),
emergency response plans, operations
and maintenance manuals, and other
safety practices. These proposals
implement provisions of the Leonel
Rondon Pipeline Safety Act—part of the
Protecting our Infrastructure of
Pipelines and Enhancing Safety Act of
2020—and a National Transportation
Safety Board (NTSB) recommendation
directed toward preventing catastrophic
incidents resulting from
overpressurization of low-pressure gas
distribution systems similar to that
which occurred on a gas distribution
pipeline system in Merrimack Valley on
September 13, 2018. PHMSA also
proposes to codify use of its State
Inspection Calculation Tool, which is
used to help states determine the baselevel amount of time needed for
inspections to maintain an adequate
pipeline safety program. Further,
PHMSA proposes other pipeline safety
initiatives for all part 192-regulated
pipelines, including gas transmission
and gathering pipelines, such as
updating emergency response plans and
inspection requirements. Finally,
PHMSA proposes to apply annual
reporting requirements to small,
liquefied petroleum gas (LPG) operators
in lieu of DIMP requirements.
DATES: Individuals interested in
submitting written comments on this
NPRM must do so by November 6, 2023.
ADDRESSES: Comments should reference
Docket No. PHMSA–2021–0046 and
may be submitted in any of the
following ways:
E-Gov Web: https://
www.regulations.gov. This site allows
the public to enter comments on any
Federal Register notice issued by any
ddrumheller on DSK120RN23PROD with PROPOSALS3
SUMMARY:
VerDate Sep<11>2014
20:23 Sep 06, 2023
Jkt 259001
agency. Follow the online instructions
for submitting comments.
Mail: Docket Management System:
U.S. Department of Transportation, 1200
New Jersey Avenue SE, West Building
Ground Floor, Room W12–140,
Washington, DC 20590–0001.
Hand Delivery: DOT Docket
Management System: West Building
Ground Floor, Room W12–140, 1200
New Jersey Avenue SE, between 9:00
a.m. and 5:00 p.m. ET, Monday–Friday,
except Federal holidays.
Fax: 202–493–2251
Instructions: Include the agency name
and identify Docket No. PHMSA–2021–
0046 at the beginning of your
comments. Note that all comments
received will be posted without change
to https://www.regulations.gov
including any personal information
provided. If you submit your comments
by mail, submit two copies. If you wish
to receive confirmation that PHMSA
received your comments, include a selfaddressed stamped postcard.
Confidential Business Information:
Confidential Business Information (CBI)
is commercial or financial information
that is both customarily and actually
treated as private by its owner. Under
the Freedom of Information Act (5
U.S.C. 552), CBI is exempt from public
disclosure. If your comments in
response to this NPRM contain
commercial or financial information
that is customarily treated as private,
that you actually treat as private, and
that is relevant or responsive to this
NPRM, it is important that you clearly
designate the submitted comments as
CBI. Pursuant to 49 Code of Federal
Regulations (CFR) 190.343, you may ask
PHMSA to provide confidential
treatment to the information you give to
the agency by taking the following steps:
(1) mark each page of the original
document submission containing CBI as
‘‘Confidential;’’ (2) send PHMSA a copy
of the original document with the CBI
deleted along with the original,
unaltered document; and (3) explain
why the information you are submitting
is CBI. Submissions containing CBI
should be sent to Ashlin Bollacker, 1200
New Jersey Avenue SE, DOT: PHMSA–
PHP–30, Washington, DC 20590–0001.
Any comment PHMSA receives that is
not explicitly designated as CBI will be
placed in the public docket.
Docket: To access the docket, which
contains background documents and
any comments that PHMSA has
received, go to https://
www.regulations.gov. Follow the online
instructions for accessing the docket.
Alternatively, you may review the
documents in person at DOT’s Docket
PO 00000
Frm 00002
Fmt 4701
Sfmt 4702
Management Office at the address listed
above.
FOR FURTHER INFORMATION CONTACT:
Ashlin Bollacker by phone at 202–680–
8303 or by email at ashlin.bollacker@
dot.gov.
SUPPLEMENTARY INFORMATION:
I. Executive Summary
A. Purpose of the Regulatory Action
B. Summary of the Proposed Regulatory
Action
C. Costs and Benefits
II. Background
A. Gas Distribution Systems Overview
B. Gas Distribution Configurations
C. Merrimack Valley
D. Low-pressure Gas Distribution System
in South Lawrence
E. Gas Main Replacement Project
F. Emergency Response to the Merrimack
Valley Incident
III Recommendations, Advisory Bulletins,
and Mandates
A. National Transportation Safety Board
B. Advisory Bulletins
C. Statutory Authority
IV. Proposed Amendments
A. Distribution Integrity Management
Programs (Subpart P)
B. State Pipeline Safety Programs (Sections
198.3 and 198.13)
C. Emergency Response Plans (Section
192.615)
D. Operations and Maintenance Manuals
(Section 192.605)—Overpressurization
E. Operations and Maintenance Manuals
(Section 192.605)—Management of
Change
F. Gas Distribution Recordkeeping
Practices (Section 192.638)
G. Distribution Pipelines: Presence of
Qualified Personnel (Sections 192.640
and 192.605)
H. District Regulator Stations—Protections
Against Accidental Overpressurization
(Sections 192.195 and 192.741)
I. Inspection: General (Section 192.305)
J. Records: Tests (Sections 192.517 and
192.725)
K. Miscellaneous Amendments Pertaining
to Part 192—Regulated Gas Gathering
Pipelines (Sections 192.3 and 192.9)
V. Regulatory Analyses and Notices
I. Executive Summary
A. Purpose of the Regulatory Action
PHMSA proposes a series of revisions
to the pipeline safety regulations (49
CFR parts 190–199) in response to
congressional mandates and an NTSB
recommendation, and to implement
lessons learned from a September 13,
2018, incident resulting from the
overpressurization of a low-pressure gas
distribution pipeline operated by
Columbia Gas of Massachusetts (CMA)
in the Merrimack Valley. That incident
resulted in one fatality, more than 20
people (including three first responders)
being hospitalized, damage to
approximately 130 structures, and an
evacuation request for more than 50,000
E:\FR\FM\07SEP3.SGM
07SEP3
ddrumheller on DSK120RN23PROD with PROPOSALS3
Federal Register / Vol. 88, No. 172 / Thursday, September 7, 2023 / Proposed Rules
residents. PHMSA expects the proposals
of this NPRM will address the root
causes and aggravating factors
contributing to the severity of that
incident and help reduce the frequency
and consequence of other failure
mechanisms on gas distribution
pipeline systems. The proposals include
improved design standards for lowpressure gas distribution systems;
enhanced distribution integrity
management program requirements;
strengthened recordkeeping, planning,
and monitoring practices for
maintenance and construction activities
on gas distribution systems; and
improved emergency response
communication and coordination
protocols during emergency events for
all 49 CFR part 192-regulated gas
pipelines.1 PHMSA also proposes
codifying within the pipeline safety
regulations its State Inspection
Calculation Tool (SICT). The SICT is
one of many factors used to help States
determine the base-level amount of time
needed for administering adequate
pipeline safety programs, which
PHMSA considers when awarding
grants to States supporting those
programs. PHMSA anticipates these
proposed regulatory amendments will
improve public safety, while also
reducing threats to the environment
(including, but not limited to, reduction
of greenhouse gas emissions during
incidents on gas pipelines), and
promoting environmental justice for
minority populations, low-income
populations, or other underserved and
disadvantaged communities, or others
who are particularly likely to live and
work near higher-risk gas distribution
pipeline systems.
A catalyst for this rulemaking is the
2018 Merrimack Valley incident. The
NTSB investigated the cause of this
incident and issued a full report on its
findings and safety recommendations.2
The NTSB found the cause to be CMA’s
weak engineering management that
failed to adequately plan and oversee a
cast iron main replacement project.
Contributing to the incident was CMA’s
low-pressure gas distribution system
that was designed and operated without
adequate overpressure protection. The
NTSB reviewed other incidents from the
past 50 years and found several
previous incidents that involved high1 Part 192—regulated pipelines refers to gas
distribution, transmission, and gathering pipelines,
as applicable.
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.
VerDate Sep<11>2014
20:23 Sep 06, 2023
Jkt 259001
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.
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
PO 00000
Frm 00003
Fmt 4701
Sfmt 4702
61747
advancing the safe transportation of
energy and other hazardous materials
essential to our daily lives, PHMSA
proposes in this NPRM a number of
regulatory amendments to implement
those statutory mandates and NTSB
recommendations arising from the 2018
CMA overpressure incident. PHMSA
expects the proposed regulatory
amendments to reduce the likelihood of
another overpressure incident on lowpressure gas distribution systems
similar to that which occurred in
Merrimack Valley. PHMSA also expects
the proposed amendments to reduce the
frequency of, as well as public and
environmental consequences from,
failure mechanisms on gas distribution
pipeline systems and other pipeline
facilities. Additionally, this rulemaking
aligns with the Administration’s efforts
to improve environmental justice and
combat the climate crisis.3 Older castiron or bare-steel gas distribution
pipelines—a type of gas distribution
pipeline particularly vulnerable to
failure and overpressurization—are
disproportionately concentrated in
older, residential (often urban) areas
with large minority, low- income, and
other historically underserved and
disadvantaged populations.4 In
addition, the reduced frequency and
severity of incidents on gas pipelines
anticipated from this rulemaking would
have the benefit of minimizing the
release of greenhouse gases from
pipeline incidents—in particular
methane—to the atmosphere.
The proposed rule is consistent with
the goals of a new grant program
established by the Bipartisan
Infrastructure Law (BIL, enacted as the
Infrastructure Investment and Jobs Act,
Pub. L. 117–58). The new grant
program, PHMSA’s first ever Natural
Gas Distribution Infrastructure Safety
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-MethaneEmissions-Reduction-Action-Plan-1.pdf. This and
other PHMSA rulemakings are identified in the U.S.
Methane Emissions Reduction Action Plan as
critical elements in the Federal government’s efforts
to address the climate crisis. Id. at 7–8 (listing
PHMSA’s Leak Detection and Repair rulemaking
(proposed in 88 FR 31890 (May 18, 2023) (Leak
Detection NPRM)), its Gas Gathering Final Rule (86
FR 63266 (Nov. 15, 2021)), its Valve Installation and
Minimum Rupture Detection Standards Final Rule
(87 FR 20940 (Apr. 8, 2022) (Valve Rule)), and its
Gas Transmission Pipeline Safety Final Rule (87 FR
52224 (Aug. 24, 2022)).
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).
E:\FR\FM\07SEP3.SGM
07SEP3
61748
Federal Register / Vol. 88, No. 172 / Thursday, September 7, 2023 / Proposed Rules
ddrumheller on DSK120RN23PROD with PROPOSALS3
and Modernization grant program,
authorizes $200 million a year in grant
funding with a total of $1 billion in
grant funding over the next five years.
The grant funding is to be made
available to a municipality or
community owned utility (not including
for-profit entities) to repair, rehabilitate,
or replace its natural gas distribution
pipeline systems or portions thereof or
to acquire equipment to (1) reduce
incidents and fatalities and (2) to avoid
economic losses. The new grant
program authorized by BIL can,
however, address only part of the
universe of at-risk distribution pipeline
systems. While the grant program would
assist eligible entities who receive
funding in making needed repairs to
their pipeline systems, PHMSA’s
proposal would go further in ensuring
that all gas distribution and other part192 regulated operators improve and
maintain the safety of their systems and
reduce the risk of public safety impacts
and environmental damage from
incidents on their pipeline systems.
B. Summary of the Proposed Regulatory
Action
In this rulemaking, PHMSA proposes
amendments to 49 CFR parts 191, 192,
and 198. PHMSA also proposes
compliance deadlines for each of the
NPRM’s regulatory amendments.
1. Clarifications and Updates to DIMP
Plans—Part 192, Subpart P. Pursuant to
49 U.S.C. 60109(e)(7), PHMSA proposes
several revisions to its DIMP regulations
at 49 CFR part 192, subpart P. PHMSA
further proposes that, subject to certain
exceptions at § 192.1003, all gas
distribution pipeline operators—
including service lines—would need to
update their DIMP plans in conformity
with the amended requirements no later
than one year after the publication of
any final rule in this proceeding.
First, PHMSA proposes to require all
operators of gas distribution pipeline
systems identify and minimize the risks
to their systems from specific threats in
their DIMP. These specific threats,
where applicable, include: (1) the
presence of certain materials, such as
cast iron and other piping with known
issues; (2) overpressurization of lowpressure systems; and (3) extreme
weather and other geohazards.
Operators must also consider the effect
of age on those specific threats faced by
a distribution pipeline.
For operators of low-pressure gas
distribution systems, PHMSA proposes
that, when evaluating and ranking the
above and other threats identified in
their DIMP plans, operators must
evaluate risks from: (1) abnormal
operating conditions; and (2) potential
VerDate Sep<11>2014
20:23 Sep 06, 2023
Jkt 259001
consequences associated with lowprobability events. If an operator can
demonstrate through a documented
engineering analysis, or an equivalent
analysis incorporating operational
knowledge, that no potential
consequences are associated with a
particular low-probability event, and
therefore no potential risk exists, then
the operator must notify PHMSA and
state regulatory authorities of that
determination within 30 days.
Additionally, as part of the proposal to
implement measures to minimize the
risk of overpressurization, PHMSA
would require operators of low-pressure
distribution systems to identify,
maintain, and obtain pressure control
records. PHMSA would also require
operators to identify and implement
preventive and mitigative measures
based on the unique characteristics of
their system. If operators choose to
implement measures to minimize the
risk of an overpressurization on a lowpressure system, then they must notify
PHMSA and state regulatory authorities
no later than 90 days in advance of
implementing any alternative measures.
As an alternative to implementing such
preventive and mitigative measures,
operators could choose to upgrade their
systems to meet new proposed design
requirements applicable to new systems.
PHMSA is also proposing to omit
operators of a liquefied petroleum gas
(LPG) distribution pipeline system that
serves fewer than 100 customers (small
LPG operators) from the DIMP
requirements. Based on
recommendations from the National
Association of Pipeline Safety
Representatives (NAPSR), a National
Academies of Science (NAS) study, and
PHMSA’s incident data, current DIMP
requirements do not provide a safety
benefit warranting the compliance
burdens those requirements impose on
small LPG operators and the
administrative burdens placed on
PHMSA and state regulatory authorities.
Instead, PHMSA proposes to add a
requirement for small LPG operators to
complete an annual report providing
data that would support PHMSA’s
regulatory oversight of the safety of
those facilities.
2. Codifying in Regulation the Use of
the State Inspection Calculation Tool—
§§ 198.3 and 198.13. Consistent with 49
U.S.C. 60105(b) and 60105 note,
PHMSA will update the SICT and
proposes to revise its regulations to
require that states use the SICT when
ensuring an adequate number of safety
inspectors are employed in their
PO 00000
Frm 00004
Fmt 4701
Sfmt 4702
pipeline safety programs.5 States would
have to comply with these proposed
changes no later than the next SICT
update immediately following the
effective date of any final rule in this
proceeding. PHMSA proposes
amendments to 49 CFR part 198 that
would codify in regulation the SICT’s
use and define the terms ‘‘State
Inspection Calculation Tool’’ and
‘‘inspection person-days’’ for the
purposes of 49 CFR part 198.
3. Updates to Emergency Response
Communications—§ 192.615. Pursuant
to 49 U.S.C. 60102(a), PHMSA proposes
a series of updates to its emergency
response plan requirements that will be
applicable to all operators of part 192regulated gas pipelines. PHMSA also
proposes certain emergency response
plan requirements specific to gas
distribution pipeline operators pursuant
to 49 U.S.C. 60102(r). Unless a different
compliance timeline is specified below,
operators would need to update their
emergency response plans in conformity
with those amended requirements no
later than one year after the publication
of any final rule in this proceeding.
For all gas pipeline operators, PHMSA
proposes to expand the existing list of
pipeline emergencies in its regulations
at § 192.615 for which operators must
have procedures ensuring prompt and
effective response by adding
emergencies involving a release of gas
that results in a fatality, as well as any
other emergency deemed significant by
the operator. In the event of a release of
gas resulting in one or more fatalities,
all operators must also immediately and
directly notify emergency response
officials upon receiving notice of the
same. For distribution pipeline
operators only, PHMSA’s proposed
expansion of the list of emergencies
discussed above will also include the
unintentional release of gas and
shutdown of gas service to 50 or more
customers (or 50 percent of its
customers if it has fewer than 100 total
customers); operators would need to
immediately and directly notify
emergency response officials on
receiving notice of the same.
PHMSA also proposes regulatory
amendments requiring gas distribution
operators to update their emergency
response plans to improve
communications with the public during
an emergency. First, PHMSA proposes
to require gas distribution operators to
establish and maintain communications
with the general public as soon as
practicable during an emergency.
Second, PHMSA proposes to require gas
5 The SICT can be accessed on the PHMSA Portal
by authorized users.
E:\FR\FM\07SEP3.SGM
07SEP3
ddrumheller on DSK120RN23PROD with PROPOSALS3
Federal Register / Vol. 88, No. 172 / Thursday, September 7, 2023 / Proposed Rules
distribution pipeline operators to
develop and implement, no later than
18 months after the publication of any
final rule in this proceeding, an opt-in
system to keep their customers informed
of the safety status of pipelines in their
communities should an emergency
occur.
PHMSA also seeks comment on
whether it should require gas
distribution operators to develop and
implement emergency response
procedures in accordance with incident
command system (ICS) tools and
practices. PHMSA also invites comment
on the technical feasibility,
practicability, and cost of immediate
emergency notifications to customers
via electronic text message or via a
cellular phone application (‘‘app’’)—
including both opt-in and opt-out
notification approaches.
4. Updates to Operations and
Maintenance Procedural Manuals—
§ 192.605. Pursuant to 49 U.S.C.
60102(s), PHMSA also proposes a series
of amendments to operations and
maintenance (O&M) procedure manuals
in § 192.605 that would require all gas
distribution operators to implement
within one year of the publication of
any final rule issued in this proceeding.
First, PHMSA proposes to require that
operators of all gas distribution
pipelines update their O&M procedures
to account for the risk of
overpressurization. PHMSA would
require operators to have procedures for
identifying and responding to
overpressurization indications,
including the specific actions and
sequence of actions an operator would
carry out to immediately reduce
pressure or shut down portions of the
gas distribution system, if necessary.
PHMSA proposes that these O&M
procedures would also describe
investigating, responding to, and
correcting the cause(s) of
overpressurization indications.
Second, and again pursuant to 49
U.S.C. 60102(s), PHMSA proposes to
require that operators of gas distribution
pipelines develop and follow an MOC
process when (1) installing, modifying,
replacing, or upgrading regulators,
pressure monitoring locations, or
overpressure protection devices; (2)
modifying alarm setpoints or upper or
lower trigger limits on monitoring
equipment; (3) introducing new
technologies for overpressure protection
into the system; (4) revising, changing,
or introducing new standard operating
procedures for design, construction,
installation, maintenance, and
emergency response; and (5) making any
other changes that could impact the
integrity or safety of a gas distribution
VerDate Sep<11>2014
20:23 Sep 06, 2023
Jkt 259001
system. Should any of these changes
that an operator makes introduce a
public safety hazard into the operator’s
gas distribution system, PHMSA
proposes that the operator must
identify, analyze, and control these
hazards before resuming operations.
As part of the MOC process, PHMSA
also proposes to require that gas
distribution operators ensure qualified
personnel review and certify
construction plans associated with
installations, modifications,
replacements, or upgrades for accuracy
and completeness, before the work
begins. This amendment would ensure
that qualified personnel—who are
competently trained and experienced to
identify system design and process
deficiencies on gas distribution pipeline
systems—provide oversight during the
planning of those activities.
5. New Recordkeeping
Requirements—§ 192.638. Pursuant to
49 U.S.C. 60102(t)(1), PHMSA proposes
that all gas distribution pipeline
operators identify and maintain
traceable, verifiable, and complete maps
and records documenting the
characteristics of their systems that are
critical to ensuring proper pressure
controls for their gas distribution
pipeline systems and to ensure that
those records are accessible to anyone
performing or supervising design,
construction, and maintenance activities
on their systems. PHMSA proposes to
specify that these required records
include (1) the maps, location, and
schematics related to underground
piping, regulators, valves, and control
lines; (2) regulator set points, design
capacity, and valve-failure mode (open/
closed); (3) the system’s overpressure
protection configuration; and (4) any
other records deemed critical by the
operator. PHMSA proposes to require
that the operator maintain these
integrity-critical records for the life of
the pipeline because these records are
critical to the safe operation and
pressure control of a gas distribution
system. Operators would need to
comply with this new requirement
within one year of the publication of
any final rule in this proceeding. If an
operator does not have traceable,
verifiable, and complete records as
contemplated by this new requirement,
then the operator must (1) identify and
document which records they need, and
(2) develop and implement procedures
for generating or collecting those
records, to include procedures for
ensuring the generation or collection of
those records. PHMSA also proposes
that operators update these records on
an opportunistic basis (i.e., through
PO 00000
Frm 00005
Fmt 4701
Sfmt 4702
61749
normal operations, maintenance, and
emergency response activities).
PHMSA expects that many gas
distribution pipeline operators already
have these records. Where they do not,
these amendments would help to ensure
that gas distribution pipeline operators
improve the completeness and accuracy
of their records. This amendment will
also help to improve pipeline safety by
ensuring operators provide appropriate
personnel—such as qualified employees
responsible for planning construction
activities—with better, more complete,
and more accurate records.
6. Monitoring of Gas Systems by
Qualified Personnel—§ 192.640.
Pursuant to 49 U.S.C. 60102(t)(2),
PHMSA proposes that, where operators
of gas distribution pipelines do not have
the capability to remotely monitor
pressure and either remotely or
automatically shut off the gas flow at
district regulator stations, operators
must have qualified personnel on site to
monitor certain construction projects so
that they can prevent or respond to an
overpressurization at a district
regulatory station during those
construction activities that have been
determined to involve potential for such
an event. Accordingly, PHMSA
proposes requirements for all gas
distribution operators to evaluate their
construction projects to identify
activities that could result in an
overpressurization event at a district
regulator station. If the operator
identifies a potential for
overpressurization due to a construction
project, then the operator must ensure
that at least one qualified employee or
contractor is present during those
activities that could result in a potential
threat of overpressurization of the
system. That qualified personnel would
be responsible for monitoring the gas
pressure in the affected portion of a gas
distribution system and for promptly
shutting off the gas flow to control an
overpressurization event on the system.
PHMSA is also proposing that operators
must provide those qualified personnel
with the location of all critical shutoff
valves, pressure control records, and
stop-work authority (unless prohibited
by operator procedures) as well as the
emergency response procedures,
including the contact information of
appropriate emergency response
personnel. PHMSA proposes that gas
distribution pipeline operators would
need to comply with these requirements
beginning one year after the publication
of any final rule in this proceeding.
7. Requirements for New Regulator
Stations—§§ 192.195 and 192.741.
Pursuant to 49 U.S.C. 60102(t)(3),
PHMSA proposes to require that
E:\FR\FM\07SEP3.SGM
07SEP3
ddrumheller on DSK120RN23PROD with PROPOSALS3
61750
Federal Register / Vol. 88, No. 172 / Thursday, September 7, 2023 / Proposed Rules
operators design new regulator stations
on low-pressure distribution systems so
there are redundant technologies
installed to avoid or mitigate
overpressurizations. Specifically,
PHMSA proposes that all gas
distribution operators, beginning one
year after the publication of any final
rule in this proceeding, equip all new,
replaced, relocated, or otherwise
changed district regulator stations
serving low-pressure gas distribution
systems with at least two methods of
overpressure protection (such as a relief
valve, monitoring regulator, automatic
shutoff valve, or some combination
thereof) that is appropriate for the
configuration and siting of the station.
Additionally, PHMSA proposes that
operators minimize the risks from an
overpressurization of a low-pressure
system caused by a single event (such as
excavation damage, natural forces,
equipment failure, or incorrect
operations) that either immediately or
over time affects the safe operation of
more than one overpressure protection
device.
PHMSA also proposes to require that
operators of low-pressure gas
distribution systems monitor the outlet
gas pressure at or near the district
regulator station on such systems using
a device capable of real-time
notification to the operator of
overpressurization. Low-pressure gas
distribution operators are already
required to have devices such as
telemetering or recording gauges that
record the gas pressure on their systems.
However, some of these devices are not
designed with the ability to provide
real-time notification, and there is no
explicit requirement that those devices
be located near the district regulator
station.
8. Construction Inspections for Gas
Transmission Pipelines and Distribution
Mains—§ 192.305. PHMSA proposes to
amend § 192.305 to lift the indefinite
stay of a regulatory amendment to that
provision that had been introduced
within a final rule issued on March 11,
2015.6
PHMSA also proposes an exception
from this provision’s inspection
requirements for small gas distribution
pipeline operators who would not be
able to comply with the construction
inspection requirement without using a
6 ‘‘Pipeline Safety: Miscellaneous Changes to
Pipeline Safety Regulations,’’ 80 FR 12762, 12779
(Mar. 11, 2015). PHMSA indefinitely stayed
§ 192.305 in response to a petition for
reconsideration. See ‘‘Pipeline Safety:
Miscellaneous Changes to Pipeline Safety
Regulations: Response to Petitions for
Reconsideration,’’ 80 FR 58633, 58634 (Sept. 30,
2015).
VerDate Sep<11>2014
20:23 Sep 06, 2023
Jkt 259001
third-party inspector. These regulatory
amendments would, beginning one year
after the publication of any final rule
issued in this proceeding, apply to all
other gas distribution pipelines
operators; all gas transmission, all
offshore gas gathering, and Type A gas
gathering pipelines, and certain Types B
and C gathering pipelines (specifically,
those that are new, replaced, relocated,
or otherwise changed).
9. Test Records—Clarification for
Tests on Gas Distribution Systems—
§§ 192.517 and 192.725. PHMSA
proposes to amend § 192.517 to
specifically identify the information that
operators must record for tests
performed on new, replaced, or
relocated gas distribution pipelines and
to ensure such records are available to
operator personnel throughout the life
of the pipeline. PHMSA proposes to
amend § 192.725 to clarify that each
disconnected service line must be tested
in the same manner as a new, replaced,
or relocated service line—that is, tested
in accordance with 49 CFR part 192,
subpart J—before being reinstated.
PHMSA proposes to require that gas
distribution operators comply with
these amended testing recordkeeping
requirements in connection with gas
distribution pipelines that are new,
replaced, or relocated beginning one
year after the publication of any final
rule in this proceeding.
10. Annual Reporting—§ 191.11.
PHMSA proposes to add or expand
annual reporting requirements for
operators of gas distribution pipeline
systems, including small LPG operators.
For gas distribution pipelines, PHMSA
proposes to collect additional
information, such as the number and
miles of low-pressure service lines,
including their overpressure protection
methods. For small LPG operators, these
annual reports will collect information
on the number and miles of service
lines, and the disposition of any leaks.
These proposed amendments will not
apply to master meter systems,
petroleum gas systems excepted from 49
CFR part 192 in accordance with
§ 192.1(b)(5), or individual service lines
directly connected to production
pipelines or gathering pipelines, other
than a regulated gathering pipeline, as
determined in § 192.8. PHMSA proposes
that operators would need to comply
with the above changes to annual
reporting requirements beginning with
the first annual reporting cycle after the
effective date of any final rule issued in
this proceeding.
11. Miscellaneous Amendments
Pertaining to Part 192—Regulated Gas
Gathering Pipelines—§§ 192.3 and
192.9. Following a decision by the U.S.
PO 00000
Frm 00006
Fmt 4701
Sfmt 4702
Court of Appeals for the District of
Columbia Circuit in litigation
challenging application of requirements
of PHMSA’s April 2022 Valve Rule to
gas and hazardous liquid gathering
pipelines,7 PHMSA issued a technical
correction to the April 2022 Valve Rule
codifying that decision.8 PHMSA now
proposes removal of certain exceptions
introduced in the Technical Correction
to restore, with respect to certain part
192-regulated gas gathering pipelines,
application of specific regulatory
amendments from the Valve Rule
pertaining certain definitions (§ 192.3)
as well as—by way of removal of
exceptions within the regulatory crossreferences at § 192.9—emergency
planning and response (§ 192.615) and
protocols for notifications of potential
ruptures (§ 192.635).
C. Costs and Benefits
Consistent with 49 U.S.C. 60102(b)
and Executive Order 12866 ‘‘Regulatory
Planning and Review,’’ as amended by
Executive Order 14094 ‘‘Modernizing
Regulatory Review’’, PHMSA has
prepared an assessment of the benefits
and costs of the proposed rule as well
as reasonable alternatives.9 PHMSA
expects that the rulemaking will yield
significant public safety benefits
associated with reduced frequency and
severity of incidents similar to that
which occurred in 2018 in Merrimack
Valley, which resulted in a number of
adverse consequences described in
Section I.A. of this NPRM, as well as
approximately $1.7 billion in property
damage, lost gas, claims, other
mitigation costs, and the social cost of
methane emissions. PHMSA also
expects that the proposed rule will yield
other, unquantified benefits, which
include improvements in risk reduction
for pipeline leaks and incidents;
reduced consequences from all
incidents and emergencies; improved
enforcement and oversight procedures;
advanced safety measures and
communications; avoided emissions;
improved public confidence in the
safety of gas pipeline systems; and
associated environmental enhancements
for populations, including those in
historically disadvantaged areas. Cost
savings reflect the removal of some
requirements for small LPG operators.
The costs of the proposed rule are
attributed to new requirements and
7 GPA Midstream Ass’n v. Dep’t of Transp., 67
F.4th 1188 (D.C. Cir. 2023).
8 ‘‘Pipeline Safety: Requirement of Valve
Installation and Minimum Rupture Detection
Standards: Technical Corrections,’’ 88 FR 50056
(Aug. 1, 2023).
9 88 FR 21879 (Apr. 6, 2023); 58 FR 51735 (Oct.
4, 1993).
E:\FR\FM\07SEP3.SGM
07SEP3
Federal Register / Vol. 88, No. 172 / Thursday, September 7, 2023 / Proposed Rules
updates to operators’ DIMPs, emergency
response plans, operations and
maintenance procedures, monitoring
and inspection protocols, and other
reporting and record-keeping proposals.
The provisions include a range of
proposals for primarily gas distribution
operators, along with some proposals for
other gathering and transmission
operators.
PHMSA estimates the annualized
costs of the proposed rule to be
approximately $110 million per year at
a 3 percent discount rate. In Table ES–
1, below, PHMSA provides a summary
of the estimated costs for the major
provisions in this rulemaking and the
total cost. For the full cost/benefit
analysis and additional details on the
summaries, please see the preliminary
regulatory impact analysis (PRIA) in
Docket No. PHMSA–2021–0046.
TABLE ES–1—TOTAL ANNUALIZED
COSTS
[Millions, 2020$]
Proposed rule
requirement
3%
discount
rate
7%
discount
rate
DIMP .........................
Small LPG DIMP ......
SICT ..........................
Emergency response
O&M ..........................
Recordkeeping ..........
Qualified personnel ...
District regulator stations .......................
Inspections ................
Records: Tests .........
Annual Reporting ......
$3.2
¥0.3
0.0
1.0
42.8
24.3
34.8
$4.3
¥0.3
0.0
1.2
44.7
27.8
34.8
1.2
0.04
0.6
2.3
1.6
0.05
0.6
2.3
Total ...................
110.0
117.1
ddrumheller on DSK120RN23PROD with PROPOSALS3
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.
VerDate Sep<11>2014
20:23 Sep 06, 2023
Jkt 259001
II. Background
A. Gas Distribution Systems Overview
More than 2.3 million miles of gas
distribution pipelines deliver gas to
communities and businesses across the
United States.10 Gas distribution
systems are made up of pipelines called
‘‘mains,’’ which distribute the gas
within the system, and much smaller
lines called ‘‘service lines,’’ which
distribute gas to individual customers.
Because the purpose of distribution
pipelines is to deliver gas to customers,
distribution pipeline systems are
located predominantly in urban and
suburban areas. Distribution pipelines
are generally smaller in diameter than
transmission pipelines and operate at
lower pressures.
Risk to the public from gas
distribution pipelines result from the
potential for unintentional releases of
the gas transported through the
pipelines. Due to their proximity to
populations, releases from distribution
pipelines bear a particular risk to
surrounding populations, communities,
property, and the environment, and may
result in death, injuries, and property
damage.11 Even small releases of natural
gas can result in environmental harm, as
methane (the primary constituent of
natural gas) is a significant contributor
to the climate crisis, with more than 25
times the impact on an equivalent basis
as carbon dioxide.12 While the overall
trend in pipeline safety has steadily
improved over the past two decades, gas
distribution pipelines are still involved
in a majority of serious gas pipeline
incidents.13 According to PHMSA’s
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.
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 §§ 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/importancemethane#:∼:text=Methane%20is%20more%20than
%2025,due%20to%20human%2Drelated
%20activities.
13 Serious incidents are those including a fatality
or injury requiring in-patient hospitalization,
excluding incidents when secondary ignition is
PO 00000
Frm 00007
Fmt 4701
Sfmt 4702
61751
data, between 2003 and 2022,
excavation damage was the leading
cause of serious incidents along gas
distribution pipelines (28 percent),
followed by other outside force damage
(23 percent) and incorrect operation (14
percent).14
Much of the Nation’s gas distribution
piping has been in the ground for a long
time. Per PHMSA’s gas distribution
operator database, more than 50 percent
of the nation’s pipelines were
constructed before 1970 during the
creation of the interstate pipeline
network built in response to the demand
for energy in the post-World War II
economy.15 Historically, gas
distribution pipelines were constructed
from many different materials,
including cast iron, steel, and copper.
However, material fabrication and
installation practices have improved
since much of the Nation’s gas
distribution pipeline systems were
installed, in acknowledgment that iron
alloys like cast iron and steel degrade or
corrode over time. Consequently, the
age of a gas distribution system pipeline
is an important factor in evaluating the
risk it poses to public safety and the
environment.
On April 4, 2011, following a string of
major gas pipeline incidents, the
Secretary of Transportation announced
a Pipeline Safety Action Plan (Action
Plan) that was a vehicle for Federal and
State cooperation to accelerate the
repair, rehabilitation, and replacement
of the highest-risk pipeline
infrastructure.16 Efforts implementing
the Action Plan focused on pipeline age
and material as significant risk
indicators. Pipelines constructed of castand wrought iron and bare steel were
among those materials identified as
posing the highest risk. In fact, operators
of cast-iron and bare-steel distribution
pipelines perform the vast majority of
all leak repairs, despite these lines only
making up about 21 percent of all
distribution pipelines according to
involved, sometimes called ‘‘fire first’’ incidents.
Between 2001 and 2020, gas distribution incidents
comprised 81 percent of all the serious incidents
reported to PHMSA. The three-year average
incident count between 2018 and 2020 is 25, down
from an average of 28 serious incidents between
2001 and 2020. ‘‘Pipeline Incident 20 Year Trends’’
(Nov. 15, 2022), https://www.phmsa.dot.gov/dataand-statistics/pipeline/pipeline-incident-20-yeartrends.
14 ‘‘Pipeline Incident 20 Year Trends’’ (Nov. 15,
2022), https://www.phmsa.dot.gov/data-andstatistics/pipeline/pipeline-incident-20-year-trends.
15 PHMSA, ‘‘By-Decade Inventory: Reports’’ (Mar.
16, 2020), https://www.phmsa.dot.gov/data-andstatistics/pipeline-replacement/decade-inventory.
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.
E:\FR\FM\07SEP3.SGM
07SEP3
61752
Federal Register / Vol. 88, No. 172 / Thursday, September 7, 2023 / Proposed Rules
PHMSA’s distribution operators’ annual
report data.17
Though the amount of cast and
wrought iron pipe in use within gas
distribution systems has declined
significantly in recent years thanks to
State and Federal safety initiatives and
pipeline operators’ replacement efforts,
there are still approximately 20,000
miles of mains and 7,000 miles of
service lines in the United States.18
According to the U.S. Department of
Energy, the total cost of replacing all
cast iron and bare steel distribution
pipelines in the United States would be
approximately $270 billion.19 PHMSA
understands that both cost and practical
barriers, such as urban excavation and
disruption of gas supplies, can also limit
replacement efforts. However, PHMSA
finds that proactive management of the
integrity of aging pipe infrastructure
enhances safety and reliability,
contributes to cost savings over the
longer term, and can be less disruptive
to customers and communities than a
reactive approach. Accelerating leak
detection, repair, rehabilitation, or
replacement efforts also delivers the
desired integrity and safety benefits
more expeditiously, lowering
maintenance requirements associated
with the aging pipe that is being
replaced.
There is no simple formula for
determining which parts of the Nation’s
pipeline infrastructure should be of
greatest concern. Factors often
associated with higher risk include
pipeline age, materials of construction,
exposure to elements or outside forces,
and an operator’s practices in managing
the integrity of its pipeline system. Each
of these factors can contribute to a
pipeline’s risk, but effective integrity
management can counterbalance the
impact of aging and types of
construction materials.
B. Gas Distribution Configurations
In a distribution system, gas is
sourced from a transmission pipeline
operating at a high pressure and must be
safely delivered to the customer at lower
ddrumheller on DSK120RN23PROD with PROPOSALS3
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-andstatistics/pipeline-replacement/cast-and-wroughtiron-inventory (‘‘Cast and Wrought Iron Inventory’’).
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.
VerDate Sep<11>2014
20:23 Sep 06, 2023
Jkt 259001
pressures that are safe for customer
piping and appliances. There are
multiple points along the system where
operators can reduce the pressure to be
more suitable for the needs of the
customer. City gate stations are the first
such reduction point, and district
regulator stations are pressure-reducing
facilities downstream of city gate
stations that further reduce the pressure
from the pipeline coming from the city
gate.20 This lower pressure downstream
of a district regulator station is more
suitable for providing service to
customers.
Each gas distribution system must be
designed to operate safely at or below a
certain pressure, also known as its
maximum allowable operating pressure
(MAOP), as determined in accordance
with § 192.619. Exceeding this pressure
can cause the gas to build up in the
pipeline and potentially cause the
failure of piping, joints, fittings, or
customer appliances. As gas flows
through a distribution system, devices
called regulators control the flow of gas
to maintain a constant pressure. If a
regulator senses a drop or rise in
pressure above or below a set point, it
will open or close accordingly to adjust
the pressure of gas. As an additional
safety precaution against
overpressurization, some distribution
pipelines are also designed with a relief
valve to vent the gas into the
atmosphere. While modern gas
regulators are highly reliable devices,
they can fail due to physical damage,
equipment failure (e.g., degradation of
materials such as seals and gaskets,
defects or maintenance issues, or
inability to control pressure as set), or
the presence of foreign material in the
gas stream.21 Because there is the
possibility of a regulator failing,
distribution systems are typically
designed with multiple means of
protection and redundancies to reduce
the likelihood of a catastrophic failure.
Many regulators require external
control lines, which sense the outlet
pressure of the regulator. Based on the
20 ‘‘At the city gate the pressure of the gas is
reduced, and [this] is normally the location where
odorant (typically mercaptan) is added to the gas,
giving it the characteristic smell of rotten eggs so
leaks can be detected.’’ Pipeline Safety Trust,
‘‘Pipeline Basics & Specifics About Natural Gas
Pipelines’’ at 4 (Feb. 2019), https://pstrust.org/wpcontent/uploads/2019/03/2019-PST-Briefing-Paper02-NatGasBasics.pdf.
21 Gas may contain moisture, dirt, sand, welding
slag, metal cuttings from tapping procedures, or
other debris. Problems caused by such foreign
material in the gas stream are most prevalent
following construction on the pipeline supplying
gas to the district regulator station. American Gas
Association, ‘‘Leading Practices to Reduce the
Possibility of a Natural Gas Over-Pressurization
Event’’ at 447 (Nov. 26, 2018).
PO 00000
Frm 00008
Fmt 4701
Sfmt 4702
pressure sensed through the control
lines, the regulator valve will open or
close to control the downstream
pressure of the regulator. In some older
installations, control lines are located
farther downstream of the regulator
station on the buried outlet piping based
on either the manufacturer’s
recommendations or previous controlline standards and practices at the time
of installation. However, a break in the
control line (e.g., if it is damaged during
an excavation) will make the regulator
sense a lower downstream pressure and
will cause the regulator valve to open
wider automatically. This could result
in overpressurization of the downstream
piping, which could lead to a
catastrophic event. The same result
occurs if the flow through the control
line is otherwise disrupted, for example
if the control line valve is shut off or if
the control line is isolated from the
regulator it is controlling.
In general, gas distribution pipeline
systems can be classified as either low
pressure or high pressure. In a highpressure gas distribution system, the gas
pressure in the main is substantially
higher than what the customer requires,
and a pressure regulator installed at
each meter reduces the pressure from
the main to a pressure that can be used
by the customer’s equipment and
appliances. These regulators incorporate
an overpressure-protection device to
prevent overpressurization of the
customer’s piping and appliances
should the regulator fail. Additionally,
all new or replaced service lines
connected to a high-pressure
distribution system must have excess
flow valves (see § 192.383). Excess flow
valves can reduce the flow of gas
through the service line by minimizing
unplanned, excessive gas flows.22
In a low-pressure distribution system,
the gas pressure in the main is
substantially the same as the pressure
provided to the customer (see § 192.3).
Since a district regulator station located
upstream of service lines acts as the
primary means of pressure control in
low-pressure distribution systems, an
overpressurization in the system served
by the district regulator could affect all
the customers served by the system.
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.
E:\FR\FM\07SEP3.SGM
07SEP3
Federal Register / Vol. 88, No. 172 / Thursday, September 7, 2023 / Proposed Rules
This is what occurred during the
Merrimack Valley incident and is an
inherent weakness of low-pressure gas
distribution systems.
ddrumheller on DSK120RN23PROD with PROPOSALS3
C. Merrimack Valley
On September 13, 2018, fires and
explosions occurred after high-pressure
natural gas entered a low-pressure
natural gas distribution system operated
by CMA, a subsidiary of NiSource,
Inc.23 One person, 18-year-old Leonel
Rondon, was killed, and 22 people,
including 3 firefighters, were
transported to hospitals for treatment of
their injuries. At least five homes were
destroyed in the city of Lawrence and
the towns of Andover and North
Andover, MA, by the fires and
explosions. More than 130 structures
were damaged in total. Most of the
damage occurred from fires ignited by
natural gas-fueled appliances. More
than 50,000 residents were asked to
evacuate.
In response, fire departments from
three municipalities were dispatched to
the fires and explosions. First
responders initiated the Massachusetts
fire mobilization plan and received
mutual aid from neighboring districts in
Massachusetts, New Hampshire, and
Maine. Emergency management officials
had the electric utility shut off electrical
power in the area. Additionally, CMA
shut down its low-pressure natural gas
distribution system, affecting 10,894
customers, including some outside of
the affected area who had their service
shut off as a precaution.
The NTSB on September 24, 2019,
issued a final report of its investigation
into the Merrimack Valley incident.24
The NTSB found the cause of the
incident was CMA’s weak engineering
management that failed to adequately
plan, review, sequence, and oversee the
construction project that led to the
abandonment of a cast iron main
without first relocating the regulator
control lines to the new plastic main.
The NTSB also found that contributing
to the accident was CMA’s low-pressure
natural gas distribution system that was
designed and operated without adequate
overpressure protection.
D. Low-Pressure Gas Distribution
System in South Lawrence
At the time of the incident, CMA
owned and operated a network of gas
pipeline systems for the transportation
and delivery of natural gas that included
approximately 25 different low-pressure
gas distribution systems in
23 CMA transferred from NiSource, Inc. to
Eversource Energy in November 2020.
24 NTSB/PAR–19/02 at 49.
VerDate Sep<11>2014
20:23 Sep 06, 2023
Jkt 259001
Massachusetts. Among these systems,
CMA owned and operated a lowpressure system in the area of South
Lawrence, Massachusetts that served
Lawrence, Andover, and North
Andover, among other communities
(South Lawrence system). The South
Lawrence system was installed in the
early 1900s and was constructed with
cast iron and bare steel mains and used
several regulator stations to control
downstream pressure. The regulator
stations were located below ground and
contained regulators that monitored and
controlled downstream pressure.
Natural gas came into the South
Lawrence system at a pressure of about
75 pounds per square inch, gauge (psig).
The regulators reduced the pressure to
about 0.5 psig for delivery to customers.
The South Lawrence system consisted
of 14 regulator stations, wherein the
regulator valves opened or closed based
on the pressure the regulator sensed
downstream to maintain the
downstream pressure at a pre-set limit
called a ‘‘set point.’’ This was to ensure
the pressure in the system did not
exceed the MAOP and become unsafe.
Each regulator station in the South
Lawrence system had at least two
regulators in series—a ‘‘worker
regulator’’ and a ‘‘monitor regulator’’—
each with a control line that sensed
downstream pressure and connected
back to its regulator, thereby enabling
the regulator station to regulate system
pressure. The worker regulator was the
primary regulator that maintained
system pressure. The monitor regulator
was the redundant backup in case the
worker regulator was damaged or
malfunctioned. If both control lines
experienced a decrease in pressure,
such as when the cast iron main was
disconnected, the worker regulator and
monitor regulator would automatically
and continually increase the pressure,
resulting in an overpressurization of the
low-pressure system. That is precisely
what occurred in CMA’s gas main
replacement project.
E. Gas Main Replacement Project
Beginning in 2016, CMA began a pipe
replacement project in the South
Lawrence system called the South
Union Street project. CMA’s field
engineering department initiated the
project in part due to the pending City
of Lawrence water main project that
would encroach on two aging cast iron
mains on South Union Street. The
construction project was also part of
CMA’s Gas System Enhancement Plan
that called for replacing existing lowpressure cast iron pipelines (both mains
and the accompanying service lines)
PO 00000
Frm 00009
Fmt 4701
Sfmt 4702
61753
with higher-pressure modern plastic
piping.
The South Union Street project
proposed replacing two low-pressure
cast iron mains with one plastic highpressure main. Once installed, the new
plastic main would be ‘‘tied-in’’ to the
distribution system and service lines
supplying gas to customers. As is
typical in pipe replacement projects, the
two cast iron mains would be
completely disconnected from the lowpressure system and abandoned in the
ground upon completion.
The scope of the South Union Street
project included the replacement of the
cast iron mains near a belowground
regulator station located at the
intersection of Winthrop Avenue and
South Union Street (the Winthrop
regulator station), one of the 14
regulator stations that monitored and
controlled downstream pressure in the
South Lawrence system. Up until the
time of the incident, two control lines
connected the Winthrop regulator
station and the two cast iron and bare
steel mains on South Union Street.
CMA contracted with a pipeline
services firm to complete the
replacement project. CMA prepared a
work package, which included materials
such as isometric drawings and
procedural details for disconnecting and
connecting pipes, for each of the
planned construction activities.
However, CMA did not prepare a
package for the relocation of the control
lines serving the regulator station. The
absence of a complete work package led
to the contractor completing the
installation of the plastic main with the
regulator control lines at the regulator
station still connected to the cast iron
main that was being replaced.
In 2016, the construction crew
installed the new plastic main on South
Union Street and began feeding the new
plastic main with gas from the Winthrop
regulator station. However, CMA put the
work on hold due to a city-wide
moratorium on all gas, water, and sewer
projects in Lawrence. Consequently, the
construction crew was unable to begin
any of the tie-in and abandonment
procedures to tie-in or connect the
mains or services to the new plastic
main and thus was also unable to
abandon the cast iron mains on South
Union Street. The regulator control lines
at the Winthrop regulator station
remained connected to the cast iron
mains that would ultimately be
decommissioned.
The final stage of the South Union
Street project involved the installation
of tie-ins to the new plastic main, after
which the legacy cast iron mains would
be decommissioned and abandoned in
E:\FR\FM\07SEP3.SGM
07SEP3
61754
Federal Register / Vol. 88, No. 172 / Thursday, September 7, 2023 / Proposed Rules
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.
ddrumheller on DSK120RN23PROD with PROPOSALS3
F. Emergency Response to the
Merrimack Valley Incident
On September 13, 2018, the
monitoring center in Columbus, OH,
which was overseeing the CMA system,
received pressure alarms on its
supervisory control and data acquisition
(SCADA) system.25 The system recorded
a sudden increase in pressure in the
Merrimack Valley low-pressure system
at 3:57 p.m. The SCADA’s high-pressure
alarms activated at 4:04 p.m. and 4:05
p.m. for the South Lawrence district
regulator station and Andover,
respectively. The SCADA system was
only able to monitor system pressures;
it could not remotely control the
pressure of this system.
Following company protocol, at 4:06
p.m., the SCADA controller called the
on-call technician in Lawrence, MA,
and reported the high-pressure event.
The on-call technician dispatched 3
field technicians to perform field checks
on the 14 regulators within the South
25 Operators use SCADA systems to monitor and
control critical assets remotely. See § 192.631. Here,
the South Lawrence system was monitored by
CMA’s corporate owner at the time, NiSource.
VerDate Sep<11>2014
20:23 Sep 06, 2023
Jkt 259001
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
PO 00000
Frm 00010
Fmt 4701
Sfmt 4702
September 14, 2018, at 6:27 a.m., CMA
confirmed the low-pressure distribution
system was shut down for the 8,447
customers in the Lawrence, Andover,
and North Andover areas. CMA shut
down the natural gas to an additional
2,447 customers outside the immediate
area as a precaution.
The following days required an
unprecedented response effort. More
than 50,000 residents were asked to
evacuate from their homes following the
overpressurization.26 Thousands of
homes needed to be entered, rendered
safe, and secured to ensure that
dangerous gas levels no longer existed.
As the emergency response concluded,
it was clear that the recovery effort
would span months. CMA’s work in the
aftermath of the incident focused on
repairing infrastructure damage,
providing shelter, and finding longerterm housing solutions as recovery
efforts extended into the fall and winter
months.
The 2018 incident impacted three
communities in the Merrimack Valley
that, while geographically near one
another, are different demographically.
Lawrence is a densely populated city
with many Spanish-speaking residents
and a higher poverty rate than Andover
and North Andover. Andover and North
Andover are middle-class suburban
communities, and although each has
half the population size of Lawrence,
their geographic size is four to five times
that of Lawrence.
III. Recommendations, Advisory
Bulletins, and Mandates
A. National Transportation Safety
Board
The NTSB investigates serious
pipeline accidents, including those that
occur on gas distribution pipeline
systems. The NTSB investigated CMA’s
overpressurization incident and issued
its final report,27 which included
several findings and safety
recommendations to NiSource, Inc., the
Commonwealth of Massachusetts
(Massachusetts), several other States,28
and PHMSA.
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-ofcolumbia-gas-of-massachusetts-merrimack-valleyrestoration-program/download.
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
E:\FR\FM\07SEP3.SGM
07SEP3
Federal Register / Vol. 88, No. 172 / Thursday, September 7, 2023 / Proposed Rules
In its accident report, the NTSB
issued two safety recommendations to
PHMSA. The first, P–19–14,
recommended that PHMSA require
overpressure protection for low-pressure
natural gas distribution systems that
cannot be defeated by a single operator
error or equipment failure. The NTSB
further clarified that to satisfy this
recommendation, PHMSA would not
have to require that existing lowpressure gas distribution systems be
completely redesigned; rather, PHMSA
may satisfy this recommendation by
requiring operators to add additional
protections, such as slam-shut or relief
valves, to existing district regulator
stations or other appropriate locations
in the system.29 The second, P–19–15,
recommended that PHMSA issue an
advisory bulletin to all low-pressure
natural gas distribution system
operators of the possibility of a failure
of overpressure protection. Further, P–
19–15 stated that the advisory bulletin
should recommend that operators use a
failure modes and effects analysis or an
equivalent structured and systematic
method to identify potential failures and
take action to mitigate those identified
failures. In developing this NPRM,
PHMSA also reviewed additional
recommendations relating to the
Merrimack Valley incident that NTSB
made to states and operators.
B. Advisory Bulletins
ddrumheller on DSK120RN23PROD with PROPOSALS3
1. Possibility of Overpressurization of
Low-Pressure Distribution Systems
Advisory Bulletin
On September 29, 2020, PHMSA
issued an advisory bulletin (ADB–2020–
02) to urge owners and operators of gas
distribution systems to conduct a
comprehensive review of their systems
for the possibility of a failure of
overpressure protection on low-pressure
distribution systems.30 The advisory
bulletin addressed NTSB safety
recommendation P–19–15, which
underscored the elevated possibility of
a common mode of failure on lowpressure distribution systems.
Specifically, PHMSA requested owners
and operators of low-pressure
distribution systems to review the
NTSB’s report concerning the 2018
Merrimack Valley overpressurization
event. PHMSA also recommended that
Dakota, Texas, Utah, Virginia, and Wyoming.
NTSB/PAR–19/02 at 50.
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/srdetails/P-19-014.
30 ‘‘Pipeline Safety: Overpressure Protection on
Low-Pressure Natural Gas Distribution Systems,’’
ADB–2020–02, 85 FR 61097 (Sept. 29, 2020).
VerDate Sep<11>2014
20:23 Sep 06, 2023
Jkt 259001
operators review their current systems
for a similar overpressure-protection
configuration to that on the CMA
pipeline involved in the incident. In the
review of their systems, PHMSA urged
operators to consider the possibility of
a failure of overpressure-protection
devices as a threat to their system’s
integrity. Additionally, PHMSA
reminded owners and operators of their
responsibilities under 49 CFR part 192,
subpart P, to follow their DIMP and to
revise their DIMP based on the new
information provided in the NTSB’s
report and PHMSA’s advisory bulletin.
Finally, PHMSA recommended several
ways that an operator can protect lowpressure distribution systems from an
overpressurization event. Some
examples include:
1. Installing a full-capacity relief valve
downstream of the regulator station,
including in applications where there is
only worker-monitor pressure control;
2. Installing a ‘‘slam-shut’’ device;
3. Using telemetered pressure
recordings at district regulator stations
to signal failures immediately to
operators at control centers; and
4. Completely and accurately
documenting the location for all control
lines on the system.
2. Cast-Iron Pipe Advisory Bulletin
On March 23, 2012, PHMSA issued
advisory bulletin ADB–2012–05 to
owners and operators of cast-iron
distribution pipelines and State pipeline
safety representatives.31 PHMSA issued
this advisory bulletin partly in response
to the 2011 deadly explosions in
Philadelphia and Allentown, PA,
involving cast-iron pipelines installed
in 1942 and 1928, respectively.32 These
incidents gained national attention and
highlighted the need for continued
safety improvements to aging gas
pipeline systems. This advisory bulletin
updated two prior advisory bulletins
(ALN–91–02, issued on October 11,
1991, and ALN–92–02, issued on June
26, 1992 33) covering the continued use
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).
PO 00000
Frm 00011
Fmt 4701
Sfmt 4702
61755
of cast-iron pipe in gas distribution
pipeline systems. The ADB–2012–05
reiterated the two prior advisory
bulletins, urging owners and operators
to conduct a comprehensive review of
their cast-iron gas distribution pipelines
and replacement programs and to
accelerate repair and replacement of
high-risk pipelines. ADB–2012–05 also
requested that State agencies consider
enhancements to cast-iron replacement
plans and programs. Specifically, in
ADB–2012–05, PHMSA asked owners
and operators of cast-iron distribution
pipelines and State safety
representatives to consider the
following where improvements in safety
are necessary:
1. Review current cast-iron
replacement programs and consider
establishing mandated replacement
programs;
2. Establish accelerated leakage
survey frequencies or leak testing;
3. Focus pipeline safety efforts on
identifying the highest-risk pipe;
4. Use rate adjustments to incentivize
pipeline rehabilitation, repair, and
replacement programs;
5. Strengthen pipeline safety
inspections, accident investigations, and
enforcement actions; and
6. Install interior/home methane gas
alarms.
PHMSA reminded owners and
operators of their responsibilities under
§ 192.617 to establish procedures for
analyzing incidents and failures to
determine the causes of the failures and
to minimize the possibility of a
reoccurrence.
Finally, the advisory bulletin notes
that the DOT, in accordance with the
Pipeline Safety, Regulatory Certainty,
and Job Creation Act of 2011 (Pub. L.
112–90), will continue to monitor the
progress made by operators to
implement plans of safe management
and replacement of cast-iron gas
pipelines and identify the total miles of
cast iron pipelines in the United States.
C. Statutory Authority
Title II of the PIPES Act of 2020, the
‘‘Leonel Rondon Pipeline Safety Act,’’
included several mandates for PHMSA
to update the regulations governing
operators of gas distribution systems.
This NPRM addresses mandates
codified at 49 U.S.C. 60102(r)–(t),
60105(b), and 60109(e)(7). (See sections
202, 203, 204, and 206 of the PIPES Act
of 2020). Additionally, PHMSA has
general statutory authority to regulate
the safety of gas pipeline facilities
subject to this rulemaking as discussed
in section V.A of this NPRM.
E:\FR\FM\07SEP3.SGM
07SEP3
61756
Federal Register / Vol. 88, No. 172 / Thursday, September 7, 2023 / Proposed Rules
1. Distribution Integrity Management
Program Plans and State Inspection
Calculation Tool (49 U.S.C. 60109(e)(7)
and 49 U.S.C. 60105(b) and 60105 Note;
PIPES Act of 2020 Section 202)
PHMSA is required to issue
regulations ensuring that DIMP plans for
gas distribution operators include an
evaluation of certain risks, such as those
posed by cast iron pipes and mains and
low-pressure distribution systems, as
well as the possibility of future
accidents to better account for highconsequence but low-probability events.
(49 U.S.C. 60109(e)(7)). Gas distribution
operators were required make their
DIMP plans, emergency response plans,
and O&M manuals available to PHMSA
or the relevant State regulatory agency
no later than December 27, 2022. Gas
distribution operators must also make
these documents, in updated form,
available to PHMSA or the relevant
State regulatory agency: (1) two years
after the promulgation of regulations as
required; and (2) every 5 years
thereafter, as well as following any
significant change to the document.
PHMSA must also update and codify
the use of the SICT, a tool used to help
states determine the minimum amount
of time it must dedicate to inspections.
(See 49 U.S.C. 60105(b) and 60105
note).
ddrumheller on DSK120RN23PROD with PROPOSALS3
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.
VerDate Sep<11>2014
20:23 Sep 06, 2023
Jkt 259001
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)).
PO 00000
IV. Proposed Amendments
A. Distribution Integrity Management
Programs (Subpart P)
In 2009, PHMSA issued a final rule
titled ‘‘Pipeline Safety: Integrity
Management Program for Gas
Distribution Pipelines,’’ creating 49 CFR
part 192, subpart P.34 As specified in
§ 192.1003, subpart P applies to
operators of all gas distribution
pipelines covered under part 192,
subject to certain exceptions, and
prescribes minimum requirements for
integrity management programs for any
such pipelines (referred to in this
rulemaking as DIMPs). Adherence to a
DIMP is an overall approach by
operators to ensure the integrity of their
distribution systems. The purpose of
DIMP is to enhance safety by identifying
and reducing pipeline integrity risks.
DIMP regulations require that operators
develop an integrity management plan
that they must re-evaluate periodically;
that integrity management plan
complements operator efforts in
complying with prescriptive operating
and maintenance requirements
elsewhere in part 192.
Pursuant to § 192.1007, DIMP
regulations require operators implement
the following steps in developing their
DIMP plans:
(1) Knowledge (§ 192.1007(a))—
Requires operators to understand their
pipeline system’s design and material
characteristics, operating conditions and
environment, and maintenance and
operating history;
(2) Identify Threats (§ 192.1007(b))—
Requires operators to identify existing
and potential threats to their pipeline
systems;
(3) Evaluate and Rank Risk
(§ 192.1007(c))—Requires operators to
evaluate and identify threats to
determine their relative importance and
rank the risks associated with their
pipeline systems;
(4) Identify and Implement Measures
to Address Risks (§ 192.1007(d))—
Requires operators to determine and
implement measures designed to reduce
the risks from failure of their pipeline
systems;
(5) Measure Performance, Monitor
Results, and Evaluate Effectiveness
(§ 192.1007(e))—Requires operators to
measure the performance of their DIMPs
and reevaluate threats and risks to their
pipeline systems;
(6) Periodic Evaluation and
Improvement (§ 192.1007(f))—Requires
operators to periodically reevaluate
threats and risks across the entire
pipeline system; and
34 74
Frm 00012
Fmt 4701
Sfmt 4702
E:\FR\FM\07SEP3.SGM
FR 63906 (Dec. 4, 2009).
07SEP3
Federal Register / Vol. 88, No. 172 / Thursday, September 7, 2023 / Proposed Rules
ddrumheller on DSK120RN23PROD with PROPOSALS3
(7) Report Results (§ 192.1007(g))—
Requires operators to report their
performance results to PHMSA and the
applicable State agency through annual
reports (required by § 191.11).
The first step in developing a robust
DIMP plan, as required in § 192.1007(a),
is for operators to have knowledge of
their gas distribution system. PHMSA
has clarified through enforcement
guidance that this knowledge should
include, but is not limited to, the
following characteristics: location,
material composition, piping sizes,
joining methods, construction methods,
date of installation, soil conditions
(where appropriate), operating and
design pressures, operating history,
operating performance data, condition
of system, and any other characteristics
noted by operators as important to
understanding their system. This
information may be obtained from
sources including system maps,
construction records, work management
system, geographic information systems
(GIS), corrosion records, and personnel
who have knowledge of the system
(subject matter experts).35 This step also
requires operators to identify missing
data and to develop a plan to collect
relevant information as part of their
normal pipeline activities over time.
The second step in developing and
implementing a DIMP plan, as required
in § 192.1007(b), is for operators to use
the information they have gathered in
compliance with § 192.1007(a) to
identify threats to the integrity of their
gas distribution systems. Section
192.1007(b) currently requires that
operators consider eight broad
categories of threats. These threats are
corrosion (including atmospheric
corrosion), natural forces, excavation
damage, other outside force damage,
material or welds, equipment failure,
incorrect operations, and other issues
that could threaten the integrity of the
pipeline.36 Operators must consider
reasonably available information to
identify existing and potential threats.
Sources of data may include incident
and leak history, corrosion control
records (including atmospheric
corrosion records), continuing
surveillance records, patrolling records,
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’’).
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.
VerDate Sep<11>2014
20:23 Sep 06, 2023
Jkt 259001
maintenance history, and excavation
damage experience (see § 192.1007(b)).
Section 192.1007(b) requires operators
to consider certain categories of threats
and consider reasonably available
information to identify other existing
and potential threats not specifically
listed. PHMSA has clarified through
guidance that operators should use
sources of information such as past
O&M procedures, abnormal operating
events, purchase orders, material lists
from old field orders or standards, and
information from industry sources (e.g.,
plastic pipe database committee
(PPDC),37 NTSB accident reports, or
PHMSA advisory bulletins) to help
identify threats.38 PHMSA identified
potential threats that include, but are
not limited to, non-leak events such as
near misses, overpressurizations, and
material and appurtenance failures.
Even though certain potential threats
may not have caused system integrity
issues on an operator’s particular system
in the past, the fact that known industry
or systemic risks exist requires operators
to account for the threat in their DIMP.
Further, operators should not eliminate
any existing or potential threat to a
system without an adequate basis for
doing so.39 PHMSA reiterated through
guidance material that operators should
consider environmental conditions that
may be conducive to threats developing
over time (e.g., atmospheric corrosion,
hurricanes, flooding, excavation
damage, or materials with known
integrity issues), so that operators do not
eliminate potential threats without
proper consideration.40 Prior to
excluding a potential threat, operators
should perform an analysis of their
records to ensure that the pipeline has
not experienced the threat to date.41
PHMSA clarified through
enforcement guidance that to exclude a
threat from consideration, an operator
should document the basis for that
conclusion and should not exclude a
threat based on the unavailability of
information to support the existence of
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.
PO 00000
Frm 00013
Fmt 4701
Sfmt 4702
61757
such a threat.42 Where data is missing
or insufficient, an operator should use a
conservative assumption in the risk
assessment. Operators must maintain
records that identify how they use
unsubstantiated data so that operators
and regulators can consider the impact
on the variability and accuracy of risk
analysis results.43
The third step in developing and
implementing a DIMP plan, as required
in § 192.1007(c), is to evaluate and rank
risk. Risk is the likelihood of an event
occurring multiplied by the
consequence of that event. An event that
is highly likely and has significant
public safety or environmental
consequences constitutes an event of
greatest concern, while an unlikely
event that has minimal consequences
may not justify any particular
precautions. On the other hand, an
unlikely event that could have very high
consequences may justify special
precautions. Incidents on gas
distribution systems are generally lowlikelihood, but high-consequence,
events.
Risk analysis is an ongoing process of
understanding the risk each identified
threat presents to a pipeline. Operators
use the threats identified in
§ 192.1007(b) and any knowledge gained
when complying with § 192.1007(a) to
evaluate the risks associated with their
pipelines. Operators then must rank the
risks to determine their relative
importance. PHMSA has recommended
that operators prioritize and address the
risks of greatest concern first.44
The fourth step in developing and
implementing a DIMP plan, as required
in § 192.1007(d), is for operators to
determine and implement measures
designed to reduce the risks from failure
of their gas distribution pipelines. These
measures include having an effective
leak management program (unless all
leaks are repaired when found).45
PHMSA’s enforcement guidance
specifies that the process for identifying
risk reduction measures should be based
on identified threats.46 Operators
42 DIMP
Guidance at 18–19.
Guidance at 19, 58. Section 192.1011
requires that operators must maintain records
demonstrating compliance with the requirements of
this subpart for at least 10 years. The records must
include copies of superseded integrity management
plans developed under this subpart.
44 DIMP Guidance at 22, 61.
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.
43 DIMP
E:\FR\FM\07SEP3.SGM
07SEP3
ddrumheller on DSK120RN23PROD with PROPOSALS3
61758
Federal Register / Vol. 88, No. 172 / Thursday, September 7, 2023 / Proposed Rules
should promptly identify the need for
risk reduction measures if a new risk is
identified.
Overall, DIMP requirements direct
operators to identify conditions that can
result in hazardous leaks or other
unintended consequences and take
actions to reduce the likelihood of the
occurrence of a hazardous condition
and the consequences of a resulting
failure. It is critical for operators to
identify threats that affect, or could
potentially affect, a distribution pipeline
to ensure that pipeline’s integrity.
Knowledge of applicable threats,
whether actual or potential, allows
operators to evaluate the safety risks
they pose and to rank those risks,
allowing the operator to apply safety
resources where they will be most
effective. For the most effective results,
operators should break down these
broad threat categories into more
specific threats. An operator must use
the knowledge of their system gained as
a result of complying with
§ 192.1007(a), combined with the threats
identified pursuant to § 192.1007(b), to
perform a risk analysis to evaluate the
likelihood and consequences of failures
for those threats described in
§ 192.1007(c) for which risk-reduction
measures are then identified and
implemented under § 192.1007(d). The
more accurately and completely an
operator characterizes their system, the
more accurate the risk analysis results
will be. This in turn should inform how
an operator allocates resources to
mitigate the risks associated with its
system.
Pipeline incidents since the
promulgation of the DIMP rules in 2011
have demonstrated that some
distribution operators whose systems
are subject to DIMP requirements are
not adequately identifying (step 2),
evaluating (step 3), or mitigating (step 4)
the threats that are degrading and
reducing the integrity of their pipeline
systems. For example, NTSB’s report on
the Merrimack Valley incident found
that, by at least September 2015, CMA
employees knew of overpressure
dangers associated with maintenance on
belowground control lines for lowpressure system regulator stations: a
faulty, damaged, or unaccounted for
control line could lead to
overpressurization, resulting in fires and
explosions in a populated area.47 In
September 2015, NiSource and CMA
internally disseminated Operational
Notice (ON) 15–05, titled ‘‘Below Grade
Regulator Control Lines: Caution When
Excavating Near Regulator Stations or
47 NTSB/PAR–19/02
VerDate Sep<11>2014
at 18.
20:23 Sep 06, 2023
Jkt 259001
Regulator Buildings.’’ 48 The impetus for
ON 15–05 was a ‘‘near-miss’’ experience
involving another NiSource company
outside of Massachusetts where a
construction crew that was excavating
to repair a gas leak near a regulator
station came close to hitting a control
line and was unaware of its purpose and
importance. The NTSB’s report
concludes that even though NiSource
had historically identified
overpressurization as a threat in at least
some of its internal procedures,
NiSource had nevertheless failed to
undertake a systemic evaluation (e.g., a
failure modes and effects analysis) of
the risks associated with that threat and
the mitigating actions needed to manage
those risks.49
More robust risk management was
also needed in the planning of the South
Union Street project, particularly with
respect to the threat of
overpressurization. NTSB concluded
that NiSource’s engineering package for
that construction project failed to
identify, and control for the
vulnerability of its system to, a common
mode of failure during the construction
project that could result in an
overpressurization. After the incident in
the Merrimack Valley, NiSource worked
to improve its risk management
processes and installed automatic
pressure-control equipment.50
Therefore, the NTSB concluded that
NiSource’s engineering risk
management processes were deficient.
Subsequent to the Merrimack Valley
incident, 49 U.S.C. 60109(e)(7) was
amended to require PHMSA to add
more specificity to the DIMP
requirements to ensure that operators
consider specific threats to their
systems. Specifically, PHMSA must
update its regulations to ensure DIMP
plans for distribution operators include
an evaluation of certain risks, such as
those posed by cast iron pipes and
mains and low-pressure distribution
systems, as well as the possibility of
future accidents, to better account for
high-consequence but low-probability
events. Distribution operators must
make their updated DIMP plans
available to PHMSA or the relevant
State regulatory agency two years after
any final rule in this proceeding is
issued and every 5 years thereafter, as
well as following any significant change
to an operator’s DIMP plan or
distribution system.51
48 NTSB/PAR–19/02
at 59–61.
at 40.
50 NTSB/PAR–19/02 at 43.
51 This provision also requires that operators
make their current DIMP plans, emergency response
plans, and O&M manuals available to PHMSA or
49 NTSB/PAR–19/02
PO 00000
Frm 00014
Fmt 4701
Sfmt 4702
Another recent incident that
illustrates operator failure to adequately
identify, evaluate, and rank risk is a
series of leaks and explosions that
occurred on a gas distribution system
operated by Atmos Energy Corporation
between February 21, 2018, and
February 23, 2018, in Dallas, TX. The
NTSB investigated the February 2018
incident.52 As specified by the NTSB,
although Atmos’ DIMP plan was
consistent with the currently applicable
minimum requirements, their plan did
not adequately address the inherent
risks of its 71-year-old system. In
addressing the likelihood of failure, the
age of a pipe is generally recognized as
an important performance factor.53
Currently, PHMSA’s regulations do not
explicitly require gas distribution
operators to consider the age of their
pipelines under a DIMP. Instead,
PHMSA’s regulations in § 192.1007(c)
state that ‘‘[a]n operator may subdivide
its pipeline into regions with similar
characteristics (e.g., contiguous areas
within a distribution pipeline consisting
of mains, services and other
appurtenances; areas with common
materials or environmental factors), and
for which similar actions likely would
be effective in reducing risk.’’ Similar to
what is described in PHMSA’s
regulations, Atmos grouped its assets
into failure families based on asset
attributes, such as material and coating.
This method of evaluating the risks
proved to be inadequate, given the high
number of leaks observed that were due
to the degradation of their pipelines
over time.
Following the Atmos incident, NTSB
issued recommendation P–21–2 to
PHMSA.54 This recommendation
requires PHMSA to evaluate industry’s
implementation of DIMP requirements
and to develop updated guidance for
improving the effectiveness of operator
DIMP plans. The recommendation goes
on to say that the evaluation should
‘‘specifically consider factors that
increase the likelihood of failure such as
age, increase the overall risk (including
factors that simultaneously increase the
likelihood and consequence of failure),
and limit the effectiveness of leak
management programs.’’
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).
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.
54 NTSB/PAR–21/01 at 72.
E:\FR\FM\07SEP3.SGM
07SEP3
Federal Register / Vol. 88, No. 172 / Thursday, September 7, 2023 / Proposed Rules
ddrumheller on DSK120RN23PROD with PROPOSALS3
In this NPRM, PHMSA proposes to
revise DIMP requirements so that
operators of gas distribution systems
will improve their identification of
existing and potential threats to their
pipelines’ integrity, improve the
accuracy of their risk analyses, and take
meaningful, timely actions to remediate
or mitigate the highest risks to their
infrastructure. When developing the
proposals in this NPRM, PHMSA
considered applicable statutory
mandates and the NTSB
recommendations that followed the
CMA and Atmos incidents. The
proposals described in the paragraph’s
below apply to all gas distribution
operators, including individual service
lines (also known as farm taps),55 but
excluding small LPG operators. PHMSA
discusses the proposal to remove small
LPG operators from DIMP in IV.A.7.
Based on its review of the evidence in
the record, PHMSA expects the
proposed amendments to the DIMP
requirements would be reasonable,
technically feasible, cost-effective, and
practicable for gas distribution
operators. As explained above, these
operators are already required by
PHMSA regulations to have DIMPs for
(inter alia) identifying threats to
pipeline integrity, evaluating the risks of
those threats, and implementing
mitigation measures to manage those
risks. The NPRM’s proposed
amendments would clarify baseline
expectations for implementation of
those existing DIMP elements consistent
with historical PHMSA guidance,
industry operational experience and
research, and statutory mandates in the
PIPES Act of 2020, enacted after the
Merrimack Valley incident. Said
another way, the NPRM’s proposed
revisions are consistent with the actions
reasonably prudent gas distribution
operators would undertake in ordinary
course in implementing current DIMP
requirements on gas distribution
pipelines transporting pressurized
(natural, flammable, toxic, or corrosive)
gasses that are typically in close
proximity to, or within, population
centers. Within the guardrails proposed
herein, operators would retain the
significant flexibility contemplated by
current DIMP regulations for operators
to design and implement their DIMPs in
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 § 192.740, for service lines that
are not operated as part of a distribution system, or
DIMP (as detailed in § 192.1003(b)) for any portion
of the individual service line that is classified as a
service line. This rule proposed no change to this
scope. The proposals apply to those individual
service lines (aka farm taps) that apply DIMP.
VerDate Sep<11>2014
20:23 Sep 06, 2023
Jkt 259001
a manner appropriate for managing
integrity risks on their specific pipeline
facilities while minimizing compliance
costs. Viewed against those
considerations and the compliance costs
estimated in the PRIA, PHMSA expects
its proposed amendments will be a costeffective approach to achieving the
commercial, public safety, and
environmental benefits discussed in this
NPRM and its supporting documents.
Lastly, PHMSA understands that its
proposed compliance timeline—one
year after publication of a final rule
(which would necessarily be in addition
to the time since publication of this
NPRM)—would provide operators
ample time to implement requisite
changes to their DIMPs and manage any
related compliance costs.
1. DIMP—Identify Threats
(§ 192.1007(b))—Materials
a. Current Requirements—DIMP—
Identify Threats—Materials
Section 192.1007(b) requires operators
to consider the general threat category of
‘‘material or welds,’’ but the
requirement does not state that
operators must consider specific
material types and how each type could
pose a threat to the integrity of a system.
PHMSA has clarified through
enforcement guidance that operators
should consider subcategories of
‘‘material’’ threats to better categorize
their pipelines by age or specific pipe
type (such as bare steel, cast iron,
wrought iron, and plastic piping) to
focus on the root cause of potential
failures.56 PHMSA has also issued
advisory bulletins alerting operators of
threats related to specific material types,
including cast iron (ADB–2012–05) and
plastic piping (ADB–07–01 and ADB–
2012–03).57 PHMSA’s annual report
form, PHMSA F 7100.1–1 (see 49 CFR
191.11), also requires operators to
identify specific subtypes of materials
and the pipeline mileage of each.
b. Need for Change—DIMP—Identify
Threats—Materials
Different piping materials could pose
different threats to gas distribution
systems and should be identified prior
to conducting a risk analysis of those
threats. All things equal, pipelines that
56 DIMP
Guidance at 20.
Safety: Cast Iron Pipe
(Supplementary Advisory Bulletin),’’ ADB–2012–
05, 77 FR 17119 (Mar. 23, 2012); ‘‘Pipeline Safety:
Notice to Operators of Driscopipe® 8000 High
Density Polyethylene Pipe of the Potential for
Material Degradation,’’ ADB–2012–03, 77 FR 13387
(Mar. 6, 2012); ‘‘Updated Notification of
Susceptibility to Premature Brittle-Like Cracking of
Older Plastic Pipe,’’ ADB–07–02, 72 FR 51301
(Sept. 6, 2007).
57 ‘‘Pipeline
PO 00000
Frm 00015
Fmt 4701
Sfmt 4702
61759
are made of certain materials, like cast
iron, wrought iron, bare steel,
unprotected steel, and certain plastic
pipelines, are more susceptible to leaks
and other pipeline integrity issues. In
particular, cast-iron pipe was the subject
of an advisory bulletin (ADB–2012–05)
that reiterated two alert notices
previously issued by PHMSA that
addressed the continued use of cast- and
wrought-iron pipe in gas distribution
pipeline systems and reminded owners
and operators and State pipeline safety
representatives of the need to maintain
an effective cast-iron management
program.58 Similar to cast- and wroughtiron piping, steel pipelines without
corrosion protection coating—also
known as bare-steel or unprotected
pipelines—are made of a material that
could be a threat to a gas distribution
system, as that material is more
susceptible to corrosion than coated
steel.
Certain vintages and types of plastic
piping are also known throughout the
industry to present acute threats to
pipeline integrity. For example,
susceptibility to premature brittle-like
cracking of certain Aldyl ‘‘A’’ pipe,
along with other vintages and
manufacturers’ products, is a
well-documented problem in the
industry and the subject of the advisory
bulletin ADB–07–02. In this advisory
bulletin, PHMSA recommended that
operators consider the threat of brittlelike cracking applicable to any Aldyl
‘‘A’’ pipe in service (under the general
category of ‘‘material’’), regardless of
whether the threat had resulted in
leakage to date. Similarly, PHMSA also
alerted operators to the risks of material
degradation on Driscopipe8000
(Driscopipe Series 8000 high-density
poly-ethylene (HDPE)) pipe in Arizona
and Nevada in ADB–2012–03.
While many of these pipelines have
been taken out of service, some of them
continue to operate today. As discussed
earlier, the Merrimack Valley incident
involved the replacement of cast-iron
and bare-steel pipelines with modern
plastic piping. This was part of CMA’s
pipeline replacement program, which
called for the replacement of leak-prone
low-pressure cast iron pipelines (both
mains and services) with modern plastic
pipe. Many operators are also engaged
in pipeline replacement projects in
response to PHMSA’s Action Plan;
managing the reduction in cast- and
wrought-iron inventory has been a
priority and in progress for many years.
Following the Merrimack Valley
incident, PHMSA was required by
58 RSPA, ALN–92–02 (June 26, 1992); RSPA,
ALN–91–02 (Oct. 11, 1991).
E:\FR\FM\07SEP3.SGM
07SEP3
61760
Federal Register / Vol. 88, No. 172 / Thursday, September 7, 2023 / Proposed Rules
statute to ensure that operators evaluate
the risk of the presence of cast iron in
their DIMP plans. While only cast-iron
was specifically identified as a material
warranting explicit mention in DIMP
regulations,59 PHMSA understands that
the Merrimack Valley incident (which
occurred on a pipeline with both cast
iron and bare steel) underscores that
other types of high-risk materials on gas
distribution systems warrant similar
treatment. Although operators are
already identifying what specific piping
materials are on their system,60 and
§ 192.1007(b) requires operators to
actively monitor and consider the
presence of piping material with known
issues under the general threat category
of ‘‘material or welds,’’ PHMSA believes
that clarifying this practice in the DIMP
regulations would ensure that as
operators implement their DIMP plans,
they consider the risks associated with
the presence of these leak-prone
materials, as required by the risk
analysis in § 192.1007(c).
c. Proposal To Amend § 192.1007(b)—
DIMP—Identify Threats—Materials
PHMSA proposes to revise
§ 192.1007(b) to clarify that operators
must identify the threats posed by
specific material types in their pipeline
system, such as cast iron, wrought iron,
bare steel, and historic plastic pipe with
known issues. PHMSA expects that, in
determining whether a plastic pipe
material is a ‘‘historic plastic with
known issues’’ representing a threat to
pipeline integrity, operators should
consider PHMSA and State regulatory
actions and industry technical resources
identifying systemic integrity issues on
plastic pipe made from particular
materials manufactured at particular
times or by particular companies, or
fabricated and installed pursuant to
ddrumheller on DSK120RN23PROD with PROPOSALS3
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 selfexecuting statutory mandate within its 49 CFR part
192 regulations. See ‘‘Gas Pipeline Leak Detection
and Repair,’’ 88 FR 31890 (May 18, 2023). PHMSA
submits that this NPRM’s amendments to DIMP
requirements at subpart P would complement any
revisions to prescriptive regulations elsewhere in 49
CFR part 192 that PHMSA may adopt in that
parallel rulemaking.
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.
VerDate Sep<11>2014
20:23 Sep 06, 2023
Jkt 259001
particular processes. As noted above,
PHMSA issues advisory bulletins
cautioning operators regarding the
susceptibility of certain historic plastic
pipelines to systemic integrity issues.
Similarly, State pipeline safety
regulatory actions, PHMSA pipeline
failure investigation reports, and NTSB
findings can inform operator
determinations whether historic plastic
pipe is at a high-risk loss of integrity.
Industry efforts and resources are
another resource for operators in
determining whether historic plastic
pipe has known issues. For example, the
PPDC publishes periodic status reports
of data submitted by program
participants that incorporates
information regarding investigations of
materials of concern or potential
concern.61 PHMSA expects that these
and other authoritative resources—
coupled with an operator’s own design
expertise and operational and
maintenance history—would be
adequate for a reasonably prudent
operator to determine whether the
particular plastic pipe in its distribution
system is a historic plastic with known
issues. PHMSA further invites comment
on whether, within a final rule in this
proceeding, there would be value (in
addition to being cost-effective,
practicable, and technically feasible) in
either explicitly listing (within subpart
P or periodically-issued implementing
guidance) historic plastics prone to
leakage, or deleting the scope
qualification ‘‘historic’’ from proposed
regulatory text.
Once the threats are identified under
§ 192.1007(b), operators are also
required to evaluate these risks under
§ 192.1007(c) and to ensure that risk
reduction measures are identified and
implemented under § 192.1007(d).
2. DIMP—Identify Threats
(§ 192.1007(b))—Overpressurization
a. Current Requirements—DIMP—
Identify Threats—Overpressurization
Section 192.1007(b) does not
explicitly require operators to consider
the threat of overpressurization as a
threat under their DIMP plans. Instead,
§ 192.1007(b) requires operators to
consider the general threat category of
‘‘incorrect operations’’ or ‘‘other issues
that could threaten the integrity of [a]
pipeline’’ and requires operators to
consider whether those threats exist on
their systems. However,
overpressurization is a potential threat
to gas distribution systems. PHMSA has
61 AGA, ‘‘Plastic Pipe Data Collection Initiative’’,
https://www.aga.org/natural-gas/safety/promotingsafety/plastic-pipe-data-collection-initiative/ (last
visited March 10, 2023).
PO 00000
Frm 00016
Fmt 4701
Sfmt 4702
stated through previous enforcement
guidance and an advisory bulletin
(ADB–2020–02) that overpressurization
is a threat, especially for low-pressure
gas distribution systems, and
recommended that operators identify
overpressurization as a threat in their
DIMP plans. Further, § 192.195 provides
design requirements for the protection
against accidental overpressurization,
including additional requirements for
distribution systems.
b. Need for Change—DIMP—Identify
Threats—Overpressurization
The threat of overpressurization,
particularly on low-pressure gas
distribution systems, is a threat that
PHMSA expects operators to consider in
their DIMP plans. PHMSA considers the
threat of overpressurization to fall under
the threat categories of both ‘‘incorrect
operations’’ and ‘‘other issues that could
threaten the integrity of [a] pipeline’’ in
§ 192.1007(b). In enforcement guidance,
PHMSA lists ‘‘overpressurization
events’’ as an example of potential
threats operators could experience on
their pipelines.62 PHMSA also requires
operators to have sufficient knowledge
of their systems, per § 192.1007(a), to
determine if overpressurization is a
threat on their specific systems and to
develop and implement measures to
mitigate the consequences of a potential
overpressurization. As discussed earlier,
PHMSA also issued an advisory bulletin
(ADB–2020–02) alerting operators of
low-pressure gas distribution systems of
the increased risk of overpressurization
on those systems and recommended that
operators consider the threat of
overpressurization in their DIMP plans.
Recent incidents underscore the
importance of operators adequately
identifying the risk of
overpressurization on distribution
systems. Prior to the Merrimack Valley
incident on September 13, 2018, the
operator experienced four other
overpressurizations and one ‘‘nearmiss’’ within its network of distribution
systems.63
On March 1, 2004, a system
overpressurized when debris lodged at
the seat of the bypass valve in
Lynchburg, VA.
On February 28, 2012, an operator
error during an inspection resulted in
accidental overpressurization in
Wellston, OH. 300 customers were
without service for 14 hours.
On March 21, 2013, a segment of a
pipe with an MAOP of 1 psig was
pressurized at over 2 psig in Pittsburgh,
PA. A work crew, under the direction of
62 DIMP
Guidance at 19, 59.
at 25.
63 NTSB/PAR–19/02
E:\FR\FM\07SEP3.SGM
07SEP3
ddrumheller on DSK120RN23PROD with PROPOSALS3
Federal Register / Vol. 88, No. 172 / Thursday, September 7, 2023 / Proposed Rules
the local NiSource subsidiary, was
making a tie-in and failed to monitor the
pressure and flow of the existing lowpressure natural gas distribution system
during the tie-in process.
On August 11, 2014, a local NiSource
crew in Frankfort, KY, was excavating to
repair a leak located on the outside of
a regulator station building. The crew
uncovered and narrowly missed hitting
the 1-inch control line and tap located
on the 8-inch outlet pipeline. The crew
was unaware of the purpose of the 1inch 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,
VerDate Sep<11>2014
20:23 Sep 06, 2023
Jkt 259001
PHMSA was required by law to ensure
that operators evaluate the risk of
overpressurization in their DIMP plans.
PHMSA therefore proposes to amend
§ 192.1007(b) to explicitly require
operators to identify overpressurization
as a threat to low-pressure distribution
systems. The proposal is intended to
ensure that operators consider this risk
on their system as required by the risk
analysis in § 192.1007(c) and identify
risk reduction measures in accordance
with § 192.1007(d).
c. Proposal To Amend § 192.1007(b)—
DIMP—Identify Threats—
Overpressurization on Low-Systems
PHMSA proposes to amend
§ 192.1007(b) to create a new threat
category of ‘‘overpressurization on lowpressure systems.’’ This change would
ensure that consideration of risks under
the DIMP regulations explicitly includes
overpressurization of a low-pressure
system as a threat. Once identified as a
threat under § 192.1007(b), operators
would also have to evaluate the
likelihood and the potential
consequences of such a failure, as
required in § 192.1007(c), and ensure
risk-reduction measures are identified
and implemented under § 192.1007(d).
PHMSA discusses the actions operators
must take to implement § 192.1007(c)
and § 192.1007(d) in subsection IV.A.5
and 6 of this preamble.
3. DIMP—Identify Threats
(§ 192.1007(b))—Natural Forces
a. Current Requirements—DIMP—
Identify Threats—Natural Forces
Including Extreme Weather and
Geohazards
Section 192.1007(b) requires operators
to consider the general threat category of
‘‘natural forces,’’ but the requirement
does not explicitly state what natural
forces could pose a threat to the
integrity of the system. Natural force
damage occurs as a result of naturally
occurring events, including: (1)
earthquakes and landslides; (2) heavy
rains and flooding; (3) high winds,
tornadoes, or hurricanes; (4)
temperature extremes; and (5)
lightning.64 Further, PHMSA has issued
advisory bulletins alerting operators to
threats related to natural forces such as
land movement (i.e., geological hazards
or ‘‘geohazards’’ 65) (ADB–2022–01 and
ADB–2019–02), severe flooding (ADB–
2019–01), snow and ice build-up (ADB–
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.
PO 00000
Frm 00017
Fmt 4701
Sfmt 4702
61761
2016–03), and extreme temperatures
(ADB–2012–03).66
b. Need for Change—DIMP—Identify
Threats—Natural Forces Including
Extreme Weather and Geohazards
A distribution pipeline system
operates in a discrete environment due
to the limited geographic scope of each
individual system. The environment in
which a system operates significantly
affects the threats to pipeline integrity
that it faces. Factors such as weather
(dry or wet, hot or subject to freezing)
can significantly shape the threats
affecting individual distribution
operators and the actions necessary to
address those threats. Major climate
trends, such as elevated average surface
temperatures, more intense storm
events, and flooding, can,
independently and in combination,
affect the reliability and integrity of the
United States’ gas distribution
infrastructure. As climate change has
made extreme weather more common, it
is harder to categorize what types of
environmental factors facing
distribution pipelines are ‘‘normal’’
based on geography and historical
averages alone.
While freezing weather once seemed
like a problem reserved for northern
regions of the United States, southern
regions are also experiencing
unseasonable and extremely cold
weather. For example, in February of
2021, Texas experienced a winter storm
that brought some of the coldest
temperatures in its history.67 Extremely
cold weather can cause thermal
contraction stress or fractures of
pipelines due to the expansion of
moisture trapped inside components. In
addition, safety relief devices can
malfunction due to icing or freezing.
Low temperatures and the
accumulation of snow and ice also
increases the potential for physical
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.
67 On February 16, 2021, Dallas, TX recorded
temperatures as low as ¥2 °F.
E:\FR\FM\07SEP3.SGM
07SEP3
61762
Federal Register / Vol. 88, No. 172 / Thursday, September 7, 2023 / Proposed Rules
damage to meters and regulators and
other aboveground pipeline facilities
and components. For example, ice
forming on regulators or pressure relief
devices can cause them to malfunction
or stop working completely.68 Exposed
piping at metering and pressure
regulating stations, at service regulators,
and at propane tanks are at the greatest
risk. On February 11, 2016, PHMSA
issued advisory bulletin ADB–2016–03
alerting operators to the dangers of
abnormal snow and ice buildup on gas
distribution systems. PHMSA has issued
four other advisory bulletins since 1993
on this same issue.69
Natural forces such as severe flooding,
river scour, and river channel migration
can also adversely affect the safe
operation of a pipeline. These incidents
can damage a pipeline as a result of
additional stresses imposed on the pipe
by undermining underlying support
soils, exposing the pipeline to lateral
water forces and impact from
waterborne debris. Additionally, the
proper function of valves, regulators,
relief sets, pressure sensors, and other
facilities normally above ground or
above water can be jeopardized when
covered by water. PHMSA has issued
several advisory bulletins alerting
operators to the dangers severe flooding,
river scour, and river channel migration
can impose on a pipeline, most recently
in 2019 through ADB–2019–01 and
again in 2022 through ADB–2022–01.70
Sometimes flooding is seasonal and
predictable; however, the
Intergovernmental Panel on Climate
ddrumheller on DSK120RN23PROD with PROPOSALS3
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 BuildUp on Gas Distribution Systems,’’ ADB–08–03, 73
FR 12796 (Mar. 10, 2008); ‘‘Potential Damage to
Pipelines by Impact of Snowfall, and Actions Taken
by Homeowners and Others to Protect Gas Systems
from Abnormal Snow Build-up,’’ ADB–97–01 (Jan.
24, 1997); ‘‘Pipeline Safety Advisory Bulletin; Snow
Accumulation on Gas Pipeline Facilities,’’ ADB–
93–01, 58 FR 7034 (Feb. 3, 1993).
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).
VerDate Sep<11>2014
20:23 Sep 06, 2023
Jkt 259001
Change (IPCC) predicts increases in the
frequency and intensity of heavy
precipitation, which will give rise to
increased risk of flooding.71 In some
areas, climate change means higher
average precipitation,72 resulting in
water saturation that inhibits the ability
of soil to absorb extreme precipitation
events. Climate change may, however,
result in drought for other parts of the
United States,73 as lower average annual
precipitation rates result in lower soil
moisture—and therefore, less ability to
absorb extreme precipitation events.
Also, rainfall during the four wettest
days of the year has increased about 35
percent, and the amount of water
flowing in most streams during the
worst flood of the year has increased by
more than 20 percent.74 For parts of the
United States, spring rainfall and
average precipitation are likely to
increase and severe rainstorms are likely
to intensify during the next century.75
Each of these factors will tend to further
increase the risk of flooding—operators
must assess how this may impact the
integrity of their pipelines.
Extremely high temperatures can also
pose integrity threats to certain
materials. In March 2012, PHMSA
issued advisory bulletin ADB–2012–03
regarding the potential for degradation
of Driscopipe8000 pipes, which were
produced from 1979 through 1997.76 All
reported occurrences of in-service
degradation and leaks related to
Driscopipe8000 pipes were installed in
the desert region of the southwestern
United States, particularly in the Mojave
Desert region in Arizona, California, and
Nevada. The ambient temperatures in
the southwestern United States are very
high (typically over 100 degrees
Fahrenheit) and may contribute to
issues for plastic piping. Driscopipe
Series 7000 and 8000 HDPE pipe
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).
76 77 FR at 13388.
PO 00000
Frm 00018
Fmt 4701
Sfmt 4702
exposed to prolonged elevated
temperatures may degrade as a result of
thermal oxidation. One of the largest
producers of polyethylene piping
products in North America, has noted
that ‘‘the mechanism for this oxidation
appears to be the depletion of the
thermal stabilizer, which has been
shown to occur over time in high
ambient temperature conditions.’’ 77
PHMSA has reminded operators
through ADB–2012–03 that they should
monitor the performance of their plastic
piping.
Following the Merrimack Valley
incident, PHMSA reviewed its current
DIMP regulations for areas where
additional clarification could improve
the safety of gas distribution pipelines.
As climate change increases the
frequency of extreme weather events
and natural forces that can impact the
integrity of pipelines, PHMSA proposes
to add clarity to the DIMP regulations to
ensure that operators are considering
these threats when evaluating risks.
Operators would, therefore, need to
consider and take appropriate action to
address the impacts of extreme weather
as a threat, regardless of whether they
had experienced such events in their
pipelines’ history, while still
recognizing regional differences.
PHMSA expects operators to continue
evaluating reasonably available
information regarding changing
operating environments (i.e., climate)
and the regional impacts of extreme
weather on their pipeline.
c. PHMSA’s Proposal To Amend
§ 192.1007(b)—DIMP—Identify
Threats—Natural Forces Including
Extreme Weather and Geohazards
PHMSA proposes to amend
§ 192.1007(b) to specify that operators
must include the threat of extreme
weather and geohazards as
subcategories under the threat category
of ‘‘natural forces.’’ This amendment
would ensure that operators consider
the threat of extreme weather under the
DIMP regulations. Once identified as a
threat under § 192.1007(b), operators
would be required to consider how
potential extreme weather events could
increase the likelihood of failure. They
would also need to consider the
potential consequences of such a failure,
as required in § 192.1007(c), and ensure
that they identify risk-reduction
measures and implement them under
§ 192.1007(d). PHMSA expects that
operators would not limit their
77 Performance Pipe, ‘‘Driscopipe® 8000 Pipe
Degradation in High Temperature Applications’’
https://www.cpchem.com/sites/default/files/202005/DriscopipeDegradation.pdf (last visited Mar. 1,
2023).
E:\FR\FM\07SEP3.SGM
07SEP3
Federal Register / Vol. 88, No. 172 / Thursday, September 7, 2023 / Proposed Rules
consideration of the threat of extreme
weather solely on past normal weather
patterns but would also consider any
anticipated increases in extreme
weather conditions and fluctuations.
This proposed requirement would
improve safety by ensuring that
operators address the impacts of climate
change and protect the reliability and
integrity of their pipeline systems, even
if operators have yet to experience these
issues on their systems.
4. DIMP—Identify Threats
(§ 192.1007(b))—Age of the System,
Pipe, and Components
a. Current Requirements—DIMP—
Identify Threats—Age of the System,
Pipe, and Components
Section 192.1007(b) includes a
generic threat category of ‘‘other issues
that could threaten the integrity of [a]
pipeline,’’ which operators should use
to identify threats that do not fit into the
other threat categories. When
performing their risk analysis,
§ 192.1007(c) states that operators ‘‘may
subdivide [their] pipeline into regions
with similar characteristics.’’ PHMSA
has observed operators using age as a
method of subdividing their pipeline
segments when performing the risk
analysis. Further, PHMSA’s annual
report form, PHMSA F 7100.1–1,
requires operators to identify the miles
of pipeline by decade of installation.
Section 192.1007(b) does not, however,
specifically require that operators
consider the age of a pipe or
components when identifying threats to
pipeline integrity.
ddrumheller on DSK120RN23PROD with PROPOSALS3
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
VerDate Sep<11>2014
20:23 Sep 06, 2023
Jkt 259001
weaknesses, or accelerate timedependent degradation processes.
Age can impact and potentially
modify each of the threats an operator
identifies in § 192.1007(b). The potential
threat to pipeline integrity posed by age
depends on the age of the pipeline
components of which it is comprised.
PHMSA understands the cumulative
effect of those age-related threats to
integrity across an entire pipeline are
not merely the sum of age-related,
component-specific threats; rather,
those threats can magnify or exacerbate
one another when integrated within a
pipeline system. For example, one
component’s failure due to timedependent degradation processes can
strain other components throughout the
system (e.g., by releasing corrosion
products that can damage other, newer
components within the system).
PHMSA further notes that trending
failure rates by age can be a useful tool
for revealing degraded performance
throughout a pipeline system.
Similarly, the overall age of the
pipeline system can provide more
opportunities for safety-critical gaps in
material records. Poor recordkeeping
with respect to a pipeline component
dating from a certain time period may
threaten not only pipeline integrity on
that segment, but also other components
of the same pipeline installed at a
different time period.
Age can also be expressed in terms of
vintage of pipes or components. Specific
manufacturing techniques and materials
used during certain periods of time can
result in similar characteristics among
pipes and components of a given
vintage. The vintage of pipes or
components can interact with other
threats, including materials, equipment
failures, or natural forces. For example,
pipe installed earlier than 1950 has
disproportionately high susceptibility to
problems from cold weather and
freezing, which could interact with the
threat of natural forces. The greater
susceptibility of pre-1950 pipe is
thought to be due to inferior lowtemperature ductility of the steels of the
era and the methods used to join pipe
at the time (such as electric arc welds,
acetylene welds, couplings, and
threaded collars).78 Additionally, as
described in section IV.A.1 (materials),
some of the early plastic piping
products manufactured from the 1960s
and into the early 1980s are more
susceptible to brittle-like cracking (also
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-weathercan-play-havoc-on-natural-gas-systems.
PO 00000
Frm 00019
Fmt 4701
Sfmt 4702
61763
known as slow-crack growth) than
newer materials.79
Even though time-dependent
degradation processes are widely
understood threats to the integrity of
pipeline systems, as discussed earlier,
§ 192.1007(b) does not specifically state
that operators must account for the age
of the system, pipe, and components in
identifying threats. Increasing failure
rates have been observed in older gas
distribution infrastructure that has
certain attributes.80 The increasing
failure rate typically occurs toward the
end of life and accelerates the rate by
which the reliability decreases. This
behavior is typically attributed to
cumulative degradation that occurs in
the system over its service period.
Trending failure rates by system age can
reveal degrading performance.
Recent incidents have illustrated that
operators may be inadequately
identifying and managing threats related
to the age of components on their
systems. For example, in its risk
analysis, Atmos used a commercially
available software that did not explicitly
consider the age of the pipeline
segments, instead grouping them into
failure categories based on similar
attributes, such as material and coating.
Although such an approach may have
been compliant with current
regulations, this approach to risk
analysis disregards how the age could
contribute to failures. Following the
2018 Atmos incidents, the NTSB
recommended that Gas Piping
Technology Committee develop
guidance and identify steps operators
can take to ensure that their gas
distribution IM programs appropriately
consider threats that degrade a system
over time.81 By adopting such a
practice, operators would recognize the
full threat based on the impact of age
and prioritize remediating or replacing
segments of the pipe and components
that pose more acute threats. PHMSA
therefore proposes to revise
§ 192.1007(b) to explicitly identify age
as a factor in addressing threats to
integrity.
c. Proposal To Amend § 192.1007(b)—
DIMP—Identify Threats—Age of the
System, Pipe, and Components
PHMSA proposes to amend
§ 192.1007(b) to clarify that operators
79 Brittle-like cracking failures occur under
conditions of stress intensification. Stress
intensification is more common in fittings and
joints.
80 PHMSA, ‘‘Pipeline Replacement Background’’
(Apr. 26, 2021), https://www.phmsa.dot.gov/dataand-statistics/pipeline-replacement/pipelinereplacement-background.
81 NTSB/PAR–21/01 at 82.
E:\FR\FM\07SEP3.SGM
07SEP3
61764
Federal Register / Vol. 88, No. 172 / Thursday, September 7, 2023 / Proposed Rules
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.
ddrumheller on DSK120RN23PROD with PROPOSALS3
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
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).
83 DIMP Guidance at 22.
84 DIMP Guidance at 23.
VerDate Sep<11>2014
20:23 Sep 06, 2023
Jkt 259001
that conclusion.85 This basis should
consider the pipeline’s failure history,
design, manufacturing, construction,
operation, and maintenance.
b. Need for Change—DIMP—Evaluate
and Rank Risk
Recent incidents have demonstrated
the importance of operators adequately
evaluating and ranking risks on their
systems and in their DIMP plans. For
example, as demonstrated by the 2018
Merrimack Valley and other incidents
investigated by the NTSB, some
operators have not been adequately
evaluating the risk of
overpressurization, and thus not taking
appropriate mitigating measures to
account for those risks.86
Overpressurization incidents—in
particular on low-pressure gas
distribution systems—merit mitigation
because they have a high-consequence.
As previously noted, CMA had
knowledge of the risks of an
overpressurization, updated their
procedures, and still did not take
appropriate action to mitigate the risks.
Similarly, the Atmos incident in Texas
demonstrated how operators can
underestimate the risks associated with
the presence of leak-prone materials.
PHMSA is required by law to ensure
that operators’ DIMP plans evaluate the
presence and risks associated with cast
iron piping and the threat of
overpressurization on low-pressure gas
distribution systems (49 U.S.C.
60109(e)(7)). PHMSA is also required to
prohibit operators, when evaluating
risks related to the operation of a lowpressure gas distribution system, from
determining that there are no potential
consequences associated with lowprobability events unless that
determination is supported by
‘‘engineering analysis or operational
knowledge.’’ PHMSA must also ensure
that operators of gas distribution
systems consider factors other than past
observed ‘‘abnormal operating
conditions’’—as that term is defined at
§ 192.803—when ranking risks and
identifying measures to mitigate those
risks.
c. PHMSA’s Proposal To Amend
§ 192.1007(c)—DIMP—Evaluate and
Rank Risk
PHMSA proposes to redesignate the
general requirements of § 192.1007(c)
under a new paragraph (c)(1). These
general requirements still require
operators to consider the identified
threats proposed in § 192.1007(b) as
they evaluate and rank risks.
85 DIMP
Guidance at 18, 57.
at 18–21, 39–40, 48.
86 NTSB/PAR–19/02
PO 00000
Frm 00020
Fmt 4701
Sfmt 4702
i. Certain Pipe Materials With Known
Issues
PHMSA proposes to amend
§ 192.1007(c) by creating a new
§ 192.1007(c)(2) to specify that operators
must evaluate the risks resulting from
pipelines constructed with certain
materials (including cast iron, bare steel,
unprotected steel, wrought iron, and
historic plastics with known issues)
when such materials are present in their
pipeline systems. Overall, these
proposed requirements would improve
safety by codifying in DIMP
requirements some of the known,
industry-wide threats if the materials
that have exhibited these threats are
present in the operator’s systems, even
if operators have not yet experienced
any of these issues on their systems.
ii. Evaluate and Rank Risk: LowPressure Distribution Systems
PHMSA also proposes to amend
§ 192.1007(c) by creating a new
§ 192.1007(c)(3) applicable to lowpressure distribution systems.
Consistent with the mandate in 49
U.S.C. 60109(e)(7), PHMSA proposes to
require operators of low-pressure gas
distribution systems to evaluate ‘‘the
risks that could lead to or result from
the operation of a low-pressure
distribution system at a pressure that
makes the operation of any connected
and properly adjusted low-pressure gas
burning equipment unsafe.’’ For the
purposes of this NPRM, PHMSA
determines that ‘‘unsafe’’ in this context
means that gas flowing into the
downstream equipment is at a pressure
beyond the rated supply pressure
specified by the manufacturer of that
equipment. This amendment would
ensure that operators are addressing the
risks on their pipeline that could result
in an overpressurization.
In evaluating the risks to low-pressure
distribution systems, the mandate in 49
U.S.C. 60109(e)(7)(B) requires PHMSA
to ensure that operators consider
‘‘factors other than past observed
abnormal operating conditions [. . .] in
ranking risks.’’ This includes any
abnormal operating conditions (AOCs)
that operators have experienced (i.e.,
observed) on their system and any
unobserved AOCs that could occur on
their system (i.e., an overpressurization
on a low-pressure system), including
any known industry threats, risks, or
hazards, as identified by an operator
from available sources (e.g., PHMSA
advisory bulletins, PHMSA incident and
accident reports, PHMSA and NTSB
accident reports, State pipeline safety
regulatory actions, and operator
knowledge sharing). PHMSA proposes
E:\FR\FM\07SEP3.SGM
07SEP3
ddrumheller on DSK120RN23PROD with PROPOSALS3
Federal Register / Vol. 88, No. 172 / Thursday, September 7, 2023 / Proposed Rules
in § 192.1007(c)(3)(i) to require
operators of low-pressure systems to
evaluate risks to their systems in
accordance with the mandate. This
amendment would ensure that operators
are reviewing their past observed
operational performance to evaluate the
risks on their systems. This amendment
would also ensure that operators are
considering risks even if they have yet
to experience those risks on their
systems. For example, if an operator has
not experienced an overpressurization
on its system, that operator must still
consider the risks of an
overpressurization on its system.
The mandate in 49 U.S.C.
60109(e)(7)(B) also states that operators
may not determine that low probability
events have no potential consequences
without a supporting determination.
PHMSA proposes integrating this
mandate by adding a new paragraph
§ 192.1007(c)(3)(ii) that will direct
operators to evaluate the potential
consequences associated with lowprobability events, unless a
determination—supported and
documented by an engineering analysis
or other equivalent analysis
incorporating operational knowledge—
demonstrates that the event results in no
potential consequences (and therefore
no potential risk).
An engineering analysis would
include documentation of the
engineering principles used to calculate
the flows, pressures, and other
parameters of the piping and systems to
calculate the actual downstream
pressure. This engineering analysis
would also include documentation of
the methods used to determine that the
system cannot fail and cause
overpressurization, including any data
and assumptions (including mitigation
and control measures) utilized by the
operator. This engineering analysis may
necessarily include degrees of
measurable operational knowledge
regarding specific pipeline
characteristics and evidence from that
analysis combined with documentable
known pipeline characteristics. An
operator that determines there are no
potential consequences from a lowprobability event must document all
these reasons as part of its ‘‘engineering
analysis’’ submitted to PHMSA
according to § 192.18 with sufficient
detail as listed in
§ 192.1007(c)(3)(ii)(A)–(F).
Because the statute requires operators
to make an affirmative determination
that there are no potential consequences
associated with low probability events
and recognizing that some operators
might not have fully considered the risk
of low-probability events based solely
VerDate Sep<11>2014
20:23 Sep 06, 2023
Jkt 259001
on operational knowledge, PHMSA
proposes that any operational
knowledge relied upon must include
with it a quantifiable assessment and
support the operator’s determination
with a level of rigor equal to that of an
engineering analysis. This operational
knowledge could be included as part of
the proposed regulatorily required
‘‘engineering analysis, or an equivalent
analysis,’’ as used in § 192.1007(c)(3)(ii).
For example, should an operator
determine that a release of gas from the
pipeline, such as a leak, has no potential
consequences, the operator should
include documentation demonstrating
that many scenarios were considered
(such as a leak with ignition or gas
migration under nearby pavement) and
that no potential consequences were
identified in any of those potential
scenarios. This amendment would
ensure that operators do not dismiss
material risks without a meaningful
evidentiary basis, and PHMSA or
pertinent State authorities would have
the opportunity to review and consider
the validity of the operator’s
determination when reviewing DIMP
plans.
State regulatory authorities already
review operators’ DIMP plans during
regular inspections. Because incorrectly
determining that a potential threat has
no consequences would have serious
public safety impacts, however, PHMSA
understands there is a compelling
policy reason for an operator’s
determination that a low-frequency
event entails zero risk be reviewed by
those State regulatory authorities as well
as PHMSA. Therefore, if operators
choose to apply the proposed exception
in § 192.1007(c)(3)(ii), they must notify
PHMSA and the appropriate State
Authority in accordance with § 192.18
within 30 days of making this
determination that there are no potential
consequences associated with the lowprobability event. The notification must
include information such as the date the
determination was made (to ensure
compliance with the proposed
timeline), descriptions of the lowprobability events being considered, and
a description of the logic supporting the
determination, including information
from an engineering analysis or an
equivalent analysis incorporating
operational knowledge. Further, this
notification should contain a
description of any preventive and
mitigative measures, including any
measures considered but not taken, as
determined through the engineering
analysis or an equivalent analysis
incorporating operational knowledge.
The notification should also include a
PO 00000
Frm 00021
Fmt 4701
Sfmt 4702
61765
description of the low-pressure system,
including, at a minimum, miles of pipe,
number of customers, number of district
regulators supplying the system, and
other relevant information. In addition,
operators must provide a written
statement summarizing the
documentation it evaluated and how the
conclusion that there would be no
potential consequences associated with
the low-probability event was reached.
This documentation could include the
inspection and maintenance history of
the pipeline segment, incident reports,
any leak repair data, and any failure
investigations or abnormal operations
records. Providing this information
would be critical in ensuring that
operators robustly evaluated methods of
reducing risk and that the operator did
not ignore any material factors in their
engineering analysis or an equivalent
analysis incorporating operational
knowledge.
In a new § 192.1007(c)(3)(iii), PHMSA
proposes to require that in evaluating
and ranking risks in their DIMP plans,
operators of low-pressure gas
distribution systems must evaluate the
configuration of their primary and any
secondary overpressure protection
installed at the district regulator
stations, the availability of gas pressure
monitoring at or near overpressure
protection equipment, and the
likelihood of any single event that
immediately or over time could result in
an overpressurization of the lowpressure system (see amended
§ 192.195(c)). Operators’ overpressure
protection configurations vary—some
include a combination of relief valves,
monitoring regulators, or automatic
shutoff valves. Other operators have
real-time monitoring devices located at
the district regulator station, while yet
others rely on telemetering devices.
Some operators, as demonstrated by the
events of September 13, 2018, may have
an overpressure protection
configuration that can be defeated by a
single event, such as excavation
damage, natural forces, an equipment
failure, or incorrect operations. This
amendment would ensure that operators
are evaluating their existing
overpressure protection system for
inadequacies or additional risks that
could result in an overpressurization of
the system.
E:\FR\FM\07SEP3.SGM
07SEP3
61766
Federal Register / Vol. 88, No. 172 / Thursday, September 7, 2023 / Proposed Rules
6. DIMP—Identify and Implement
Measures To Address Risks (Section
192.1007(d))
ddrumheller on DSK120RN23PROD with PROPOSALS3
a. Current Requirements—DIMP—
Identify and Implement Measures To
Address Risks
Section 192.1007(d) requires
operators to determine and implement
measures designed to reduce the risks
from failure of their gas distribution
pipeline systems following the
identification of threats (in accordance
with § 192.1007(b)) and the evaluation
and ranking of risks (in accordance with
§ 192.1007(c)). Section 192.1007(d) also
requires that these risk mitigation
measures include an effective leak
management program (unless all leaks
are repaired when found). Although the
specific process is not defined in
§ 192.1007(d), PHMSA has issued
guidance material to support the
implementation of these requirements.
In the guidance material, PHMSA
states that operators should have a
documented list of measures to reduce
risks identified on their pipeline
system.87 The process for identifying
risk mitigation measures must be based
on identified threats to each pipeline
segment and the risk analysis. Operators
should rank pipeline segments and
group segments that represent the
highest risk as the most important
candidates for which measures are taken
to reduce risk. The operator should
ensure that the highest priority
measures for reducing risk are for the
highest-ranked segments as indicated by
the risk analysis. Because the design
and operation of gas distribution
systems are so diverse, no single risk
control method is appropriate in all
cases. Therefore, the objective of
§ 192.1007(d) is to ensure that each
operator has documented and described
existing and proposed measures to
address the unique risks to its system
and that the operator has evaluated and
prioritized actions to reduce risks to
pipeline integrity.
b. Need for Change—DIMP—Identify
and Implement Measures To Address
Risks
Proper implementation of a DIMP
plan should result in aggressive
oversight and replacement of higher-risk
infrastructure. For example, there are
many benefits to replacing old, castiron, low-pressure distribution pipes
with newer materials, such as modern
plastic pipe. Replacement projects,
however, entail their own risks to public
safety and the environment that need to
be balanced against the risks associated
87 DIMP
Guidance at 28.
VerDate Sep<11>2014
20:23 Sep 06, 2023
Jkt 259001
with leaving a pipeline segment
undisturbed. Poorly managed
construction projects can result in
property damage and personal injury,
and replacement activity can include
blowdowns to the atmosphere of
methane gas that contribute to climate
change. Work on existing pipeline
facilities can also cause a catastrophic
overpressurization, as was the case in
CMA’s 2018 incident. Operators must
manage those risks while still
implementing preventive and mitigative
measures that would reduce the risk of
identified threats.
In 2020, PHMSA issued an advisory
bulletin to remind operators of the
possibility of failure due to an
overpressurization on low-pressure
distribution systems.88 In that advisory
bulletin, PHMSA reminded operators of
the existing DIMP regulations and
recommended that per § 192.1007(d),
operators take additional actions to
reduce risks if they found their current
overpressure protection design to be
insufficient. PHMSA also identified for
operators that ‘‘[t]here are several ways
that operators can protect low-pressure
distribution systems from overpressure
events,’’ such as:
1. Installing a full-capacity relief valve
downstream of the low-pressure
regulator station, including in
applications where there is only workermonitor pressure control;
2. Installing a ‘‘slam shut’’ device;
3. Using telemetered pressure
recordings at district regulator stations
to signal failures immediately to
operators at control centers; and
4. Completely and accurately
documenting the location for all control
(i.e., sensing) lines on the system.
As discussed earlier, subsequent to
the 2018 Merrimack Valley incident,
PHMSA was required by statute to
ensure that operators of low-pressure
gas distribution systems evaluate the
risk of overpressurization in their DIMP
plans. (49 U.S.C. 60109(e)(7)(A)(ii)). For
existing low-pressure systems, operators
already have a mechanism in place—
their DIMP—to evaluate their systems to
ensure they can identify and implement
measures to minimize the risk imposed
by any inadequate overpressure
protection.
c. PHMSA’s Proposal To Amend
§ 192.1007(d)—DIMP—Identify and
Implement Measures To Address Risks
PHMSA proposes to amend
§ 192.1007(d) to establish additional
88 See ‘‘Pipeline Safety: Overpressure Protection
on Low-Pressure Natural Gas Distribution
Systems,’’ ADB–2020–02, 85 FR 61097 (Sept. 29,
2020).
PO 00000
Frm 00022
Fmt 4701
Sfmt 4702
criteria for operators to evaluate when
identifying and implementing measures
to address risks identified in DIMP
plans. PHMSA’s proposal would require
operators—when identifying and
implementing measures—to specifically
account for risks associated with the age
of the pipe, the age of the system, the
presence of pipes with known issues,
and overpressurization of low-pressure
distribution systems. PHMSA is adding
these specific risks to § 192.1007(d)
because they were the subject of recent
incidents, as discussed earlier. This
amendment would ensure that operators
are not only identifying these specific
threats (in § 192.1007(b)), but also
implementing measures to address those
risks. In a new § 192.1007(d)(2), PHMSA
is proposing to explicitly require
operators of existing low-pressure
systems to take certain actions to
prevent and mitigate the risk of an
overpressurization that could be the
result of any single event or failure.
These actions include identifying,
maintaining, and (if necessary)
obtaining traceable, verifiable, and
complete records that document the
characteristics of the pipeline that are
critical to ensuring proper pressure
controls for the system. PHMSA
discusses the criteria for these pressure
control records in section IV.F of this
NPRM.
In addition to this recordkeeping
requirement, in a new § 192.1007(d)(2),
PHMSA proposes that operators must
confirm and document that each district
regulator station meets the design
standards in § 192.195(c)(1)–(3) or take
the following actions: (1) identify
preventative and mitigative measures
based on the unique characteristics of
their system to minimize the risk of
overpressurization on low-pressure
systems, or (2) upgrade their systems to
meet design standards in
§ 192.195(c)(1)–(3). PHMSA discusses
the criteria for this proposed upgrade in
section IV.H of this NPRM. Should an
operator choose to identify preventative
and mitigative measures based on the
unique characteristics of their system to
minimize the risk of overpressurization,
PHMSA proposes that the operator
notify PHMSA and State or local
pipeline authorities no later than 90
days in advance of implementing any
alternative measures. PHMSA proposes
that an operator must make this
notification in accordance with
§ 192.18, which would include a
description of the operator’s proposed
alternative measures, identification, and
location of facilities to which the
measures would be applied, and a
description of how the measures would
E:\FR\FM\07SEP3.SGM
07SEP3
ddrumheller on DSK120RN23PROD with PROPOSALS3
Federal Register / Vol. 88, No. 172 / Thursday, September 7, 2023 / Proposed Rules
ensure the safety of the public, affected
facilities, and environment. This
notification would ensure that operators
are keeping PHMSA and State
authorities informed of alternative
measures to address risk. This
amendment would apply to existing
low-pressure systems that have
evaluated and identified inadequate
overpressure protections in accordance
with § 192.1007(c).
PHMSA has also proposed to amend
§ 192.18 to reflect this proposed change
by including a reference to § 192.1007.
Should an operator choose to
implement an alternative method of
minimizing overpressurization, PHMSA
proposes that the operator notify
PHMSA and State or local pipeline
authorities no later than 90 days in
advance of implementing any
alternative measures. PHMSA proposes
that operators must make this
notification in accordance with
§ 192.18, which would include a
description of the operators’ proposed
alternative measures, identification, and
location of facilities to which the
measures would be applied, and a
description of how the measures would
ensure the safety of the public, affected
facilities, and environment. This
notification would ensure that operators
are keeping PHMSA and State
authorities informed of alternative
measures to address risk.
PHMSA proposes these amendments
pursuant to 49 U.S.C. 60102(t) and
60109(e)(7). The proposed amendments
would reinforce the recommended
actions from PHMSA’s 2020 advisory
bulletin in which PHMSA identified for
operators of low-pressure distribution
systems the risks inherent to those
systems and the preventative or
mitigative measures they should
implement to address the risk of
overpressurization. PHMSA expects that
operators may already be complying
with many of these practices subsequent
to issuance of the advisory bulletin,
which set forth PHMSA’s existing
policy and interpretation of the current
DIMP requirements. In this NPRM,
PHMSA proposes to codify this existing
policy and interpretation in its
regulations.
This amendment is also aligned with
the NTSB’s clarification to
recommendation P–19–14 that PHMSA
would not have to require that existing
low-pressure gas distribution systems be
completely redesigned; rather, PHMSA
may satisfy the recommendation by
requiring operators to add additional
protections, such as slam-shut or relief
valves, to existing district regulator
VerDate Sep<11>2014
20:23 Sep 06, 2023
Jkt 259001
stations or other appropriate locations
in the system.89
7. DIMP—Small LPG Operators (Section
192.1015)
a. Current Requirements—DIMP and
Annual Reporting for Small LPG
Operators
A ‘‘small LPG operator’’ is currently
defined at § 192.1001 as an operator of
a liquefied petroleum gas (LPG)
distribution pipeline system that serves
fewer than 100 customers from a single
source. Small LPG operators are treated
differently in the DIMP regulations than
larger operators and they follow their
own set of DIMP requirements in
§ 192.1015 that reflect the relative
simplicity of these pipeline systems.
The current DIMP requirements for
small LPG operators in § 192.1015 are
less extensive than for other gas
distribution systems, but still provide
operator personnel direction for
implementing their DIMP plans.
Currently, under § 191.11, operators of
small LPG systems are not required to
submit an annual report to PHMSA.
b. Need for Change—DIMP—
Applicability for Small LPG Operators
In the 2009 DIMP Final Rule, PHMSA
imposed requirements for small LPG
operators similar to those for other
operators but with more limited
requirements for documentation,
consistent with how these operators are
treated throughout the pipeline safety
regulations. PHMSA did not require
operators to report performance
measures as they do not file annual
reports. Although the DIMP
requirements for small LPG operators
are similar to those applicable to other
operators, PHMSA codified them
separately under § 192.1015,
emphasizing that DIMPs for small LPG
operators should reflect the relative
simplicity of their pipeline systems.
On January 11, 2021, PHMSA issued
a final rule titled ‘‘Pipeline Safety: Gas
Pipeline Regulatory Reform,’’ 90 which
among other things, excepted master
meters from the DIMP requirements.
During the development of that rule,
PHMSA received several comments in
support of extending that exception to
small LPG operators. For example, the
National Association of Pipeline Safety
Representatives (NAPSR) suggested that
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/srdetails/P-19-014.
90 86 FR 2210 (Jan. 11, 2021) (‘‘Gas Regulatory
Reform Final Rule’’). The comments submitted by
stakeholders in this rulemaking may be found in
Doc. No. PHMSA–2018–0046.
PO 00000
Frm 00023
Fmt 4701
Sfmt 4702
61767
small gas distribution utilities with 100
or fewer customers—including small
LPG operators—should be excepted
from the DIMP requirements, stating
that many master meter systems, small
distribution systems, and small LPG
systems typically have no threats
beyond the minimum threats listed in
§ 192.1015(b)(2). Various other
commenters, including the National
Propane Gas Association (NPGA),
AmeriGas, and Superior Plus Propane,
voiced support for excepting small LPG
operators from the DIMP requirements.
The Pipeline Safety Trust did not
oppose an exception from DIMP
requirements for master meter systems
in that rulemaking, only urging PHMSA
and its State partners to ensure that
master meter operators are managing the
integrity risks to their systems outside
the context of a DIMP plan. In response,
PHMSA in the Gas Regulatory Reform
Final Rule stated, ‘‘that the decision
about whether to extend the DIMP
exception to [other] facilities or to all
distribution systems with fewer than
100 customers would benefit from
additional safety analysis and notice
and comment procedures prior to
further consideration.’’ PHMSA went on
to say that it would ‘‘continue to
evaluate the issue of DIMP requirements
for small LPG systems and, if
appropriate, propose changes in a future
rulemaking[.]’’ 91
On December 17, 2021, the NPGA
filed a petition for rulemaking in
accordance with 49 CFR 190.331.92
NPGA petitioned PHMSA to amend 49
CFR part 192, subpart P to create an
exception for small LPG systems in the
DIMP requirements. In support of their
petition, they cited that NPGA, PHMSA,
and the National Academies of Sciences
(NAS) have considered the operation
and safety of small LPG systems for
more than 10 years.93 As an alternative,
NPGA proposed that PHMSA could
enable a special permit (through
§ 190.341) for small LPG systems, for
which NPGA would assist small LPG
system operators in providing necessary
information to PHMSA in the special
permit process.
91 86
FR at 2216.
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).
92 NPGA,
E:\FR\FM\07SEP3.SGM
07SEP3
ddrumheller on DSK120RN23PROD with PROPOSALS3
61768
Federal Register / Vol. 88, No. 172 / Thursday, September 7, 2023 / Proposed Rules
The basis of NPGA’s petition is that
small LPG system operators are
comparable to master meter systems, a
set of operators that PHMSA recently
removed from the DIMP requirements
through the 2021 Gas Regulatory Reform
Final Rule. As NPGA explained, master
meter systems tend to be operated by
small entities with simple systems
compared to natural gas distribution
operators. Master meters also often
include only one type of pipe, and the
systems operate at a single operating
pressure. Similarly, as NPGA stated, the
vast majority of small LPG pipeline
systems are single property systems that
occupy a small, overall footprint in size
and generally operate at a single
operating pressure. Although such
systems may be metered or nonmetered, the nature of their simplicity
in size and application make them
comparable to master meter systems
such that, owing to their ‘‘nearly
identical’’ function and structure, ‘‘the
two systems should be categorized
together for the same treatment under
the regulations’’ exempting them from
DIMP requirements.94
NPGA reiterated that PHMSA further
noted in the 2021 Gas Regulatory
Reform Final Rule that the agency’s
experience indicated the analysis and
documentation requirements of DIMP
had little safety benefit for this type of
operator and that focusing on more
fundamental risk mitigation activities
has more safety benefits than
implementing a DIMP for this class of
operators. NPGA went on to reiterate
PHMSA’s position in the Gas Regulatory
Reform Final Rule (as discussed above),
where PHMSA indicated that exempting
master meter operators from subpart P
would result in cost savings for master
meter operators without negatively
impacting safety. NPGA stated that
PHMSA had previously expressed its
intention to address small LPG systems
in a future rulemaking and added that
this change would not conflict with the
Administration’s aims of reducing
methane emissions.95
PHMSA has reviewed and considered
NPGA’s petition and agrees with its
assertion that small LPG systems do not
present the same complexity or incur
the same risks as large networks of
pipeline systems crossing hundreds of
miles. Therefore, PHMSA addresses
NPGA’s petition through this proposed
rule and continued oversight through
partnership with State agencies.
94 NPGA
Petition at 3.
Petition at 3–5. PHMSA notes that LPG
releases are not themselves generally considered to
be releases of GHGs.
95 NPGA
VerDate Sep<11>2014
20:23 Sep 06, 2023
Jkt 259001
PHMSA has concluded that its
existing approach requiring small LPG
operators to comply with limited DIMP
requirements offers little public safety
benefit. Small LPG operators by
definition have limited systems serving
a small number of customers; in fact,
NAPSR data suggests that there are only
between 3,800 and 5,800 multi-user
systems nationwide, with most serving
fewer than 50 customers (often well
below 50 customers).96 Small LPG
systems are also more simple systems—
less piping and fewer components that
could fail—that are inherently less
susceptible to loss of pipeline integrity
than large gas distribution systems.
Further, PHMSA incident data indicate
that small LPG systems entail relatively
low public safety risks. PHMSA’s
incident data suggest small LPG systems
average less than one incident involving
a fatality or serious injury per year.
Incidents reported by operators to
PHMSA from 2010 through 2017
include 10 incidents, seven injuries, and
approximately $2 million in property
damage.97 No fatalities have been
reported since 2006. Incorporating fire
events from the National Fire Incident
Reporting System with the PHMSA
incident data suggests that the number
of incidents involving LPG distribution
systems averages in the single digits per
year. And, because releases of LPG are
not themselves generally considered
GHG emissions, continued regulation of
small LPG systems pursuant to
PHMSA’s DIMP requirements provides
little benefit for mitigating climate
change.
PHMSA understands that even
limited DIMP requirements can place a
significant compliance burden on small
LPG operators and administrative
burdens on PHMSA and State regulatory
authorities—which in turn can detract
from other safety efforts. A 2018 study
issued by the NAS found that there is
significant regulatory uncertainty among
small LPG operators regarding whether
PHMSA’s DIMP regulations apply at
all—resulting in many such operators
neither understanding they are obliged
to comply with PHMSA regulations nor
being regularly inspected by State
regulatory authorities.98
Given their small size and the relative
simplicity of their systems, as discussed
in the preceding paragraphs, and the
significant compliance burden that
96 NAS
Study at 83.
Study at 41, Table 3–4.
98 The NAS Study identified as a source of much
of that regulatory uncertainty the varied
interpretations of ‘‘public place’’ used at
§ 192.1(b)(5) to determine if certain petroleum gas
systems are subject to PHMSA’s 49 CFR part 192
regulations. NAS Study at 87–88.
97 NAS
PO 00000
Frm 00024
Fmt 4701
Sfmt 4702
DIMP requirements impose on such
entities with limited safety benefit,
PHMSA has determined that it is more
appropriate to exempt small LPG
operators from DIMP requirements but
impose an annual reporting requirement
on these operators.
c. PHMSA’s Proposal To Exempt Small
LPG Operators From DIMP
Requirements and Extend Annual
Reporting Requirements to Small LPG
Systems
PHMSA proposes to add a new
§ 192.1003(b)(4) and delete existing
§ 192.1015 to remove small LPG
operators from DIMP requirements but
extend annual reporting requirements to
these operators. With small LPG
operators removed from DIMP
requirements at § 192.1015, the
definition of small LPG operators in
§ 192.1001 becomes redundant and
therefore PHMSA would also remove it
from DIMP. In developing this proposal,
PHMSA considered the comments made
in the Gas Regulatory Reform Final Rule
on the topic of the application of DIMP
requirements to small LPG operators,
the NPGA’s petition for rulemaking, the
NAS study, and PHMSA’s incident data.
PHMSA has preliminarily determined
that continuing to impose DIMP
requirements (even in the abbreviated
form pursuant to existing § 192.1015) on
small LPG systems that have been
proven by PHMSA incident data to
entail inherently limited public safety
risks imposes outsized compliance
burdens on operators and administrative
burdens on PHMSA and State regulatory
authorities.99 At the same time,
extending the annual reporting
requirement to these operators is
intended to ensure that PHMSA will
maintain the ability to identify and
respond to systemic or emerging issues
on those systems.
PHMSA does not expect that this
proposed exception from DIMP
requirements would adversely impact
public safety. As discussed above,
PHMSA understands the public safety
benefits attributable to existing, limited
DIMP requirements for small LPG
operators are limited. PHMSA will be
able to retain regulatory oversight of
small LPG operator systems through
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.
E:\FR\FM\07SEP3.SGM
07SEP3
ddrumheller on DSK120RN23PROD with PROPOSALS3
Federal Register / Vol. 88, No. 172 / Thursday, September 7, 2023 / Proposed Rules
other requirements within 49 CFR part
192, including the proposed annual
reporting requirement and the incident
reporting requirements at 49 CFR part
191.
To improve the information available
to PHMSA and State regulatory
authorities for identifying and
addressing systemic public safety issues
from small LPG systems, PHMSA is
proposing to revise § 191.11 to require
operators of small LPG systems to
submit annual reports using newly
designated form PHMSA F 7100.1–2.
These annual reports would require
operators of small LPG systems to report
the location and number of customers
served by their distribution pipeline
systems, as well as the disposition of
any discovered leaks. PHMSA expects
that through an annual reporting
requirement, PHMSA would also be
able to provide better data to the public
on small LPG systems, which the agency
could assess and may ultimately inform
a future rulemaking. PHMSA also
expects that its proposal to require
annual reporting for small LPG
operators may help alleviate the
confusion noted by the NAS Study
regarding whether those operators are
subject to PHMSA regulations at 49 CFR
part 192.
PHMSA expects the extension of its
part 191 annual reporting requirements
to small LPG systems would be
reasonable, technically feasible, costeffective, and practicable. The
information PHMSA collects on its
current annual report form for gas
distribution operators (Form F7100.1–1)
does not require significant technical
expertise or particularly expensive
equipment to populate; small LPG
operators may also reduce their burdens
further by contracting with vendors to
operate and perform maintenance on
their systems and complete annual
report forms. PHMSA also expects that
the forthcoming annual report form
(PHMSA F 7100.1–2) specific to small
LPG operators will be a further
simplified version of the current annual
report form. Additionally, PHMSA notes
that the information it expects will be
collected within that simplified annual
report form—operator corporate
information, length and composition of
the system, leaks on that system, etc.—
is minimal information that a
reasonably prudent small LPG operator
would maintain in ordinary course
given that their systems transport
pressurized (natural, flammable, toxic,
or corrosive) gasses. Viewed against
those considerations and the
compliance costs estimated in section
V.D herein and the PRIA, PHMSA
expects the new annual reporting
VerDate Sep<11>2014
20:23 Sep 06, 2023
Jkt 259001
requirement for these operators will be
a cost-effective approach to ensuring
PHMSA has adequate information to
monitor the public safety and
environmental risks associated with
small LPG systems that would no longer
be subject to DIMP requirements. Lastly,
PHMSA expects that the compliance
timeline proposed for this new reporting
requirement—which would begin with
the first annual reporting cycle after the
effective date of any final rule issued in
this proceeding (which would
necessarily be in addition to the time
since publication of this NPRM)—would
provide affected operators ample time to
compile requisite information and
familiarize themselves with the new
annual report form (and manage any
related compliance costs).
B. State Pipeline Safety Programs
(Sections 198.3 and 198.13)
1. Current Requirements—State
Programs and Use of SICT
PHMSA relies heavily on its State
partners for inspecting and enforcing
the pipeline safety regulations. The
pipeline safety regulations provide that
States may assume safety authority over
intrastate pipeline facilities, including
gas pipeline, hazardous liquid pipeline,
and underground natural gas storage
facilities through certifications and
agreements with PHMSA under 49
U.S.C. 60105 and 60106. States may also
act as an interstate agent on behalf of
DOT to inspect interstate pipeline
facilities for compliance with the
pipeline safety regulations pursuant to
agreement with PHMSA.
To support states’ pipeline safety
programs, PHMSA provides grants to
reimburse up to 80 percent of the total
cost of the personnel, equipment, and
activities reasonably required by the
State agency to conduct its safety
programs during a given calendar year.
49 CFR part 198 contains regulations
governing grants to aid State pipeline
safety programs. PHMSA also maintains
‘‘Guidelines for States Participating in
the Pipeline Safety Program’’
(‘‘Guidelines’’), which contains
guidance for how State pipeline safety
programs should conduct and execute
their delegated responsibilities.100 The
Guidelines promote consistency among
the many State agencies that participate
under certifications and agreements and
are updated on an annual basis.
In 2017, PHMSA adopted within its
Guidelines the State Inspection
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-withAppendices-2020-5-27.pdf.
PO 00000
Frm 00025
Fmt 4701
Sfmt 4702
61769
Calculation Tool (SICT), a tool that
helps states conduct an inspection
activity needs analysis for regulatory
oversight of every operator subject to its
jurisdiction, for the purpose of
establishing a base level of inspection
person-days 101 needed to maintain an
adequate pipeline safety program.102 In
the SICT, each State agency considers
the type of inspection it needs to
conduct (e.g., standard, comprehensive,
integrity management, operator
qualification, damage prevent activities,
drug and alcohol); analyzes each
operator’s system for several risk factors
(e.g., cast iron pipe, replacement
construction activity, compliance
issues); assigns each operator a risk
ranking based on the risk factors (e.g.,
leak prone pipe would have a higher
score than modern, coated, and
cathodically protected pipe); and lists
other unique concerns and
considerations (e.g., travel distance to
conduct the inspection) applicable to
each operator.103 Each State agency
proposes an inspection activity level for
each operator, which is subsequently
peer-reviewed before being finalized by
PHMSA. PHMSA expects that each
State agency will dedicate a minimum
of 85 inspection person-days for each of
its full-time pipeline safety inspectors
for pipeline safety compliance activities
each calendar year.104 PHMSA
considers a State agency’s inspection
activity level, among several other
factors, when awarding grants to State
pipeline safety programs.
2. Need for Change—State Programs and
Use of the SICT
A State is authorized to enforce safety
standards for intrastate pipeline facility
or intrastate pipeline transportation if
the State submits annually to PHMSA a
certification that complies with 49
U.S.C. 60105(b) and (c). As amended in
2020, the certification includes a
requirement that each State agency have
the capability to sufficiently review and
evaluate the adequacy of each
distribution system operator’s DIMP
plan, emergency response plan, and
operations, maintenance, and
emergency procedures, as well as ‘‘a
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.
E:\FR\FM\07SEP3.SGM
07SEP3
61770
Federal Register / Vol. 88, No. 172 / Thursday, September 7, 2023 / Proposed Rules
sufficient number of employees’’ to help
ensure the safe operations of pipeline
facilities, as determined by the SICT. (49
U.S.C. 60105(b)). PHMSA updates
Guidelines and its evaluation process
annually to ensure that State agencies
are meeting the certification
requirements.105
In certifying that the State has a
‘‘sufficient number of employees’’, the
State must use the SICT to account for:
1. The number of miles of gas and
hazardous liquid pipelines in the State,
including the number of miles of cast
iron and bare steel pipelines;
2. The number of services in the State;
3. The age of the gas distribution
systems in the State; and
4. Environmental factors that could
impact the integrity of the pipeline,
including relevant geological issues.
Currently, the SICT accounts for the
size (e.g., mileage, service line count,
etc.) of each operator’s system; type of
operator and product being transported;
risk factors of material composition,
including but not limited to, the
presence of cast iron and bare steel; and
environmental factors that could impact
the integrity of a pipeline, including
geological issues. Total miles of gas and
hazardous liquid pipelines in a State
and the age of gas distribution systems
are, however, only implicitly
considered. To comply with the
mandate, PHMSA proposes to codify
within its regulations the use of the
SICT for establishing inspection persondays and update the SICT to explicitly
include the total gas or hazardous liquid
pipeline mileage in the State and the age
of a gas distribution system as a factor
for consideration.
ddrumheller on DSK120RN23PROD with PROPOSALS3
3. PHMSA’s Proposal To Codify the Use
of the SICT in Pipeline Safety
Regulations
This NPRM proposes amendments to
the pipeline safety regulations at 49 CFR
part 198 to codify use of the SICT by all
PHMSA’s State partners holding
certifications or agreements per 49
U.S.C. 60105 or 60106. Specifically,
PHMSA proposes to revise § 198.3 to
add definitions for ‘‘inspection personday’’ and ‘‘State Inspection Calculation
Tool’’ and by revising § 198.13 to
include the use of the SICT for
determining inspection person-days.
PHMSA proposes to define ‘‘inspection
person-day’’ to mean ‘‘all or part of a
day, including travel, spent by State
agency personnel in on-site or virtual
evaluation of a pipeline system to
determine compliance with Federal or
105 PHMSA anticipates issuing updated Guidance
to reflect the changes to the Pipeline Safety Grant
Program.
VerDate Sep<11>2014
20:23 Sep 06, 2023
Jkt 259001
State Pipeline Safety Regulations.’’
PHMSA will continue to permit travel
to be included for inspection persondays even if travel requires a full day
before or after the inspection because
some states cover a large geographical
area that requires substantial travel time
and a State agency’s staffing
requirement could be impacted if travel
is not considered. PHMSA will also
continue to allow inspection persondays to be counted for those individuals
who have not completed training
requirements but who assist in
inspections if they are supervised by a
qualified inspector. PHMSA proposes to
define the term ‘‘State Inspection
Calculation Tool (SICT)’’ to mean ‘‘a
tool used to determine the required
minimum number of annual inspection
person-days for a State agency.’’ These
proposed definitions are consistent with
those in the Guidelines.
PHMSA is required to promulgate
regulations to require that a State
authority with a certification under 49
U.S.C. 60105 has a sufficient number of
qualified inspectors to ensure safe
operations, as determined by the SICT
and other factors determined
appropriate by the Secretary. (49 U.S.C.
60105 note). Pursuant to this legal
requirement, PHMSA proposes revising
§ 198.13(c)(6) to state that when
allocating funding and considering
various performance factors, PHMSA
considers the number of State
inspection person-days, ‘‘as determined
by the SICT and other factors.’’ These
amendments would codify PHMSA’s
current practice of using the SICT in the
determination of the minimum number
of inspection person-days each State
must dedicate to inspections in a given
calendar year.
C. Emergency Response Plans (Section
192.615)
The pipeline safety regulations
require operators to have written
procedures for responding to
emergencies involving their pipeline
systems to ensure a coordinated
response to a pipeline emergency. This
response includes communicating with
fire, police, and other public officials
promptly. Through a final rule issued
on April 8, 2022, titled ‘‘Requirement of
Valve Installation and Minimum
Rupture Detection Standards’’, PHMSA
extended that emergency
communication for all gas pipeline
operators to include a public safety
answering point (PSAP; i.e., 9–1–1
emergency call center).106 Among other
changes, the Valve Rule amended
§ 192.615(a) to ensure proper
106 87
PO 00000
FR at 20940, 20973.
Frm 00026
Fmt 4701
Sfmt 4702
communication with PSAPs, requiring
operators to immediately and directly
notify PSAPs upon notification of a
potential rupture. However, the Valve
Rule requirements were not in effect at
the time of the Merrimack Valley
incident.
Subsequent to the 2018 Merrimack
Valley incident, 49 U.S.C. 60102 was
amended to improve the emergency
response and communications of gas
distribution operators during gas
pipeline emergencies in several ways.
Specifically, 49 U.S.C. 60102(r) was
added, which requires PHMSA to
promulgate regulations ensuring that gas
distribution operators develop written
emergency response procedures for
notifying and communicating with
emergency response officials as soon as
practicable from the time of confirmed
discovery of certain gas pipeline
emergencies; communicate with the
public during and after such a gas
pipeline emergency; and establish an
opt-in system for operators to rapidly
communicate with customers. Gas
distribution operators must make their
updated emergency response plans
available to PHMSA or the relevant
State regulatory agency within 2 years
after the final rule is issued, and every
5 years thereafter (49 U.S.C.
60108(a)(3)).
PHMSA, in this NPRM, proposes
building on the Valve Rule’s changes to
emergency response plan requirements
through additional changes to ensure
prompt and effective emergency
response coordination. For all gas
pipeline operators subject to
§ 192.615,107 PHMSA proposes to
expand the requirements to have
procedures for a prompt and effective
response to include emergencies
involving notification of potential
ruptures, a release of gas that results in
a fatality, and any other emergencies
deemed significant by the operator, with
similar requirements to notify PSAPs in
those instances. PHMSA understands
these proposed amendments of existing
emergency response plan requirements
as applicable to all part 192-regulated
pipelines would be reasonable,
technically feasible, cost-effective, and
practicable. The proposed changes are
common-sense, incremental
supplementation of current
requirements regarding the content and
execution of emergency response plans
for gas pipeline operators.
107 PHMSA notes that § 192.9(d) does not
currently require compliance with § 192.615 for
Type B gathering lines, however PHMSA has
proposed, in another rulemaking, to amend
§ 192.9(d) to require Type B gas gathering operators
to comply with § 192.615. See 88 FR at 31952–53,
31955–56.
E:\FR\FM\07SEP3.SGM
07SEP3
ddrumheller on DSK120RN23PROD with PROPOSALS3
Federal Register / Vol. 88, No. 172 / Thursday, September 7, 2023 / Proposed Rules
Implementation of the proposed
requirements should not require special
expertise or investment in expensive
new equipment; PHMSA expects that
some operators may already comply
with these proposed requirements either
voluntarily or due to similar
requirements imposed by State pipeline
safety regulators. And insofar as these
incremental proposed additions to
emergency planning requirements are
consistent with historical PHMSA
guidance, industry operational
experience, and the lessons learned
from incidents such as the Merrimack
Valley incident, they are precisely the
sort of actions a reasonably prudent
operator of any gas pipeline facility
would maintain in ordinary course
given that their systems transport
commercially valuable, pressurized
(natural flammable, toxic, or corrosive)
gasses. Viewed against those
considerations and the compliance costs
estimated in the PRIA, PHMSA expects
its proposed amendments are a costeffective approach to achieving the
commercial, public safety, and
environmental benefits discussed in this
NPRM and its supporting documents.
Lastly, PHMSA understands that its
proposed compliance timeline—one
year after publication of a final rule
(which would necessarily be in addition
to the time since publication of this
NPRM)—would provide operators
ample time to implement requisite
changes to their procedures (and
manage any related compliance costs).
PHMSA proposes additional
requirements for gas distribution
operators. First, those operators would
be subject to an expanded list of
emergencies that includes unintentional
releases of gas with significant
associated shutdown of customer
services. Second, gas distribution
operators must establish written
procedures for communications with
the general public during an emergency,
and continue communications through
service restoration and recovery efforts,
to inform the public of the emergency
and service restoration and recovery
efforts. Third, gas distribution operators
would be required to develop and
implement for their customers an opt-in
or opt-out notification system to provide
them with direct communications
during a gas pipeline emergency.
PHMSA understands its proposed
amendments enhancing existing
emergency response plan requirements
would be reasonable, technically
feasible, cost-effective, and practicable
for affected gas distribution operators.
PHMSA expects that some gas
distribution operators may already
VerDate Sep<11>2014
20:23 Sep 06, 2023
Jkt 259001
comply with these requirements either
voluntarily or due to similar
requirements imposed by State pipeline
safety regulators. PHMSA also expects
that operators will already have (due to
the need to bill their customers) the
requisite contact information needed to
implement voluntary opt-in or opt-out
notification systems; as explained
below, some operators may also be able
to leverage existing emergency
notification systems maintained by local
and State government officials in
satisfying this proposed requirement.
PHMSA further notes that its proposed
enhancements for emergency
communications are precisely the sort of
minimal actions a reasonably prudent
operator of gas distribution pipeline
facility would undertake in ordinary
course to protect each of (1) the public
safety, given that their systems transport
pressurized (natural, flammable, toxic,
or corrosive) gasses; and (2) their
customers, given the economic cost to
those customers from interruption of
supply. Viewed against those
considerations and the compliance costs
estimated in the PRIA, PHMSA expects
its proposed amendments will be a costeffective approach to achieving the
public safety and environmental
benefits discussed in this NPRM and its
supporting documents. Lastly, PHMSA
understands that its proposed
compliance timeline—between 12 to 18
months after publication of a final rule
(which would necessarily be in addition
to the time since publication of this
NPRM)—would provide operators
ample time to implement requisite
changes to their procedures and procure
necessary personnel and vendor
services (and manage any related
compliance costs).
Finally, PHMSA is requesting
comments on whether it should require
gas distribution operators to follow
incident command systems (ICS) during
an emergency response. PHMSA may
consider whether to include this
requirement in any final rule in this
proceeding. The sections below discuss
each of these proposals in more detail.
1. Emergency Response Plans—First
Responders
a. Current Requirements—Emergency
Response Plans—Notifying PSAPs, First
Responders, and Public Officials
Section 192.615(a) requires that each
gas pipeline operator have written
procedures for responding to gas
pipeline emergencies, including for how
operators are expected to communicate
with fire, police, and other appropriate
public officials before and during an
emergency. The Valve Rule revised
PO 00000
Frm 00027
Fmt 4701
Sfmt 4702
61771
§ 192.615(a)(2) to add direct
communication with PSAPs in response
to gas pipeline emergencies and
required operators to establish and
maintain an adequate means of
communication with PSAPs.108 Further,
the Valve Rule revised § 192.615(a)(8) to
require operators to notify these entities
and coordinate with them during an
emergency. This communication to the
appropriate PSAPs must occur
immediately and directly upon
receiving a notification of potential
rupture to coordinate and share
information to determine the location of
any release.109 The Valve Rule also
revised § 192.615(c) to require each
operator establish and maintain liaison
with the appropriate PSAPs ‘‘where
direct access to a 9–1–1 emergency call
center is available from the location of
the pipeline, as well as fire, police, and
other public officials’’ to coordinate
responses and preparedness planning.
Further, PHMSA issued an advisory
bulletin in 2012 (ADB–2012–09)
regarding communications between
pipeline operators and PSAPs.110 In the
advisory bulletin, PHMSA reminded
operators that they should notify PSAPs
of indications of a pipeline facility
emergency, including an unexpected
drop in pressure, an unanticipated loss
of SCADA communications, or reports
from field personnel. In the advisory
bulletin, PHMSA recommended that
pipeline operators immediately contact
the PSAPs of the communities in which
such indications occur. Furthermore,
the advisory bulletin noted that
operators should have the ability to
immediately contact PSAPs along their
pipeline routes if there is an indication
of a pipeline emergency to determine if
the PSAP has information that may help
the operator confirm whether a pipeline
emergency is occurring or to provide
assistance and information to public
safety personnel who may be
responding to the event. The revisions
to § 192.615 in the Valve Rule
essentially codified this advisory.
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.
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.
E:\FR\FM\07SEP3.SGM
07SEP3
61772
Federal Register / Vol. 88, No. 172 / Thursday, September 7, 2023 / Proposed Rules
ddrumheller on DSK120RN23PROD with PROPOSALS3
PHMSA notes that indications of a gas
pipeline emergency, including
unexpected pressure drops or reports
from field personnel, might be a
notification of potential rupture under
amended § 192.615, which would
require the direct and immediate
notification of the appropriate PSAP.
b. Need for Change—Emergency
Response Plans—Notifying PSAPs, First
Responders, and Public Officials
During the initial response to the 2018
Merrimack Valley incident, the three
fire departments in the affected
municipalities were inundated with
emergency calls from residents and
businesses reporting fires and
explosions and requesting assistance
shortly after 4 p.m. on September 13,
2018. Around that same time, the CMA
technician reported smoke and
explosions. However, it was not until
nearly 4 hours later at 7:43 p.m. that the
president of CMA declared a ‘‘Level 1’’
emergency under CMA’s emergency
response plan. Lawrence’s deputy fire
chief told NTSB investigators that,
during the incident response, he
attempted to contact CMA through the
station dispatch to get a status update to
see if CMA had the gas incident under
control but did not receive updates from
the company until hours later. About 2
hours after the initial fires, Lawrence’s
deputy fire chief assumed the gas
company had resolved the incident.111
The Andover fire chief recognized the
events occurring were gas-related and
contacted CMA through a regular
dispatch number to provide status
updates so the fire department could
relay information to the public. He told
NTSB investigators that CMA did call
him back more than 4 hours later, while
also acknowledging the delay was likely
caused by the number of emergency
calls CMA received.
The NTSB report noted that CMA had
emergency response plans but did not
implement their plans in a manner that
would allow them to effectively respond
to such a large incident, explaining that
ambiguities within the operator’s
emergency response plans could have
contributed to the poor emergency
response in that incident. Specifically,
the NTSB pointed out that the operator’s
emergency response plans suggested
that notification could be discretionary,
as those procedures stated that when an
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.
VerDate Sep<11>2014
20:23 Sep 06, 2023
Jkt 259001
overpressurization of the system occurs,
there ‘‘may be a need’’ to communicate
with local government officials and
emergency management agencies, as
well as with fire and police
departments.112 According to the NTSB
report, the NiSource emergency plan
also stated that it is ‘‘imperative for all
entities involved to remain informed of
each other’s activities,’’ and that CMA’s
Incident Commander (IC), (in this case,
the field operations leader (FOL)) was
required to establish appropriate
contacts for communication purposes
throughout the incident. However,
during the initial hours of the event, the
IC did not establish these requisite
communication contacts because the IC
was involved with shutting down the
natural gas system. And although CMA
representatives went to emergency
responder staging areas and emergency
operations centers, the NTSB report
noted that CMA representatives could
not address many of the questions from
emergency responders because the
representatives were not prepared with
thorough and actionable information. As
a result of the lack of timely, thorough,
and actionable information on the
circumstances of the overpressurization
event, emergency responders
unnecessarily evacuated areas, straining
limited emergency response resources,
and creating confusion among the
public. The NTSB concluded that CMA
was not adequately prepared with the
resources necessary to assist emergency
management services with the
emergency response.
Subsequent to the 2018 Merrimack
Valley incident, PHMSA was required
by law to promulgate regulations to
ensure that gas distribution system
operators include in their emergency
response plans written procedures for
notifying ‘‘first responders and other
relevant public officials as soon as
practicable, beginning from the time of
confirmed discovery, as determined by
[PHMSA], by the operator of a gas
pipeline emergency,’’ and including gas
distribution-specific indications of what
constitutes a gas pipeline emergency.
(49 U.S.C. 60102(r)).
c. Proposal To Amend § 192.615—
Emergency Response Plans—Notifying
PSAPs, First Responders, and Public
Officials
As discussed earlier, the Valve Rule
revised the existing emergency response
regulations to require operators notify
PSAPs in the event of gas pipeline
emergencies, and immediately and
directly notify PSAPs when receiving a
notification of potential rupture. In this
112 NTSB/PAR–19/02
PO 00000
Frm 00028
at 46.
Fmt 4701
Sfmt 4702
NPRM, PHMSA proposes to revise the
non-exclusive list at § 192.615(a)(3) of
gas pipeline emergencies requiring all
part 192-regulated gas pipeline
operators to undertake prompt, effective
response on notification of potential
ruptures; a release of gas that results in
one or more fatalities; and any other
emergency deemed significant by the
operator. PHMSA is also proposing that
gas distribution pipeline operators
would need to undertake prompt,
effective response on notification of the
unintentional release of gas and
shutdown of gas service to either 50 or
more customers or, if the operator has
fewer than 100 customers, 50 percent of
total customers. Additionally, PHMSA
proposes to amend existing
requirements at § 192.615(a)(8) to apply
its requirement for operators of all gas
pipelines to establish written
procedures for immediately and directly
notifying PSAPs, or other coordinating
agencies for the communities and
jurisdictions in which the pipeline is
located, to include after a notification of
these gas pipeline emergencies. Gas
distribution operators, moreover, would
also have to immediately and directly
notify PSAPs on notification of an
unintentional release and shutdown of
gas services where either 50 or more
customers lose service, or for operators
with fewer than 100 customers, if 50
percent of all the operator’s customers
lose service.
i. What is a ‘‘Gas Pipeline Emergency?’’
PHMSA is revising the list of gas
pipeline emergencies in § 192.615(a)(3)
to add: (1) for all part 192-regulated gas
pipeline operators, events involving 1 or
more fatalities or any other emergency
deemed significant by the operator; and
(2) for gas distribution pipeline
operators only, an unintentional release
of gas resulting in a shutdown of gas
services affecting at least 50 customers,
or for operators with fewer than 100
customers, 50 percent of customers.113
The statutory language does not
elaborate on the meaning of
‘‘significant’’ within its usage in the
phrase ‘‘the unscheduled release of gas
and shutdown of gas service to a
significant number of customers.’’
Therefore, PHMSA proposes to establish
the threshold for a ‘‘significant number
of customers’’ to be 50 customers or, for
operators with fewer than 100
customers, 50 percent of all the
operator’s customers. In determining
this threshold, PHMSA reviewed the
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 § 192.615(a)(8).
E:\FR\FM\07SEP3.SGM
07SEP3
Federal Register / Vol. 88, No. 172 / Thursday, September 7, 2023 / Proposed Rules
data for all reportable gas distribution
incidents from 2010 to 2021 and
averaged the number of residential,
commercial, and industrial customers
affected by those incidents.114
PHMSA also proposes to add ‘‘other
emergency deemed significant by the
operator’’ to the list of examples of a gas
pipeline emergency to allow operators
to use their best professional judgment
when coordinating with first responders
and other relevant public officials and
account for other system-specific
circumstances, such as an outage to a
single customer that happens to be a
hospital or other critical-use facility,
when complying with § 192.615. This
amendment would specify a nonexclusive list of gas pipeline
emergencies.
ddrumheller on DSK120RN23PROD with PROPOSALS3
ii. When must operators communicate
with PSAPs, first responders, and other
relevant public officials?
PHMSA proposes to adopt the
aforementioned more-inclusive list of
gas pipeline emergencies into the
§ 192.615(a)(8) notification requirements
established in the Valve Rule that
required the immediate and direct
notification of PSAPs and other relevant
emergency responders and public
officials after receiving notice of such an
emergency. Pursuant to 49 U.S.C.
60102(r), operator communications with
first responders and other relevant
public officials must occur ‘‘as soon as
practicable, beginning from the time of
confirmed discovery, as determined by
the Secretary, by the operator of a gas
pipeline emergency.’’ PHMSA, in
§§ 191.5 and 195.52, already uses the
term ‘‘confirmed discovery’’ 115 to
require operators to report certain
events to the National Response Center
at the earliest practicable moment
following ‘‘confirmed discovery;’’
however, these notifications may occur
up to 1 hour after confirmation. Further,
those §§ 191.5 and 195.52 reportable
events may not always constitute a gas
pipeline emergency as proposed in
§ 192.615. Because the 49 U.S.C.
60102(r) mandate directs PHMSA to
improve and expand emergency
response efforts—distinct from operator
notification of incidents/accidents for
reporting purposes—PHMSA
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/distributiontransmission-gathering-lng-and-liquid-accidentand-incident-data.
115 The term ‘‘confirmed discovery,’’ defined at
§§ 191.3 and 195.3, ‘‘means when it can be
reasonably determined, based on information
available to the operator at the time a reportable
event has occurred, even if only based on a
preliminary evaluation.’’
VerDate Sep<11>2014
20:23 Sep 06, 2023
Jkt 259001
determines that the timing of local
emergency communication must come
immediately and directly upon
indication of such a gas pipeline
emergency. PHMSA, therefore, does not
propose to interpret ‘‘confirmed
discovery’’ in 49 U.S.C. 60102(r) to
apply in § 192.615(a) in the same
manner as the term is used in 49 CFR
parts 191 and 195.116 Instead, PHMSA
proposes ‘‘confirmed discovery’’ in 49
U.S.C. 60102(r), for purposes of
§ 192.615, to mean immediately after
receiving notice of a gas pipeline
emergency.117 This will bring local
emergency services to bear as near as
possible to a gas pipeline emergency
based on early indications, rather than
considering whether the gas pipeline
emergency is also a reportable event
under § 191.5 before initiating an
emergency response.
PHMSA proposes that gas pipeline
emergencies be immediately and
directly communicated to local
emergency responders because any
delays in emergency response may make
the emergency significantly more
difficult to contain. PHMSA expects that
in no case should that ‘‘immediate’’
communication to PSAPs begin any
later than 15 minutes following initial
notification to the operator of that
emergency. This expectation is
consistent with certain criteria for
‘‘notification of a potential rupture’’
adopted in the Valve Rule,118 and
would ensure the timely and effective
implementation of the pipeline
operator’s emergency response plan and
coordinated response with local public
safety officials. PHMSA also expects
that if a gas pipeline emergency also
meets the criteria of an incident in
§ 191.3, operators would report the
incident to the National Response
Center in accordance with § 191.5, as
already required.
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.
118 See § 192.635(a)(1) (specifying a 15-minute
time interval for evaluating significant pressure
losses on gas pipelines as an indicium of a rupture).
PO 00000
Frm 00029
Fmt 4701
Sfmt 4702
61773
iii. What information should operators
provide to first responders and public
officials?
As the emergency response to the
Merrimack Valley incident continued,
public safety officials asked CMA for
detailed information on the locations of
the overpressurized gas lines to aid in
assessing the scope and scale of the
incident. Officials requested maps and
lists of impacted customers and
impacted streets, but CMA did not
provide them in a timely manner. This
significantly hampered the response to
the event and caused first responders to
take unnecessary actions during the
immediate response efforts. For
example, instead of targeting specific
residents based on the location of the
affected services, first responders
needed to go door to door to evaluate
safety impacts and determine where the
gas lines were overpressurized. To
prevent such delays from occurring in
the future, PHMSA recommends
operators provide first responders and
public officials with pertinent
information, as it becomes available, to
support emergency communications
during a gas pipeline emergency,
including: (1) the operator’s response
efforts; (2) information on the gas
service sites impacted by the release; (3)
the magnitude of the incident and its
expected impact; (4) the location(s) of
the emergency and of affected
customers; (5) the specific hazard and
the potential risks; and (6) the operator
point of contact responsible for
addressing first responder and public
official questions and concerns.
Procedures to provide such information
must be included in their emergency
response plans and should also comport
with guidance by the Federal
Emergency Management Agency
(FEMA) for State and local governments
in developing effective hazard
mitigation planning and would help
ensure that appropriate instructions,
directions, and information is provided
to the right people at the appropriate
time.119
2. Emergency Response Plans—General
Public
a. Current Requirements—Emergency
Response Plans—General Public
Currently, there are no Federal
regulations requiring gas distribution
operators to establish communications
with the general public during or
following a gas pipeline emergency.
Section 192.615 requires operator
119 FEMA, ‘‘Lesson 3: Communicating in an
Emergency’’ (Feb. 2014), https://training.fema.gov/
emiweb/is/is242b/instructor%20guide/ig_03.pdf.
E:\FR\FM\07SEP3.SGM
07SEP3
61774
Federal Register / Vol. 88, No. 172 / Thursday, September 7, 2023 / Proposed Rules
coordination and communication with
only fire, law enforcement, emergency
management, and other public safety
officials. Section 192.616 contains
requirements for public awareness but
does not contain provisions specific to
communications with the public during
or after an emergency.120
b. Need for Change—Emergency
Response Plans—General Public
In any gas pipeline emergency,
communicating basic information and a
consistent message can be difficult.
While communication with emergency
responders is important, so too is
contemporaneously updating affected
members of the public, as both serve to
reduce public safety harms. CMA’s
failure to communicate promptly with
its affected customers throughout the
2018 Merrimack Valley incident showed
deficiencies in CMA’s incident response
planning. CMA first provided the public
with information regarding the incident
at approximately 9:00 p.m. on
September 13, 2018—nearly 5 hours
after the onset of the emergency at
approximately 4:00 p.m. when the first
9–1–1 calls on the incident were made.
Although CMA was still gathering
relevant information during the first
several hours following the incident and
did not have a complete understanding
of the situation, it nevertheless should
have conveyed information to the public
on the nature of the incident and
affected areas more quickly.
Subsequent to the 2018 Merrimack
Valley incident, PHMSA was directed in
49 U.S.C. 60102(r) to revise its
regulations to ensure that each gas
distribution operator includes written
procedures in its emergency plan for
‘‘establishing general public
communication through an appropriate
channel’’ as soon as practicable after a
gas pipeline emergency. In particular,
operators should communicate to the
public information regarding the gas
pipeline emergency and ‘‘the status of
public safety.’’
ddrumheller on DSK120RN23PROD with PROPOSALS3
c. PHMSA’s Proposal To Amend
§ 192.615—Emergency Response
Plans—General Public
Gas distribution pipeline operators
are not currently required to
communicate public safety or service
120 Section 192.616 requires operators to develop
and implement a written continuing publiceducation program that follows the guidance
provided in American Petroleum Institute’s (API)
Recommended Practice (RP) 1162 (incorporated by
reference, see § 192.7). API RP 1162 is a consensus
standard that establishes a baseline publicawareness program for pipeline operators. It states
that operators should provide notice of, and
information regarding, their emergency response
plans to appropriate local emergency officials.
VerDate Sep<11>2014
20:23 Sep 06, 2023
Jkt 259001
interruption and restoration information
to the public during and following a gas
pipeline emergency. Therefore, PHMSA
proposes that gas distribution operators
include procedures for establishing and
maintaining communication with the
general public as soon as practicable
during a gas pipeline emergency on a
gas distribution pipeline. Operators
would need to continue
communications through service
restoration and recovery efforts.
Operators would need to establish
communication through one or more
channels appropriate for their
communities, which could include inperson events (e.g., press conferences or
town hall-style events), print media,
broadcast media, the internet or social
media, text messages, phone apps, or
any combination of these channels.
Further, PHMSA proposes that such
communications must include the
following components:
1. Information regarding the gas
pipeline emergency (which could
include the specific hazard and
potential risks to the community, the
location of the incident and boundaries
of the impacted area, the magnitude of
the event and the expected impact,
protective actions the public should
take, and how long the public may be
impacted),
2. The status of the emergency (e.g.,
have the condition causing the
emergency or the resulting public safety
risks been resolved),
3. The status of pipeline operations
affected by the gas pipeline emergency
and when possible, a timeline for
expected service restoration, and
4. Directions for the public to receive
assistance (e.g., provide a phone number
for customers to call if they are without
power for 24 hours, or directions to safe
local shelters should temperatures drop
below freezing).
PHMSA believes that providing in its
regulations a list of information for
operators to include in their procedures
will help streamline communications to
the public during a gas pipeline
emergency and post-emergency efforts
and ensure that members of the public
have information needed to understand
the risks to public safety posed by a gas
pipeline emergency. In addition, by
providing a list of minimum
requirements for public
communications, operators can train
personnel on the type of information
they should collect and share with the
public. Operators can require the
communication of additional
information in their procedures, but
should, at a minimum, inform the
public of the information listed above.
During an emergency response, an
PO 00000
Frm 00030
Fmt 4701
Sfmt 4702
operator’s resources may be strained
such that not all the information
pertaining to the incident may be
available at a given time. Therefore,
during a gas pipeline emergency on a
distribution line, operators should
provide updates to the public on a
reasonable basis as this information
becomes available or changes. This
provision allows for a common-sense
approach to when an operator must
provide general public updates to an
emergency. However, it would require
operators to provide these updates
based on the circumstances of the
emergency such that the general public
timely receives information that could
influence the public’s response to the
emergency or benefit affected
communities’ understanding of recovery
effort progress.
Further, PHMSA also proposes that
when communicating this minimum
information with the general public,
operators must ensure these messages
are issued in English and in other
languages commonly understood by a
significant number and concentration of
the non-English speaking population in
the operator’s service area and are
delivered in a manner accessible to
diverse populations in their service
operators. Operators should use clear
and simple language in their
communications. The Merrimack Valley
incident underscores the value of such
broadly accessible communications. The
city of Lawrence, MA, is comprised of
a higher percentage of Spanish-speaking
residents than other areas affected by
the Merrimack Valley incident. In the
Massachusetts Emergency Management
Agency (MEMA) After Action Report,
MEMA reported that CMA did not fully
account for the demographics of the
impacted communities when attempting
to communicate with the public during
and following the incident, which in
some cases delayed delivery of
appropriate information and services to
impacted customers.121
Operators must prepare their public
communication plans before a gas
pipeline emergency develops to ensure
that the proper tools and resources are
available to assist limited English
proficiency (LEP) individuals in the
communities they serve when an
emergency arises. PHMSA notes that, as
required under § 192.616(g), operators
must conduct their public awareness
program in other languages commonly
understood by a significant number and
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-gasexplosions-after-action-report/download
(‘‘Merrimack Valley After Action Report’’).
E:\FR\FM\07SEP3.SGM
07SEP3
Federal Register / Vol. 88, No. 172 / Thursday, September 7, 2023 / Proposed Rules
concentration of the non-English
speaking population in the operator’s
area. Therefore, operators should
already be aware of the languages used
in their service areas and have this
information readily available. If
operators do not already have this
information, data from the U.S. Census
Bureau American Community Survey at
the tract level—including summarized
information on English proficiency
along with mapping of critical
infrastructure and locations of hospitals,
long-term care facilities, police, and fire
stations—can help provide more
targeted and community-specific
services.122 Operators can use this
information to understand the
demographics of their communities and
build lists of common media sources for
each language population in their
service area. More information on how
to reach LEP communities in emergency
preparedness, response, and recovery is
available through the Department of
Justice.123 Where appropriate, operators’
communications during pipeline
emergencies should account for
disabilities that might make
communication difficult by, for
example, having American Sign
Language interpreters present during
press conferences to ensure that
hearing-impaired residents can receive
communications during a pipeline
emergency.
3. Emergency Response Plans—Opt-in
System for Customers
ddrumheller on DSK120RN23PROD with PROPOSALS3
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
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.
VerDate Sep<11>2014
20:23 Sep 06, 2023
Jkt 259001
targeting their residents by using 9–1–1
call location data to estimate the
locations of the affected services. Local
officials used this data to reach a
consensus about which areas to
evacuate because they were unable to
use more accurate data from CMA
regarding the number and location of
impacted customers.124
Andover and North Andover used
their existing emergency notification
systems to notify residents to evacuate.
Authorities in North Andover issued a
voluntary evacuation for all occupied
structures with natural gas utility
service, using local cable channels, the
town website, and a citizen alert
telephone system that sends public
service messages. The alert system
automatically called every landline.
However, cell phones and private
numbers had to be registered to receive
a call. The Andover fire chief called for
an evacuation using a citizen alert
telephone system and social media. The
wireless emergency alerts to evacuate
South Lawrence, and later to return
home, were sent out in both English and
Spanish. The South Lawrence mayor’s
evacuation order was issued as an alert
over cell phones and media broadcasts
to residents in the area. In total, more
than 50,000 residents were asked to
evacuate through a variety of methods.
While many municipalities have
communication systems to rapidly
communicate with their constituents
during an emergency, not all gas
distribution operators are using these
tools to rapidly communicate with their
customers during a gas pipeline
emergency. PHMSA believes that
operators could use these tools to
provide customers with real-time
information during an emergency to
protect public safety. The Merrimack
Valley incident underscored the need
for operators to improve their
communication with customers when
responding to an emergency on a gas
distribution pipeline. Subsequently, 49
U.S.C. 60102 was amended to include a
new mandate to expand the use of
voluntary, opt-in customer notifications
during an emergency. Specifically,
PHMSA was directed to update its
regulations to ensure that each
emergency response plan developed by
an operator of a gas distribution system
includes written procedures for ‘‘the
development and implementation of a
voluntary, opt-in system that would
allow operators of distribution systems
to rapidly communicate with customers
in the event of an emergency.’’ (49
U.S.C. 60102(r)(3)). PHMSA
understands that a ‘‘system’’ to ‘‘rapidly
124 Merrimack
PO 00000
Frm 00031
Valley After Action Report at 46.
Fmt 4701
Sfmt 4702
61775
communicate with customers’’ could
take many forms; however, in practice,
it is typically a ‘‘reverse 9–1–1’’ system
that calls or texts individual customers
to notify them of significant, timesensitive events. Many cities and
utilities already use such systems to
allow emergency officials to notify
residents and businesses of emergencies
or outages by telephone, cell phone, text
message, or email.
c. Proposal To Amend § 192.615—
Emergency Response Plans—Customers
Pursuant to 49 U.S.C. 60102(r)(3),
PHMSA proposes to add to § 192.615 a
new paragraph (d) that would require
operators of gas distribution pipelines to
establish procedures for developing and
implementing a voluntary, opt-in
customer notification system to
communicate with customers in the
event of a gas pipeline emergency.
PHMSA understands the statutory
mandate for a ‘‘voluntary, opt-in
system’’ to mean that the gas pipeline
operators give the customers they serve
the opportunity to opt-in (or opt-out) to
receiving notifications from the
operator’s communication system,
therefore making the system voluntary
for customers. Gas distribution
operators must notify all customers of
the existence of such a communications
tool and their ability to elect to receive
such emergency notifications.
PHMSA does not expect that a
voluntary, opt-in emergency notification
system would impose a significant
burden on operators. PHMSA notes that
operators will often already have from
their billing activities much of the
information (customer phone numbers,
email and postal addresses, and
preferred language) needed to
implement such a system. And because
an iteration of a voluntary, opt-in or optout emergency notification systems may
already be in place in some local
communities,125 PHMSA concludes that
operators could comply with this
proposed requirement by coordinating
with cities and townships to utilize
those existing systems. Where
coordination with an existing
communication system is not possible,
operators may choose to utilize a thirdparty vendor or build such a service inhouse. Regardless of who administers
the notification system proposed in
§ 192.615(d), operators would need to
provide a basic description of the
system and describe the operation of the
system in their procedures. Operators
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.
E:\FR\FM\07SEP3.SGM
07SEP3
ddrumheller on DSK120RN23PROD with PROPOSALS3
61776
Federal Register / Vol. 88, No. 172 / Thursday, September 7, 2023 / Proposed Rules
must also include in their procedures a
description of the protocols for
activating the system and notifying
customers (i.e., who initiates the
notification and when). PHMSA notes
that such a voluntary opt-in or opt-out
system could have additional benefits
outside of gas pipeline emergencies, as
operators could use such a system to
communicate with their customers
during non-emergencies (such as service
outages or planned maintenance) or for
billing purposes.
Because periodic testing is essential
for ensuring proper operation of such an
emergency customer notification
system, PHMSA includes within its
proposed § 192.615(d) that operators’
procedures must describe system testing
protocols and (at least) annual testing.
Operators would need to maintain the
results of their testing and operations
history for at least 5 years. If an operator
does not control the testing protocol
(e.g., because they rely on an emergency
notification system administered by a
local government), they should describe
in their procedures the frequency of
testing performed by partnered
municipality and arrange to receive
confirmation of those tests after they
occur.
Similar to the requirements discussed
earlier for public communications
during and following gas pipeline
emergencies, PHMSA is also proposing
that an operator’s written procedures for
this opt-in notification system include a
description of how the system’s
messages will be accessible to Englishspeaking and LEP customers alike.
Operators should describe the process
for identifying any LEP or other
pertinent demographic information for
the areas they serve. These procedures
should include a description of any
non-English languages required in
standardized emergency
communications that would be
provided in an operator’s system.
Because there may be LEP individuals
who need to receive these messages,
operators should be prepared to
translate messages about public safety
into the required non-English
language(s).
PHMSA also proposes to require
operators’ procedures include
cybersecurity measures to protect the
notification system and customer
information. As with any system that
interfaces with operators’ information
technology assets or customers private
information, operators should protect
against cybersecurity vulnerabilities and
insider threats. Operators should, for
example, include protocols aimed at
protecting their infrastructure from
malicious attacks, false notifications
VerDate Sep<11>2014
20:23 Sep 06, 2023
Jkt 259001
being sent to customers, and theft of
customers’ information. If the
communication system is operated by a
third party, operators should document
the cybersecurity measures managed by
the vendor.126
PHMSA proposes that operators of gas
distribution systems must implement
such a voluntary, opt-in notification
system in accordance with their
procedures (i.e., ensure that the system
is ready for use during a gas pipeline
emergency) no later than 18 months
after the publication of the final rule.127
PHMSA proposes that 18 months after
the publication of the final rule in this
proceeding is a reasonable timeframe to
implement these new procedures and
seeks comment on this conclusion.
4. Emergency Response—Incident
Command Systems
a. Background
Communication during a pipeline
emergency is complex and includes
communication between the pipeline
operator, other pipeline companies,
non-pipeline utilities, emergency
responders, elected officials, PSAPs,
and the public. Effective
communication between and within
each of these entities is crucial to the
successful response to a gas pipeline
emergency. For this reason, some gas
distribution pipeline operators and
other utilities use an Incident Command
System (ICS) to coordinate emergency
response actions.
An ICS is a standardized approach to
the command, control, and coordination
of on-scene management of emergencies
and other incidents, providing a
common hierarchy within which
personnel from multiple organizations
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.
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.
PO 00000
Frm 00032
Fmt 4701
Sfmt 4702
can be effective.128 An ICS is the
combination of procedures, personnel,
facilities, equipment, and
communications operating within a
common organizational structure,
designed to aid in the management of
on-scene resources. It can be applied to
incidents (including emergencies and
planned events alike) of any size.
The National Incident Management
System (NIMS), a system commonly
used in the public and private sectors of
incident management, uses ICS
principles. As stated in the American
Gas Association’s (AGA) Emergency
Preparedness Handbook, ‘‘[u]tilities
across our nation are increasingly
integrating [NIMS] into their planning
and incident management structure.’’ 129
Additionally, API in API RP 1174
recommends the use of NIMS for
responding to accidents on hazardous
liquid pipelines.130 FEMA has also
indirectly recommended the use of
NIMS through its recommendation of
National Fire Protection Association
(NFPA) Standard 1600 for emergency
preparedness, a standard which
recommends the use of NIMS.131
Typically, local authorities handle
most incidents using the
communications systems, dispatch
centers, and incident personnel within
their jurisdiction. For larger and more
complex incidents, however, response
efforts may rapidly expand to multijurisdictional or multi-disciplinary
efforts requiring outside resources and
support. Widespread use of ICSs could
allow the efficient integration of outside
resources and enable personnel from
anywhere in the Nation to participate in
the incident-management structure.
Regardless of the size, complexity, or
scope of the incident, the use of an ICS
could benefit pipeline operators.
PHMSA is considering an ICS-based
system in this rulemaking to provide
safety benefits. However, PHMSA has
preliminarily determined further input
from the public would be beneficial in
assessing the feasibility of doing so, as
well as the best practices that would
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.
129 AGA, ‘‘Emergency Preparedness Handbook for
Natural Gas Utilities’’ at 10, https://www.aga.org/
wp-content/uploads/2022/12/aga-emergencypreparedness-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.
E:\FR\FM\07SEP3.SGM
07SEP3
ddrumheller on DSK120RN23PROD with PROPOSALS3
Federal Register / Vol. 88, No. 172 / Thursday, September 7, 2023 / Proposed Rules
inform such a regulatory standard.
Specifically, PHMSA is considering
requirements under § 192.615 for
operators of gas distribution pipelines to
follow ICS procedures in response to gas
pipeline emergencies. For example,
PHMSA could require that operators of
gas distribution pipelines develop
written procedures in accordance with
ICS tools and practices. An example of
an ICS practice would be to identify the
roles and responsibilities of emergency
responders and communicate those
responsibilities to designated personnel,
which would be similar to the current
requirements in § 192.615(c). PHMSA
recognizes the benefit of pipeline
operators using ICS for gas pipeline
emergencies, as such an approach can
help hone and maintain skills needed to
coordinate response efforts effectively,
even as poor implementation of an ICS
may hinder effectiveness. For example,
in the Merrimack Valley incident, both
the operator and emergency responders
had an ICS in their respective
emergency response manuals; however,
the ICS procedures were implemented
with mixed results. While State and
local emergency responders were able to
effectively manage, organize, and
coordinate the activities of multiple
agencies serving in the emergency
response by following the ICS, the
NTSB concluded that CMA’s Incident
Commander (IC) struggled to manage
the multiple competing priorities, such
as communicating with affected
municipalities, updating emergency
responders, and shutting down the
natural gas distribution system, which
adversely affected the IC’s ability to
complete tasks in a timely manner.132
The Merrimack Valley incident
underscores that effective execution of
an ICS is still dependent upon each
operator’s ability to implement the
practices during a crisis.
PHMSA is also considering, if it
determines to adopt requirements for
operators of gas distribution pipelines to
follow ICS procedures in response to gas
pipeline emergencies, requiring
operators to train personnel on ICS tools
and practices. PHMSA expects that to
develop an ICS for a response to gas
pipeline emergencies, operator
personnel would need to undergo
extensive training and coordination
exercises with first responders, and
local and State public safety officials.
FEMA provides free resources for
implementing and training on ICS on
their website.133 Because this training is
132 NTSB/PAR–19/02
at 45–47, 48–49.
‘‘National Incident Management
System’’ (May 24, 2022), https://www.fema.gov/
emergency-managers/nims.
133 FEMA,
VerDate Sep<11>2014
20:23 Sep 06, 2023
Jkt 259001
free, PHMSA expects there should be no
upfront costs to provide training,
however, there would be a burden in
terms of time for operators to (1) take
these trainings and (2) incorporate ICS
tools and practices into their training
and emergency response procedures.
Further, the ICS tools and guidance are
designed to be integrated into an
organization’s existing infrastructure, so
PHMSA would not expect operators to
have to hire additional personnel to
meet a new requirement in its
regulations for an ICS. PHMSA seeks
comment on these assumptions.
b. Request for Input on the Adoption of
ICS Requirements in PHMSA
Regulations
PHMSA is seeking public comments
regarding the potential adoption within
the pipeline safety regulations of a
requirement at § 192.615 that each
operator employ an ICS for gas pipeline
emergencies to include the following
topics that could inform the specifics of
any such requirement:
1. Should PHMSA promulgate new
regulations requiring ICS for all gas
distribution systems? Any other
pipeline facilities?
2. If PHMSA were to adopt ICS
requirements, should there be any
exceptions from the ICS requirements?
3. Should PHMSA develop a standard
for ICS or incorporate by reference an
existing industry-based standard for
ICS?
4. What are current sources of ICS
training?
5. How long does it take, or would it
take, for operators to train an employee
on ICS tools and practices?
6. How often should qualified
employees receive periodic training on
ICS tools and practices?
7. What is an appropriate timeline for
operators to incorporate ICS practices
into their procedures if PHMSA were to
promulgate an ICS standard?
PHMSA requests that commenters
provide specific proposals for what
provisions should be adopted or
changes that should be made to the
regulations related to the questions
listed above.
In addition to the questions above,
PHMSA requests commenters to provide
information and supporting data related
to:
1. The number of gas distribution
operators that have currently adopted an
ICS in their emergency procedures.
2. The technical feasibility, costeffectiveness, and practicability of
implementing any requirement for
operators to adopt ICS.
3. The potential quantifiable safety
and societal benefits of adopting ICS.
PO 00000
Frm 00033
Fmt 4701
Sfmt 4702
61777
4. The potential impacts on small
businesses adopting ICS.
5. The potential environmental
impacts of adopting ICS.
D. Operations and Maintenance
Manuals (Section 192.605)—
Overpressurization
1. Current Requirements—O&M
Manuals—Overpressurization
Section 192.605 includes minimum
requirements for gas pipeline operators’
procedural manuals for operations,
maintenance, and emergencies. Section
192.605(a) requires gas pipeline
operators to have ‘‘a manual of written
procedures for conducting operations
and maintenance activities and for
emergency response,’’ otherwise known
as an O&M manual. Operators must
review and update this manual at
intervals that do not exceed 15 months
and at least once each calendar year.
Appropriate parts of the manual must be
kept where operations and maintenance
activities take place.
Section 192.605(b) lists various
procedures that each gas pipeline
operator must include in the manual to
provide safety during operation and
maintenance. Among other
requirements, § 192.605(b)(5) requires
that the O&M manual include a
procedure for ‘‘[s]tarting up and
shutting down any part of the pipeline
in a manner designed to assure
operation within the MAOP limits
prescribed in this part, plus the buildup allowed for operation of pressurelimiting and control devices’’ in order
‘‘to provide safety during maintenance
and operations.’’
Subpart L also requires an operator to
‘‘keep records necessary to administer
the procedures established under
§ 192.605.’’ 134 Among the records
required to be kept and made available
to operating personnel are ‘‘construction
records, maps and operating history,’’
per § 192.605(b)(3). Sections
192.605(d)–(e) require an O&M manual
to include procedures for both reporting
safety-related conditions and for
surveillance, emergency response, and
accident investigations, respectively.
2. Need for Change—O&M Manuals—
Overpressurization
Clearly written procedures aid in the
successful execution of tasks and
processes necessary to ensure a gas
distribution pipeline system is operated
and maintained in a safe manner.
Overpressurizations, while rare, can
cause a pipeline failure if not addressed
in a timely manner. Including measures
134 49
E:\FR\FM\07SEP3.SGM
CFR 192.603(b).
07SEP3
61778
Federal Register / Vol. 88, No. 172 / Thursday, September 7, 2023 / Proposed Rules
ddrumheller on DSK120RN23PROD with PROPOSALS3
in O&M manuals to respond to
indications of an overpressurization can
help ensure a timely, effective response.
As demonstrated by the Merrimack
Valley incident, operators of gas
distribution pipelines must be prepared
to recognize and respond to
overpressurization indications, as these
events can have significant
consequences for public safety and the
environment. PHMSA regulations have
a requirement in § 192.605(b)(5) for
operators to have procedures for
‘‘starting up and shutting down any part
of the pipeline in a manner designed to
assure operation within the MAOP
limits prescribed by this part, plus the
build-up allowed for operation of
pressure-limiting and control devices.’’
To further reduce the likelihood of
future incidents like the 2018
Merrimack Valley incident, however,
PHMSA proposes to amend § 192.605 to
ensure that operators explicitly account
for overpressurization in their O&M
procedures.
Subsequent to the 2018 Merrimack
Valley incident, 49 U.S.C. 60102 was
amended to require PHMSA to
undertake a new rulemaking that would
require operators of gas distribution
systems to update their operations,
maintenance, and emergency plans to
include procedures for specific actions
to be taken on receipt of an indication
of an overpressurization on their
systems. Those actions include an order
of operations for immediately reducing
pressure in, or shutting down portions
of, the gas distribution system, if
necessary. (49 U.S.C. 60102(s)).
Amendments to 49 U.S.C. 60108 require
gas distribution operators to make their
updated O&M manuals available to
PHMSA or the relevant State regulatory
agency within 2 years after any final
rule is issued and every 5 years
thereafter.
3. Proposal To Amend § 192.605—O&M
Manuals—Overpressurization
In this NPRM, PHMSA proposes to
amend § 192.605 to require that
operators of gas distribution pipelines
establish procedures for responding to,
investigating, and correcting the cause
of overpressurization indications as
soon as practicable. This will include
specific actions to take and an order of
operations for immediately reducing
pressure in portions of the gas
distribution system affected by the
overpressurization, shutting down that
portion, or taking other actions as
necessary.
A timely response to an
overpressurization event will require
operators to promptly recognize
overpressurization indications. Operator
VerDate Sep<11>2014
20:23 Sep 06, 2023
Jkt 259001
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
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:
PO 00000
Frm 00034
Fmt 4701
Sfmt 4702
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
Whistleblower Protection for Pipeline Facility
Workers,’’ (Feb. 2022), https://www.osha.gov/sites/
default/files/publications/OSHA4072.pdf.
E:\FR\FM\07SEP3.SGM
07SEP3
Federal Register / Vol. 88, No. 172 / Thursday, September 7, 2023 / Proposed Rules
by State pipeline safety regulators, or
pursuant to their DIMPs. PHMSA
further notes that its proposed
enhancements of baseline expectations
for O&M manual contents are precisely
the sort of minimal actions a reasonably
prudent operator of gas distribution
pipeline facility would adopt in
ordinary course to protect public safety
given that their systems transport
pressurized (natural, flammable, toxic,
or corrosive) gasses typically within or
in close proximity to population
centers. Viewed against those
considerations and the compliance costs
estimated in the PRIA, PHMSA expects
its proposed amendments will be a costeffective approach to achieving the
public safety and environmental
benefits discussed in this NPRM and its
supporting documents. Lastly, PHMSA
understands that its proposed
compliance timeline—one year after
publication of a final rule (which would
necessarily be in addition to the time
since publication of this NPRM)—would
provide operators ample time to
implement requisite changes to their
O&M manuals (and manage any related
compliance costs).
ddrumheller on DSK120RN23PROD with PROPOSALS3
E. Operations and Maintenance
Manuals (Section 192.605)—
Management of Change
1. Current Requirements—O&M
Manuals—Management of Change
(MOC)
There are no current requirements in
the pipeline safety regulations for
operators of gas distribution pipelines to
follow management of change (or MOC)
processes in their operations and
maintenance activity. While not
specifically an MOC process, the
operator qualification provisions in
§ 192.805(f) require that changes that
affect covered tasks be communicated to
individuals performing these tasks. As
such, operators may have in place some
type of process for reviewing changes,
including whether such changes will
impact O&M procedures and those
performing the procedures. Further, gas
transmission pipelines located in a high
consequence area have an MOC
requirement in § 192.911(k), which
adopts an MOC process outlined in the
American Society of Mechanical
Engineers/American National Standards
Institute (ASME/ANSI) standard B31.8S,
section 11.137 The 192.911(k)
requirement, however, applies only to
operators of gas transmission pipelines
subject to subpart O integrity
management requirements (i.e., high137 Am. Soc’y of Mech. Eng’s, ANSI B31.8S–2004,
‘‘Managing System Integrity of Gas Pipelines’’ (Jan.
14, 2005).
VerDate Sep<11>2014
20:23 Sep 06, 2023
Jkt 259001
consequence areas, which are not
applicable to gas distribution pipelines).
2. Need for Change—O&M Manuals—
MOC
Inadequately reviewed or documented
design, construction, maintenance, or
operational changes can seriously
impact pipeline integrity. MOC
procedures are designed to prevent such
impacts. In the Merrimack Valley
incident, NTSB investigators discovered
omissions in CMA’s engineering work
package and construction
documentation for the South Union
Street project and that the work package
was completed without a proper
constructability review. NTSB
investigators reviewed the engineering
plans that CMA used during the
construction work and found that the
CMA engineers did not document the
location of regulator control lines.138
Had CMA accurately documented the
regulator control lines, engineers and
work crews would have been able to
relocate them prior to abandoning the
pipeline main.
CMA did not employ MOC processes
for its maintenance and construction
operations. Instead, CMA’s engineering
department relied on simple checklists
in its workflow documentation. The
NTSB determined that if NiSource had
adequately employed a MOC process, it
could have identified potential risk of
overpressurization of its system from a
common mode of failure as a result of
the South Union Street project
construction activity and employed
control measures to prevent or mitigate
the Merrimack Valley incident. As a
result, the NTSB recommended in P–
18–8 that NiSource apply an MOC
process to all changes to adequately
identify system threats that could result
in a common mode of failure.139
NTSB also stated that CMA did not
identify the omission of regulator
control lines from its engineering work
package during its constructability
review of that documentation.
Constructability reviews—an element of
MOC processes—are recognized and
accepted as a necessary engineering
practice for the execution of
construction services. If properly
implemented, constructability reviews
provide structured reviews of
construction plans and specifications to
ensure functionality, sustainability, and
safety, thus reducing the potential for
shortcomings, omissions, inefficiencies,
conflicts, or errors. The NTSB
concluded that the CMA
constructability review process was not
138 NTSB/PAR–19/02
139 NTSB/PAR–19/02
PO 00000
Frm 00035
at 16.
at 51.
Fmt 4701
Sfmt 4702
61779
sufficiently robust to detect the
omission of a work order to relocate the
sensing lines. The NTSB identified that
part of the failure of the process was
likely due to the absence of a review by
a critical department (CMA’s
measurement and regulation or M&R
department). Despite there being at least
two constructability reviews for the
South Union Street project, the M&R
department did not participate. The
NTSB stated that a comprehensive
constructability review, which would
require all pertinent departments to
review each project, along with the
endorsement by a professional engineer
(PE), would likely have identified the
omission of the regulator control lines,
thereby preventing the error that led to
the Merrimack Valley incident. As a
result of its investigation, the NTSB
recommended that NiSource revise its
constructability review process to
ensure that all pertinent departments
review construction documents for
accuracy and completeness, and that the
documents or plans be endorsed by a PE
prior to commencing work.
Subsequent to the 2018 Merrimack
Valley incident, PHMSA was required
by statute to update its regulations to
require gas distribution operators to
include in their O&M manuals an MOC
process which must apply to
‘‘significant technology, equipment,
procedural, and organizational changes
to the distribution system[.]’’ (49 U.S.C.
60102(s)(2)). This provision also
requires that operators ‘‘ensure that
relevant qualified personnel, such as an
engineer with a professional engineer
licensure, subject matter expert, or other
employee who possesses the necessary
knowledge, experience, and skills
regarding natural gas distribution
systems, review and certify construction
plans for accuracy, completeness, and
correctness.’’ In addition, 49 U.S.C.
60108 requires gas distribution
operators to make their updated O&M
manuals available to PHMSA or the
relevant State regulatory agency within
2 years after the final rule is issued in
this proceeding and every 5 years
thereafter.
3. Proposal To Amend § 192.605 To
Require an MOC Process
Pursuant to 49 U.S.C. 60102(s),
PHMSA proposes to require that gas
distribution operators update their O&M
manuals to include a detailed MOC
process.140 Under this proposal,
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.
Continued
E:\FR\FM\07SEP3.SGM
07SEP3
ddrumheller on DSK120RN23PROD with PROPOSALS3
61780
Federal Register / Vol. 88, No. 172 / Thursday, September 7, 2023 / Proposed Rules
operators would be required to apply an
MOC process to technology, equipment,
procedural, and organizational changes
that may impact the integrity or safety
of the gas distribution system.
Specifically, operators must apply an
MOC process to changes to their
pipeline systems, organization, and
O&M procedures in connection with the
(1) installation, modification, or
replacement of, or upgrades to,
regulators, pressure monitoring
locations, or overpressure protection
devices; (2) modifications to alarm set
points or upper/lower trigger limits on
monitoring equipment; (3) introduction
of new technologies for overpressure
protection into the system; (4) revisions,
changes to, or introduction of new
standard operating procedures for
design, construction, installation,
maintenance, and emergency response;
and (5) other changes that may impact
the integrity or safety of the gas
distribution system. PHMSA notes that
although most of the occasions for
changes to operator pipelines and
procedures listed above are directed
toward reducing the potential for
overpressurization, it expects that MOC
processes will also help reduce the risk
of other incidents on gas distribution
pipelines. Towards that end, PHMSA
proposes savings language (‘‘other
changes that may impact the integrity or
safety of the gas distribution systems’’)
that would require operators to employ
a MOC process in connection with
changes to their systems and procedures
in connection with high-risk activities.
PHMSA also proposes to require that
the MOC process must ensure that
qualified personnel review and certify
construction plans associated with
installations, modifications,
replacements, or upgrades for accuracy
and completeness before the work
begins. These personnel must be
qualified to perform these tasks under
subpart N of 49 CFR part 192.141
Qualified personnel could include an
engineer with a professional engineer
(PE) license, a subject matter expert, or
any other employee who possesses the
necessary knowledge, experience, and
skills regarding gas distribution systems.
This proposal would ensure that
personnel who work on planning
construction projects have the
appropriate qualifications and training
60102(s) explicitly required update of regulations
governing ‘‘procedural manuals for operations,
maintenance, and emergencies’’—located at
§ 192.605.
141 ‘‘Qualified’’ under § 192.803 means that an
individual has been evaluated pursuant to the
requirements of Subpart N and can perform
assigned covered tasks and recognize and react to
abnormal operating conditions.
VerDate Sep<11>2014
20:23 Sep 06, 2023
Jkt 259001
necessary to ensure these tasks are
performed safely.
In developing this proposed
requirement, PHMSA reviewed NTSB
recommendation P–19–16, which called
on states to require that all future gas
infrastructure projects require licensed
PE approval and stamping.142 This
NPRM in no way prohibits states from
applying a higher standard than that
provided in the Federal regulations.
Additionally, PHMSA acknowledges
that a PE could provide the best
assurance of high-quality review of
construction plans. PHMSA is uncertain
as to the availability of those personnel
resources in all states or for all gas
distribution operators, however, and
any shortage of licensed PEs could
cause delays in the construction or
remediation of integrity issues. Other
qualified professionals, such as
experienced engineers or subject matter
experts, may have an equivalent level of
experience or skills without holding the
licensure. PHMSA is proposing this
amendment pursuant to 49 U.S.C.
60102(s), which contemplates a larger
pool of personnel qualified to perform
these reviews and certifications than
just licensed PEs. Nevertheless, PHMSA
expects that when operators evaluate
construction projects, operators
consider assigning qualified personnel
with experience commensurate to the
complexity of each project and its
potential impacts on public safety and
the environment. The most complex and
riskiest projects should be reviewed by
a licensed PE, if available, while less
complex or routine construction
projects may be suitable for review by
qualified personnel who do not hold
such a credential. PHMSA welcomes
comments on the availability of PE
licensure in various jurisdictions and
the appropriateness of review by other,
non-licensed qualified individuals.
Finally, PHMSA proposes to require
that operators’ MOC process must
ensure that any hazards introduced by
a change are identified, analyzed, and
controlled before resuming operations.
Quality originates at the planning stages
of a pipeline project. When pipeline
facilities are designed or modified,
operators intend for these changes to
provide decades of safe and reliable
operation. But any change to a pipeline
system can also introduce potential
hazards. Operators can manage risks
introduced by changes to the system
through a robust MOC process. It is a
standard practice in any MOC process
or system to analyze and control for
risks. PHMSA is proposing this general
requirement for operators to identify
142 NTSB/PAR–19/02
PO 00000
Frm 00036
at 50.
Fmt 4701
Sfmt 4702
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
143 ASME/ANSI, B31.8S–2004, ‘‘Managing
System Integrity of Gas Pipelines, Supplement to
B31.8’’ (Jan. 14, 2005) (incorporated by reference
under § 192.7).
E:\FR\FM\07SEP3.SGM
07SEP3
Federal Register / Vol. 88, No. 172 / Thursday, September 7, 2023 / Proposed Rules
ddrumheller on DSK120RN23PROD with PROPOSALS3
necessarily be in addition to the time
since publication of this NPRM)—would
provide operators ample time to
implement requisite changes to their
O&M manuals and identify or procure
personnel resources needed to comply
with the new certification requirement
(and manage any related compliance
costs).
PHMSA is also requesting comments
on whether it should promulgate the
MOC requirement described above,
adopt the industry standard ASME/
ANSI B31.8S for gas distribution
operators, or both.144 PHMSA has
adopted ASME/ANSI B31.8S for gas
transmission operators subject to 49
CFR, part 192, subpart O integrity
management requirements. Specifically,
PHMSA at § 192.911(k) requires
operators of certain gas transmission
pipelines to develop and follow an MOC
process, as outlined in ASME/ANSI
B31.8S, section 11, that addresses
technical, design, physical,
environmental, procedural, operational,
maintenance, and organizational
changes to the pipeline or processes,
whether permanent or temporary. While
provisions in section 11 of ASME/ANSI
B31.8S outline formal elements of an
MOC process resembling the elements
within the regulatory text proposed in
this NPRM, other provisions of ASME/
ANSI B31.8S section 11, such as (b)(1),
are specific to changes in population
that may be more appropriate for gas
transmission operators required to
identify high consequence areas (HCAs)
along their pipeline. But the HCA
concept does not apply to gas
distribution operators, and as noted
above, PHMSA expects it can capture
the public safety and environmental
benefits from MOC processes by
adopting the regulatory text proposed in
this NPRM without incorporating by
reference ASME/ANSI B31.8S directly.
Nevertheless, PHMSA requests
comments on whether adoption within
a final rule of a similar approach for gas
distribution operators would provide
better protection for public safety and
the environment, and otherwise be
technically feasible, cost-effective, and
practicable.
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.
VerDate Sep<11>2014
20:23 Sep 06, 2023
Jkt 259001
F. Gas Distribution Recordkeeping
Practices (Section 192.638)
1. Current Requirements—
Recordkeeping
Operators must collect and maintain
records about their gas distribution
pipelines in compliance with
requirements of 49 CFR part 192,
including those governing DIMPs.
Section 192.1007(a) requires operators
to identify reasonably available
information necessary to develop an
understanding of the characteristics of
their pipelines, identify applicable
threats, and analyze the risk associated
with the threats. Section 192.1007(a)(3)
requires that operators have a plan to
collect information needed to conduct
the risk analysis required in DIMP.
Section 192.1007(a)(5) requires
operators to capture and retain
information on any new pipeline
installed, including, at a minimum, the
location of the pipeline and the material
of which it is constructed.
In addition to keeping records as part
of complying with DIMP requirements,
an operator must also consider the data
it needs to comply with the various
recordkeeping requirements in 49 CFR
part 192, such as those for pipeline
design, testing and construction
(§ 192.517); corrosion control
(§ 192.491); customer notification
(§ 192.16); uprating (§ 192.553);
surveying, patrolling, monitoring,
inspections, operations, maintenance,
and emergencies (§§ 192.603 and
192.605); and operator qualification
(§ 192.807). Sections 192.603(b) and
192.605 further require that each
operator establish a written operating
and maintenance plan that meets the
requirements of the pipeline safety
regulations and keep records necessary
to administer the plan. Sections
192.603(b) and 192.605(e) require
operators to maintain current records
and maps of the location of their
facilities for use in operations,
maintenance, and emergency response
activities (e.g., surveillance, leak
surveys, cathodic protection, etc.).
Further, § 192.605 requires that
operators make construction records,
maps, and the pipeline’s operating
history available to appropriate
operating personnel. Therefore, if an
operator requires maps as a record to
properly administer its O&M procedures
consistent with Federal safety
requirements, these maps must be
maintained by the operator.
Additionally, operators must keep
records related to the design and
installation of their pipeline
components, including protection
against overpressurization under 49 CFR
PO 00000
Frm 00037
Fmt 4701
Sfmt 4702
61781
part 192, subparts L and M.145 These
records would include valve failure
position and capacity records, which
include information operators used
when designing the system to ensure
sufficient overpressure protection.
2. Need for Change—Recordkeeping
Maintaining accurate and reliable
records is critical for safe operation,
maintenance, pipeline integrity
management, and emergency response.
Records of the physical components on
a gas distribution system, such as
regulators, valves, and underground
piping (including control lines), are
necessary for an operator to have the
basic knowledge of its system needed to
maintain control of system pressure.
Mapping of all gas systems enables
proper planning of system upgrade
activities, maintenance, and protection
of the system from excavation damage.
Knowing the location of control lines is
critically important to preventing
incidents on low-pressure distribution
systems because they can be easily
damaged during excavation activities or
inadvertently taken out of service, as
demonstrated by the Merrimack Valley
incident. Further, mapping of all gas
systems, such as documenting the
location of shutoff valves, could
improve the response time during an
emergency. In the event of an incident
or other emergency, being able to locate
and operate valves is critical to
achieving the effective shutdown and
isolation of any sections of a gas
distribution system. Incomplete,
inaccurate, unreliable, or inaccessible
records hinder the safe operation of a
pipeline, reduce the effectiveness of the
integrity assessment (as required under
DIMP regulations), and impede timely
emergency response.
The 2018 Merrimack Valley incident
illustrated how incomplete records of
gas distribution systems can lead to or
exacerbate safety issues. One of the
issues identified in the NTSB’s report
was that the engineers responsible for
developing CMA’s construction plan
did not have all the records necessary to
plan the construction project correctly,
such as control line drawings and
location information. Further, the CMA
engineers knew that even if they had
access to the records regarding the
location of the control lines, the records
CMA maintained were often outdated,
and thus potentially inaccurate and
incomplete.146 For example, for the
Winthrop regulator station, the records
had the location of the control lines as
145 See §§ 192.603(b), 192.605(b)(1), and subpart
M (incorporating §§ 192.199 and 192.201).
146 NTSB/PAR–19/02 at 16–17.
E:\FR\FM\07SEP3.SGM
07SEP3
ddrumheller on DSK120RN23PROD with PROPOSALS3
61782
Federal Register / Vol. 88, No. 172 / Thursday, September 7, 2023 / Proposed Rules
they existed around May 2010; however,
CMA installed a new control line
around September 2015 and never
updated its records to reflect the change.
Without access to accurate maps and
drawings of the system, CMA did not
include control line maps or procedures
for handling control line removal in the
construction plan. CMA then passed
along an inaccurate and incomplete
construction plan to the contractor
doing the work. As a result, NTSB
recommended that NiSource review and
ensure that all records and
documentation of its natural gas systems
are traceable, reliable, and complete.
The Merrimack Valley incident
further illustrated how the lack of
accurate maps of pipeline systems can
inhibit effective emergency response.
During the emergency response to the
overpressurization, the operator took too
long to provide maps of the lowpressure system to emergency response
officials, who needed street maps
showing the layout of the natural gas
distribution system to understand where
the affected customers were located.
CMA did not provide the information
requested until hours after the
overpressurization began. The
emergency responders emphasized to
the NTSB that the absence of this
information impeded their emergency
response and public safety decisionmaking. Without maps of the lowpressure system, the ICs managing
emergency response had to evacuate
thousands of people from their homes,
including people in unaffected areas,
out of an abundance of caution.
Subsequent to the 2018 Merrimack
Valley incident, 49 U.S.C. 60102 was
amended to ensure that operators keep
better, more complete records (such as
maps that include the location of
control lines and other critical
infrastructure) and make those available
to the emergency responders and public
officials who need them. Specifically,
49 U.S.C. 60102(t)(1) directs PHMSA to
issue regulations that require
distribution pipeline operators to
identify and manage ‘‘traceable, reliable,
and complete’’ maps and records of
critical pressure-control infrastructure,
and update other records needed for risk
analysis. Operators must update their
records ‘‘on an opportunistic basis.’’
These records must be accessible to all
personnel responsible for performing or
overseeing relevant construction or
engineering work. Pursuant to 49 U.S.C.
60102(t)(1), PHMSA proposes to amend
its regulations to supplement existing
requirements pertaining to gas
distribution operators’ recordkeeping
critical to pressure control on their
systems. The proposal would require
VerDate Sep<11>2014
20:23 Sep 06, 2023
Jkt 259001
operators to collect or generate
complete, reliable, and accurate records
if they are not available, and make the
records accessible to the personnel who
need them.
3. Proposal To Add a New § 192.638—
Records: Distribution System Pressure
Controls
PHMSA proposes a new § 192.638 to
specify that an operator of a gas
distribution system must identify and
maintain traceable, verifiable, and
complete records documenting the
characteristics of the pipeline critical to
ensuring proper pressure controls.147
In 2019, PHMSA introduced a
regulatory amendment requiring gas
transmission records pertaining to
MAOP to be ‘‘traceable, verifiable, and
complete.’’ 148 49 U.S.C. 60102(t)(1)
similarly requires PHMSA to require
operators to identify and manage
‘‘traceable, reliable, and complete’’
records. PHMSA understands that the
phrase ‘‘traceable, reliable, and
complete,’’ as used in 49 U.S.C.
60102(t)(1) is substantively the same
standard with respect to the quality and
accessibility of records maintained as
the ‘‘traceable, verifiable, and complete’’
language adopted in the 2019 final rule
for gas transmission pipelines.149
PHMSA interprets ‘‘reliable’’ as used in
49 U.S.C. 60102(t)(1) to mean the same
as ‘‘verifiable’’ as used in the 2019 rule
because both verifiable and reliable
would mean to prove that a record is
trustworthy and authentic. A record is
considered reliable if it is verifiable and
vice versa. PHMSA’s proposed
§ 192.638 recordkeeping requirement is
intended to encompass any records
essential to pressure control on a system
and not just pertain to MAOP or
material property and attribute
verification activities. PHMSA would
require operators to identify what
records they currently have that
document the characteristics of the
pipeline that are ‘‘critical to ensuring
147 As discussed elsewhere in the preamble,
PHMSA also proposes to introduce a crossreference to this new § 192.638 within its existing
DIMP plan knowledge management requirements at
§ 192.1007(a)(3).
148 ‘‘Pipeline Safety: Safety of Gas Transmission
Pipelines: MAOP Reconfirmation, Expansion of
Assessment Requirements, and Other Related
Amendments,’’ 84 FR 52180 (Oct. 1, 2019).
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 . . . .’’).
PO 00000
Frm 00038
Fmt 4701
Sfmt 4702
proper pressure controls’’ for the
system.
In § 192.638(a), PHMSA identifies the
types of records that it proposes are
critical to ensuring proper pressure
control for a gas distribution system.
These records include: (1) current
location information (including maps
and schematics) for regulators, valves,
and underground piping (including
control lines); (2) attributes of the
regulator(s), such as set points, design
capacity, and the valve failure position
(open/closed); (3) the overpressure
protection configuration; and (4) other
records deemed critical by the operator.
Regarding item (1), operators
generally keep records, such as maps
and schematics, when designing their
system and district regulator stations.
Operators should also have records of
selected regulators, valves, and other gas
pressure control equipment based on
several factors, for the purpose of
determining, for example, the overall
capacity and future flow requirements
of the system.
Regarding item (2), records related to
the attributes of the regulators’ set
points, design capacity, and valve
failure position are necessary to ensure
that the design of the district regulator
station can protect the distribution
system from overpressurization. For
example, demands on the system may
change over time due to customer usage,
weather, or maintenance requirements.
Operators can use design capacity
records to validate and revalidate that
their systems are capable of meeting
changing customer demands and
weather dynamics.
Regarding item (3), maintaining
records for the overpressure protection
configuration are necessary for the safe
operation of the pipeline and for
performing a robust risk analysis
required under DIMP regulations. As
demonstrated by the 2018 Merrimack
Valley incident, certain overpressure
protection configurations on lowpressure distribution systems (i.e.,
redundant worker-monitor regulators)
alone are inadequate for preventing an
overpressurization. Requiring operators
to keep records of their systems’
overpressure configurations will ensure
that operators will be able to identify
any higher-risk configurations in their
systems. Once identified, operators can
properly assess the overall risk to their
systems and take preventive or
mitigative actions to reduce the
likelihood or consequences of a
potential failure.
Regarding item (4), PHMSA proposes
that operators must have traceable,
verifiable, and complete records for any
records they deem critical but that were
E:\FR\FM\07SEP3.SGM
07SEP3
ddrumheller on DSK120RN23PROD with PROPOSALS3
Federal Register / Vol. 88, No. 172 / Thursday, September 7, 2023 / Proposed Rules
not mentioned in the list provided by
PHMSA. This general requirement
would ensure that operators keep
records based on the unique
characteristics of their system.
When taking inventory of the records
described above, operators must identify
if those records are traceable (e.g., can
be clearly linked to original information
about, or changes to, a pipeline segment,
facility, or district regulator station),
verifiable (e.g., their information is
confirmed by other complementary but
separate documentation), and complete
(e.g., as evidenced by a signature, date,
or other appropriate marking such as a
corporate stamp or seal). This
amendment would improve the
completeness and accuracy of the
records needed during normal
operations, emergency response
activities, and risk analyses.
In § 192.638(b), PHMSA proposes to
require that if an operator does not yet
have traceable, verifiable, and complete
records, then the operator must develop
a plan for collecting those records.
PHMSA also proposes to revise
§ 192.605 to ensure that operators have
procedures for implementing the new
recordkeeping requirements proposed in
§ 192.638. Because the availability and
form of records, as well as records
retention practices, will vary among
operators, PHMSA proposes that
operators must identify what records
they need to collect under this
requirement.
In § 192.638(c), PHMSA proposes that
operators must collect records needed to
meet this standard on an opportunistic
basis, which is defined as occurring
during normal operations conducted on
the pipeline including (but not limited
to) design, construction, operations, or
maintenance activities. PHMSA notes
that its proposed language in paragraph
(c) mirrors the language at
§ 192.1007(a)(3) governing operator
knowledge management in connection
with a performance of the risk analysis
within their DIMPs. PHMSA expects
this approach will minimize compliance
burdens on operators, as they would be
able to collect or generate records
through existing regulatory mechanisms
such as DIMPs or annual inspections.
PHMSA also proposes to revise
§ 192.1007(a)(3) so that it references
§ 192.638(c). This would require
operators to identify records specified in
§ 192.638(c) that they could collect as
part of their DIMP plan.
In § 192.638(d), PHMSA proposes to
require that operators ensure the records
required in this section are accessible to
personnel performing or overseeing
design, construction, operations, and
maintenance activities. In the 2018
VerDate Sep<11>2014
20:23 Sep 06, 2023
Jkt 259001
Merrimack Valley incident, the
engineering staff did not have access to
the maps containing control line
information and were unaware if the
department had access to such records.
This lack of access and awareness
resulted in the omission of critical
information that should have been
considered through a proper risk
analysis under their DIMPs. Therefore,
PHMSA proposes to add a requirement
for operators to provide the personnel
responsible for planning and performing
work on critical infrastructure with the
records they need to perform their work
safely and effectively. Operators should
note that access would extend to the
qualified employees monitoring the gas
pressure (as proposed in § 192.640).
PHMSA expects that during a
construction activity, these qualified
personnel may need records such as
maps of control lines to effectively
monitor the safety of excavation
activities around gas distribution
systems.
In § 192.638(e), PHMSA proposes to
require that once a record is generated
or collected under this section, that
operators must keep the record for the
life of the pipeline. This will help
facilitate traceability of records as
required by 49 U.S.C. 60102(t).
In § 192.638(f), PHMSA specifies that
the requirements in this section would
not apply to master meter systems,
liquefied petroleum gas (LPG)
distribution pipeline systems that serve
fewer than 100 customers from a single
source, or any individual service line
directly connected to a transmission,
gathering, or production pipeline that is
not operated as part of a distribution
system. As discussed above, small LPG
operators are relatively simple, low-risk
systems affecting a finite (generally
small) number of customers such that
the public safety and environmental
benefits from imposing new
requirements on these systems would be
limited. Similar reasoning applies to
master meter systems. PHMSA
understands that compliance costs
generally are felt more acutely by small
LPG operators and master meter system
operators. PHMSA does not expect that
these operators would have the means
(e.g., access to detailed maps and GIS
tools) to be able to comply with the
recordkeeping requirements proposed in
this NPRM. For individual service lines,
the consequences of an
overpressurization are smaller relative
to a district regulator station. Given the
relatively low public safety and
environmental benefits from extending
the new § 192.638 recordkeeping
requirements to those operators,
PHMSA proposes to except those
PO 00000
Frm 00039
Fmt 4701
Sfmt 4702
61783
systems from the new recordkeeping
requirement at § 192.638. Nevertheless,
PHMSA does encourage these excepted
operators to, where applicable, follow
the recordkeeping specifications
proposed in this NPRM.
Overall, PHMSA expects that its
proposed new § 192.638 would ensure
that operators are documenting and
maintaining records of how their critical
pressure controlling facilities operate so
that they can review and assess their
performance over time. Keeping
complete and accurate records for the
life of these assets could help improve
operators’ risk analyses, as required by
DIMP regulations, and thus improve the
overall integrity of gas distribution
pipelines.
PHMSA also understands this
proposed requirement for gas
distribution operators to identify and
maintain traceable, accurate, and
complete records documenting system
characteristics pertinent to pressure
control would be reasonable, technically
feasible, cost-effective, and practicable.
As explained above, the proposed
requirement is analogous to material
property documentation requirements
elsewhere in PHMSA regulations (e.g.,
§ 192.607) for gas transmission systems.
And PHMSA understands that some gas
distribution operators may already
comply with this proposed requirement
either voluntarily (e.g., to minimize
losses of commercially valuable
commodities, in response to the
Merrimack Valley incident and NTSB
recommendations, or consistent with
broadly applicable, consensus industry
standards such as ASME/ANSI
B31.8S 150), as a result of similar
requirements imposed by State pipeline
safety regulators, or as risk mitigation
measures pursuant to their DIMPs.
Indeed, the sort of records subject to this
proposed requirement are precisely the
sort of records that a reasonably prudent
operator of gas distribution pipeline
facility would in ordinary course
already have identified and be
maintaining to protect the public given
that their systems transport pressurized
(natural, flammable, toxic, or corrosive)
gasses typically within or in close
proximity to population centers. Viewed
against those considerations and the
compliance costs estimated in the PRIA,
PHMSA expects its proposed
amendments will be a cost-effective
approach to achieving the commercial,
public safety, and environmental
benefits discussed in this NPRM and its
150 ASME/ANSI, B31.8S–2004, ‘‘Managing
System Integrity of Gas Pipelines, Supplement to
B31.8’’ (Jan. 14, 2005) (incorporated by reference
under § 192.7).
E:\FR\FM\07SEP3.SGM
07SEP3
61784
Federal Register / Vol. 88, No. 172 / Thursday, September 7, 2023 / Proposed Rules
supporting documents. Lastly, PHMSA
understands that its proposed
compliance timeline—one year after
publication of a final rule (which would
necessarily be in addition to the time
since publication of this NPRM)—would
provide operators ample time to review
and compile pertinent existing records
and develop and implement procedures
to generate or obtain missing records on
a going-forward basis (and manage any
related compliance costs).
G. Distribution Pipelines: Presence of
Qualified Personnel (Sections 192.640
and 192.605)
1. Current Requirements—Procedures
for Qualified Personnel Monitoring Gas
Pressure
Currently, PHMSA does not require
operators to have procedures for
monitoring gas pressure with qualified
persons and equipment capable of
ensuring pressure control and having
the ability to shut off the flow of gas.
There are other provisions related to
personnel qualification included in 49
CFR part 192, subpart N, which contain
requirements for operators of gas
pipelines to develop a qualification
program to qualify employees for certain
covered tasks. Covered tasks include
those activities that affect the operation
or integrity of the pipeline. PHMSA
defines ‘‘Qualified’’ in § 192.803 to
mean that ‘‘an individual has been
evaluated and can: (a) [p]erform
assigned covered tasks; and (b)
[r]ecognize and react to abnormal
operating conditions.’’
ddrumheller on DSK120RN23PROD with PROPOSALS3
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
VerDate Sep<11>2014
20:23 Sep 06, 2023
Jkt 259001
responding to overpressurization
indications on gas distribution systems.
During the Merrimack Valley
incident, the SCADA controller
responded to a high-pressure alarm by
contacting the field technician who
could adjust the flow of gas at the
Winthrop regulator station. CMA’s
system had remote pressure monitoring
but no remote or automatic shutoff. It
took 30 minutes from the time CMA’s
SCADA controller noticed an alarm to
the time when the field technician
began to adjust the flow of gas. NTSB
investigators learned that, at one time,
CMA required that a technician monitor
any gas main revision work that
required depressurizing the main.151 Per
those historical procedures, the
technician would use a gauge to monitor
the pressure readings on the impacted
main and would communicate directly
with the crew performing the work. If a
pressure anomaly occurred, the
technician could quickly act to prevent
an overpressurization event. CMA
offered no explanation to the NTSB as
to why this procedure was phased out.
As a result of the incident, the NTSB
recommended in P–18–9 that NiSource,
Inc., develop and implement control
procedures during modifications to gas
distribution mains to mitigate the risks
identified during MOC operations, and
stated that gas main pressures should be
continually monitored during these
modifications and that assets should be
placed at critical locations to
immediately shut down the system if
abnormal operations are detected.
PHMSA agrees with NTSB’s
recommendation and concludes that
requiring these procedures could benefit
safety for all gas distribution operators.
Further, PHMSA believes that operators
can mitigate the consequences of the
overpressurization by requiring
qualified personnel capable of shutting
off the gas to monitor the gas pressure
during construction associated with
installations, modifications,
replacements, or upgrades on gas
distribution mains that could result in
overpressurization.
Subsequent to the 2018 Merrimack
Valley incident, PHMSA was directed to
issue regulations requiring qualified
personnel of a gas distribution system
operator, with the ability to ensure
proper pressure control and shut off, or
limit gas pressure should
overpressurization occur, monitor gas
pressure at district regulator stations
during certain times. (49 U.S.C.
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.
PO 00000
Frm 00040
Fmt 4701
Sfmt 4702
60102(t)(2)). The mandate specifies that
those times are during any construction
project that has the potential to cause an
overpressurization, including projects
such as tie-ins or abandonment of
distribution mains. These requirements
do not apply if a district regulator
station has a monitoring system and the
capability of remote or automatic
shutoff. Further, amendments to 49
U.S.C. 60108 now require gas
distribution operators to make their
updated O&M manuals available to
PHMSA or the relevant State regulatory
agency within 2 years after any final
rule is issued and every 5 years
thereafter.
3. Proposal To Add a New § 192.640
Distribution Pipelines: Presence of
Qualified Personnel
In a new § 192.640, PHMSA proposes
an additional layer of safety at district
regulator stations during construction
projects by requiring qualified
personnel to be present, monitor the gas
pressure, and have the capability to shut
off the flow of gas during an
overpressurization event. This
provision, including each of the below
proposed parts, would not apply if an
operator already has equipped that
district regulator station with a remote
pressure monitoring system that has the
capability for remote or automatic
shutoff.152
In paragraph (a), PHMSA proposes
that operators of a distribution system
must conduct an evaluation of planned
and future installation, modification, or
replacement of, or upgrade construction
projects and identify any potential for
an overpressurization to occur at a
district regulator station. Operators must
perform this evaluation before
performing activities that could result in
an overpressurization. PHMSA
recognizes that not every construction
project performed on a gas distribution
system has the same risk profile and not
all would require on-site gas monitoring
by a qualified employee. However, the
pre-construction evaluation must occur
regardless to assess the probability of an
overpressurization. Some construction
projects clearly entail a potential for
overpressurization, such as tie-ins and
abandonment of distribution pipelines
and mains, because work is done while
part of the gas system remains active.
Similarly, the consequences of
overpressurization during construction
projects may increase when that work is
on low-pressure gas distribution
systems where customers do not have
152 This exception will be reflected by addition of
new paragraph (d).
E:\FR\FM\07SEP3.SGM
07SEP3
ddrumheller on DSK120RN23PROD with PROPOSALS3
Federal Register / Vol. 88, No. 172 / Thursday, September 7, 2023 / Proposed Rules
secondary pressure regulation at their
individual meter.
In paragraph (b), PHMSA proposes
that once the evaluation is complete, if
an operator has determined that a
construction project activity presents a
potential for overpressurization, then
the operator must ensure that at least
one qualified employee or contractor
with the capability to shut off the flow
of gas is present at that district regulator
station to monitor the gas pressure
during the construction project activity.
This will result in safer construction
activities on gas distribution pipelines
by requiring operators to ensure that
resources have been deployed to
effectively mitigate risks the operator
had determined exist.
Under this proposal, the employee or
contractor must be qualified to monitor
the gas pressure in accordance with 49
CFR, part 192, subpart N. Subpart N
already requires that operators ensure
on-site personnel, such as maintenance
crew members and inspectors, are
qualified by training and experience to
perform covered tasks. Further, subpart
N requires that operators qualify these
individuals to ensure that covered tasks
are conducted in a safe, reliable manner
in compliance with regulatory
standards. In complying with this new
proposal, operators would need to
qualify employees and contractors
responsible for monitoring the gas
pressure during construction to perform
various tasks, such as reading and
understanding gas monitoring
equipment; responding to abnormal
operating conditions (see § 192.805),
including overpressurization
indications; shutting off or reducing the
pressure to the system; implementing
any stop-work authority granted by the
operator; and notifying appropriate
emergency response personnel should
an incident occur. They should also be
qualified on the relevant proposed new
O&M requirements discussed in
subsection IV.D and E.
In paragraph (c), PHMSA proposes to
require that, when monitoring the
system as described in this section, the
qualified personnel should be provided,
at a minimum, information regarding
the location of all valves necessary for
isolating the pipeline system and
pressure control records (see § 192.638).
Providing access to this information
could be essential to an employee or
contractor performing their gas
monitoring responsibilities effectively
and help shorten the response time to
emergency indications. For example, a
qualified employee responsible for
monitoring the gas pressure may need to
access valves on the system so that they
can shut off the flow of gas, isolate the
VerDate Sep<11>2014
20:23 Sep 06, 2023
Jkt 259001
pipeline system, or otherwise mitigate
the consequences of an incident.
Similarly, a qualified employee
responsible for monitoring the gas
pressure may need to have more
extensive maps of the entire gas system
to identify an affected area and detailed
information—such as a specific
regulator’s set point—to determine if a
system is operating abnormally. The
records proposed in § 192.638 would
provide this information and must be
accessible to qualified personnel who
monitor gas pressure.
Further, under paragraph (c), PHMSA
proposes that operators must also
ensure that qualified employees
monitoring the gas pressure have
information regarding emergency
response procedures. PHMSA expects
such information would include the
contact information of the appropriate
emergency response personnel. Should
field personnel recognize an emergency
condition, it is critical for those
personnel to have updated emergency
contacts and to know what to do and
how to respond in an emergency.
PHMSA expects operators would
already have general emergency contact
information in an emergency response
plan under § 192.615; however, given
that these qualified personnel may be
the first to witness overpressurization
indications, PHMSA believes it is
essential they have immediate access to
this information on site during their
activities.
Some operators may already provide
qualified employees with ‘‘stop-work
authority’’ to halt work that does not
conform to specifications or if they
observe unsafe activities on the job site.
Although this authority is not required
to be given to all qualified employees
under proposed § 192.640, it is
recommended. Where operators have
granted this authority to these qualified
personnel monitoring the gas pressure,
operators should ensure these
employees are trained to recognize
unsafe, abnormal conditions that are
consistent with an overpressurization.
Overall, the proposals in § 192.640
would reduce the time to respond to an
overpressurization by ensuring qualified
employees are on site or at an
alternative location, and that they are
capable of actively monitoring the gas
pressure during certain construction
project activities. Should an
overpressurization occur, these
qualified employees would be able to
respond (i.e., shutting off or reducing
the flow of gas) and thereby mitigate the
impact. Under PHMSA’s proposal, the
qualified employees would be trained to
recognize overpressurization indications
and be able to respond more quickly.
PO 00000
Frm 00041
Fmt 4701
Sfmt 4702
61785
This should mitigate some of the impact
of an overpressurization and improve
the response time of the operator.
PHMSA also understands that this
proposed new requirement would be
reasonable, technically feasible, costeffective, and practicable for gas
distribution operators. That operators
should evaluate construction projects on
their systems to determine whether they
could result in an overpressurization at
a district regulator station and then
ensure that personnel are present who
can monitor pressure and prevent such
a condition during the work is a
common-sense, best practice within
industry—whose value was underscored
by the Merrick Valley incident and
subsequent NTSB recommendation P–
18–9. Indeed, PHMSA understands that
some operators may already employ
compliant maintenance and
construction protocols in ordinary
course. For other operators, integration
of this new requirement within their
procedures could be accomplished via
supplementation rather than material
revisions; the proposed new staffing
requirements for construction activity
would not require unique skills or
equipment to which operators would
not have access. Viewed against those
considerations and the compliance costs
estimated in the PRIA, PHMSA expects
its proposed amendments will be a costeffective approach to achieving the
public safety and environmental
benefits discussed in this NPRM and its
supporting documents. Lastly, PHMSA
understands that its proposed
compliance timeline—one year after
publication of a final rule (which would
necessarily be in addition to the time
since publication of this NPRM)—would
provide operators ample time to develop
procedures implementing this new
regulatory requirement (and manage any
related compliance costs).
4. Proposal To Amend § 192.605
Procedures for Qualified Personnel
Monitoring Gas Pressure
PHMSA proposes to revise § 192.605,
by adding paragraph (b)(13), to ensure
gas distribution operators have
procedures for implementing the
monitoring requirements in the
proposed § 192.640. During construction
projects on a gas distribution system,
qualified personnel may need to
perform their monitoring or shutdown
activities in a specific sequence. Doing
work out of sequence may result in an
overpressurization or exacerbate an
emergency. For this reason, it is critical
to pipeline safety that operators have
written procedures for personnel
performing the construction activity
monitoring requirements proposed in
E:\FR\FM\07SEP3.SGM
07SEP3
61786
Federal Register / Vol. 88, No. 172 / Thursday, September 7, 2023 / Proposed Rules
§ 192.640 to follow. This amendment
would ensure that operators must
provide qualified personnel with clear
procedures for how to perform their
responsibilities in a safe manner, and
specifically how to monitor for
abnormal operating conditions that
could lead to an overpressurization.
PHMSA also understands that this
proposed new requirement would be
reasonable, technically feasible, costeffective, and practicable for gas
distribution operators. As noted above,
many operators may already have
compliant procedures; those operators
lacking such procedures should be able
to develop new procedures (or
supplement existing procedures) with
relatively little difficulty. Viewed
against those considerations and the
compliance costs estimated in the PRIA,
PHMSA expects its proposed
amendments are a cost-effective
approach to achieving the public safety
and environmental benefits discussed in
this NPRM and its supporting
documents. Lastly, PHMSA understands
that its proposed compliance timeline—
one year after publication of a final rule
(which would necessarily be in addition
to the time since publication of this
NPRM)—would provide operators
ample time to develop procedures
implementing this new regulatory
requirement (and manage any related
compliance costs).
ddrumheller on DSK120RN23PROD with PROPOSALS3
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)
VerDate Sep<11>2014
20:23 Sep 06, 2023
Jkt 259001
a worker and monitor regulator system,
and (3) automatic or remote shutoff (or
‘‘slam-shut’’) valves.
Pressure relief valves provide
overpressure protection by venting
excess gas into the atmosphere and can
be used alone or in combination with
other methods of overpressure
protection. If the relief valve senses that
the downstream pressure has exceeded
a set point, then the relief valve
automatically begins to open to relieve
excess gas pressure in the system. If
activated, the relief valve protects from
overpressurization while allowing gas to
flow at a safe pressure, maintaining
normal service to customers. In general,
the relief valve is a highly reliable
device for overpressure protection.
Relief valves also provide benefits with
respect to alerting or warning operator
personnel or the public that an
emergency has occurred because (1)
these devices are loud if operated at or
near a full discharge of excess gas
pressure, and (2) the smell of the
odorized gas that is vented is also
noticeable. However, pressure relief
valves entail their own potential public
safety harms through their release of
gas—which can sometimes ignite—into
the atmosphere when activated. Venting
of gas to the atmosphere by a relief valve
also entails environmental risks: a
primary component of natural gas is
methane, an ignitable, potent
greenhouse gas. For these reasons,
section 114 of the PIPES Act of 2020
(codified at 49 U.S.C. 60108(a)(2)(D)(ii))
contains a self-executing requirement
for operators of gas distribution
pipelines to have a written plan to
minimize releases of natural gas—such
as by venting from relief valves—from
their systems.153
A worker and monitor regulator
system is a type of pressure control and
overpressure protection configuration
that involves two pressure reducing
valves (e.g., control or pilot valves)
installed in a series.154 One regulator
valve controls the pressure of gas to the
downstream system. The second
regulator valve remains on standby with
a slightly higher set point and only
begins operating in the event of a
malfunction of the first regulator or
another failure results in pressure
exceeding the set point of the first
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).
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.
PO 00000
Frm 00042
Fmt 4701
Sfmt 4702
regulator. If the first, primary regulator
(the ‘‘worker’’ regulator) cannot control
the pressure, the second regulator (the
‘‘monitor’’), which senses the rising
downstream pressure, automatically
begins to operate to maintain the
pressure downstream at a gas pressure
slightly higher than normal, albeit still
within safe operation. Sometimes an
operator will also install a small relief
valve downstream to act as a ‘‘token
relief’’ or an alarm to alert the operator
that the regulator has failed.
When working properly, a worker and
monitor regulator system should not
interrupt service if an
overpressurization occurs. An advantage
of the worker and monitor regulator
system is that it does not result in
venting large volumes of gas to the
atmosphere, thereby reducing public
safety and environmental harms. Unlike
with pressure relief valves, the pressure
reducing valves used in the worker and
monitor regulator system described
above are not self-operated; instead,
control lines are installed in this type of
system. Control lines (often called
‘‘sensing’’ or ‘‘impulse’’ lines) are smalldiameter pipes that transmit the signal
pressure from the tie-in point on the
downstream piping line to the pressure
regulating device. When the
downstream pressure decreases, the
regulator opens wider to allow more gas
to flow. The regulator valve remains
open until it senses an increase in
pressure or the demand of the
downstream pressure has been met.
Control lines must be protected against
breakage because the regulator will open
wide if the control lines are cut or
damaged because the regulator will not
detect that the demand has been met, it
will remain open, allowing gas to flow
freely. This could result in full upstream
pressure being forced into the lowpressure system, resulting in a
catastrophic situation as seen in the
Merrimack Valley incident.
A third type of overpressure
protection is automatic shutoff devices.
In the event of an overpressurization
indication or event, an automatic
shutoff device completely shuts off the
gas flow to the system until the operator
determines the cause of the malfunction
and resets the device. In many cases, an
automatic shutoff device is used as a
secondary form of overpressure
protection.
2. Current Requirements—Overpressure
Protection
Section 192.195 describes the
minimum requirements for protection
against accidental overpressurization.
Section 192.195(a) requires that ‘‘each
pipeline that is connected to a gas
E:\FR\FM\07SEP3.SGM
07SEP3
ddrumheller on DSK120RN23PROD with PROPOSALS3
Federal Register / Vol. 88, No. 172 / Thursday, September 7, 2023 / Proposed Rules
source so that the [MAOP] could be
exceeded as the result of pressure
control failure or of some other type of
failure, must have pressure relieving or
pressure limiting devices that meet the
requirements of §§ 192.199 and
192.201.’’ 155 Section 192.195(b) adds
that ‘‘[e]ach distribution system that is
supplied from a source of gas that is at
a higher pressure than the [MAOP] for
the system must—(1) [h]ave pressure
regulation devices capable of meeting
the pressure, load, and other service
conditions that will be experienced in
normal operation of the system, and that
could be activated in the event of failure
of some portion of the system; and (2)
[b]e designed so as to prevent accidental
overpressuring.’’ This pipeline safety
regulation has existed in 49 CFR part
192 since its inception.156
Section 192.199 describes the
minimum requirements for the design of
pressure relief and limiting devices.
Section 192.199(g) states that ‘‘[w]here
installed at a district regulator station to
protect a pipeline system from
overpressuring, [the pressure relief or
pressure-limiting device must] be
designed and installed to prevent any
single incident such as an explosion in
a vault or damage by a vehicle from
affecting the operation of both the
overpressure protective device and the
district regulator[.]’’
Section 192.201 describes the
minimum requirements for the required
capacity of pressure-relieving and
-limiting stations. Section 192.201(a)(1)
requires that ‘‘[i]n a low-pressure
distribution system, the pressure may
not cause the unsafe operation of any
connected and properly adjusted gas
utilization equipment.’’ Section
192.201(c) requires that ‘‘[r]elief valves
or other pressure limiting devices must
be installed at or near each regulator
station in a low-pressure distribution
system, with a capacity to limit the
maximum pressure in the main to a
pressure that will not exceed the safe
operating pressure for any connected
and properly adjusted gas utilization
equipment.’’ Section 192.203(b)(9) adds
that ‘‘[e]ach control line must be
protected from anticipated causes of
damage and must be designed and
installed to prevent damage to any one
control line from making both the
regulator and the over-pressure
protective device inoperative.’’ PHMSA
has clarified through its enforcement
guidance that an occurrence of
155 Except as provided in § 192.197, which only
applies to high-pressure gas distribution systems.
156 See ‘‘Establishment of Minimum Standards,’’
35 FR 13248, 13264 (Aug. 19, 1970).
VerDate Sep<11>2014
20:23 Sep 06, 2023
Jkt 259001
overpressurization may be indicative of
an equipment failure or design flaw.157
In addition, § 192.739 describes the
minimum requirements for the
inspection and testing of pressurelimiting and regulating stations. Section
192.739 requires annual inspection and
testing of each pressure limiting or
regulating stations, including relief
devices. The inspection and tests should
determine that the station is: (1) in good
mechanical condition; (2) adequate from
the standpoint of capacity and
reliability of operation for the service in
which it is employed; (3) except as
provided in § 192.739(b) applicable to
certain steel pipelines, set to control or
relieve at the correct pressure consistent
with the pressure limits of § 192.201(a);
and (4) properly installed and protected
from dirt, liquids, or other conditions
that might prevent proper operation.
These requirements are intended to
address inspection and testing of
pressure-limiting and regulator stations
necessary to maintain safe pressures on
the gas distribution system.
Section 192.741 describes minimum
requirements for the telemetering or
recording gauges on pressure-limiting
and regulating stations. Section
192.741(a) states that ‘‘[e]ach
distribution system supplied by more
than one district pressure regulating
station must be equipped with
telemetering or recording pressure
gauges to indicate the gas pressure in
the district.’’ Section 192.741(b) requires
that, ‘‘[o]n distribution systems supplied
by a single district pressure regulating
station, the operator shall determine the
necessity of installing telemetering or
recording gauges in the district, taking
into consideration the number of
customers supplied, the operating
pressures, the capacity of the
installation, and other operating
conditions.’’
3. Need for Change—Overpressure
Protection
The pipeline safety regulations
governing overpressure protection of
low-pressure distribution systems have
not changed since their inception in the
1970s. For years, low-pressure gas
distribution systems, like CMA’s system
in the Merrimack Valley, have relied on
overpressure protection systems like the
redundant worker and monitor
regulators to regulate and control the
pressure and flow of gas. While these
overpressure protection methods are
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/regulatorycompliance/pipeline/enforcement/5776/o-menforcement-guidance-part-192-7-21-2017.pdf.
PO 00000
Frm 00043
Fmt 4701
Sfmt 4702
61787
safe under normal operating conditions,
this method of overpressure protection
on low-pressure distribution systems
can be too easily defeated, as recent
events with a common mode of failure
have demonstrated. PHMSA’s proposed
change to regulations governing
overpressure protection is intended to
facilitate the operation of gas
distribution systems to avoid
catastrophic overpressurization.
According to the NTSB’s report, the
low-pressure system in Merrimack
Valley met the requirements for
overpressure protection contained in
§ 192.195 (Protection Against
Accidental Overpressuring) and
§ 192.197 (Control of the Pressure of Gas
Delivered from High-pressure
Distribution Systems). ‘‘At each of the
14 regulator stations feeding natural gas
into [CMA’s] low-pressure system, there
were two regulators [(i.e., a worker and
monitor regulator system)] installed in a
series to control the natural gas flow
from the high-pressure [. . .]
system.’’ 158 The worker regulator and
the monitor regulator were set to limit
the pressure to a maximum safe value to
the customer. But the system
nonetheless failed. After reviewing
accidents investigated by the NTSB over
the past 50 years, as well as prior
NiSource incidents, the NTSB found
that this scheme for overpressure
protection can be defeated by a common
mode of failure, like operator error or
equipment failure.159
CMA’s overpressurization was not an
isolated event. For example, on January
28, 1982, in Centralia, MO, highpressure natural gas entered a lowpressure natural gas distribution system
after a backhoe damaged the regulator
control line at the Missouri Power and
Light Company’s district regulator
station.160 Because the regulator no
longer sensed system pressure, the
regulator opened, and high-pressure
natural gas entered customer piping
systems. In some cases, this resulted in
high pilot-light flames that ignited fires
in buildings. In other cases, the pilotlight flames were blown out, allowing
natural gas to escape within the
buildings. Of the 167 buildings affected
by the overpressurization, 12 were
destroyed and 32 sustained moderate to
heavy damage. Five occupants suffered
minor injuries.
The NTSB investigated one other
incident in 1977 that was nearly
identical to the 2018 incident in
158 NTSB/PAR–19/02
at 39.
at 39–40.
160 NTSB, Accident Report PAR–82/03, ‘‘Missouri
Power and Light Company Natural Gas Fires,
Centralia, Missouri, January 28, 1982’’ (Aug. 24,
1982).
159 NTSB/PAR–19/02
E:\FR\FM\07SEP3.SGM
07SEP3
ddrumheller on DSK120RN23PROD with PROPOSALS3
61788
Federal Register / Vol. 88, No. 172 / Thursday, September 7, 2023 / Proposed Rules
Merrimack Valley. Both incidents
occurred when a cast-iron main with
control lines attached was isolated as
part of a pipe replacement project. On
August 9, 1977, natural gas under high
pressure entered a Southern Union Gas
Company’s low-pressure natural gas
distribution pipeline and
overpressurized a system serving more
than 750 customers in a 7-block area in
El Paso, TX. The gas company was
replacing a section of 10-inch cast-iron
low-pressure natural gas main
containing the pressure-sensing control
lines for a nearby upstream regulator
station and its monitor and isolated it
between two valves with a temporary
bypass installed. Southern Union Gas
Company was aware that the isolated
section contained the control lines but
did not realize the potential hazard of
isolating the pressure-sensing control
lines, which would make the two
regulators inoperative. Without the
ability to sense the actual pressure in
the gas main, the regulators allowed the
pressure to build up and
overpressurized the rest of the affected
system. The problem was corrected
before causing any fatalities or major
injuries.161
As a result of its investigation of the
CMA overpressurization event, as well
as a review of multiple
overpressurizations that occurred as the
result of a common mode of failure, the
NTSB recommended in P–19–14 that
PHMSA revise 49 CFR part 192 to
require additional overpressure
protection for low-pressure natural gas
distribution systems that cannot be
defeated by a single operator error or
equipment failure. NiSource also took
action to remove this vulnerable design
on their systems. On December 14,
2018, the CEO of NiSource committed to
the NTSB that they would install
automatic pressure control equipment,
referred to as ‘‘slam-shut’’ devices, on
every low-pressure system throughout
their operating area.162 These devices
provide another level of control and
protection, as they immediately shut off
gas to the system when they sense
operating pressure that is too high or too
low. That measure exceeds current
Federal requirements.
Subsequent to the 2018 CMA
incident, PHMSA was required by
statute to issue regulations ensuring that
distribution system operators minimize
the risk of a common mode of failure at
161 NTSB, Safety Recommendation(s) P–77–43
(Dec. 9, 1977), https://www.ntsb.gov/safety/safetyrecs/RecLetters/P77_43.pdf.
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.
VerDate Sep<11>2014
20:23 Sep 06, 2023
Jkt 259001
low-pressure district regulator stations,
monitor the gas pressure of a lowpressure system, and install
overpressure protection safety
technology at low-pressure district
regulator stations. (49 U.S.C.
60102(t)(3)). The mandate also provides
that if it is not operationally possible to
install such technology, PHMSA’s
regulations must provide that operators
would have to develop and follow plans
that would minimize the risk of an
overpressurization.
After reviewing NTSB’s
recommendations, the CMA and other
related incidents, and the requirements
of 49 U.S.C. 60102(t)(3), PHMSA
proposes additional requirements to
improve the design standard for
overpressure protection on low-pressure
distribution systems. Gas distribution
systems that use only regulators and
control lines as the means to prevent
overpressurization are not sufficient
protection from overpressurization
events. Therefore, PHMSA is proposing
additional layers of protection specific
to low-pressure distribution systems to
set a safer design standard for these
systems.
4. Proposal To Amend § 192.195—
Overpressure Protection
Consistent with 49 U.S.C. 60102(t)(3),
PHMSA proposes to amend § 192.195 to
impose three additional requirements
for each district regulator station that
serves a low-pressure distribution
system. First, each district regulator
station must consist of at least two
methods of overpressure protection
(such as a relief valve, monitoring
regulator, or automatic shutoff valve)
appropriate for the configuration and
location of the station. Under this
proposal, operators have options for
meeting the new requirements for
overpressure protection. For example,
one option is for operators of lowpressure distribution systems to install
a full relief valve downstream of
existing overpressure protections.
Another option is to install an automatic
shutoff valve. In that case, for operators
with the worker and monitor regulator
set up, the addition of an automatic
shutoff valve downstream of the existing
setup would stop the flow of gas if an
overpressurization occurred and both
regulators failed. Further, some
automatic shutoff valves have the
capability to activate if the system
experiences an underpressurization.163
PHMSA discussed these additional
options in the overpressure protection
163 An underpressurization could occur if there is
a pipeline rupture downstream, which is a risk
during excavation.
PO 00000
Frm 00044
Fmt 4701
Sfmt 4702
advisory bulletin (ADB–2020–02), but
there are other configurations that
would be suitable as well.
PHMSA proposes this two-method
requirement as mandatory for district
regulator stations that are new, replaced,
relocated, or otherwise changed after the
effective date of the final rule. For all
other systems, PHMSA proposes to
amend § 192.1007(d)(2)(ii) to require
operators to ensure district regulator
stations have two methods of
overpressure protection consistent with
proposed § 192.195(c)(1), or identify and
notify PHMSA of alternative preventive
and mitigative measures. PHMSA finds
that this approach meets the mandate
found at 49 U.S.C. 60102(t)(3)(iii) and
(iv) for all district regulator stations to
have at least two methods of
overpressure protection technology
appropriate for the configuration and
siting of the station, while allowing for
alternate action where PHMSA
determines it is not operationally
possible to have such secondary relief.
PHMSA concludes that it is
operationally possible for operators to
include at least two methods of
overpressure protection in new,
replaced, relocated, or otherwise
changed district regulator stations. And,
for existing district regulator stations,
PHMSA recognizes that there may be
unique cases where it is not
operationally possible to have a second
measure, in which circumstance an
operator may notify PHMSA under
§ 192.1007(d)(2)(ii)(B) of the alternative
measures to minimize the risk of an
overpressure event.
Second, PHMSA proposes that each
district regulator station that services a
low-pressure system must minimize the
risk of overpressurization that could be
caused by any single event (such as
excavation damage, natural forces,
equipment failure, or incorrect
operations) that either immediately or
over time affects the safe operation of
more than one overpressure protection
device. PHMSA notes that 49 U.S.C.
60102(t)(3) requires the promulgation of
regulations that minimize the risk of gas
pressure exceeding the MAOP from a
common mode of failure. PHMSA
interprets the statutory term ‘‘common
mode of failure’’ to mean a failure where
a single common cause could
immediately or over time cause multiple
failures that result in an
overpressurization on a downstream
distribution system. PHMSA’s
interpretation of ‘‘common mode of
failure’’ is intended to ensure that
operators are identifying as many
potential failure modes in their systems
as possible.
E:\FR\FM\07SEP3.SGM
07SEP3
ddrumheller on DSK120RN23PROD with PROPOSALS3
Federal Register / Vol. 88, No. 172 / Thursday, September 7, 2023 / Proposed Rules
This practice of identifying potential
common modes of failure will be
particularly important for operators of
low-pressure gas distribution systems,
whose designs make them more
vulnerable to overpressurization. For
example, hydrotesting upstream of the
district regulator station could cause
moisture to be injected into the gas
system, which then could cause the
working and monitor regulators to
freeze up before the gas distribution
operator responds. Construction work
upstream of the district regulator station
could cause contaminants like metal
shavings to be introduced into the gas
system, which then could damage the
working and monitor regulator
diaphragms before the gas distribution
operator could respond. Oil, hydrates,
or high sulfides that enter the gas
system could affect both the working
and monitoring regulators before the gas
distribution operator could respond. A
contractor or third party could damage
both downstream control lines at the
same time. And, as seen in the 2018
Merrimack Valley incident, connecting
a new main to the district regulator
station without connecting the control
lines to the new piping could result in
an overpressurization. In its proposed
§ 192.195(c)(2), PHMSA provides
examples of single events that could
cause a common mode of failure, such
as excavation damage, natural forces,
equipment failure, or incorrect
operations. While operators are best
positioned to identify other scenarios
that could introduce a common mode of
failure on their unique gas distribution
systems, applying any of the design
standards described in this proposed
amendment could eliminate most of the
common modes of failure described in
this paragraph and in § 192.195(c)(2) by
providing additional redundancy in the
gas distribution system.
Third, pursuant to 49 U.S.C.
61012(t)(3), PHMSA proposes in
§ 192.195(c)(3) to require that lowpressure distribution systems have
remote monitoring of gas pressure at or
near the location of overpressure
protection devices. Remote monitoring
in this context means that the device is
capable of monitoring the gas pressure
near the location of overpressure
protection devices and remotely
displaying the gas pressure to operator
personnel in real time. Low-pressure gas
distribution operators are already
required to have devices such as
telemetering or recording gauges that
record gas pressure (see §§ 192.199 and
192.201). However, the current
telemetering and recording device
requirements in § 192.741 do not require
VerDate Sep<11>2014
20:23 Sep 06, 2023
Jkt 259001
active monitoring and some of these
devices employed under §§ 192.199,
192.201, and 192.741 are not designed
to provide real-time awareness or
notification of potential
overpressurizations. Installing these
real-time monitoring devices will
improve an operator’s ability to receive
timely overpressurization indications,
thereby giving operator personnel an
opportunity to avoid or mitigate adverse
consequences. Accordingly, PHMSA
also proposes a conforming change in a
new § 192.741(d) to specify that
operators of low-pressure distribution
systems that are new, replaced,
relocated, or otherwise changed
beginning one year after the publication
of any final rule in this proceeding must
monitor the gas pressure in accordance
with § 192.195(c)(3).
These three new design standards
would be applicable to low-pressure
distribution systems that are new,
replaced, relocated, or otherwise
changed beginning one year after the
publication of any final rule in this
proceeding. A modification to either the
low-pressure system or the district
regulator station made on or after the
compliance date above would require an
operator to meet the proposed new
design standards described in this
section. For example, as operators
upgrade their low-pressure systems as
part of the cast iron replacement
program or implement mitigating
measures to address the risk of
overpressurization through the DIMP
requirements in § 192.1007, they would
be required to ensure those upgrades
meet the proposed design standard in
§ 192.195(c). PHMSA would not expect
operators performing routine
maintenance to upgrade their systems to
meet the proposed design standard.
PHMSA understands this proposed
requirement for gas distribution
operators to incorporate in their design
of low-pressure distribution systems the
overpressure protection measures
described above would be reasonable,
technically feasible, cost-effective, and
practicable. These proposed enhanced
design and installation requirements
would be applicable only to certain gas
distribution operators—those with
district regulators serving low-pressure
systems—and then only when
components within their systems are
new, replaced, relocated, or otherwise
changed. Affected operators would
therefore be able to integrate these
common-sense, proposed safety
enhancements within larger
construction, installation, and
replacement projects. Indeed, some lowpressure gas distribution system
operators may already be complying
PO 00000
Frm 00045
Fmt 4701
Sfmt 4702
61789
with this proposed requirement either
as a voluntarily for commercial reasons
(to minimize the loss of a valuable
commodity), as a safety practice
(implementing lessons learned from the
Merrimack Valley incident and NTSB
recommendation P–19–14) or as a
mitigation measure pursuant to their
DIMP. Viewed against those
considerations and the compliance costs
estimated in the PRIA, PHMSA expects
its proposed amendments will be a costeffective approach to achieving the
commercial, public safety, and
environmental benefits discussed in this
NPRM and its supporting documents.
Lastly, PHMSA understands that its
proposed compliance timeline—one
year after publication of a final rule
(which would necessarily be in addition
to the time since publication of this
NPRM)—would provide operators
ample time to incorporate these
requirements in plans for new, replaced,
relocated, or otherwise changed low
pressure distribution systems (and
manage any related compliance costs).
I. Inspection: General (Section 192.305)
1. Current Requirements—Inspections
Section 192.305 (Inspection: General)
states that ‘‘[e]ach transmission line or
main must be inspected to ensure that
it is constructed in accordance with this
part.’’
2. Need for Change—Inspections
On November 29, 2011, PHMSA
issued an NPRM that included a
proposal to modify the requirements
contained in § 192.305 to specify that a
gas transmission pipeline or distribution
main cannot be inspected by someone
who participated in its construction.164
This addressed concerns expressed by
State and Federal regulators and was
based in part on a 2011 NAPSR
resolution calling for revisions to
§ 192.305 to provide that contractors
who install a transmission pipeline or
distribution main should be prohibited
from inspecting their own work for
compliance purposes.165 At the time,
§ 192.305 had simply provided that each
transmission pipeline or distribution
main must be inspected to ensure that
it was constructed in accordance with
49 CFR part 192. In a final rule issued
on March 11, 2015, PHMSA amended
§ 192.305 to specify that a pipeline
operator may not use the same operator
personnel to perform a required
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).
E:\FR\FM\07SEP3.SGM
07SEP3
61790
Federal Register / Vol. 88, No. 172 / Thursday, September 7, 2023 / Proposed Rules
ddrumheller on DSK120RN23PROD with PROPOSALS3
inspection who also performed the
construction task that required
inspection.166
PHMSA received petitions for
reconsideration of various elements of
the March 2015 final rule, including
petitions from the American Public Gas
Association (APGA) and other
stakeholders raising concern about the
construction inspection requirement in
§ 192.305 for smaller operators for
whom it may be particularly difficult to
have different personnel perform
construction and inspection
activities.167 The APGA petition noted
that utilities with only one qualified
crew who work together to construct
distribution mains would not have
anyone working for the utility available
and qualified to perform the inspection
under the amended language, which
could significantly increase the costs for
those utilities by requiring small
utilities to contract with third parties for
such inspections.168 In 2015, according
to the APGA, 585 municipal gas utilities
had 5 or fewer employees. The APGA
stated that its concerns would be
alleviated by a clarification stating a
two-man utility crew may inspect each
other’s work and comply with the
amendment to § 192.305.
NAPSR, on the other hand, submitted
a petition criticizing the March 2015
final rule for not limiting the § 192.305
prohibition to contractor personnel
inspecting the work performed by their
own company’s crews, contending that
such an approach would not resolve the
potential conflict of interest that had
been the occasion for its 2011
resolution.169 NAPSR added that
prohibition should not apply to an
operator’s own construction personnel
as NAPSR believed they would have
less of an incentive to accept poor
quality work when conducting an
inspection than a contractor inspecting
166 ‘‘Pipeline Safety: Miscellaneous Changes to
Pipeline Safety Regulations,’’ 80 FR 12762, 12779
(Mar. 11, 2015).
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).
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).
VerDate Sep<11>2014
20:23 Sep 06, 2023
Jkt 259001
his colleagues’ work. NAPSR asked for
a delay in the effective date of the final
rule relative to § 192.305 until PHMSA
had reviewed the rule and worked with
NAPSR to address its concerns.
PHMSA responded to the petitions for
reconsideration of the March 2015 final
rule on September 30, 2015, and, in
recognition of the concerns expressed,
indefinitely delayed the effective date of
the § 192.305 amendment.170 Because
other proposed amendments in this
NPRM may impact the number of
inspections and construction activities
on gas distribution mains, PHMSA
believes it is appropriate to re-examine
this issue.
3. Proposal To Amend § 192.305—
Inspections
In this NPRM, PHMSA proposes to
remove the existing suspension of
§ 192.305, relocate the existing
regulatory language adopted in the
March 2015 final rule to a new
paragraph (a), and add a new paragraph
(b) addressing concerns raised in
APGA’s petition for reconsideration
pertaining to the potential impact on
small operators.
If adopted, PHMSA’s proposed
§ 192.305(a) would require each gas
transmission pipeline (along with each
offshore gas gathering, and Types A, B,
and C gathering pipelines pursuant to
§ 192.9) and distribution main that is
newly installed, replaced, relocated, or
otherwise changed beginning one year
after the publication of a final rule to be
inspected to ensure that it is constructed
in accordance with the requirements of
this subpart, using different personnel
to conduct the inspection than had
performed the construction activity.
This requirement—which would lift the
suspension of the regulatory
amendments adopted in the March 2015
final rule—was the subject of extensive
consideration in PHMSA’s earlier notice
and comment rulemaking (including
during a meeting of the Gas Pipeline
Advisory Committee (GPAC)).171
PHMSA understands that the public
safety and environmental risks
associated with releases from Type C
gathering pipelines, a category created
in a final rule issued in November
2021 172 and thus not included in the
170 ‘‘Pipeline Safety: Miscellaneous Changes to
Pipeline Safety Regulations: Response to Petitions
for Reconsideration,’’ 80 FR 58633, 58634 (Sept. 30,
2015).
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.
172 ‘‘Pipeline Safety: Safety of Gas Gathering
Pipelines: Extension of Reporting Requirements,
Regulation of Large, High-Pressure Lines, and Other
PO 00000
Frm 00046
Fmt 4701
Sfmt 4702
2015 assessment of cost-effectiveness,
technical feasibility, and practicability,
are similar to the risks associated with
other part 192-regulated gas gathering
pipelines (which generally transport
unprocessed natural gas containing
higher percentages of volatile organic
compounds, corrosives, and hazardous
airborne pollutants than processed
natural gas transported in other
pipelines). PHMSA therefore proposes
to subject Type C gathering pipelines to
the inspection requirements at
§ 192.305(a). PHMSA expects to have
operator-reported data after the
reporting cycle completes in spring of
2023 for these newly regulated gathering
lines.173 To address this uncertainty,
PHMSA estimates that most Type C
lines are operated by operators of other
part 192-regulated gathering pipelines
such that they are already included in
the 2015 assessment of this regulatory
requirement for other lines.174 PHMSA
explains this estimate in greater length
in the associated preliminary regulatory
impact analysis.
Additionally, PHMSA has evaluated
concerns raised in APGA and other
petitioners’ reconsideration petitions,
and PHMSA proposes to add a
paragraph (b) that would provide an
exception to the construction inspection
requirement for gas distribution mains
for small gas distribution operators for
whom complying with paragraph (a)
may prove difficult due to their limited
staffing. Specifically, PHMSA proposes
to allow operator personnel involved in
the same construction task to inspect
each other’s work on mains when the
operator could otherwise comply with
the construction inspection requirement
in paragraph (a) of this section only by
using a third-party inspector. This
justification must be documented and
retained for the life of the pipeline. This
exception is in acknowledgment that, as
highlighted by APGA, there are times
when only one or two people are
available to perform a task and the
current requirements may be overly
burdensome for smaller gas distribution
operators. PHMSA proposes to limit this
exception to distribution operators
because it understands that: (1) many of
these operators are likely to have a
limited number of employees, thereby
necessitating reliance on contractor
personnel; and (2) the public safety risks
from delays in undertaking safetyimproving construction projects
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.
E:\FR\FM\07SEP3.SGM
07SEP3
ddrumheller on DSK120RN23PROD with PROPOSALS3
Federal Register / Vol. 88, No. 172 / Thursday, September 7, 2023 / Proposed Rules
(because of a lack of qualified
inspection personnel) on these pipelines
would be particularly compelling given
their (typical) location near or within
population centers. PHMSA believes
this proposed amendment addresses
concerns raised in APGA’s petitions for
reconsideration regarding the
unintended burdens of the March 2015
rulemaking on small operators.
PHMSA acknowledges that NAPSR,
in its 2011 resolution and petition for
reconsideration of the March 2015 final
rule, called for limiting the prohibition
to contractor personnel inspecting the
work of their own crew, as NAPSR does
not view an ‘‘inherent conflict of
interest’’ arising from operatoremployed personnel doing the same.175
PHMSA agrees with NAPSR that a lack
of independence in inspection activity
raises public safety concerns but
disagrees that there is a material
distinction in risk between those
personnel directly employed by the
operator and those third-party personnel
contracted by the operator. Further,
creating such a distinction could
diminish the scope of the safety benefit
while placing burden on smaller
operators who rely on contractors for a
large portion of their construction work.
Therefore, PHMSA does not see a
reasoned basis to discriminate between
operator personnel and contracted
personnel for the purposes of this
inspection.
PHMSA understands this proposed
amendment to restore a previously
approved (but now suspended)
requirement that post-construction
inspections be performed by personnel
other than those who performed the
construction work being inspected
would be reasonable, technically
feasible, cost-effective, and practicable
for all affected operators. That
requirement reflects the proposition—
reflected in industry best practice—that
an independent second set of eyes
inspecting a construction project
provides more robust assurance of work
product quality than allowing
construction personnel to inspect their
own work. Although PHMSA
acknowledges that this proposed
requirement could entail additional
compliance burdens (in terms of costs
and stretching limited personnel
resources) for some operators, PHMSA
believes those burdens would be
manageable because (1) all operators
could account for them at the project
planning phase in a way that allows
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.
VerDate Sep<11>2014
20:23 Sep 06, 2023
Jkt 259001
them to control costs or secure requisite
supplemental personnel (or contractors),
and (2) small gas distribution system
operators whose limited personnel
resources would make them dependent
on (potentially expensive) contractors
would be excepted from this
requirement. Viewed against those
considerations and the compliance costs
estimated in the PRIA, PHMSA expects
its proposed amendments will be a costeffective approach to achieving the
commercial, public safety, and
environmental benefits discussed in this
NPRM and its supporting documents.
Lastly, PHMSA understands that its
proposed compliance timeline—one
year after publication of a final rule
(which would necessarily be in addition
to the time since publication of this
NPRM)—would provide operators
ample time to implement requisite
changes to their procedures and obtain
access to inspection personnel for nearterm installation projects (as well as
manage any resulting compliance costs).
J. Records: Tests (Sections 192.517 and
192.725)
1. Current Requirements—Records:
Tests
Section 192.517(b) applies to all gas
pipeline operators and states that
‘‘[e]ach operator must maintain a record
of each test required by §§ 192.509
[pipelines operating below 100 psig],
192.511 [service lines], and 192.513
[plastic pipelines], respectively, for at
least 5 years.’’ Section 192.725(a) states
that ‘‘each disconnected service line
must be tested in the same manner as a
new service line, before being
reinstated.’’ 176
2. Need for Change—Records: Tests
On October 7, 2021, NAPSR
submitted a resolution seeking that
PHMSA amend § 192.517(b) in several
ways. NAPSR recommended PHMSA
amend its regulations to require
operators to retain test documentation
under § 192.517(b) for the life of the
corresponding pipeline segment as
opposed to the current 5 years.177 The
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.
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
PO 00000
Frm 00047
Fmt 4701
Sfmt 4702
61791
resolution also requested that PHMSA
require operators to retain for the life of
the pipeline ‘‘the test pressure
documentation created within the five
years prior’’ to any such amendment.
Additionally, NAPSR requested that
PHMSA require additional, more
detailed, information be documented as
part of these test records. PHMSA agrees
that the detailed recordkeeping content
and retention requirements suggested by
NAPSR will improve consistency and
promote public safety and protection of
the environment.
NAPSR also requested that PHMSA
add § 192.725 (‘‘Test requirements for
reinstating service lines’’) to the list of
required test records in § 192.517(b). It
reasoned that § 192.603(b), which
requires operators to keep records
necessary to administer the procedures
established under § 192.605, is
potentially in conflict with § 192.517.
PHMSA clarifies that the requirement in
§ 192.725 to perform a test ‘‘in the same
manner as a new service line’’ is meant
to direct an operator to conduct a test
required for a new service line in
accordance with 49 CFR part 192,
subpart J. A test performed to meet
§ 192.725 does not constitute a new type
of test for purposes of identifying
recordkeeping requirements for such a
test. PHMSA expects an operator to
select the appropriate test in subpart J
to meet the testing requirement of
§ 192.725, which includes meeting the
corresponding recordkeeping
requirements of § 192.517. For that
reason, PHMSA does not propose to
include § 192.725 in the list of tests
identified within § 192.517.
3. Proposal To Amend § 192.517—
Records: Tests
PHMSA proposes to amend § 192.517
to require that records of tests covered
by § 192.517(b) (i.e., tests performed
according to § 192.509, 192.511, and
192.513) be retained for the life of the
pipeline. This amendment would be
applicable to all gas pipeline operators.
PHMSA would require operators to
retain the records for all tests presently
being retained under the existing
language of § 192.517(b) from the
preceding five years, which under the
proposal would then be retained for the
life of the pipeline. PHMSA also
proposes to require that the records of
these tests include, at a minimum,
sufficient information to document the
test, including information about the
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.’’
E:\FR\FM\07SEP3.SGM
07SEP3
ddrumheller on DSK120RN23PROD with PROPOSALS3
61792
Federal Register / Vol. 88, No. 172 / Thursday, September 7, 2023 / Proposed Rules
operator, the individual or any company
used to perform the test, pipeline
segment being tested, test date, medium,
pressure, duration, and any leaks or
failures noted and their disposition.
Retaining tests for the life of the
pipeline, instead of the current retention
period of 5 years, ensures that records
are available whenever repairs are
necessary, or should an incident occur,
records are available to support an
operator’s inspection and investigation
into the root cause of a failure. Further,
PHMSA currently requires (per
§ 192.603(b) and § 192.605) operators to
keep MAOP records for life of facility
but MAOP records established by
§ 192.517(b) tests are just 5 years.
PHMSA believes that these changes will
improve the quality and availability of
test records, including records of leaks
occurring during testing activities and
MAOP establishment records.
PHMSA understands this proposed
amendment of an existing record
retention requirement to be reasonable,
technically feasible, cost-effective, and
practicable. The proposed changes are
incremental supplementation of current
requirements regarding recording and
retaining record of pressure tests
operators are already required to
conduct. The proposed amendments
require operators to document
information they may already be
obtaining through the required tests
under this current requirement, more
clearly states that information which
operators should record from the tests
and extends the retention period;
PHMSA expects some operators may
already be in their substantial
compliance with this proposed
requirement. Viewed against those
considerations and the compliance costs
estimated in the PRIA, PHMSA expects
its proposed amendments will be a costeffective approach to achieving the
commercial, public safety, and
environmental benefits discussed in this
NPRM and its supporting documents.
Lastly, PHMSA understands that its
proposed compliance timeline—one
year after publication of a final rule
(which would necessarily be in addition
to the time since publication of this
NPRM)—would provide operators
ample time to implement requisite
changes to their procedures to ensure
identification or generation of pertinent
records (and manage any related
compliance costs).
4. Proposal To Amend § 192.725—Test
Requirements for Reinstating Service
Lines
PHMSA proposes to revise § 192.725
to clarify that ‘‘tested in the same
manner as a new service line’’ in the
VerDate Sep<11>2014
20:23 Sep 06, 2023
Jkt 259001
existing regulation means ‘‘tested in
accordance with subpart J of this part’’,
by inserting that clarifying language
within a parenthetical. PHMSA
understands that this proposed revision
merely clarifies an existing requirement
and is therefore technically feasible and
practicable. PHMSA further notes that
its proposed compliance timeline—one
year after publication of a final rule
(which would necessarily be in addition
to the time since publication of this
NPRM)—would provide operators
ample time to implement updates, if any
are needed, to their procedures.
K. Miscellaneous Amendments
Pertaining to Part 192—Regulated Gas
Gathering Pipelines (Sections 192.3 and
192.9)
1. Current Requirements—Gas Gathering
Among the regulatory amendments
adopted in the April 2022 Valve Rule
were enhanced emergency planning and
notification requirements applicable to
all part 192-regulated gas pipeline
operators subject to § 192.615, to
include new references to public safety
answering points (such as 9–1–1 call
centers) and a requirement for those
operators to update their written
procedures to provide for timely rupture
identification; certain new,
implementing definitions at § 192.3
applicable to all part 192-regulated gas
pipelines; and within a new § 192.635,
a definition of the term ‘‘notification of
potential rupture’’ applicable to those
part 192-regulated pipelines subject to
that provision.
The D.C. Circuit, however, vacated
those new requirements as to gas
gathering pipelines in a decision issued
in May 2023.178 PHMSA subsequently
issued a Technical Correction codifying
the court’s decision by introducing
exceptions to the above provisions
restricting their application to the part192 regulated gas gathering pipelines to
which they had applied.179 Specifically,
the Technical Correction introduced
language in each of the § 192.3
definitions adopted in the Valve Rule
(‘‘entirely replaced onshore
transmission pipeline segments’’;
‘‘notification of potential rupture’’; and
‘‘rupture-mitigation valve (RMV)’’)
excepting all part 192-regulated gas
gathering pipelines from those
definitions. The Technical Correction
also introduced a series of exceptions
within the regulatory cross-reference
provision at § 192.9 preventing
application of the Valve Rule’s
amendments at §§ 192.615 and 192.635
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).
PO 00000
Frm 00048
Fmt 4701
Sfmt 4702
regarding emergency response and
notification and rupture identification
procedures to each of offshore gas
gathering pipelines (§ 192.9(b)) as well
as onshore Types A (§ 192.9(c)) and C
(§ 192.9(e)) gas gathering pipelines.
2. Need for Change—Gas Gathering
Written emergency planning and
notification procedures are critical tools
for the safe operation of any gas
pipeline. Offshore, Type A, and Type C
gas gathering pipelines had—consistent
with the risks to public safety and the
environment posed by an emergency
involving those high-pressure, gas
pipeline facilities 180—been subject to
extensive emergency planning and
notification requirements before
issuance of the Valve Rule in April
2022. Those long-standing safety
standards include requirements for
operators to have written emergency
procedures for notifying, establishing,
and maintaining communications with
fire, police, and other public officials
(§ 192.615(a)(2) and (8); § 192.615(c));
taking actions necessary to minimize
hazards to public safety from the
emergency (§ 192.615(a)(6)); and
directing operator control room
response actions in an emergency
(§ 192.615(a)(11)).
The amendments to § 192.615
introduced in the Valve Rule were
modest refinements to those longstanding emergencies response planning
and notification requirements. The
Valve Rule explained its amendments to
§ 192.615(a)(2), (a)(8), and (c) adding
language requiring notification of, and
communication with, public safety
answering points (PSAPs) or emergency
coordination agencies ensure
notifications of pipeline emergencies are
channeled to resources best positioned
to alert first responders and coordinate
response efforts across multiple
jurisdictions that may be affected by a
pipeline emergency.181 The Valve Rule
also made a pair of incremental changes
to § 192.615(a)(6)’s requirement that
operator procedures provide for taking
certain actions—emergency shutdown
or pressure reduction—to minimize
public safety risks. The first change was
to add language (‘‘including, but not
limited to . . .’’) clarifying that operator
procedures could provide for actions
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 § 192.615 requirements to highpressure, large-diameter Type C gas gathering
pipelines).
181 87 FR at 20969–70, 20973.
E:\FR\FM\07SEP3.SGM
07SEP3
Federal Register / Vol. 88, No. 172 / Thursday, September 7, 2023 / Proposed Rules
ddrumheller on DSK120RN23PROD with PROPOSALS3
other than system shutdown or pressure
reduction in an emergency, thereby
granting operators greater flexibility in
designing response actions best capable
of minimizing hazards in a pipeline
emergency; this includes the
additionally enumerated action of valve
shut-off. The second change included a
reference to environmental hazards.
Among those hazards operator
procedures must minimize, reflecting
the fact that the mechanism for public
safety and environmental harms
(namely, the release of gas from a
pipeline) is identical.
The Valve Rule also made several
regulatory amendments to address the
time-dependent 182 risks to public safety
and the environment posed by ruptures
on gas pipelines. First, the Valve Rule
added at § 192.3 (which in turn
references a new § 192.935) the new
term ‘‘notification of potential rupture’’
codifying commonly-understood indicia
of a rupture.183 The Valve Rule also
added a pair of requirements ensuring
timely identification of, and response to,
this particular emergency in which
every second lost can increase public
safety and environmental consequences:
a new § 192.615(a)(12) requiring
operators develop procedures for
confirming actual ruptures following
reports of the indicia listed in the new
definition of ‘‘notification of potential
rupture’’, as well as language at
§ 192.615(a)(8) introducing a new
requirement for immediate and direct
notification of PSAPs on an operator’s
notification of a potential rupture.184
Similarly, PHMSA enhanced a
longstanding requirement at
§ 192.615(a)(11) governing emergency
procedures for control room personnel
by adding a cross-reference to newlyadopted provisions pertaining to
rupture mitigation valves at §§ 192.634
and 192.636.
Lastly, the Valve Rule adopted certain
other definitions of terms (‘‘entirely
replaced onshore transmission
segment’’; and ‘‘rupture-mitigation
valve’’) employed in its regulatory
amendments.
3. Proposal To Amend §§ 192.3 and
192.9—Emergency Procedures and
Notification; Rupture Identification
Procedures
PHMSA proposes several
amendments to restore certain
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.
VerDate Sep<11>2014
20:23 Sep 06, 2023
Jkt 259001
emergency planning, notification, and
rupture identification procedures
vacated by the D.C. Circuit with respect
to gas gathering pipelines. First, PHMSA
proposes to delete from each of the
§ 192.3 definitions introduced in the
Technical Correction language
disclaiming application of those terms
to any part 192-regulated gas gathering
line.185 Second, PHMSA proposes to
delete from § 192.9 similar language
excluding application of the Valve
Rule’s amendments to § 192.615
discussed in section IV.K.2 above to
offshore gas gathering (§ 192.9(b)), Type
A (§ 192.9(c)), and Type C (§ 192.9(e))
gas gathering lines. This proposal is
focused on application of these
emergency response provisions to
gathering lines; PHMSA is not, however,
proposing in this rulemaking to restore
application to part 192-regulated gas
gathering lines of other regulatory
amendments adopted in the Valve Rule
pertaining to rupture mitigation valve
installation, operation, and
maintenance.
As explained in section IV.K.2 above,
the Valve Rule’s amendments to
§ 192.615 are incremental improvements
on existing requirements applicable to
offshore, Type A, and Type C gas
gathering pipelines. Some of those
amendments are broad in scope and are
applicable to any emergency on those
gas gathering pipelines; others are
specific to ruptures on those pipelines.
And each of those amendments is a
common-sense, baseline expectation
ensuring operator emergency planning
and notification procedures are directed
toward timely and effective response
and mitigation of risks to public safety
and the environment.
PHMSA understands these proposed
amendments would be reasonable,
technically feasible, cost-effective and
practicable for affected gas gathering
pipeline operators. The restoration of
definitions at § 192.3 are not themselves
operative provisions entailing
compliance burdens for operators;
several of those definitions, moreover,
are used in operative provisions
inapplicable to gas gathering pipelines.
And although the restored applicability
of the Valve Rule’s revisions to
§ 192.615 could entail additional
compliance burdens for affected gas
gathering operators, some operators may
already incorporate the required content
in their pipelines’ emergency planning
and notification procedures; indeed,
such procedures are precisely the sort of
185 PHMSA understands that in so doing, the
§ 192.635 definition of ‘‘notification of potential
rupture’’ referenced within § 192.3 would apply to
all part 192-regulated gas gathering pipelines as
well.
PO 00000
Frm 00049
Fmt 4701
Sfmt 4702
61793
procedures a reasonably prudent
operator of any gas pipeline facility
would maintain in ordinary course
given that their systems transport
commercially valuable, pressurized
(natural flammable, toxic, or corrosive)
gasses. Viewed against those
considerations and the compliance costs
estimated in the PRIA, PHMSA expects
its proposed amendments will be a costeffective approach to achieving the
public safety, and environmental
benefits discussed in this NPRM and its
supporting documents. Lastly, PHMSA
understands that its proposed
compliance timeline—one year after
publication of a final rule (which would
necessarily be in addition to the time
since publication of this NPRM)—would
provide operators ample time to
implement requisite changes to their
procedures (as well as manage any
resulting compliance costs).
V. Regulatory Analyses and Notices
A. Authority for This Rule
This proposed rule is published under
the authority of the Secretary of
Transportation delegated to the PHMSA
Administrator pursuant to 49 CFR 1.97.
Among the statutory authorities
delegated to PHMSA are those set forth
in the Federal Pipeline Safety Statutes
(49 U.S.C. 60101 et seq.). 49 U.S.C.
60102 grants authority to issue
standards for the transportation of gas
via any part 192-regulated gathering
pipelines to protect public safety and
the environment; and 49 U.S.C.
60102(b)(5) specifies that PHMSA must
consider both public safety and
environmental benefits.
This NPRM proposes to implement
several provisions of the PIPES Act of
2020, including those codified at 49
U.S.C. 60102, 60105, 60106, and 60109.
Section 60102 authorizes the Secretary
of Transportation to issue regulations
governing the design, installation,
inspection, emergency plans and
procedures, testing, construction,
extension, operation, replacement, and
maintenance of gas pipeline facilities,
including gas transmission, gas
distribution, offshore gas gathering, and
Types A, B, and C gas gathering
pipelines, each of which would be
subject to various proposed
requirements in this NPRM. Sections
60105 and 60106 permit States to
assume safety authority over intrastate
pipelines, including gas and hazardous
liquid pipelines, and underground
natural gas storage facilities through
certifications or agreements with
PHMSA, while section 60107 authorizes
the Secretary to establish requirements
governing award of grants supporting
E:\FR\FM\07SEP3.SGM
07SEP3
61794
Federal Register / Vol. 88, No. 172 / Thursday, September 7, 2023 / Proposed Rules
ddrumheller on DSK120RN23PROD with PROPOSALS3
State pipeline safety programs.
Additionally, 49 U.S.C. 60117
authorizes the Secretary of
Transportation to direct operators of
those gas pipeline facilities to submit
reports to PHMSA to inform PHMSA’s
regulatory oversight activities. As
described above, 49 U.S.C. 60102,
60105, and 60109 also require the
Secretary to issue regulations updating
PHMSA regulations in 49 CFR parts 192
and 198.
B. Executive Orders 12866 and 14094;
DOT Regulatory Policies and Procedures
Executive Order 12866 (‘‘Regulatory
Planning and Review’’), as amended by
Executive Order 14094 (‘‘Modernizing
Regulatory Review’’), requires that
agencies ‘‘should assess all costs and
benefits of available regulatory
alternatives, including the alternative of
not regulating.’’ 186 Agencies should
consider quantifiable measures and
qualitative measures of costs and
benefits that are difficult to quantify.
Further, Executive Order 12866 requires
that agencies maximize net benefits
(including potential economic,
environmental, public health and safety,
and other advantages; distributive
impacts; and equity), unless a statute
requires another regulatory approach.
Similarly, DOT Order 2100.6A
(‘‘Rulemaking and Guidance
Procedures’’) requires that regulations
issued by PHMSA and other DOT
Operating Administrations should
consider an assessment of the potential
benefits, costs, and other important
impacts of the proposed action and
should quantify (to the extent
practicable) the benefits, costs, and any
significant distributional impacts,
including any environmental impacts.
Executive Order 12866 (as amended
by Executive Order 14094) and DOT
Order 2100.6A require that PHMSA
submit ‘‘significant regulatory actions’’
to the Office of Management and Budget
(OMB) for review. The proposed rule
has been determined to be significant
under section 3(f) of Executive Order
12866 (as amended by section 1(b) of
Executive Order 14094) and DOT Order
2100.6A and was reviewed by the Office
of Information and Regulatory Affairs
(OIRA) within OMB.
Consistent with Executive Order
12866 (as amended by Executive Order
14094) and DOT Order 2100.6A,
PHMSA has prepared a PRIA assessing
the benefits and costs of the proposed
rule as well as reasonable alternatives.
PHMSA estimates the proposed rule
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).
VerDate Sep<11>2014
20:23 Sep 06, 2023
Jkt 259001
will result in unquantified public safety
and environmental benefits associated
with preventing and mitigating
incidents on gas distribution and other
part 192-regulated gas pipeline
facilities. PHMSA estimates annualized
costs of $110 million per year (using a
3 percent discount rate) due to costs
associated with the proposed
requirements for updating emergency
response plans, updating O&M manuals,
keeping records, gas monitoring by
qualified employees, and assessing and
upgrading district regulator stations. For
the full cost/benefit analysis, please see
the PRIA in the rulemaking docket.
PHMSA seeks comment on the PRIA, its
approach, and the accuracy of its
estimated costs and benefits.
C. Environmental Justice
Executive Order 12898 (‘‘Federal
Actions to Address Environmental
Justice in Minority Populations and
Low-Income Populations’’),187 directs
Federal agencies to take appropriate and
necessary steps to identify and address
disproportionately high and adverse
effects of Federal actions on the health
or environment of minority and lowincome populations to the greatest
extent practicable and permitted by law.
DOT Order 5610.2C (‘‘U.S. Department
of Transportation Actions to Address
Environmental Justice in Minority
Populations and Low-Income
Populations’’) establishes departmental
procedures for effectuating Executive
Order 12898 promoting the principles of
environmental justice through full
consideration of environmental justice
principles throughout planning and
decision-making processes in the
development of programs, policies, and
activities—including PHMSA
rulemaking.
PHMSA has evaluated this NPRM
under DOT Order 5610.2C and
Executive Order 12898 and has
preliminarily determined it will not
cause disproportionately high and
adverse human health and
environmental effects on minority and
low-income populations. The proposed
rule is facially neutral and national in
scope; it is neither directed toward a
particular population, region, or
community, nor is it expected to result
in any adverse environmental or health
impact any particular population,
region, or community. Rather, PHMSA
anticipates the rulemaking will reduce
the safety and environmental risks
associated with losses of integrity on gas
pipeline facilities—particularly gas
distribution pipelines in urban or rural
areas posing higher risks due to their
187 59
PO 00000
FR 7629 (Feb. 16, 1994).
Frm 00050
Fmt 4701
Sfmt 4702
vintage, material, and proximity to
minority and low-income communities
in the vicinity of those pipelines.188
Lastly, as explained in the draft
environmental assessment in the
rulemaking docket, PHMSA anticipates
that the regulatory amendments in this
proposed rule will yield greenhouse gas
emissions reductions, thereby reducing
the risks posed by anthropogenic
climate change to minority and lowincome, populations, underserved and
other disadvantaged communities. This
finding is consistent with the most
recent Environmental Justice Executive
Order 14096—Revitalizing Our Nation’s
Commitment to Environmental Justice
for All, by achieving several goals
including continuing to deepen the
Administration’s whole of government
approach to environmental justice and
to better protect overburden
communities from pollution and
environmental harms.
D. Regulatory Flexibility Act
The Regulatory Flexibility Act, as
amended by the Small Business
Regulatory Flexibility Fairness Act of
1996 (5 U.S.C. 601 et seq.), generally
requires Federal agencies to prepare an
initial regulatory flexibility analysis
(IRFA) for a proposed rule subject to
notice-and-comment rulemaking under
the Administrative Procedure Act. 5
U.S.C. 603(a).189 Executive Order 13272
(‘‘Proper Consideration of Small Entities
in Agency Rulemaking’’) 190 obliges
agencies to establish procedures
promoting compliance with the
Regulatory Flexibility Act; DOT’s
implementing guidance is available on
its website.191
This NPRM was developed in
accordance with Executive Order 13272
and DOT guidance to ensure
compliance with the Regulatory
Flexibility Act and provide appropriate
consideration of the potential impacts of
the rulemaking on small entities.
PHMSA conducted an IRFA, which has
been made available in the docket for
this rulemaking and is summarized
below. A description of the reasons why
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).
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-concerningsmall-entities (last updated May 18. 2012).
E:\FR\FM\07SEP3.SGM
07SEP3
Federal Register / Vol. 88, No. 172 / Thursday, September 7, 2023 / Proposed Rules
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.
ddrumheller on DSK120RN23PROD with PROPOSALS3
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
VerDate Sep<11>2014
20:23 Sep 06, 2023
Jkt 259001
services, and provided a minimum,
average, and maximum annualized cost
estimate for each size category. For
small gas distribution operators with
100,000 or fewer services, PHMSA
calculated annualized estimated
compliance costs that ranged from
$8,051 to $10,528 depending on the cost
scenario and discount rate.192 For gas
transmission and gathering operators,
PHMSA calculated minimum, average,
and maximum annualized estimated
compliance costs that ranged from $44
to $52,029 depending on the cost
scenario, industry type (transmission or
gathering), and discount rate. For small
master meter systems, PHMSA
estimated pre-tax annualized
compliance costs for individual
operators from $4,421 to $4,590,
depending on the discount rate. For
small LPG systems, PHMSA estimated
pre-tax annualized compliance costs for
individual operators from $4,764 to
$4,928, again depending on the discount
rate.
PHMSA then calculated cost-torevenue ratios using the calculated
compliance costs of each small parent
entity. PHMSA estimated that 98
percent of small gas distribution parent
entities will face after-tax compliance
costs of less than 1 percent of revenue
under all evaluated cost scenarios.
PHMSA estimated that 80 to 82 percent
of small gas transmission parent entities
operators will incur after-tax
compliance costs of less than 1 percent
of revenue. Under the maximum cost
scenario, PHMSA estimates that 1
percent of small parent entities will
incur compliance costs above 1 percent
but below 3 percent of revenue. Under
this maximum cost scenario, PHMSA
also estimates that one small parent
entity will incur compliance costs above
3 percent of revenue. However, PHMSA
believes the maximum cost scenario is
unlikely, as it assumes the entirety of
estimated new and replaced lines are
attributable to a single operator.193 For
master meter operators and operators of
small LPGs, PHMSA calculated the
break-even value of annual revenue that
would be required for their calculated
after-tax compliance costs to be 1
percent and 3 percent of revenue. For
master meter operators, PHMSA
estimated that revenue would need to be
$442,122 or less for compliance costs to
be 1 percent of revenue and that
192 See
PRIA Table 45.
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.
193 For
PO 00000
Frm 00051
Fmt 4701
Sfmt 4702
61795
revenue would need to be $147,374 or
less for compliance costs to be 3 percent
of revenue. For operators of small LPGs,
PHMSA estimated that revenue would
need to be $476,357 or less for
compliance costs to be 1 percent of
revenue and that revenue would need to
be $158,786 or less for compliance costs
to be 3 percent of revenue.
Relevant Federal Rules Which May
Duplicate, Overlap or Conflict With the
Proposed Rule
PHMSA did not identify any Federal
rules that may duplicate, overlap, or
conflict with the proposed rule. In
Section 7.6 of the PRIA accompanying
this NPRM, PHMSA provides details on
other Federal regulations that may
impact operators of gas pipelines.
Description and Analysis of Significant
Alternatives to the Proposed Rule
Considered
PHMSA analyzed a number of
alternatives to the NPRM, which are
described in detail in Section 2 of the
PRIA accompanying this NPRM. In
addition to retaining the status quo and
not issuing the proposal, which PHMSA
determined would fail to satisfy PIPES
Act mandates to improve safety and
update PHMSA regulations, PHMSA
also analyzed:
1. Retaining DIMP requirements for
small LPG operators and imposing the
updated DIMP requirements of this
NPRM on those same operators.
2. Extending to all part 192-regulated
pipelines an exception that currently
allows, for distribution mains only,
distribution operator personnel
involved in the same construction task
to inspect each other’s work.
3. An alternative compliance date.
4. Imposing an ICS requirement for
emergency response.
5. Requiring all future construction
projects associated with installations,
modifications, replacements, or system
upgrades on gas distribution pipelines
to have licensed professional engineer
approval and stamping.
6. Requiring gas distribution operators
to develop and follow an MOC process
as outlined in ASME/ANSI B31.8S.
PHMSA did not identify any viable
alternative that could accomplish the
stated objectives of applicable statutes
while further minimizing any
significant economic impact of the
proposed rule on small entities. As
discussed in more detail elsewhere in
this preamble and in Section 2 of the
PRIA for this NPRM, PHMSA
determined that these requirements
could result in reductions in safety
benefits that were not justified by any
potential cost savings (e.g., the proposal
E:\FR\FM\07SEP3.SGM
07SEP3
61796
Federal Register / Vol. 88, No. 172 / Thursday, September 7, 2023 / Proposed Rules
ddrumheller on DSK120RN23PROD with PROPOSALS3
to extend the exception for distribution
mains that allows distribution operator
personnel to inspect each other’s work
on the same construction task to all
part-192 regulated pipelines) or impose
costs on small entities that were not
justified by any increased safety
benefits. PHMSA therefore declined to
propose these alternatives but seeks
comment on them in this proposed rule.
E. Executive Order 13175: Consultation
and Coordination With Indian Tribal
Governments
PHMSA analyzed this proposed rule
in accordance with the principles and
criteria contained in Executive Order
13175 (‘‘Consultation and Coordination
with Indian Tribal Governments’’) 194
and DOT Order 5301.1A (‘‘Department
of Transportation Programs, Policies,
and Procedures Affecting American
Indians, Alaska Natives, and Tribes’’).
Executive Order 13175 requires agencies
to ensure meaningful and timely input
from Tribal government representatives
in the development of rules that
significantly or uniquely affect Tribal
communities by imposing ‘‘substantial
direct compliance costs’’ or ‘‘substantial
direct effects’’ on such communities, or
the relationship or distribution of power
between the Federal Government and
Tribes.
PHMSA assessed the impact of the
proposed rule and does not expect it
will significantly or uniquely affect
Tribal communities or Indian Tribal
governments. The proposed rule’s
regulatory amendments are facially
neutral and will have broad, national
scope. PHMSA, therefore, does not
expect this rule to significantly or
uniquely affect Tribal communities,
impose substantial compliance costs on
Native American Tribal governments, or
mandate Tribal action. And insofar as
PHMSA expects the NPRM will improve
safety and reduce environmental risks
associated with gas distribution
pipelines, PHMSA expects it will not
entail disproportionately high adverse
risks for Tribal communities. Therefore,
PHMSA concludes that the funding and
consultation requirements of Executive
Order 13175 and DOT Order 5301.1A do
not apply to this proposed rule.
While PHMSA is not aware of specific
Tribal-owned business entities that
operate part 192-regulated gas pipelines,
any such business entities could be
subject to direct compliance costs as a
result of this proposed rule. PHMSA
seeks comment on the applicability of
Executive Order 13175 to this proposed
rule and the existence of any Tribalowned business entities operating
194 65
FR 67249 (Nov. 6, 2000).
VerDate Sep<11>2014
20:23 Sep 06, 2023
Jkt 259001
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
PO 00000
Frm 00052
Fmt 4701
Sfmt 4702
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,
E:\FR\FM\07SEP3.SGM
07SEP3
ddrumheller on DSK120RN23PROD with PROPOSALS3
Federal Register / Vol. 88, No. 172 / Thursday, September 7, 2023 / Proposed Rules
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-
VerDate Sep<11>2014
20:23 Sep 06, 2023
Jkt 259001
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.
PO 00000
Frm 00053
Fmt 4701
Sfmt 4702
61797
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.
E:\FR\FM\07SEP3.SGM
07SEP3
ddrumheller on DSK120RN23PROD with PROPOSALS3
61798
Federal Register / Vol. 88, No. 172 / Thursday, September 7, 2023 / Proposed Rules
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
VerDate Sep<11>2014
20:23 Sep 06, 2023
Jkt 259001
to enforce regulatory compliance. This
information collection request requires a
participating State to annually submit a
Gas Pipeline Safety Program
Performance Progress Report and
Hazardous Liquid Pipeline Safety
Program Performance Progress Report to
PHMSA’s Office of Pipeline Safety
(OPS) signifying compliance with the
terms of the certification and to
maintain records detailing a damage
prevention plan for PHMSA inspectors
whenever requested. The purpose of the
collection is to exercise oversight of the
grant program and to ensure that States
are compliant with Federal pipeline
safety regulations. PHMSA is revising
this information collection to include
the reporting of inspection data via the
State Inspection Calculation Tool
(SICT). PHMSA expects 66 State
representatives to submit data
pertaining to the number of safety
inspectors employed in their pipeline
safety programs via the SICT. PHMSA
estimates that, on average, State
representatives will spend 8 hours
annually compiling and submitting
SICT data.
Affected Public: Pipeline operators
applying for State grants.
Annual Reporting Burden:
Total Annual Responses: 183.
Total Annual Burden Hours: 5,001.
Frequency of Collection: Annual.
6. Title: Annual for Gas Distribution
Operators.
OMB Control Number: 2137–0629.
Current Expiration Date: 06/30/2026.
Abstract: This mandatory information
collection request would require
operators of gas distribution pipeline
systems to submit annual report data to
the Office of Pipeline Safety in
accordance with the regulations
stipulated in 49 CFR part 191 by way of
form PHMSA F 7100.1–1. The form is to
be submitted once for each calendar
year. The annual report form collects
data about the pipe material, size, and
age. The form also collects data on leaks
from these systems as well as excavation
damages. PHMSA uses the information
to track the extent of gas distribution
systems and normalize incident and
leak rates.
The Gas Distribution NPRM proposes
to revise the Annual Report for Gas
Distribution Operators, form PHMSA F
7100.1–1, to collect additional
information on gas distribution systems
such as the number and miles of lowpressure service pipelines, including
their overpressure protection methods.
The current approved burden for gas
distribution operators to complete this
report is 20 hours, annually. As a result
of the proposed change, the burden for
completing PHMSA F 7100.1-collection
PO 00000
Frm 00054
Fmt 4701
Sfmt 4702
is being increased by 6 hours annually,
resulting in an overall burden of 26
hours, per annual report, for gas
distribution operators.
Affected Public: Owners and
operators of gas distribution pipelines.
Annual Reporting Burden:
Total Annual Responses: 1,446.
Total Annual Burden Hours: 37,596.
Frequency of Collection: Annually.
Requests for a copy of these
information collections should be
directed to Angela Hill via email at
angela.hill@dot.gov or via telephone
(202) 366–4595.
Comments are invited on:
(a) The need for the proposed
collection of information for the proper
performance of the functions of the
agency, including whether the
information will have practical utility;
(b) The accuracy of the agency’s
estimate of the burden of the revised
collection of information, including the
validity of the methodology and
assumptions used;
(c) Ways to enhance the quality,
utility, and clarity of the information to
be collected;
(d) Ways to minimize the burden of
the collection of information on those
who are to respond, including the use
of appropriate automated, electronic,
mechanical, or other technological
collection techniques; and
(e) Ways the collection of this
information is beneficial or not
beneficial to public safety.
Send comments directly to the Office
of Management and Budget, Office of
Information and Regulatory Affairs,
Attn: Desk Officer for the Department of
Transportation, 725 17th Street NW,
Washington, DC 20503.
G. Unfunded Mandates Reform Act of
1995
The Unfunded Mandates Reform Act
(UMRA, 2 U.S.C. 1501 et seq.) requires
agencies to assess the effects of Federal
regulatory actions on State, local, and
Tribal governments, and the private
sector. For any NPRM or final rule that
includes a Federal mandate that may
result in the expenditure by State, local,
and Tribal governments, in the aggregate
of $100 million or more (in 1996
dollars) in any given year, the agency
must prepare, amongst other things, a
written statement that qualitatively and
quantitatively assesses the costs and
benefits of the Federal mandate.
As explained further in the PRIA,
PHMSA does not expect that the
proposed rule will impose enforceable
duties on State, local, or Tribal
governments or on the private sector of
$100 million or more (in 1996 dollars)
in any one year. A copy of the PRIA is
E:\FR\FM\07SEP3.SGM
07SEP3
Federal Register / Vol. 88, No. 172 / Thursday, September 7, 2023 / Proposed Rules
available for review in the docket.
Therefore, the requirement to prepare a
statement pursuant to UMRA does not
apply.
ddrumheller on DSK120RN23PROD with PROPOSALS3
H. National Environmental Policy Act
The National Environmental Policy
Act of 1969 (NEPA, 42 U.S.C. 4321 et
seq.) requires Federal agencies to
prepare a detailed statement on major
Federal actions significantly affecting
the quality of the human environment.
The Council on Environmental Quality’s
implementing regulations (40 CFR parts
1500–1508) require Federal agencies to
conduct an environmental review
considering (1) the need for the action,
(2) alternatives to the action, (3)
probable environmental impacts of the
action and alternatives, and (4) the
agencies and persons consulted during
the consideration process. DOT Order
5610.1C (‘‘Procedures for Considering
Environmental Impacts’’) establishes
departmental procedures for evaluation
of environmental impacts under NEPA
and its implementing regulations.
PHMSA has completed a draft
environmental assessment and expects
that an environmental impact statement
will not be required for this rulemaking
because it will not have a significant
impact on the human environment. To
the extent that the proposed rule could
impact the environment, PHMSA
expects those impacts will be primarily
beneficial impacts from reducing the
likelihood and consequences of
incidents on gas distribution pipelines
and other part 192-regulated gas
pipelines. A copy of the draft
environmental assessment is available
in the docket. PHMSA invites comment
on the potential environmental impacts
of this proposed rule.
I. Executive Order 13132: Federalism
PHMSA has analyzed this proposed
rule in accordance with the principles
and criteria contained in Executive
Order 13132 (‘‘Federalism’’) 195 and the
Presidential Memorandum titled
‘‘Preemption.’’ 196 Executive Order
13132 requires agencies to ensure
meaningful and timely input by State
and local officials in the development of
regulatory policies that may have
‘‘substantial direct effects on the states,
on the relationship between the national
government and the states, or on the
distribution of power and
responsibilities among the various
levels of government.’’
PHMSA does not expect this
proposed rule will have a substantial
direct effect on State and local
195 64
196 74
FR 43255 (Aug. 10, 1999).
FR 24693 (May 22, 2009).
VerDate Sep<11>2014
20:23 Sep 06, 2023
governments, the relationship between
the Federal Government and the States,
or the distribution of power and
responsibilities among the various
levels of government. The provisions
proposed involving SICT codify in
regulation existing practice and do not
impose any noteworthy additional
direct compliance costs on State and
local governments.
States are generally prohibited by 49
U.S.C. 60104(c) from regulating the
safety of interstate pipelines. States that
have submitted a current certification
under 49 U.S.C. 60105(a) can augment
Federal pipeline safety requirements for
intrastate pipelines regulated by
PHMSA but may not approve safety
requirements less stringent than those
required by Federal law. A State may
also regulate an intrastate pipeline
facility that PHMSA does not regulate.
In this instance, the preemptive effect
of the proposed rule would be limited
to the minimum level necessary to
achieve the objectives of the statutory
authority under which the proposed
rule is promulgated. While the 49 CFR
part 192 safety requirements in this
proposed rule may, if adopted in a final
rule, preempt some State requirements,
preemption arises by operation of 49
U.S.C. 60104, and this proposed rule
would not impose any regulation that
has substantial direct effects on the
states, the relationship between the
national government and the states, or
the distribution of power and
responsibilities among the various
levels of government. Therefore, the
PHMSA has determined that the
consultation and funding requirements
of Executive Order 13132 do not apply
to this proposed rule.
J. Executive Order 13211: Significant
Energy Actions
Executive Order 13211 (‘‘Actions
Concerning Regulations That
Significantly Affect Energy Supply,
Distribution, or Use’’) 197 requires
Federal agencies to prepare a Statement
of Energy Effects for any ‘‘significant
energy action.’’ Executive Order 13211
defines a ‘‘significant energy action’’ as
any action by an agency (normally
published in the Federal Register) that
promulgates or is expected to lead to the
promulgation of a final rule or
regulation that (1)(i) is a significant
regulatory action under Executive Order
12866 or any successor order, and (ii) is
likely to have a significant adverse effect
on the supply, distribution, or use of
energy; or (2) is designated by OIRA as
a significant energy action.
197 66
Jkt 259001
PO 00000
FR 28355 (May 22, 2001).
Frm 00055
Fmt 4701
Sfmt 4702
61799
This proposed rule is not anticipated
to be a ‘‘significant energy action’’ under
Executive Order 13211. It is not likely
to have a significant adverse effect on
the supply, distribution, or use of
energy. Further, the OIRA has not
designated this proposed rule as a
significant energy action.
K. Privacy Act Statement
In accordance with 5 U.S.C. 553(c),
DOT solicits comments from the public
to better inform its rulemaking process.
DOT posts these comments without
edit, including any personal information
the commenter provides, to https://
www.regulations.gov, as described in
the system of records notice (DOT/ALL–
14 FDMS), which can be reviewed at
https://www.dot.gov/privacy.
L. Regulation Identifier Number
A regulation identifier number (RIN)
is assigned to each regulatory action
listed in the Unified Agenda of
Regulatory and Deregulatory Actions
(Unified Agenda). The RIN contained in
the heading of this document can be
used to cross-reference this action with
the Unified Agenda.
M. Executive Order 13609 and
International Trade Analysis
Executive Order 13609 (‘‘Promoting
International Regulatory
Cooperation’’) 198 requires agencies to
consider whether the impacts associated
with significant variations between
domestic and international regulatory
approaches are unnecessary or may
impair the ability of American business
to export and compete internationally.
In meeting shared challenges involving
health, safety, labor, security,
environmental, and other issues,
international regulatory cooperation can
identify approaches that are at least as
protective as those that are or would be
adopted in the absence of such
cooperation. International regulatory
cooperation can also reduce, eliminate,
or prevent unnecessary differences in
regulatory requirements.
Similarly, the Trade Agreements Act
of 1979 (Pub. L. 96–39), as amended by
the Uruguay Round Agreements Act
(Pub. L. 103–465), prohibits Federal
agencies from establishing any
standards or engaging in related
activities that create unnecessary
obstacles to the foreign commerce of the
United States. For purposes of these
requirements, Federal agencies may
participate in the establishment of
international standards so long as the
standards have a legitimate domestic
objective, such as providing for safety,
198 77
E:\FR\FM\07SEP3.SGM
FR 26413 (May 4, 2012).
07SEP3
ddrumheller on DSK120RN23PROD with PROPOSALS3
61800
Federal Register / Vol. 88, No. 172 / Thursday, September 7, 2023 / Proposed Rules
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.
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.
N. Cybersecurity and Executive Order
14028
Executive Order 14028 (‘‘Improving
the Nation’s Cybersecurity’’) 199 directed
the Federal government to improve its
efforts to identify, deter, and respond to
‘‘persistent and increasingly
sophisticated malicious cyber
campaigns.’’ Accordingly, PHMSA has
assessed the effects of this NPRM to
determine what impact the proposed
regulatory amendments may have on
cybersecurity risks for pipeline facilities
and has preliminarily determined that
this NPRM will not materially affect the
cybersecurity risk profile for pipeline
facilities.
Operator DIMPs, O&M manuals and
procedures, and facility design
standards are largely static materials;
because those materials are not means of
manipulating pipeline operations in
real-time, PHMSA’s proposed
amendments of requirements governing
those materials are therefore unlikely to
increase the risk of cybersecurity
incidents. Although other proposals
within the NPRM—in particular, realtime overpressurization monitoring and
customer opt-in/opt-out emergency
communication systems—may offer
more attractive targets for cybersecurity
incidents, PHMSA understands the
incremental additional risk from the
NPRM’s proposed regulatory
amendments to be minimal. Operator
compliance strategies for these proposed
requirements will be subject to current
Transportation Security Agency (TSA)
pipeline cybersecurity directives; 200
PHMSA further understands
Cybersecurity & Infrastructure Security
Agency (CISA) and the Pipeline
Cybersecurity Initiative (PCI) of the U.S.
Department of Homeland Security
conduct ongoing activities to address
cybersecurity risks to U.S. pipeline
infrastructure and may introduce other
cybersecurity requirements and
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.
199 86
FR 26633 (May 17, 2021).
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).
200 E.g.,
VerDate Sep<11>2014
20:23 Sep 06, 2023
Jkt 259001
M. Severability
List of Subjects
§ 191.11
report.
Distribution system: Annual
(a) General. Except as provided in
paragraph (b) of this section, each
operator of a distribution pipeline
system, excluding a liquefied petroleum
gas system that serves fewer than 100
customers from a single source, must
submit an annual report for that system
on DOT Form PHMSA F 7100.1–1. Each
operator of a liquefied petroleum gas
system that serves fewer than 100
customers from a single source must
submit an annual report for that system
on DOT Form PHMSA F 7100.1–2.
Reports must be submitted each year,
not later than March 15, for the
preceding calendar year.
(b) Not required. The annual report
requirement in this section does not
apply to a master meter system, a
petroleum gas system excepted from
part 192 in accordance with
§ 192.1(b)(5), or an individual service
line directly connected to a production
pipeline or a gathering line other than
a regulated gathering line as determined
in § 192.8.
PART 192—TRANSPORTATION OF
NATURAL AND OTHER GAS BY
PIPELINE: MINIMUM FEDERAL
SAFETY STANDARDS
49 CFR Part 191
3. The authority citation for 49 CFR
part 192 continues to read as follows:
Liquefied petroleum gas, Pipeline
reporting requirements.
Authority: 30 U.S.C. 185(w)(3), 49 U.S.C.
5103, 60101 et seq., and 49 CFR 1.97.
49 CFR Part 192
§ 192.3
■
District regulator stations, Emergency
response, Gas monitoring, Integrity
management, Inspections, Gas,
Overpressure protection, Pipeline
safety, Reporting and recordkeeping
requirements.
49 CFR Part 198
State inspector staffing requirements.
For the reasons provided in the
preamble, PHMSA proposes to amend
49 CFR parts 191, 192, and 198 as
follows:
PART 191—TRANSPORTATION OF
NATURAL AND OTHER GAS BY
PIPELINE; ANNUAL, INCIDENT, AND
OTHER REPORTING
1. The authority citation for 49 CFR
part 191 continues to read as follows:
■
Authority: 30 U.S.C. 185(w)(3); 49 U.S.C.
5121, 60101 et seq., and 49 CFR 1.97.
■
2. Revise § 191.11 to read as follows:
201 See, e.g., CISA, National Cyber Awareness
System Alerts, https://www.cisa.gov/uscert/ncas/
alerts (last accessed Feb. 1, 2023).
PO 00000
Frm 00056
Fmt 4701
Sfmt 4702
[Amended]
4. Amend § 192.3, by removing the
last sentence ‘‘This definition does not
apply to any gathering line.’’ from the
definitions of ‘‘Entirely replaced
onshore transmission pipeline
segments’’, ‘‘Notification of potential
rupture’’ and ‘‘Rupture-mitigation valve
(RMV)’’.
■
§ 192.9
[Amended]
5. Amend § 192.9 by:
a. Removing from paragraph (b) the
last sentence;
■ b. Removing from paragraph (c) the
last sentence; and
■ c. Removing from paragraph (e)(1)(iv)
the words ‘‘effective as of October 4,
2022.’’
■ 6. Amend § 192.18 by revising
paragraph (c) to read as follows:
■
■
§ 192.18
How to notify PHMSA.
*
*
*
*
*
(c) Unless otherwise specified, if an
operator submits, pursuant to §§ 192.8,
192.9, 192.13, 192.179, 192.319,
192.506, 192.607, 192.619, 192.624,
192.632, 192.634, 192.636, 192.710,
192.712, 192.714, 192.745, 192.917,
192.921, 192.927, 192.933, 192.937, or
E:\FR\FM\07SEP3.SGM
07SEP3
Federal Register / Vol. 88, No. 172 / Thursday, September 7, 2023 / Proposed Rules
192.1007, a notification for use of a
different integrity assessment method,
analytical method, compliance period,
sampling approach, pipeline material,
or technique (e.g., ‘‘other technology’’ or
‘‘alternative equivalent technology’’)
than otherwise prescribed in those
sections, that notification must be
submitted to PHMSA for review at least
90 days in advance of using the other
method, approach, compliance timeline,
or technique. An operator may proceed
to use the other method, approach,
compliance timeline, or technique 91
days after submitting the notification
unless it receives a letter from the
Associate Administrator for Pipeline
Safety, or his or her delegate, informing
the operator that PHMSA objects to the
proposal or that PHMSA requires
additional time and/or more
information to conduct its review.
■ 7. Amend § 192.195 by adding
paragraph (c) to read as follows:
perform a required inspection if the
operator personnel performed the
construction task requiring inspection.
Nothing in this section prohibits the
operator from inspecting construction
tasks with operator personnel who are
involved in other construction tasks.
(b) For the construction inspection of
a main that is new, replaced, relocated,
or otherwise changed after [ONE YEAR
AFTER THE PUBLICATION DATE OF
THE RULE], operator personnel
involved in the same construction task
may inspect each other’s work in
situations where the operator could
otherwise only comply with the
construction inspection requirement in
paragraph (a) of this section by using a
third-party inspector. This justification
must be documented and retained for
the life of the pipeline.
■ 9. Amend § 192.517 by revising
paragraph (b) to read as follows:
§ 192.195 Protection against accidental
overpressuring.
*
*
*
*
*
(c) Additional requirements for lowpressure distribution systems. Each
regulator station, serving a low-pressure
distribution system, that is new,
replaced, relocated, or otherwise
changed after [ONE YEAR AFTER THE
PUBLICATION DATE OF THE RULE]
must include:
(1) At least two methods of
overpressure protection (such as a relief
valve, monitoring regulator, or
automatic shutoff valve) appropriate for
the configuration and siting of the
station;
(2) Measures to minimize the risk of
overpressurization of the low-pressure
distribution system that could be caused
by any single event (such as excavation
damage, natural forces, equipment
failure, or incorrect operations), that
either immediately or over time affects
the safe operation of more than one
overpressure protection device; and
(3) Remote monitoring of gas pressure
at or near the location of overpressure
protection devices.
■ 8. Amend § 192.305 by:
■ a. Lifting the stay of the section; and
■ b. Revising the section.
The revision reads as follows:
ddrumheller on DSK120RN23PROD with PROPOSALS3
*
§ 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
VerDate Sep<11>2014
20:23 Sep 06, 2023
Jkt 259001
§ 192.517
Records.
*
*
*
*
(b) Each operator must maintain a
record of each test required by
§§ 192.509, 192.511, and 192.513 for the
life of the pipeline.
(1) For tests performed before [ONE
YEAR AFTER THE PUBLICATION
DATE OF THE FINAL RULE] for which
records are maintained, the record must
continue to be maintained for the life of
the pipeline.
(2) For tests performed on or after
[ONE YEAR AFTER THE
PUBLICATION DATE OF THE FINAL
RULE], the records must contain at least
the following information:
(i) The operator’s name, the name of
the employee responsible for making the
test, and the name of the company or
contractor used to perform the test.
(ii) Pipeline segment pressure tested.
(iii) Test date.
(iv) Test medium used.
(v) Test pressure.
(vi) Test duration.
(vii) Leaks and failures noted and
their disposition.
■ 10. Amend § 192.605 by adding
paragraphs (b)(13), (f), and (g) to read as
follows:
§ 192.605 Procedural manual for
operations, maintenance, and emergencies.
*
*
*
*
*
(b) * * *
(13) Implementing the applicable
requirements for distribution systems in
paragraphs (f) and (g) of this section,
§ 192.638, and § 192.640.
*
*
*
*
*
(f) Overpressurization. For
distribution lines, the manual required
by paragraph (a) of this section must, no
later than [ONE YEAR AFTER THE
PO 00000
Frm 00057
Fmt 4701
Sfmt 4702
61801
PUBLICATION DATE OF THE RULE],
include procedures for responding to,
investigating, and correcting, as soon as
practicable, the cause of
overpressurization indications. The
procedures must include the specific
actions and an order of operations for
immediately reducing pressure in or
shutting down portions of the
distribution system affected by an
overpressurization.
(g) Management of Change (MOC)
Process. For distribution lines, the
manual required by paragraph (a) of this
section must, no later than [ONE YEAR
AFTER THE PUBLICATION DATE OF
THE RULE], include a detailed MOC
process for the following:
(1) Technology, equipment,
procedural, and organizational changes,
including:
(i) Installations, modifications,
replacements, or upgrades to regulators,
pressure monitoring locations, or
overpressure protection devices;
(ii) Modifications to alarm set points
or upper/lower trigger limits on
monitoring equipment;
(iii) The introduction of new
technologies for overpressure protection
into the system;
(iv) Revisions, changes, or the
introduction of new standard operating
procedures for design, construction,
installation, maintenance, and
emergency response;
(v) Other changes that may impact the
integrity or safety of the gas distribution
system.
(2) Ensuring that personnel—such as
an engineer with a professional engineer
license, a subject matter expert, or
another person who possesses the
necessary knowledge, experience, and
skills regarding gas distribution
systems—review and certify
construction plans associated with
installations, modifications,
replacements, or system upgrades for
accuracy and completeness before the
work begins. These personnel must be
qualified to perform these tasks under
subpart N of this part.
(3) Ensuring that any hazards
introduced by a change are identified,
analyzed, and controlled before
resuming operations.
■ 11. Amend § 192.615 by:
■ a. Adding paragraphs (a)(3)(v) through
(viii);
■ b. Revising paragraph (a)(8); and
■ c. Adding paragraphs (a)(13) and
paragraph (d).
The additions and revision read as
follows:
§ 192.615
Emergency plans.
(a) * * *
(3) * * *
E:\FR\FM\07SEP3.SGM
07SEP3
ddrumheller on DSK120RN23PROD with PROPOSALS3
61802
Federal Register / Vol. 88, No. 172 / Thursday, September 7, 2023 / Proposed Rules
(v) Notification of potential rupture
(see § 192.635).
(vi) Beginning no later than [ONE
YEAR AFTER THE PUBLICATION
DATE OF THE FINAL RULE], release of
gas that results in one or more fatalities.
(vii) Beginning no later than [ONE
YEAR AFTER THE PUBLICATION
DATE OF THE FINAL RULE], for
distribution line operators only,
unintentional release of gas and
shutdown of gas service to 50 or more
customers or, if the operator has fewer
than 100 customers, 50 percent or more
of its total customers.
(viii) Beginning no later than [ONE
YEAR AFTER THE PUBLICATION
DATE OF THE FINAL RULE], any other
emergency deemed significant by the
operator.
*
*
*
*
*
(8) Notifying the appropriate public
safety answering point (i.e., 9–1–1
emergency call center) where direct
access to a 9–1–1 emergency call center
is available from the location of the
pipeline, and fire, police, and other
public officials, of gas pipeline
emergencies to coordinate and share
information to determine the location of
the emergency, including both planned
responses and actual responses during
an emergency. The operator must
immediately and directly notify the
appropriate public safety answering
point or other coordinating agency for
the communities and jurisdictions in
which the pipeline is located after
receiving notice of a gas pipeline
emergency under paragraph (a)(3) of this
section. The operator must coordinate
and share information to determine the
location of any release, regardless of
whether the segment is subject to the
requirements of §§ 192.179, 192.634, or
192.636.
*
*
*
*
*
(13) For distribution line operators,
beginning no later than [ONE YEAR
AFTER THE PUBLICATION DATE OF
THE FINAL RULE], establishing and
maintaining communication with the
general public in the operator’s service
area as soon as practicable during a gas
pipeline emergency on a distribution
line. The communication(s) must be in
English, and any other languages
commonly understood by a significant
number and concentration of the nonEnglish speaking population in the
operator’s service area; be in one or
more formats or media accessible to the
population in the operator’s service
area; continue through service
restoration and recovery efforts; and
provide the following:
(i) Information regarding the gas
pipeline emergency;
VerDate Sep<11>2014
20:23 Sep 06, 2023
Jkt 259001
(ii) The status of the emergency (e.g.,
have the condition causing the
emergency or the resulting public safety
risks been resolved);
(iii) Status of pipeline operations
affected by the gas pipeline emergency,
and when possible, a timeline for
expected service restoration; and
(iv) Directions for the public to
receive assistance.
The operator must provide updates
when the information in
§ 192.615(a)(13)(i) through (iv) changes.
*
*
*
*
*
(d) No later than [DATE 18 MONTHS
AFTER THE PUBLICATION DATE OF
THE RULE], each distribution line
operator must develop and implement a
system, including written procedures,
that allows operators to rapidly
communicate with customers in the
event of a gas pipeline emergency under
this section. The notification system
must be voluntary for the public,
allowing customers to opt-in (or opt-out)
to receiving notifications from the
system. The written procedures must
provide for the following:
(i) A description of the notification
system and how it will be used to notify
customers of a gas pipeline emergency;
(ii) Who is responsible for the
development, operation, and
maintenance of the system;
(iii) How information on the system is
delivered to customers, ensuring that all
customers are notified of the existence
of the system and necessary steps if they
wish to opt-in (or opt-out);
(iv) Description of the system-wide
testing protocol, including the testing
interval (which must not be less than
once per calendar year), to ensure the
system is functioning properly and
performing notifications as designed;
(v) Maintenance of the results of
testing and operations history for at
least 5 years;
(vi) Details regarding how the
operator ensures messages are accessible
in other languages commonly
understood by a significant number and
concentration of the non-English
speaking population in the operator’s
area;
(vii) Message content, including
updates as emergency conditions
change;
(viii) A process to initiate, conduct,
and complete notifications; and
(ix) Cybersecurity measures to protect
the system and customer information.
■ 12. Add § 192.638 to read as follows:
§ 192.638 Distribution lines: Records for
pressure controls.
(a) An operator of a distribution
system, except those identified in
paragraph (f) of this section, must, no
PO 00000
Frm 00058
Fmt 4701
Sfmt 4702
later than [ONE YEAR AFTER THE
PUBLICATION DATE OF THE RULE],
identify and maintain traceable,
verifiable, and complete records that
document the characteristics of its
pipeline system that are critical to
ensuring proper pressure control. These
records must include:
(1) Current location information
(including maps and schematics) for
regulators, valves, and underground
piping (including control lines);
(2) Attributes of the regulator(s), such
as set points, design capacity, and the
valve failure position (open/closed);
(3) The overpressure protection
configuration; and
(4) Other records deemed critical.
(b) If an operator does not have
traceable, verifiable, and complete
records as required by paragraph (a) of
this section, the operator must, no later
than [ONE YEAR AFTER THE
PUBLICATION DATE OF THE RULE],
identify and document those records
needed and develop and implement
procedures for collecting those records.
(c) The records identified in
paragraph (a) of this section must be
collected, generated, or updated on an
opportunistic basis, as specified in
§ 192.1007(a)(3).
(d) An operator must ensure the
records required by this section are
accessible to all personnel responsible
for performing or supervising design,
construction, operations, and
maintenance activities.
(e) An operator must retain the
records required in this section for the
life of the pipeline.
(f) Exception. This section does not
apply to master meter systems, liquefied
petroleum gas (LPG) distribution
pipeline systems that serve fewer than
100 customers from a single source, or
any individual service line directly
connected to a transmission, gathering,
or production pipeline that is not
operated as part of a distribution
system.
■ 13. Add § 192.640 to read as follows:
§ 192.640 Distribution lines: Presence of
qualified personnel.
(a) An operator of a distribution
system must conduct a documented
evaluation of each construction project
that begins after [ONE YEAR AFTER
THE PUBLICATION DATE OF THE
RULE] to identify any potential project
activities during which an
overpressurization could occur at a
district regulator station. This
evaluation must occur before such
activities begin. Activities that may
present a potential for
overpressurization include, but are not
limited to, tie-ins, abandonment of
E:\FR\FM\07SEP3.SGM
07SEP3
Federal Register / Vol. 88, No. 172 / Thursday, September 7, 2023 / Proposed Rules
distribution lines, and equipment
replacement.
(b) If the evaluation in paragraph (a)
of this section results in a determination
that a potential for overpressurization
exists during construction project
activity, the operator must:
(1) Ensure that at least one person
qualified according to subpart N of this
part is present at that district regulator
station, or at an alternative site, during
the construction project activity that
could cause an overpressurization;
(2) Monitor gas pressure with
equipment capable of ensuring proper
pressure controls; and
(3) Have the capability to promptly
shut off the flow of gas or control
overpressurization at a district regulator
station.
(c) When monitoring the system as
described in this section, the qualified
personnel must be provided, at a
minimum: information regarding the
location of all valves necessary for
isolating the pipeline system; pressure
control records (see § 192.638); the
authority to stop work (unless
prohibited by operator procedures);
operations procedures under § 192.605;
and emergency response procedures
under § 192.615.
(d) Exception. Distribution systems
with a remote monitoring system in
effect with the capability for remote or
automatic shutoff need not comply with
the requirements in paragraphs (a)
through (c) of this section.
■ 14. Amend § 192.725 by revising
paragraph (a) to read as follows:
§ 192.725 Test requirements for reinstating
service lines.
ddrumheller on DSK120RN23PROD with PROPOSALS3
(a) Except as provided in paragraph
(b) of this section, each disconnected
service line being restored to service on
or after [ONE YEAR AFTER THE
PUBLICATION DATE OF THE RULE]
must be tested in the same manner as a
new service line (i.e., tested in
accordance with subpart J of this part)
before being restored to service.
*
*
*
*
*
■ 15. Amend § 192.741 by:
■ a. Revising the title of the section, and
■ b. Adding paragraph (d).
The revision and addition read as
follows:
§ 192.741 Pressure limiting and regulating
stations: Telemetering, recording gauges,
and other monitoring devices.
*
*
*
*
*
(d) On low-pressure distribution
systems that are new, replaced,
relocated, or otherwise changed after
[ONE YEAR AFTER THE
PUBLICATION DATE OF THE RULE],
the operator must monitor the gas
VerDate Sep<11>2014
20:23 Sep 06, 2023
Jkt 259001
pressure in accordance with
§ 192.195(c)(3).
§ 192.1001
[AMENDED]
16. Amend § 192.1001 by removing
the definition of ‘‘Small LPG Operator.’’
■ 17. Amend § 192.1003 by adding
paragraph (b)(4) to read as follows:
■
§ 192.1003 What do the regulations in this
subpart cover?
*
*
*
*
*
(b) * * *
(4) A system of a liquefied petroleum
gas (LPG) distribution pipeline that
serves fewer than 100 customers from a
single source.
■ 18. Amend § 192.1005 by revising the
title of the section to read as follows:
§ 192.1005 What must a gas distribution
operator do to implement this subpart?
19. Amend § 192.1007 by revising
paragraphs (a)(3), (b), (c), and (d) to read
as follows:
■
§ 192.1007 What are the required elements
of an integrity management plan?
*
*
*
*
*
(a) * * *
(3) Identify additional information
needed and provide a plan for obtaining
that information over time (including
the records specified in § 192.638(c))
through normal activities conducted on
the pipeline (for example, design,
construction, operations, or
maintenance activities).
*
*
*
*
*
(b) Identify threats. The operator must
consider the following categories of
threats to each gas distribution pipeline:
corrosion (including atmospheric
corrosion); natural forces (including
extreme weather, land movement, and
other geological hazards); excavation
damage; other outside force damage;
material (including the presence and age
of pipes such as cast iron, bare steel,
unprotected steel, wrought iron, and
historic plastics with known issues) or
welds; equipment failure; incorrect
operations; overpressurization of lowpressure distribution systems; and other
threats that pose a risk to the integrity
of a pipeline. An operator must also
consider the age of the system, pipe, and
components in identifying threats. An
operator must consider reasonably
available information to identify
existing and potential threats. Sources
of data may include, but are not limited
to, incident and leak history, corrosion
control records (including atmospheric
corrosion records), continuing
surveillance records, patrolling records,
maintenance history, and excavation
damage experience.
(c) Evaluate and rank risk.
PO 00000
Frm 00059
Fmt 4701
Sfmt 4702
61803
(1) General. An operator must
evaluate the risks associated with its
distribution pipeline. In this evaluation,
the operator must determine the relative
importance of each threat and estimate
and rank the risks posed to its pipeline.
This evaluation must consider each
applicable current and potential threat,
the likelihood of failure associated with
each threat, and the potential
consequences of such a failure. An
operator may subdivide its pipeline into
regions with similar characteristics (e.g.,
contiguous areas within a distribution
pipeline consisting of mains, services
and other appurtenances, areas with
common materials, age, or
environmental factors), and for which
similar actions likely would be effective
in reducing risk.
(2) Certain pipe with known issues.
An operator must, no later than [ONE
YEAR AFTER THE PUBLICATION
DATE OF THE RULE], evaluate the risks
in the distribution system resulting from
pipelines with known issues based on
the material (including, cast iron, bare
steel, unprotected steel, wrought iron,
and historic plastics with known
issues), design, age, or past operating
and maintenance history.
(3) Low-pressure Distribution Systems.
An operator must, no later than [ONE
YEAR AFTER THE PUBLICATION
DATE OF THE RULE], evaluate the risks
that could lead to or result from the
operation of a low-pressure distribution
system at a pressure that makes the
operation of any connected and
properly adjusted low-pressure gas
burning equipment unsafe. In the
evaluation of risks, an operator must:
(i) Evaluate factors other than past
observed abnormal operating conditions
(as defined in § 192.803) in ranking
risks, including any known industry
threats, risks, or hazards to public safety
that could occur on its system based on
knowledge gained from available
sources;
(ii) Evaluate potential consequences
associated with low-probability events
unless a determination, supported and
documented by an engineering analysis,
or an equivalent analysis incorporating
operational knowledge, demonstrates
that the event results in no potential
consequences and therefore no potential
risk. An operator must notify PHMSA
and State or local pipeline safety
authorities, as applicable, in accordance
with § 192.18 within 30 days of making
such a determination. The notification
must include the following:
(A) Date the determination was made;
(B) Description of the low-probability
event being considered;
(C) Logic supporting the
determination, including information
E:\FR\FM\07SEP3.SGM
07SEP3
61804
Federal Register / Vol. 88, No. 172 / Thursday, September 7, 2023 / Proposed Rules
ddrumheller on DSK120RN23PROD with PROPOSALS3
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
VerDate Sep<11>2014
20:23 Sep 06, 2023
Jkt 259001
Distribution Systems. An operator must,
no later than [ONE YEAR AFTER THE
PUBLICATION DATE OF THE RULE],
implement the following preventive and
mitigative measures to minimize the
risk of overpressurization of a lowpressure distribution system that could
be the result of any single event or
failure:
(i) Identify, maintain, and obtain, if
necessary, pressure control records in
accordance with §§ 192.638 and
192.1007(a)(3).
(ii) Confirm and document that each
district regulator station meets the
requirements of § 192.195(c)(1) through
(3). If an operator determines that a
district regulator station does not meet
the requirements of § 192.195(c)(1)
through (3), then by [ONE YEAR AFTER
THE PUBLICATION DATE OF THE
RULE], the operator must take either of
the following actions:
(A) Upgrade the district regulator
station to meet the requirements of
§ 192.195(c)(1) through (3), or
(B) Identify alternative preventive and
mitigative measures based on the
unique characteristics of its system to
minimize the risk of overpressurization
of a low-pressure distribution system.
The operator must notify PHMSA and
State or local pipeline safety authorities,
as applicable, no later than 90 days in
advance of implementing any
alternative measures. The notification
must be made in accordance with
§ 192.18(c) and must include a
description of proposed alternative
measures, identification and location of
facilities to which the measures would
be applied, and a description of how the
measures would ensure the safety of the
public, affected facilities, and
environment.
*
*
*
*
*
PART 198—REGULATIONS FOR
GRANTS TO AID STATE PIPELINE
SAFETY PROGRAMS
§ 192.1015
[FR Doc. 2023–18585 Filed 9–6–23; 8:45 am]
■
[Removed]
20. Remove § 192.1015.
PO 00000
Frm 00060
Fmt 4701
Sfmt 9990
21. The authority citation for part 198
continues to read as follows:
■
Authority: 49 U.S.C. 60101 et seq.; 49 CFR
1.97.
22. Amend § 198.3 by adding the
definitions for ‘‘Inspection person-day’’
and ‘‘State Inspection Calculation Tool
(SICT)’’ in alphabetical order to read as
follows:
■
§ 198.3
Definitions.
*
*
*
*
*
Inspection person-day means all or
part of a day, including travel, spent by
State agency personnel in on-site or
virtual evaluation of a pipeline system
to determine compliance with Federal
or State pipeline safety regulations.
*
*
*
*
*
State Inspection Calculation Tool
(SICT) means a tool used to determine
the required number of annual
inspection person-days for a State
agency.
*
*
*
*
*
■ 23. Amend § 198.13 by revising
paragraph (c)(6) to read as follows:
§ 198.13
Grant-allocation formula.
*
*
*
*
*
(c) * * *
(6) Number of state inspection persondays, as determined by the SICT and
other factors;
*
*
*
*
*
Issued in Washington, DC, on August 23,
2023, under authority delegated in 49 CFR
1.97.
Alan K. Mayberry,
Associate Administrator for Pipeline Safety.
BILLING CODE 4910–60–P
E:\FR\FM\07SEP3.SGM
07SEP3
]]>Agencies
[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
-----------------------------------------------------------------------
Pipeline and Hazardous Materials Safety Administration
-----------------------------------------------------------------------
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]]
-----------------------------------------------------------------------
DEPARTMENT OF TRANSPORTATION
Pipeline and Hazardous Materials Safety Administration
49 CFR Parts 191, 192, and 198
[Docket No. PHMSA-2021-0046]
RIN 2137-AF53
Pipeline Safety: Safety of Gas Distribution Pipelines and Other
Pipeline Safety Initiatives
AGENCY: Pipeline and Hazardous Materials Safety Administration (PHMSA),
Department of Transportation (DOT).
ACTION: Notice of proposed rulemaking (NPRM).
-----------------------------------------------------------------------
SUMMARY: PHMSA proposes revisions to the pipeline safety regulations to
require operators of gas distribution pipelines to update their
distribution integrity management programs (DIMP), emergency response
plans, operations and maintenance manuals, and other safety practices.
These proposals implement provisions of the Leonel Rondon Pipeline
Safety Act--part of the Protecting our Infrastructure of Pipelines and
Enhancing Safety Act of 2020--and a National Transportation Safety
Board (NTSB) recommendation directed toward preventing catastrophic
incidents resulting from overpressurization of low-pressure gas
distribution systems similar to that which occurred on a gas
distribution pipeline system in Merrimack Valley on September 13, 2018.
PHMSA also proposes to codify use of its State Inspection Calculation
Tool, which is used to help states determine the base-level amount of
time needed for inspections to maintain an adequate pipeline safety
program. Further, PHMSA proposes other pipeline safety initiatives for
all part 192-regulated pipelines, including gas transmission and
gathering pipelines, such as updating emergency response plans and
inspection requirements. Finally, PHMSA proposes to apply annual
reporting requirements to small, liquefied petroleum gas (LPG)
operators in lieu of DIMP requirements.
DATES: Individuals interested in submitting written comments on this
NPRM must do so by November 6, 2023.
ADDRESSES: Comments should reference Docket No. PHMSA-2021-0046 and may
be submitted in any of the following ways:
E-Gov Web: https://www.regulations.gov. This site allows the public
to enter comments on any Federal Register notice issued by any agency.
Follow the online instructions for submitting comments.
Mail: Docket Management System: U.S. Department of Transportation,
1200 New Jersey Avenue SE, West Building Ground Floor, Room W12-140,
Washington, DC 20590-0001.
Hand Delivery: DOT Docket Management System: West Building Ground
Floor, Room W12-140, 1200 New Jersey Avenue SE, between 9:00 a.m. and
5:00 p.m. ET, Monday-Friday, except Federal holidays.
Fax: 202-493-2251
Instructions: Include the agency name and identify Docket No.
PHMSA-2021-0046 at the beginning of your comments. Note that all
comments received will be posted without change to https://www.regulations.gov including any personal information provided. If you
submit your comments by mail, submit two copies. If you wish to receive
confirmation that PHMSA received your comments, include a self-
addressed stamped postcard.
Confidential Business Information: Confidential Business
Information (CBI) is commercial or financial information that is both
customarily and actually treated as private by its owner. Under the
Freedom of Information Act (5 U.S.C. 552), CBI is exempt from public
disclosure. If your comments in response to this NPRM contain
commercial or financial information that is customarily treated as
private, that you actually treat as private, and that is relevant or
responsive to this NPRM, it is important that you clearly designate the
submitted comments as CBI. Pursuant to 49 Code of Federal Regulations
(CFR) 190.343, you may ask PHMSA to provide confidential treatment to
the information you give to the agency by taking the following steps:
(1) mark each page of the original document submission containing CBI
as ``Confidential;'' (2) send PHMSA a copy of the original document
with the CBI deleted along with the original, unaltered document; and
(3) explain why the information you are submitting is CBI. Submissions
containing CBI should be sent to Ashlin Bollacker, 1200 New Jersey
Avenue SE, DOT: PHMSA-PHP-30, Washington, DC 20590-0001. Any comment
PHMSA receives that is not explicitly designated as CBI will be placed
in the public docket.
Docket: To access the docket, which contains background documents
and any comments that PHMSA has received, go to https://www.regulations.gov. Follow the online instructions for accessing the
docket. Alternatively, you may review the documents in person at DOT's
Docket Management Office at the address listed above.
FOR FURTHER INFORMATION CONTACT: Ashlin Bollacker by phone at 202-680-
8303 or by email at [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.
---------------------------------------------------------------------------
\1\ Part 192--regulated pipelines refers to gas distribution,
transmission, and gathering pipelines, as applicable.
---------------------------------------------------------------------------
A catalyst for this rulemaking is the 2018 Merrimack Valley
incident. The NTSB investigated the cause of this incident and issued a
full report on its findings and safety recommendations.\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.
---------------------------------------------------------------------------
\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.
---------------------------------------------------------------------------
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.
---------------------------------------------------------------------------
\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).
---------------------------------------------------------------------------
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.
---------------------------------------------------------------------------
\5\ The SICT can be accessed on the PHMSA Portal by authorized
users.
---------------------------------------------------------------------------
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\
---------------------------------------------------------------------------
\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).
---------------------------------------------------------------------------
PHMSA also proposes an exception from this provision's inspection
requirements for small gas distribution pipeline operators who would
not be able to comply with the construction inspection requirement
without using a third-party inspector. These regulatory amendments
would, beginning one year after the publication of any final rule
issued in this proceeding, apply to all other gas distribution
pipelines operators; all gas transmission, all offshore gas gathering,
and Type A gas gathering pipelines, and certain Types B and C gathering
pipelines (specifically, those that are new, replaced, relocated, or
otherwise changed).
9. Test Records--Clarification for Tests on Gas Distribution
Systems--Sec. Sec. 192.517 and 192.725. PHMSA proposes to amend Sec.
192.517 to specifically identify the information that operators must
record for tests performed on new, replaced, or relocated gas
distribution pipelines and to ensure such records are available to
operator personnel throughout the life of the pipeline. PHMSA proposes
to amend Sec. 192.725 to clarify that each disconnected service line
must be tested in the same manner as a new, replaced, or relocated
service line--that is, tested in accordance with 49 CFR part 192,
subpart J--before being reinstated. PHMSA proposes to require that gas
distribution operators comply with these amended testing recordkeeping
requirements in connection with gas distribution pipelines that are
new, replaced, or relocated beginning one year after the publication of
any final rule in this proceeding.
10. Annual Reporting--Sec. 191.11. PHMSA proposes to add or expand
annual reporting requirements for operators of gas distribution
pipeline systems, including small LPG operators. For gas distribution
pipelines, PHMSA proposes to collect additional information, such as
the number and miles of low-pressure service lines, including their
overpressure protection methods. For small LPG operators, these annual
reports will collect information on the number and miles of service
lines, and the disposition of any leaks. These proposed amendments will
not apply to master meter systems, petroleum gas systems excepted from
49 CFR part 192 in accordance with Sec. 192.1(b)(5), or individual
service lines directly connected to production pipelines or gathering
pipelines, other than a regulated gathering pipeline, as determined in
Sec. 192.8. PHMSA proposes that operators would need to comply with
the above changes to annual reporting requirements beginning with the
first annual reporting cycle after the effective date of any final rule
issued in this proceeding.
11. Miscellaneous Amendments Pertaining to Part 192--Regulated Gas
Gathering Pipelines--Sec. Sec. 192.3 and 192.9. Following a decision
by the U.S. Court of Appeals for the District of Columbia Circuit in
litigation challenging application of requirements of PHMSA's April
2022 Valve Rule to gas and hazardous liquid gathering pipelines,\7\
PHMSA issued a technical correction to the April 2022 Valve Rule
codifying that decision.\8\ PHMSA now proposes removal of certain
exceptions introduced in the Technical Correction to restore, with
respect to certain part 192-regulated gas gathering pipelines,
application of specific regulatory amendments from the Valve Rule
pertaining certain definitions (Sec. 192.3) as well as--by way of
removal of exceptions within the regulatory cross-references at Sec.
192.9--emergency planning and response (Sec. 192.615) and protocols
for notifications of potential ruptures (Sec. 192.635).
---------------------------------------------------------------------------
\7\ GPA Midstream Ass'n v. Dep't of Transp., 67 F.4th 1188 (D.C.
Cir. 2023).
\8\ ``Pipeline Safety: Requirement of Valve Installation and
Minimum Rupture Detection Standards: Technical Corrections,'' 88 FR
50056 (Aug. 1, 2023).
---------------------------------------------------------------------------
C. Costs and Benefits
Consistent with 49 U.S.C. 60102(b) and Executive Order 12866
``Regulatory Planning and Review,'' as amended by Executive Order 14094
``Modernizing Regulatory Review'', PHMSA has prepared an assessment of
the benefits and costs of the proposed rule as well as reasonable
alternatives.\9\ PHMSA expects that the rulemaking will yield
significant public safety benefits associated with reduced frequency
and severity of incidents similar to that which occurred in 2018 in
Merrimack Valley, which resulted in a number of adverse consequences
described in Section I.A. of this NPRM, as well as approximately $1.7
billion in property damage, lost gas, claims, other mitigation costs,
and the social cost of methane emissions. PHMSA also expects that the
proposed rule will yield other, unquantified benefits, which include
improvements in risk reduction for pipeline leaks and incidents;
reduced consequences from all incidents and emergencies; improved
enforcement and oversight procedures; advanced safety measures and
communications; avoided emissions; improved public confidence in the
safety of gas pipeline systems; and associated environmental
enhancements for populations, including those in historically
disadvantaged areas. Cost savings reflect the removal of some
requirements for small LPG operators. The costs of the proposed rule
are attributed to new requirements and
[[Page 61751]]
updates to operators' DIMPs, emergency response plans, operations and
maintenance procedures, monitoring and inspection protocols, and other
reporting and record-keeping proposals. The provisions include a range
of proposals for primarily gas distribution operators, along with some
proposals for other gathering and transmission operators.
---------------------------------------------------------------------------
\9\ 88 FR 21879 (Apr. 6, 2023); 58 FR 51735 (Oct. 4, 1993).
---------------------------------------------------------------------------
PHMSA estimates the annualized costs of the proposed rule to be
approximately $110 million per year at a 3 percent discount rate. In
Table ES-1, below, PHMSA provides a summary of the estimated costs for
the major provisions in this rulemaking and the total cost. For the
full cost/benefit analysis and additional details on the summaries,
please see the preliminary regulatory impact analysis (PRIA) in Docket
No. PHMSA-2021-0046.
Table ES-1--Total Annualized Costs
[Millions, 2020$]
------------------------------------------------------------------------
3% 7%
Proposed rule requirement discount discount
rate rate
------------------------------------------------------------------------
DIMP.............................................. $3.2 $4.3
Small LPG DIMP.................................... -0.3 -0.3
SICT.............................................. 0.0 0.0
Emergency response................................ 1.0 1.2
O&M............................................... 42.8 44.7
Recordkeeping..................................... 24.3 27.8
Qualified personnel............................... 34.8 34.8
District regulator stations....................... 1.2 1.6
Inspections....................................... 0.04 0.05
Records: Tests.................................... 0.6 0.6
Annual Reporting.................................. 2.3 2.3
---------------------
Total......................................... 110.0 117.1
------------------------------------------------------------------------
Note: Costs annualized over 20 years.
Source: PHMSA analysis of gas distribution, transmission, and gathering
operators, 2022.
PHMSA expects that each of the elements of the rulemaking, as
proposed in this NPRM, will be technically feasible, reasonable, cost-
effective, and practicable for the reasons stated in this NPRM and its
supporting documents (including the PRIA and draft Environmental
Assessment, each available in the docket for this rulemaking), and
because the commercial, public safety and environmental benefits of
those proposed regulatory amendments as described therein (reduced
frequency and severity of incidents similar to the 2018 Merrimack
Valley incident which bore an approximate cost of $1.7 billion in
2020$), would outweigh any associated costs and support PHMSA's
proposed rule compared to alternatives.
II. Background
A. Gas Distribution Systems Overview
More than 2.3 million miles of gas distribution pipelines deliver
gas to communities and businesses across the United States.\10\ Gas
distribution systems are made up of pipelines called ``mains,'' which
distribute the gas within the system, and much smaller lines called
``service lines,'' which distribute gas to individual customers.
Because the purpose of distribution pipelines is to deliver gas to
customers, distribution pipeline systems are located predominantly in
urban and suburban areas. Distribution pipelines are generally smaller
in diameter than transmission pipelines and operate at lower pressures.
---------------------------------------------------------------------------
\10\ PHMSA, ``Annual Report Mileage for Gas Distribution
Systems'' (June 1, 2022), https://www.phmsa.dot.gov/data-and-statistics/pipeline/annual-report-mileage-gas-distribution-systems.
---------------------------------------------------------------------------
Risk to the public from gas distribution pipelines result from the
potential for unintentional releases of the gas transported through the
pipelines. Due to their proximity to populations, releases from
distribution pipelines bear a particular risk to surrounding
populations, communities, property, and the environment, and may result
in death, injuries, and property damage.\11\ Even small releases of
natural gas can result in environmental harm, as methane (the primary
constituent of natural gas) is a significant contributor to the climate
crisis, with more than 25 times the impact on an equivalent basis as
carbon dioxide.\12\ While the overall trend in pipeline safety has
steadily improved over the past two decades, gas distribution pipelines
are still involved in a majority of serious gas pipeline incidents.\13\
According to PHMSA's data, between 2003 and 2022, excavation damage was
the leading cause of serious incidents along gas distribution pipelines
(28 percent), followed by other outside force damage (23 percent) and
incorrect operation (14 percent).\14\
---------------------------------------------------------------------------
\11\ This gas, regulated under 49 CFR parts 191 and 192, can be
natural gas and any ``flammable gas, or gas which is toxic or
corrosive.'' See Sec. Sec. 191.3 and 192.3 (definitions of
``gas''). By way of example, in addition to natural gas, PHMSA
regulates as a ``flammable gas'' over 1,500 miles of hydrogen gas
pipelines. See PHMSA Interpretation Response Letter No. PI-92-030
(July 14, 1992) (noting PHMSA regulates hydrogen pipelines under 49
CFR part 192); PHMSA, ``Presentation of Vincent Holohan for
Workgroup#4: Hydrogen Network Components at December 2021 Meeting''
at slide 11 (Dec. 1, 2021), https://primis.phmsa.dot.gov/meetings/FilGet.mtg?fil=1227. PHMSA consequently understands the proposed
revisions to 49 CFR parts 191 and 192 within this NPRM would apply
not only to natural gas pipelines but also to other gas pipeline
governed by 49 CFR parts 191 and 192.
\12\ U.S. Envtl. Prot. Agency, Global Methane Initiative:
Importance of Methane (last updated June 9, 2022), https://
www.epa.gov/gmi/importance-
methane#:~:text=Methane%20is%20more%20than%2025,due%20to%20human%2Dre
lated%20activities.
\13\ Serious incidents are those including a fatality or injury
requiring in-patient hospitalization, excluding incidents when
secondary ignition is involved, sometimes called ``fire first''
incidents. Between 2001 and 2020, gas distribution incidents
comprised 81 percent of all the serious incidents reported to PHMSA.
The three-year average incident count between 2018 and 2020 is 25,
down from an average of 28 serious incidents between 2001 and 2020.
``Pipeline Incident 20 Year Trends'' (Nov. 15, 2022), https://www.phmsa.dot.gov/data-and-statistics/pipeline/pipeline-incident-20-year-trends.
\14\ ``Pipeline Incident 20 Year Trends'' (Nov. 15, 2022),
https://www.phmsa.dot.gov/data-and-statistics/pipeline/pipeline-incident-20-year-trends.
---------------------------------------------------------------------------
Much of the Nation's gas distribution piping has been in the ground
for a long time. Per PHMSA's gas distribution operator database, more
than 50 percent of the nation's pipelines were constructed before 1970
during the creation of the interstate pipeline network built in
response to the demand for energy in the post-World War II economy.\15\
Historically, gas distribution pipelines were constructed from many
different materials, including cast iron, steel, and copper. However,
material fabrication and installation practices have improved since
much of the Nation's gas distribution pipeline systems were installed,
in acknowledgment that iron alloys like cast iron and steel degrade or
corrode over time. Consequently, the age of a gas distribution system
pipeline is an important factor in evaluating the risk it poses to
public safety and the environment.
---------------------------------------------------------------------------
\15\ PHMSA, ``By-Decade Inventory: Reports'' (Mar. 16, 2020),
https://www.phmsa.dot.gov/data-and-statistics/pipeline-replacement/decade-inventory.
---------------------------------------------------------------------------
On April 4, 2011, following a string of major gas pipeline
incidents, the Secretary of Transportation announced a Pipeline Safety
Action Plan (Action Plan) that was a vehicle for Federal and State
cooperation to accelerate the repair, rehabilitation, and replacement
of the highest-risk pipeline infrastructure.\16\ Efforts implementing
the Action Plan focused on pipeline age and material as significant
risk indicators. Pipelines constructed of cast- and wrought iron and
bare steel were among those materials identified as posing the highest
risk. In fact, operators of cast-iron and bare-steel distribution
pipelines perform the vast majority of all leak repairs, despite these
lines only making up about 21 percent of all distribution pipelines
according to
[[Page 61752]]
PHMSA's distribution operators' annual report data.\17\
---------------------------------------------------------------------------
\16\ PHMSA, ``U.S. Transportation Secretary Ray LaHood Announces
Pipeline Safety Action Plan'' (Apr. 4, 2011), https://www.phmsa.dot.gov/sites/phmsa.dot.gov/files/docs/dot4111.pdf.
\17\ Cast iron or bare steel pipelines account for 95 percent of
corrosion leaks on mains, 92 percent of natural-force leaks on
mains, 91 percent of pipe/weld/joint failure leaks; 97 percent
``other cause'' leaks on mains; and 76 percent of all known leaks.
PHMSA, ``Cast and Wrought Iron Inventory'' (Apr. 26, 2021), https://www.phmsa.dot.gov/data-and-statistics/pipeline-replacement/cast-and-wrought-iron-inventory (``Cast and Wrought Iron Inventory'').
---------------------------------------------------------------------------
Though the amount of cast and wrought iron pipe in use within gas
distribution systems has declined significantly in recent years thanks
to State and Federal safety initiatives and pipeline operators'
replacement efforts, there are still approximately 20,000 miles of
mains and 7,000 miles of service lines in the United States.\18\
According to the U.S. Department of Energy, the total cost of replacing
all cast iron and bare steel distribution pipelines in the United
States would be approximately $270 billion.\19\ PHMSA understands that
both cost and practical barriers, such as urban excavation and
disruption of gas supplies, can also limit replacement efforts.
However, PHMSA finds that proactive management of the integrity of
aging pipe infrastructure enhances safety and reliability, contributes
to cost savings over the longer term, and can be less disruptive to
customers and communities than a reactive approach. Accelerating leak
detection, repair, rehabilitation, or replacement efforts also delivers
the desired integrity and safety benefits more expeditiously, lowering
maintenance requirements associated with the aging pipe that is being
replaced.
---------------------------------------------------------------------------
\18\ See Cast and Wrought Iron Inventory.
\19\ U.S. Dep't of Energy, ``Transforming U.S. Energy
Infrastructures in a Time of Rapid Change: The First Installment of
the Quadrennial Energy Review'' at S-5 (Apr. 2015) https://www.energy.gov/sites/prod/files/2015/08/f25/QER%20Summary%20for%20Policymakers%20April%202015.pdf.
---------------------------------------------------------------------------
There is no simple formula for determining which parts of the
Nation's pipeline infrastructure should be of greatest concern. Factors
often associated with higher risk include pipeline age, materials of
construction, exposure to elements or outside forces, and an operator's
practices in managing the integrity of its pipeline system. Each of
these factors can contribute to a pipeline's risk, but effective
integrity management can counterbalance the impact of aging and types
of construction materials.
B. Gas Distribution Configurations
In a distribution system, gas is sourced from a transmission
pipeline operating at a high pressure and must be safely delivered to
the customer at lower pressures that are safe for customer piping and
appliances. There are multiple points along the system where operators
can reduce the pressure to be more suitable for the needs of the
customer. City gate stations are the first such reduction point, and
district regulator stations are pressure-reducing facilities downstream
of city gate stations that further reduce the pressure from the
pipeline coming from the city gate.\20\ This lower pressure downstream
of a district regulator station is more suitable for providing service
to customers.
---------------------------------------------------------------------------
\20\ ``At the city gate the pressure of the gas is reduced, and
[this] is normally the location where odorant (typically mercaptan)
is added to the gas, giving it the characteristic smell of rotten
eggs so leaks can be detected.'' Pipeline Safety Trust, ``Pipeline
Basics & Specifics About Natural Gas Pipelines'' at 4 (Feb. 2019),
https://pstrust.org/wp-content/uploads/2019/03/2019-PST-Briefing-Paper-02-NatGasBasics.pdf.
---------------------------------------------------------------------------
Each gas distribution system must be designed to operate safely at
or below a certain pressure, also known as its maximum allowable
operating pressure (MAOP), as determined in accordance with Sec.
192.619. Exceeding this pressure can cause the gas to build up in the
pipeline and potentially cause the failure of piping, joints, fittings,
or customer appliances. As gas flows through a distribution system,
devices called regulators control the flow of gas to maintain a
constant pressure. If a regulator senses a drop or rise in pressure
above or below a set point, it will open or close accordingly to adjust
the pressure of gas. As an additional safety precaution against
overpressurization, some distribution pipelines are also designed with
a relief valve to vent the gas into the atmosphere. While modern gas
regulators are highly reliable devices, they can fail due to physical
damage, equipment failure (e.g., degradation of materials such as seals
and gaskets, defects or maintenance issues, or inability to control
pressure as set), or the presence of foreign material in the gas
stream.\21\ Because there is the possibility of a regulator failing,
distribution systems are typically designed with multiple means of
protection and redundancies to reduce the likelihood of a catastrophic
failure.
---------------------------------------------------------------------------
\21\ Gas may contain moisture, dirt, sand, welding slag, metal
cuttings from tapping procedures, or other debris. Problems caused
by such foreign material in the gas stream are most prevalent
following construction on the pipeline supplying gas to the district
regulator station. American Gas Association, ``Leading Practices to
Reduce the Possibility of a Natural Gas Over-Pressurization Event''
at 447 (Nov. 26, 2018).
---------------------------------------------------------------------------
Many regulators require external control lines, which sense the
outlet pressure of the regulator. Based on the pressure sensed through
the control lines, the regulator valve will open or close to control
the downstream pressure of the regulator. In some older installations,
control lines are located farther downstream of the regulator station
on the buried outlet piping based on either the manufacturer's
recommendations or previous control-line standards and practices at the
time of installation. However, a break in the control line (e.g., if it
is damaged during an excavation) will make the regulator sense a lower
downstream pressure and will cause the regulator valve to open wider
automatically. This could result in overpressurization of the
downstream piping, which could lead to a catastrophic event. The same
result occurs if the flow through the control line is otherwise
disrupted, for example if the control line valve is shut off or if the
control line is isolated from the regulator it is controlling.
In general, gas distribution pipeline systems can be classified as
either low pressure or high pressure. In a high-pressure gas
distribution system, the gas pressure in the main is substantially
higher than what the customer requires, and a pressure regulator
installed at each meter reduces the pressure from the main to a
pressure that can be used by the customer's equipment and appliances.
These regulators incorporate an overpressure-protection device to
prevent overpressurization of the customer's piping and appliances
should the regulator fail. Additionally, all new or replaced service
lines connected to a high-pressure distribution system must have excess
flow valves (see Sec. 192.383). Excess flow valves can reduce the flow
of gas through the service line by minimizing unplanned, excessive gas
flows.\22\
---------------------------------------------------------------------------
\22\ An excess-flow valve is a mechanical safety device
installed on a gas service line to a residence or small commercial
gas customer. In the event of damage to the gas service line between
the street and the meter, the excess-flow valve will minimize the
flow of gas through the service line. The pipeline safety
regulations require a gas distribution company to install such a
device on new or replacement service lines for single-family
residences and certain multifamily and commercial buildings where
the service line pressure is above 10 pounds per square inch gauge
(psig). See 49 CFR 192.383 for specific requirements.
---------------------------------------------------------------------------
In a low-pressure distribution system, the gas pressure in the main
is substantially the same as the pressure provided to the customer (see
Sec. 192.3). Since a district regulator station located upstream of
service lines acts as the primary means of pressure control in low-
pressure distribution systems, an overpressurization in the system
served by the district regulator could affect all the customers served
by the system.
[[Page 61753]]
This is what occurred during the Merrimack Valley incident and is an
inherent weakness of low-pressure gas distribution systems.
C. Merrimack Valley
On September 13, 2018, fires and explosions occurred after high-
pressure natural gas entered a low-pressure natural gas distribution
system operated by CMA, a subsidiary of NiSource, Inc.\23\ One person,
18-year-old Leonel Rondon, was killed, and 22 people, including 3
firefighters, were transported to hospitals for treatment of their
injuries. At least five homes were destroyed in the city of Lawrence
and the towns of Andover and North Andover, MA, by the fires and
explosions. More than 130 structures were damaged in total. Most of the
damage occurred from fires ignited by natural gas-fueled appliances.
More than 50,000 residents were asked to evacuate.
---------------------------------------------------------------------------
\23\ CMA transferred from NiSource, Inc. to Eversource Energy in
November 2020.
---------------------------------------------------------------------------
In response, fire departments from three municipalities were
dispatched to the fires and explosions. First responders initiated the
Massachusetts fire mobilization plan and received mutual aid from
neighboring districts in Massachusetts, New Hampshire, and Maine.
Emergency management officials had the electric utility shut off
electrical power in the area. Additionally, CMA shut down its low-
pressure natural gas distribution system, affecting 10,894 customers,
including some outside of the affected area who had their service shut
off as a precaution.
The NTSB on September 24, 2019, issued a final report of its
investigation into the Merrimack Valley incident.\24\ The NTSB found
the cause of the incident was CMA's weak engineering management that
failed to adequately plan, review, sequence, and oversee the
construction project that led to the abandonment of a cast iron main
without first relocating the regulator control lines to the new plastic
main. The NTSB also found that contributing to the accident was CMA's
low-pressure natural gas distribution system that was designed and
operated without adequate overpressure protection.
---------------------------------------------------------------------------
\24\ NTSB/PAR-19/02 at 49.
---------------------------------------------------------------------------
D. Low-Pressure Gas Distribution System in South Lawrence
At the time of the incident, CMA owned and operated a network of
gas pipeline systems for the transportation and delivery of natural gas
that included approximately 25 different low-pressure gas distribution
systems in Massachusetts. Among these systems, CMA owned and operated a
low-pressure system in the area of South Lawrence, Massachusetts that
served Lawrence, Andover, and North Andover, among other communities
(South Lawrence system). The South Lawrence system was installed in the
early 1900s and was constructed with cast iron and bare steel mains and
used several regulator stations to control downstream pressure. The
regulator stations were located below ground and contained regulators
that monitored and controlled downstream pressure. Natural gas came
into the South Lawrence system at a pressure of about 75 pounds per
square inch, gauge (psig). The regulators reduced the pressure to about
0.5 psig for delivery to customers.
The South Lawrence system consisted of 14 regulator stations,
wherein the regulator valves opened or closed based on the pressure the
regulator sensed downstream to maintain the downstream pressure at a
pre-set limit called a ``set point.'' This was to ensure the pressure
in the system did not exceed the MAOP and become unsafe. Each regulator
station in the South Lawrence system had at least two regulators in
series--a ``worker regulator'' and a ``monitor regulator''--each with a
control line that sensed downstream pressure and connected back to its
regulator, thereby enabling the regulator station to regulate system
pressure. The worker regulator was the primary regulator that
maintained system pressure. The monitor regulator was the redundant
backup in case the worker regulator was damaged or malfunctioned. If
both control lines experienced a decrease in pressure, such as when the
cast iron main was disconnected, the worker regulator and monitor
regulator would automatically and continually increase the pressure,
resulting in an overpressurization of the low-pressure system. That is
precisely what occurred in CMA's gas main replacement project.
E. Gas Main Replacement Project
Beginning in 2016, CMA began a pipe replacement project in the
South Lawrence system called the South Union Street project. CMA's
field engineering department initiated the project in part due to the
pending City of Lawrence water main project that would encroach on two
aging cast iron mains on South Union Street. The construction project
was also part of CMA's Gas System Enhancement Plan that called for
replacing existing low-pressure cast iron pipelines (both mains and the
accompanying service lines) with higher-pressure modern plastic piping.
The South Union Street project proposed replacing two low-pressure
cast iron mains with one plastic high-pressure main. Once installed,
the new plastic main would be ``tied-in'' to the distribution system
and service lines supplying gas to customers. As is typical in pipe
replacement projects, the two cast iron mains would be completely
disconnected from the low-pressure system and abandoned in the ground
upon completion.
The scope of the South Union Street project included the
replacement of the cast iron mains near a belowground regulator station
located at the intersection of Winthrop Avenue and South Union Street
(the Winthrop regulator station), one of the 14 regulator stations that
monitored and controlled downstream pressure in the South Lawrence
system. Up until the time of the incident, two control lines connected
the Winthrop regulator station and the two cast iron and bare steel
mains on South Union Street.
CMA contracted with a pipeline services firm to complete the
replacement project. CMA prepared a work package, which included
materials such as isometric drawings and procedural details for
disconnecting and connecting pipes, for each of the planned
construction activities. However, CMA did not prepare a package for the
relocation of the control lines serving the regulator station. The
absence of a complete work package led to the contractor completing the
installation of the plastic main with the regulator control lines at
the regulator station still connected to the cast iron main that was
being replaced.
In 2016, the construction crew installed the new plastic main on
South Union Street and began feeding the new plastic main with gas from
the Winthrop regulator station. However, CMA put the work on hold due
to a city-wide moratorium on all gas, water, and sewer projects in
Lawrence. Consequently, the construction crew was unable to begin any
of the tie-in and abandonment procedures to tie-in or connect the mains
or services to the new plastic main and thus was also unable to abandon
the cast iron mains on South Union Street. The regulator control lines
at the Winthrop regulator station remained connected to the cast iron
mains that would ultimately be decommissioned.
The final stage of the South Union Street project involved the
installation of tie-ins to the new plastic main, after which the legacy
cast iron mains would be decommissioned and abandoned in
[[Page 61754]]
their existing location. CMA then connected the plastic pipe to the gas
distribution system, which allowed it to be monitored for pressure
changes.
On September 13, 2018, at 4:00 p.m., the construction crew
completed the final ``tie-in'' and abandonment procedure following the
procedures CMA provided to the crew at South Union Street. Unbeknownst
to the construction crew, the control lines were still connected to the
abandoned cast iron main despite the gas now flowing through the new
plastic main. At the Winthrop regulator station, about 0.5 miles south
of the work area, the control lines that were still connected to the
cast-iron mains on South Union Street sensed a sharp decline in
pressure, causing the Winthrop regulator station to add more pressure
into the South Lawrence low-pressure system. Feeding high-pressure gas
into the low-pressure system resulted in a catastrophic
overpressurization of the system. The overpressurization of the low-
pressure system in the city of Lawrence and the towns of Andover and
North Andover sent gas into home appliances at a rate that they were
not designed to handle. This created explosions and fires in those
homes and businesses. Local fire departments were the first to receive
notification of the start of the incident via 9-1-1 calls. Shortly
after 4:00 p.m., the local fire departments were inundated with calls
from the public.
F. Emergency Response to the Merrimack Valley Incident
On September 13, 2018, the monitoring center in Columbus, OH, which
was overseeing the CMA system, received pressure alarms on its
supervisory control and data acquisition (SCADA) system.\25\ The system
recorded a sudden increase in pressure in the Merrimack Valley low-
pressure system at 3:57 p.m. The SCADA's high-pressure alarms activated
at 4:04 p.m. and 4:05 p.m. for the South Lawrence district regulator
station and Andover, respectively. The SCADA system was only able to
monitor system pressures; it could not remotely control the pressure of
this system.
---------------------------------------------------------------------------
\25\ Operators use SCADA systems to monitor and control critical
assets remotely. See Sec. 192.631. Here, the South Lawrence system
was monitored by CMA's corporate owner at the time, NiSource.
---------------------------------------------------------------------------
Following company protocol, at 4:06 p.m., the SCADA controller
called the on-call technician in Lawrence, MA, and reported the high-
pressure event. The on-call technician dispatched 3 field technicians
to perform field checks on the 14 regulators within the South Lawrence
system. Not until about 4:30 p.m. did a CMA field technician at the
Winthrop regulator station (the location of the control lines still
connected to the cast iron main) hear a loud sound and recognize that a
large quantity of natural gas was flowing through the Winthrop
regulator station. The CMA field technician adjusted the set point on
the two regulators to reduce flow and isolated them. The CMA field
technician then noticed that the sound of the flowing natural gas began
to decrease.
Meanwhile, at 4:18 p.m., a CMA field engineer and a CMA field
operations leader (FOL) were at another construction site when they
received notice to respond to fire coming out of house chimneys. Due to
traffic congestion, a police officer escorted the FOL to the
construction site at Salem and South Union streets (location of the
September 13 tie-in). When the FOL arrived at 5:08 p.m., crew members
stated that they had confirmed the pressure in the entire low-pressure
system was in the normal range before removing the bypass (i.e.,
disconnecting the cast iron main from the Winthrop regulator station
and connecting the new plastic main). At 5:19 p.m. the FOL took
pressure readings at a nearby house and found the pressure was
elevated. The FOL then recommended to a supervisor that CMA shut down
the low-pressure system.
After being designated as the CMA Incident Commander by the
Lawrence Operations Center manager, the FOL then called CMA's
engineering department for the list of valves that needed closing to
isolate and shut down the system. While waiting for this information,
the FOL assigned crews to regulator stations and directed them to
verify, with CMA's engineering department, the correct valve to close
once they arrived at the regulator station. Once confirmed, they closed
the valves. The FOL confirmed the closure of all valves at 7:24 p.m.
At 7:43 p.m., almost 4 hours after the CMA SCADA system detected
the overpressurization, the president of CMA declared a ``Level 1''
emergency, in accordance with CMA's emergency response plan. According
to the NTSB's report, the operator's Emergency Response Manual defines
a ``Level 1'' emergency as a ``catastrophic event'' that includes the
loss of a major natural gas facility or the loss of critical natural
gas infrastructure.
Working through the night, CMA's engineering department worked
under the FOL's direction to confirm that no gas was flowing into the
regulator stations on the low-pressure system. On September 14, 2018,
at 6:27 a.m., CMA confirmed the low-pressure distribution system was
shut down for the 8,447 customers in the Lawrence, Andover, and North
Andover areas. CMA shut down the natural gas to an additional 2,447
customers outside the immediate area as a precaution.
The following days required an unprecedented response effort. More
than 50,000 residents were asked to evacuate from their homes following
the overpressurization.\26\ Thousands of homes needed to be entered,
rendered safe, and secured to ensure that dangerous gas levels no
longer existed. As the emergency response concluded, it was clear that
the recovery effort would span months. CMA's work in the aftermath of
the incident focused on repairing infrastructure damage, providing
shelter, and finding longer-term housing solutions as recovery efforts
extended into the fall and winter months.
---------------------------------------------------------------------------
\26\ Mass. Dep't of Pub. Utilities, ``Independent Assessment of
Columbia Gas of Massachusetts' Merrimack Valley Restoration Program:
Final Report,'' at A-2 (June 22, 2020), https://www.mass.gov/doc/independent-assessment-of-columbia-gas-of-massachusetts-merrimack-valley-restoration-program/download.
---------------------------------------------------------------------------
The 2018 incident impacted three communities in the Merrimack
Valley that, while geographically near one another, are different
demographically. Lawrence is a densely populated city with many
Spanish-speaking residents and a higher poverty rate than Andover and
North Andover. Andover and North Andover are middle-class suburban
communities, and although each has half the population size of
Lawrence, their geographic size is four to five times that of Lawrence.
III. Recommendations, Advisory Bulletins, and Mandates
A. National Transportation Safety Board
The NTSB investigates serious pipeline accidents, including those
that occur on gas distribution pipeline systems. The NTSB investigated
CMA's overpressurization incident and issued its final report,\27\
which included several findings and safety recommendations to NiSource,
Inc., the Commonwealth of Massachusetts (Massachusetts), several other
States,\28\ and PHMSA.
---------------------------------------------------------------------------
\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.
---------------------------------------------------------------------------
[[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.
---------------------------------------------------------------------------
\29\ NTSB clarified this in an official correspondence to PHMSA
on July 31, 2020. NTSB, ``Safety Recommendation P-19-014'' (July 31,
2020), https://data.ntsb.gov/carol-main-public/sr-details/P-19-014.
---------------------------------------------------------------------------
B. Advisory Bulletins
1. Possibility of Overpressurization of Low-Pressure Distribution
Systems Advisory Bulletin
On September 29, 2020, PHMSA issued an advisory bulletin (ADB-2020-
02) to urge owners and operators of gas distribution systems to conduct
a comprehensive review of their systems for the possibility of a
failure of overpressure protection on low-pressure distribution
systems.\30\ The advisory bulletin addressed NTSB safety recommendation
P-19-15, which underscored the elevated possibility of a common mode of
failure on low-pressure distribution systems. Specifically, PHMSA
requested owners and operators of low-pressure distribution systems to
review the NTSB's report concerning the 2018 Merrimack Valley
overpressurization event. PHMSA also recommended that operators review
their current systems for a similar overpressure-protection
configuration to that on the CMA pipeline involved in the incident. In
the review of their systems, PHMSA urged operators to consider the
possibility of a failure of overpressure-protection devices as a threat
to their system's integrity. Additionally, PHMSA reminded owners and
operators of their responsibilities under 49 CFR part 192, subpart P,
to follow their DIMP and to revise their DIMP based on the new
information provided in the NTSB's report and PHMSA's advisory
bulletin. Finally, PHMSA recommended several ways that an operator can
protect low-pressure distribution systems from an overpressurization
event. Some examples include:
---------------------------------------------------------------------------
\30\ ``Pipeline Safety: Overpressure Protection on Low-Pressure
Natural Gas Distribution Systems,'' ADB-2020-02, 85 FR 61097 (Sept.
29, 2020).
---------------------------------------------------------------------------
1. Installing a full-capacity relief valve downstream of the
regulator station, including in applications where there is only
worker-monitor pressure control;
2. Installing a ``slam-shut'' device;
3. Using telemetered pressure recordings at district regulator
stations to signal failures immediately to operators at control
centers; and
4. Completely and accurately documenting the location for all
control lines on the system.
2. Cast-Iron Pipe Advisory Bulletin
On March 23, 2012, PHMSA issued advisory bulletin ADB-2012-05 to
owners and operators of cast-iron distribution pipelines and State
pipeline safety representatives.\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:
---------------------------------------------------------------------------
\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).
---------------------------------------------------------------------------
1. Review current cast-iron replacement programs and consider
establishing mandated replacement programs;
2. Establish accelerated leakage survey frequencies or leak
testing;
3. Focus pipeline safety efforts on identifying the highest-risk
pipe;
4. Use rate adjustments to incentivize pipeline rehabilitation,
repair, and replacement programs;
5. Strengthen pipeline safety inspections, accident investigations,
and enforcement actions; and
6. Install interior/home methane gas alarms.
PHMSA reminded owners and operators of their responsibilities under
Sec. 192.617 to establish procedures for analyzing incidents and
failures to determine the causes of the failures and to minimize the
possibility of a reoccurrence.
Finally, the advisory bulletin notes that the DOT, in accordance
with the Pipeline Safety, Regulatory Certainty, and Job Creation Act of
2011 (Pub. L. 112-90), will continue to monitor the progress made by
operators to implement plans of safe management and replacement of
cast-iron gas pipelines and identify the total miles of cast iron
pipelines in the United States.
C. Statutory Authority
Title II of the PIPES Act of 2020, the ``Leonel Rondon Pipeline
Safety Act,'' included several mandates for PHMSA to update the
regulations governing operators of gas distribution systems. This NPRM
addresses mandates codified at 49 U.S.C. 60102(r)-(t), 60105(b), and
60109(e)(7). (See sections 202, 203, 204, and 206 of the PIPES Act of
2020). Additionally, PHMSA has general statutory authority to regulate
the safety of gas pipeline facilities subject to this rulemaking as
discussed in section V.A of this NPRM.
[[Page 61756]]
1. Distribution Integrity Management Program Plans and State Inspection
Calculation Tool (49 U.S.C. 60109(e)(7) and 49 U.S.C. 60105(b) and
60105 Note; PIPES Act of 2020 Section 202)
PHMSA is required to issue regulations ensuring that DIMP plans for
gas distribution operators include an evaluation of certain risks, such
as those posed by cast iron pipes and mains and low-pressure
distribution systems, as well as the possibility of future accidents to
better account for high-consequence but low-probability events. (49
U.S.C. 60109(e)(7)). Gas distribution operators were required make
their DIMP plans, emergency response plans, and O&M manuals available
to PHMSA or the relevant State regulatory agency no later than December
27, 2022. Gas distribution operators must also make these documents, in
updated form, available to PHMSA or the relevant State regulatory
agency: (1) two years after the promulgation of regulations as
required; and (2) every 5 years thereafter, as well as following any
significant change to the document. PHMSA must also update and codify
the use of the SICT, a tool used to help states determine the minimum
amount of time it must dedicate to inspections. (See 49 U.S.C. 60105(b)
and 60105 note).
2. Emergency Response Plans (49 U.S.C. 60102(r); PIPES Act of 2020
Section 203)
PHMSA is required to update its emergency response plan regulations
to ensure that each emergency response plan developed by a gas
distribution system operator includes written procedures for how to
handle communications with first responders, other relevant public
officials, and the general public after certain significant pipeline
emergencies (49 U.S.C. 60102(r)). Specifically, the updated regulations
would ensure that pipeline operators contact first responders and
public officials as soon as practicable after they know a release of
gas has occurred that resulted in a fire related to an unintended
release of gas, an explosion, one or more fatalities, or the
unscheduled release of gas and shutdown of gas service to a significant
number of customers. Similarly, the updated regulations would provide
for general public communication of pertinent emergencies as soon as
practicable and leverage communications methods facilitating rapid
notice to the general public.
3. Operation and Maintenance Manuals (49 U.S.C. 60102(s); PIPES Act of
2020 Section 204)
PHMSA is required to update the regulations for O&M manuals to
require distribution system operators to have a specific action plan to
respond to overpressurization events (49 U.S.C. 60102(s)).
Additionally, operators must develop written procedures for management
of change processes for significant technology, equipment, procedural,
and organizational changes to their distribution system and ensure that
relevant qualified personnel, such as an engineer with a professional
engineer (PE) license, reviews and certifies such changes (49 U.S.C.
60102(s)).
4. Pipeline Safety Practices (49 U.S.C. 60102(t); PIPES Act of 2020
Section 206)
PHMSA is required to issue regulations that require distribution
pipeline operators to identify and manage ``traceable, reliable, and
complete'' maps and records of critical pressure-control infrastructure
and update these records as appropriate. The records must be submitted
or made available to the relevant regulatory agency (i.e., PHMSA or the
State). These regulations must require records to be gathered on an
opportunistic basis. (49 U.S.C. 60102(t)(1)).
PHMSA must also issue regulations requiring a qualified employee of
a distribution system operator to monitor gas pressure at district
regulator stations and be able to shut off flow or limit gas pressure
during construction projects that have the potential to cause a
hazardous overpressurization. An exception to this requirement would be
made for a district regulator station that has a monitoring system and
capability for a remote or automatic shutoff (49 U.S.C. 60102(t)(2)).
PHMSA is further required to issue regulations on district regulator
stations to ensure that gas distribution system operators minimize the
risk of a common mode of failure at low-pressure district regulator
stations, monitor the gas pressure of low-pressure distribution
systems, and install overpressure protection safety technology at low-
pressure district regulator stations. If it is not operationally
possible to install such technology, this section would require the
operator to identify plans that would minimize the risk of
overpressurization (49 U.S.C. 60102(t)(3)).
IV. Proposed Amendments
A. Distribution Integrity Management Programs (Subpart P)
In 2009, PHMSA issued a final rule titled ``Pipeline Safety:
Integrity Management Program for Gas Distribution Pipelines,'' creating
49 CFR part 192, subpart P.\34\ As specified in Sec. 192.1003, subpart
P applies to operators of all gas distribution pipelines covered under
part 192, subject to certain exceptions, and prescribes minimum
requirements for integrity management programs for any such pipelines
(referred to in this rulemaking as DIMPs). Adherence to a DIMP is an
overall approach by operators to ensure the integrity of their
distribution systems. The purpose of DIMP is to enhance safety by
identifying and reducing pipeline integrity risks. DIMP regulations
require that operators develop an integrity management plan that they
must re-evaluate periodically; that integrity management plan
complements operator efforts in complying with prescriptive operating
and maintenance requirements elsewhere in part 192.
---------------------------------------------------------------------------
\34\ 74 FR 63906 (Dec. 4, 2009).
---------------------------------------------------------------------------
Pursuant to Sec. 192.1007, DIMP regulations require operators
implement the following steps in developing their DIMP plans:
(1) Knowledge (Sec. 192.1007(a))--Requires operators to understand
their pipeline system's design and material characteristics, operating
conditions and environment, and maintenance and operating history;
(2) Identify Threats (Sec. 192.1007(b))--Requires operators to
identify existing and potential threats to their pipeline systems;
(3) Evaluate and Rank Risk (Sec. 192.1007(c))--Requires operators
to evaluate and identify threats to determine their relative importance
and rank the risks associated with their pipeline systems;
(4) Identify and Implement Measures to Address Risks (Sec.
192.1007(d))--Requires operators to determine and implement measures
designed to reduce the risks from failure of their pipeline systems;
(5) Measure Performance, Monitor Results, and Evaluate
Effectiveness (Sec. 192.1007(e))--Requires operators to measure the
performance of their DIMPs and reevaluate threats and risks to their
pipeline systems;
(6) Periodic Evaluation and Improvement (Sec. 192.1007(f))--
Requires operators to periodically reevaluate threats and risks across
the entire pipeline system; and
[[Page 61757]]
(7) Report Results (Sec. 192.1007(g))--Requires operators to
report their performance results to PHMSA and the applicable State
agency through annual reports (required by Sec. 191.11).
The first step in developing a robust DIMP plan, as required in
Sec. 192.1007(a), is for operators to have knowledge of their gas
distribution system. PHMSA has clarified through enforcement guidance
that this knowledge should include, but is not limited to, the
following characteristics: location, material composition, piping
sizes, joining methods, construction methods, date of installation,
soil conditions (where appropriate), operating and design pressures,
operating history, operating performance data, condition of system, and
any other characteristics noted by operators as important to
understanding their system. This information may be obtained from
sources including system maps, construction records, work management
system, geographic information systems (GIS), corrosion records, and
personnel who have knowledge of the system (subject matter
experts).\35\ This step also requires operators to identify missing
data and to develop a plan to collect relevant information as part of
their normal pipeline activities over time.
---------------------------------------------------------------------------
\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'').
---------------------------------------------------------------------------
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)).
---------------------------------------------------------------------------
\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.
---------------------------------------------------------------------------
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\
---------------------------------------------------------------------------
\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.
---------------------------------------------------------------------------
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\
---------------------------------------------------------------------------
\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.
---------------------------------------------------------------------------
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\
---------------------------------------------------------------------------
\44\ DIMP Guidance at 22, 61.
---------------------------------------------------------------------------
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.
---------------------------------------------------------------------------
\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.
---------------------------------------------------------------------------
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\
---------------------------------------------------------------------------
\47\ NTSB/PAR-19/02 at 18.
\48\ NTSB/PAR-19/02 at 59-61.
\49\ NTSB/PAR-19/02 at 40.
---------------------------------------------------------------------------
More robust risk management was also needed in the planning of the
South Union Street project, particularly with respect to the threat of
overpressurization. NTSB concluded that NiSource's engineering package
for that construction project failed to identify, and control for the
vulnerability of its system to, a common mode of failure during the
construction project that could result in an overpressurization. After
the incident in the Merrimack Valley, NiSource worked to improve its
risk management processes and installed automatic pressure-control
equipment.\50\ Therefore, the NTSB concluded that NiSource's
engineering risk management processes were deficient.
---------------------------------------------------------------------------
\50\ NTSB/PAR-19/02 at 43.
---------------------------------------------------------------------------
Subsequent to the Merrimack Valley incident, 49 U.S.C. 60109(e)(7)
was amended to require PHMSA to add more specificity to the DIMP
requirements to ensure that operators consider specific threats to
their systems. Specifically, PHMSA must update its regulations to
ensure DIMP plans for distribution operators include an evaluation of
certain risks, such as those posed by cast iron pipes and mains and
low-pressure distribution systems, as well as the possibility of future
accidents, to better account for high-consequence but low-probability
events. Distribution operators must make their updated DIMP plans
available to PHMSA or the relevant State regulatory agency two years
after any final rule in this proceeding is issued and every 5 years
thereafter, as well as following any significant change to an
operator's DIMP plan or distribution system.\51\
---------------------------------------------------------------------------
\51\ This provision also requires that operators make their
current DIMP plans, emergency response plans, and O&M manuals
available to PHMSA or the relevant State regulatory agency no later
than December 27, 2022, which PHMSA intends to continue to review as
appropriate in the course of inspection. See 49 U.S.C. 60109(e)(7).
---------------------------------------------------------------------------
Another recent incident that illustrates operator failure to
adequately identify, evaluate, and rank risk is a series of leaks and
explosions that occurred on a gas distribution system operated by Atmos
Energy Corporation between February 21, 2018, and February 23, 2018, in
Dallas, TX. The NTSB investigated the February 2018 incident.\52\ As
specified by the NTSB, although Atmos' DIMP plan was consistent with
the currently applicable minimum requirements, their plan did not
adequately address the inherent risks of its 71-year-old system. In
addressing the likelihood of failure, the age of a pipe is generally
recognized as an important performance factor.\53\ Currently, PHMSA's
regulations do not explicitly require gas distribution operators to
consider the age of their pipelines under a DIMP. Instead, PHMSA's
regulations in Sec. 192.1007(c) state that ``[a]n operator may
subdivide its pipeline into regions with similar characteristics (e.g.,
contiguous areas within a distribution pipeline consisting of mains,
services and other appurtenances; areas with common materials or
environmental factors), and for which similar actions likely would be
effective in reducing risk.'' Similar to what is described in PHMSA's
regulations, Atmos grouped its assets into failure families based on
asset attributes, such as material and coating. This method of
evaluating the risks proved to be inadequate, given the high number of
leaks observed that were due to the degradation of their pipelines over
time.
---------------------------------------------------------------------------
\52\ NTSB, Accident Report PAR-21/01, ``Atmos Energy Corporation
Natural Gas-Fueled Explosion: Dallas, Texas: February 23, 2018''
(Jan. 12, 2021), https://www.ntsb.gov/investigations/AccidentReports/Reports/PAR2101.pdf.
\53\ NTSB/PAR-21/01 at 66.
---------------------------------------------------------------------------
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.
---------------------------------------------------------------------------
[[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.
---------------------------------------------------------------------------
\55\ An individual gas service line directly connected to a gas
transmission, production, or gathering pipeline is commonly referred
to as a ``farm tap.'' Individual service lines have the option of
following either Sec. 192.740, for service lines that are not
operated as part of a distribution system, or DIMP (as detailed in
Sec. 192.1003(b)) for any portion of the individual service line
that is classified as a service line. This rule proposed no change
to this scope. The proposals apply to those individual service lines
(aka farm taps) that apply DIMP.
---------------------------------------------------------------------------
Based on its review of the evidence in the record, PHMSA expects
the proposed amendments to the DIMP requirements would be reasonable,
technically feasible, cost-effective, and practicable for gas
distribution operators. As explained above, these operators are already
required by PHMSA regulations to have DIMPs for (inter alia)
identifying threats to pipeline integrity, evaluating the risks of
those threats, and implementing mitigation measures to manage those
risks. The NPRM's proposed amendments would clarify baseline
expectations for implementation of those existing DIMP elements
consistent with historical PHMSA guidance, industry operational
experience and research, and statutory mandates in the PIPES Act of
2020, enacted after the Merrimack Valley incident. Said another way,
the NPRM's proposed revisions are consistent with the actions
reasonably prudent gas distribution operators would undertake in
ordinary course in implementing current DIMP requirements on gas
distribution pipelines transporting pressurized (natural, flammable,
toxic, or corrosive) gasses that are typically in close proximity to,
or within, population centers. Within the guardrails proposed herein,
operators would retain the significant flexibility contemplated by
current DIMP regulations for operators to design and implement their
DIMPs in a manner appropriate for managing integrity risks on their
specific pipeline facilities while minimizing compliance costs. Viewed
against those considerations and the compliance costs estimated in the
PRIA, PHMSA expects its proposed amendments will be a cost-effective
approach to achieving the commercial, public safety, and environmental
benefits discussed in this NPRM and its supporting documents. Lastly,
PHMSA understands that its proposed compliance timeline--one year after
publication of a final rule (which would necessarily be in addition to
the time since publication of this NPRM)--would provide operators ample
time to implement requisite changes to their DIMPs and manage any
related compliance costs.
1. DIMP--Identify Threats (Sec. 192.1007(b))--Materials
a. Current Requirements--DIMP--Identify Threats--Materials
Section 192.1007(b) requires operators to consider the general
threat category of ``material or welds,'' but the requirement does not
state that operators must consider specific material types and how each
type could pose a threat to the integrity of a system. PHMSA has
clarified through enforcement guidance that operators should consider
subcategories of ``material'' threats to better categorize their
pipelines by age or specific pipe type (such as bare steel, cast iron,
wrought iron, and plastic piping) to focus on the root cause of
potential failures.\56\ PHMSA has also issued advisory bulletins
alerting operators of threats related to specific material types,
including cast iron (ADB-2012-05) and plastic piping (ADB-07-01 and
ADB-2012-03).\57\ PHMSA's annual report form, PHMSA F 7100.1-1 (see 49
CFR 191.11), also requires operators to identify specific subtypes of
materials and the pipeline mileage of each.
---------------------------------------------------------------------------
\56\ DIMP Guidance at 20.
\57\ ``Pipeline Safety: Cast Iron Pipe (Supplementary Advisory
Bulletin),'' ADB-2012-05, 77 FR 17119 (Mar. 23, 2012); ``Pipeline
Safety: Notice to Operators of Driscopipe[supreg] 8000 High Density
Polyethylene Pipe of the Potential for Material Degradation,'' ADB-
2012-03, 77 FR 13387 (Mar. 6, 2012); ``Updated Notification of
Susceptibility to Premature Brittle[hyphen]Like Cracking of Older
Plastic Pipe,'' ADB-07-02, 72 FR 51301 (Sept. 6, 2007).
---------------------------------------------------------------------------
b. Need for Change--DIMP--Identify Threats--Materials
Different piping materials could pose different threats to gas
distribution systems and should be identified prior to conducting a
risk analysis of those threats. All things equal, pipelines that are
made of certain materials, like cast iron, wrought iron, bare steel,
unprotected steel, and certain plastic pipelines, are more susceptible
to leaks and other pipeline integrity issues. In particular, cast-iron
pipe was the subject of an advisory bulletin (ADB-2012-05) that
reiterated two alert notices previously issued by PHMSA that addressed
the continued use of cast- and wrought-iron pipe in gas distribution
pipeline systems and reminded owners and operators and State pipeline
safety representatives of the need to maintain an effective cast-iron
management program.\58\ Similar to cast- and wrought-iron piping, steel
pipelines without corrosion protection coating--also known as bare-
steel or unprotected pipelines--are made of a material that could be a
threat to a gas distribution system, as that material is more
susceptible to corrosion than coated steel.
---------------------------------------------------------------------------
\58\ RSPA, ALN-92-02 (June 26, 1992); RSPA, ALN-91-02 (Oct. 11,
1991).
---------------------------------------------------------------------------
Certain vintages and types of plastic piping are also known
throughout the industry to present acute threats to pipeline integrity.
For example, susceptibility to premature brittle[hyphen]like cracking
of certain Aldyl ``A'' pipe, along with other vintages and
manufacturers' products, is a well[hyphen]documented problem in the
industry and the subject of the advisory bulletin ADB-07-02. In this
advisory bulletin, PHMSA recommended that operators consider the threat
of brittle-like cracking applicable to any Aldyl ``A'' pipe in service
(under the general category of ``material''), regardless of whether the
threat had resulted in leakage to date. Similarly, PHMSA also alerted
operators to the risks of material degradation on Driscopipe8000
(Driscopipe Series 8000 high-density poly-ethylene (HDPE)) pipe in
Arizona and Nevada in ADB-2012-03.
While many of these pipelines have been taken out of service, some
of them continue to operate today. As discussed earlier, the Merrimack
Valley incident involved the replacement of cast-iron and bare-steel
pipelines with modern plastic piping. This was part of CMA's pipeline
replacement program, which called for the replacement of leak-prone
low-pressure cast iron pipelines (both mains and services) with modern
plastic pipe. Many operators are also engaged in pipeline replacement
projects in response to PHMSA's Action Plan; managing the reduction in
cast- and wrought-iron inventory has been a priority and in progress
for many years.
Following the Merrimack Valley incident, PHMSA was required by
[[Page 61760]]
statute to ensure that operators evaluate the risk of the presence of
cast iron in their DIMP plans. While only cast-iron was specifically
identified as a material warranting explicit mention in DIMP
regulations,\59\ PHMSA understands that the Merrimack Valley incident
(which occurred on a pipeline with both cast iron and bare steel)
underscores that other types of high-risk materials on gas distribution
systems warrant similar treatment. Although operators are already
identifying what specific piping materials are on their system,\60\ and
Sec. 192.1007(b) requires operators to actively monitor and consider
the presence of piping material with known issues under the general
threat category of ``material or welds,'' PHMSA believes that
clarifying this practice in the DIMP regulations would ensure that as
operators implement their DIMP plans, they consider the risks
associated with the presence of these leak-prone materials, as required
by the risk analysis in Sec. 192.1007(c).
---------------------------------------------------------------------------
\59\ PHMSA notes, however, the threats to pipeline integrity
posed by other materials. Specifically, 49 U.S.C. 60108 (Section 114
of PIPES Act of 2020) imposes a self-executing mandate on gas
transmission, distribution, and part-192 regulated gas gathering
pipeline operators to update their inspection and maintenance
procedures to provide for replacement or remediation of pipelines
``known to leak based on their material (including cast iron,
unprotected steel, wrought iron, and historic plastics with known
issues) . . . .'' PHMSA is considering within a separate rulemaking
(under RIN 2137-AF54) whether to incorporate that self-executing
statutory mandate within its 49 CFR part 192 regulations. See ``Gas
Pipeline Leak Detection and Repair,'' 88 FR 31890 (May 18, 2023).
PHMSA submits that this NPRM's amendments to DIMP requirements at
subpart P would complement any revisions to prescriptive regulations
elsewhere in 49 CFR part 192 that PHMSA may adopt in that parallel
rulemaking.
\60\ Operators are already subcategorizing their pipeline
segments by material type (i.e., cast iron, wrought iron, bare
steel, and certain plastics with known issues) in their annual
report form, PHMSA F 7100.1-1. See supra note 36.
---------------------------------------------------------------------------
c. Proposal To Amend Sec. 192.1007(b)--DIMP--Identify Threats--
Materials
PHMSA proposes to revise Sec. 192.1007(b) to clarify that
operators must identify the threats posed by specific material types in
their pipeline system, such as cast iron, wrought iron, bare steel, and
historic plastic pipe with known issues. PHMSA expects that, in
determining whether a plastic pipe material is a ``historic plastic
with known issues'' representing a threat to pipeline integrity,
operators should consider PHMSA and State regulatory actions and
industry technical resources identifying systemic integrity issues on
plastic pipe made from particular materials manufactured at particular
times or by particular companies, or fabricated and installed pursuant
to particular processes. As noted above, PHMSA issues advisory
bulletins cautioning operators regarding the susceptibility of certain
historic plastic pipelines to systemic integrity issues. Similarly,
State pipeline safety regulatory actions, PHMSA pipeline failure
investigation reports, and NTSB findings can inform operator
determinations whether historic plastic pipe is at a high-risk loss of
integrity. Industry efforts and resources are another resource for
operators in determining whether historic plastic pipe has known
issues. For example, the PPDC publishes periodic status reports of data
submitted by program participants that incorporates information
regarding investigations of materials of concern or potential
concern.\61\ PHMSA expects that these and other authoritative
resources--coupled with an operator's own design expertise and
operational and maintenance history--would be adequate for a reasonably
prudent operator to determine whether the particular plastic pipe in
its distribution system is a historic plastic with known issues. PHMSA
further invites comment on whether, within a final rule in this
proceeding, there would be value (in addition to being cost-effective,
practicable, and technically feasible) in either explicitly listing
(within subpart P or periodically-issued implementing guidance)
historic plastics prone to leakage, or deleting the scope qualification
``historic'' from proposed regulatory text.
---------------------------------------------------------------------------
\61\ AGA, ``Plastic Pipe Data Collection Initiative'', https://www.aga.org/natural-gas/safety/promoting-safety/plastic-pipe-data-collection-initiative/ (last visited March 10, 2023).
---------------------------------------------------------------------------
Once the threats are identified under Sec. 192.1007(b), operators
are also required to evaluate these risks under Sec. 192.1007(c) and
to ensure that risk reduction measures are identified and implemented
under Sec. 192.1007(d).
2. DIMP--Identify Threats (Sec. 192.1007(b))--Overpressurization
a. Current Requirements--DIMP--Identify Threats--Overpressurization
Section 192.1007(b) does not explicitly require operators to
consider the threat of overpressurization as a threat under their DIMP
plans. Instead, Sec. 192.1007(b) requires operators to consider the
general threat category of ``incorrect operations'' or ``other issues
that could threaten the integrity of [a] pipeline'' and requires
operators to consider whether those threats exist on their systems.
However, overpressurization is a potential threat to gas distribution
systems. PHMSA has stated through previous enforcement guidance and an
advisory bulletin (ADB-2020-02) that overpressurization is a threat,
especially for low-pressure gas distribution systems, and recommended
that operators identify overpressurization as a threat in their DIMP
plans. Further, Sec. 192.195 provides design requirements for the
protection against accidental overpressurization, including additional
requirements for distribution systems.
b. Need for Change--DIMP--Identify Threats--Overpressurization
The threat of overpressurization, particularly on low-pressure gas
distribution systems, is a threat that PHMSA expects operators to
consider in their DIMP plans. PHMSA considers the threat of
overpressurization to fall under the threat categories of both
``incorrect operations'' and ``other issues that could threaten the
integrity of [a] pipeline'' in Sec. 192.1007(b). In enforcement
guidance, PHMSA lists ``overpressurization events'' as an example of
potential threats operators could experience on their pipelines.\62\
PHMSA also requires operators to have sufficient knowledge of their
systems, per Sec. 192.1007(a), to determine if overpressurization is a
threat on their specific systems and to develop and implement measures
to mitigate the consequences of a potential overpressurization. As
discussed earlier, PHMSA also issued an advisory bulletin (ADB-2020-02)
alerting operators of low-pressure gas distribution systems of the
increased risk of overpressurization on those systems and recommended
that operators consider the threat of overpressurization in their DIMP
plans.
---------------------------------------------------------------------------
\62\ DIMP Guidance at 19, 59.
---------------------------------------------------------------------------
Recent incidents underscore the importance of operators adequately
identifying the risk of overpressurization on distribution systems.
Prior to the Merrimack Valley incident on September 13, 2018, the
operator experienced four other overpressurizations and one ``near-
miss'' within its network of distribution systems.\63\
---------------------------------------------------------------------------
\63\ NTSB/PAR-19/02 at 25.
---------------------------------------------------------------------------
On March 1, 2004, a system overpressurized when debris lodged at
the seat of the bypass valve in Lynchburg, VA.
On February 28, 2012, an operator error during an inspection
resulted in accidental overpressurization in Wellston, OH. 300
customers were without service for 14 hours.
On March 21, 2013, a segment of a pipe with an MAOP of 1 psig was
pressurized at over 2 psig in Pittsburgh, PA. A work crew, under the
direction of
[[Page 61761]]
the local NiSource subsidiary, was making a tie-in and failed to
monitor the pressure and flow of the existing low-pressure natural gas
distribution system during the tie-in process.
On August 11, 2014, a local NiSource crew in Frankfort, KY, was
excavating to repair a leak located on the outside of a regulator
station building. The crew uncovered and narrowly missed hitting the 1-
inch control line and tap located on the 8-inch outlet pipeline. The
crew was unaware of the purpose of the 1-inch line and called local
measurement and regulation (M&R) personnel. The M&R personnel advised
the crew of the purpose of a control line and what would have happened
had the line been broken. As discussed earlier, in 2015 NiSource issued
ON 15-05 in response to this near miss. ON 15-05 required that M&R
personnel be consulted on all future excavation work done within 25
feet of a regulator station with sensing lines, other communications
and/or electric lines critical to the operation of the regulator
station, or buried odorant lines. On September 13, 2018 (the date of
the Merrimack Valley incident), however, CMA did not follow those
procedures or implement any preventive or mitigative measures as they
should have if they were correctly following DIMP requirements.
On January 13, 2018, during the investigation of a service
complaint, an overpressurization was discovered on a natural gas
distribution system in Longmeadow, MA. The cause was associated with
debris accumulation on both the worker and monitor regulator seats at a
regulator station. Once the debris was removed, the pressure returned
to normal. This event illustrates that, in some cases, an
overpressurization can occur that does not cause a catastrophic failure
of the entire system, but if the operator takes timely, mitigative
action, the system can safely return to normal. Operators know debris
accumulation at regulator stations can cause an overpressurization and
can plan routine maintenance of regulator stations to remove debris or
install a device to prevent the debris from reaching the regulator
station. However, an operator must first recognize overpressurization
as a threat to ensure that they allocate resources to address this
threat.
While overpressurization is a threat that PHMSA expects operators
to consider in their DIMP plans, the pipeline safety regulations do not
explicitly state that operators must identify and evaluate the threat
of overpressurization in their DIMP plans. Following the Merrimack
Valley incident on September 13, 2018, PHMSA was required by law to
ensure that operators evaluate the risk of overpressurization in their
DIMP plans. PHMSA therefore proposes to amend Sec. 192.1007(b) to
explicitly require operators to identify overpressurization as a threat
to low-pressure distribution systems. The proposal is intended to
ensure that operators consider this risk on their system as required by
the risk analysis in Sec. 192.1007(c) and identify risk reduction
measures in accordance with Sec. 192.1007(d).
c. Proposal To Amend Sec. 192.1007(b)--DIMP--Identify Threats--
Overpressurization on Low-Systems
PHMSA proposes to amend Sec. 192.1007(b) to create a new threat
category of ``overpressurization on low-pressure systems.'' This change
would ensure that consideration of risks under the DIMP regulations
explicitly includes overpressurization of a low-pressure system as a
threat. Once identified as a threat under Sec. 192.1007(b), operators
would also have to evaluate the likelihood and the potential
consequences of such a failure, as required in Sec. 192.1007(c), and
ensure risk-reduction measures are identified and implemented under
Sec. 192.1007(d). PHMSA discusses the actions operators must take to
implement Sec. 192.1007(c) and Sec. 192.1007(d) in subsection IV.A.5
and 6 of this preamble.
3. DIMP--Identify Threats (Sec. 192.1007(b))--Natural Forces
a. Current Requirements--DIMP--Identify Threats--Natural Forces
Including Extreme Weather and Geohazards
Section 192.1007(b) requires operators to consider the general
threat category of ``natural forces,'' but the requirement does not
explicitly state what natural forces could pose a threat to the
integrity of the system. Natural force damage occurs as a result of
naturally occurring events, including: (1) earthquakes and landslides;
(2) heavy rains and flooding; (3) high winds, tornadoes, or hurricanes;
(4) temperature extremes; and (5) lightning.\64\ Further, PHMSA has
issued advisory bulletins alerting operators to threats related to
natural forces such as land movement (i.e., geological hazards or
``geohazards'' \65\) (ADB-2022-01 and ADB-2019-02), severe flooding
(ADB-2019-01), snow and ice build-up (ADB-2016-03), and extreme
temperatures (ADB-2012-03).\66\
---------------------------------------------------------------------------
\64\ PHMSA, ``Fact Sheet: Natural Force Damage'' (July 23,
2014), https://primis.phmsa.dot.gov/comm/FactSheets/FSNaturalForce.htm.
\65\ PHMSA also interprets natural hazards to include
geohazards.
\66\ ``Pipeline Safety: Potential for Damage to Pipeline
Facilities Caused by Earth Movement and Other Geological Hazards,''
ADB-2022-01, 87 FR 33576 (June 2, 2022); ``Pipeline Safety:
Potential for Damage to Pipeline Facilities Caused by Earth Movement
and Other Geological Hazards,'' ADB-2019-02, 84 FR 18919 (May 2,
2019); ``Pipeline Safety: Potential for Damage to Pipeline
Facilities Caused by Flooding, River Scour, and River Channel
Migration,'' ADB-2019-01, 84 FR 14715 (Apr. 11, 2019); ``Pipeline
Safety: Dangers of Abnormal Snow and Ice Build-Up on Gas
Distribution Systems,'' ADB-2016-03, 81 FR 7412 (Feb. 11, 2016);
``Notice to Operators of Driscopipe 8000 High Density Polyethylene
Pipe of the Potential for Material Degradation,''ADB-2012-03, 77 FR
13387 (Mar. 6, 2012). PHMSA notes that many of those advisory
bulletins identify resources maintained by other Federal agencies
that can assist pipeline operators in identifying and evaluating
integrity threats to their pipelines.
---------------------------------------------------------------------------
b. Need for Change--DIMP--Identify Threats--Natural Forces Including
Extreme Weather and Geohazards
A distribution pipeline system operates in a discrete environment
due to the limited geographic scope of each individual system. The
environment in which a system operates significantly affects the
threats to pipeline integrity that it faces. Factors such as weather
(dry or wet, hot or subject to freezing) can significantly shape the
threats affecting individual distribution operators and the actions
necessary to address those threats. Major climate trends, such as
elevated average surface temperatures, more intense storm events, and
flooding, can, independently and in combination, affect the reliability
and integrity of the United States' gas distribution infrastructure. As
climate change has made extreme weather more common, it is harder to
categorize what types of environmental factors facing distribution
pipelines are ``normal'' based on geography and historical averages
alone.
While freezing weather once seemed like a problem reserved for
northern regions of the United States, southern regions are also
experiencing unseasonable and extremely cold weather. For example, in
February of 2021, Texas experienced a winter storm that brought some of
the coldest temperatures in its history.\67\ Extremely cold weather can
cause thermal contraction stress or fractures of pipelines due to the
expansion of moisture trapped inside components. In addition, safety
relief devices can malfunction due to icing or freezing.
---------------------------------------------------------------------------
\67\ On February 16, 2021, Dallas, TX recorded temperatures as
low as -2 [deg]F.
---------------------------------------------------------------------------
Low temperatures and the accumulation of snow and ice also
increases the potential for physical
[[Page 61762]]
damage to meters and regulators and other aboveground pipeline
facilities and components. For example, ice forming on regulators or
pressure relief devices can cause them to malfunction or stop working
completely.\68\ Exposed piping at metering and pressure regulating
stations, at service regulators, and at propane tanks are at the
greatest risk. On February 11, 2016, PHMSA issued advisory bulletin
ADB-2016-03 alerting operators to the dangers of abnormal snow and ice
buildup on gas distribution systems. PHMSA has issued four other
advisory bulletins since 1993 on this same issue.\69\
---------------------------------------------------------------------------
\68\ Regulators must be adequately protected from obstructions
such as dirt, insects, and ice. If the vent on a regulator becomes
completely obstructed, then the regulator can either shut off the
flow of gas to a customer or increase the pressure to the upstream
pressure, causing possible failures.
\69\ ``Pipeline Safety: Dangers of Abnormal Snow and Ice Build-
Up on Gas Distribution Systems,'' ADB-11-02, 76 FR 7238 (Feb. 9,
2011); ``Pipeline Safety: Dangers of Abnormal Snow and Ice Build-Up
on Gas Distribution Systems,'' ADB-08-03, 73 FR 12796 (Mar. 10,
2008); ``Potential Damage to Pipelines by Impact of Snowfall, and
Actions Taken by Homeowners and Others to Protect Gas Systems from
Abnormal Snow Build-up,'' ADB-97-01 (Jan. 24, 1997); ``Pipeline
Safety Advisory Bulletin; Snow Accumulation on Gas Pipeline
Facilities,'' ADB-93-01, 58 FR 7034 (Feb. 3, 1993).
---------------------------------------------------------------------------
Natural forces such as severe flooding, river scour, and river
channel migration can also adversely affect the safe operation of a
pipeline. These incidents can damage a pipeline as a result of
additional stresses imposed on the pipe by undermining underlying
support soils, exposing the pipeline to lateral water forces and impact
from waterborne debris. Additionally, the proper function of valves,
regulators, relief sets, pressure sensors, and other facilities
normally above ground or above water can be jeopardized when covered by
water. PHMSA has issued several advisory bulletins alerting operators
to the dangers severe flooding, river scour, and river channel
migration can impose on a pipeline, most recently in 2019 through ADB-
2019-01 and again in 2022 through ADB-2022-01.\70\ Sometimes flooding
is seasonal and predictable; however, the Intergovernmental Panel on
Climate Change (IPCC) predicts increases in the frequency and intensity
of heavy precipitation, which will give rise to increased risk of
flooding.\71\ In some areas, climate change means higher average
precipitation,\72\ resulting in water saturation that inhibits the
ability of soil to absorb extreme precipitation events. Climate change
may, however, result in drought for other parts of the United
States,\73\ as lower average annual precipitation rates result in lower
soil moisture--and therefore, less ability to absorb extreme
precipitation events. Also, rainfall during the four wettest days of
the year has increased about 35 percent, and the amount of water
flowing in most streams during the worst flood of the year has
increased by more than 20 percent.\74\ For parts of the United States,
spring rainfall and average precipitation are likely to increase and
severe rainstorms are likely to intensify during the next century.\75\
Each of these factors will tend to further increase the risk of
flooding--operators must assess how this may impact the integrity of
their pipelines.
---------------------------------------------------------------------------
\70\ See, e.g., ``Pipeline Safety: Potential for Damage to
Pipeline Facilities Caused by Flooding, River Scour, and River
Channel Migration,'' ADB-2016-01, 81 FR 2943 (Jan. 19, 2016);
``Pipeline Safety: Potential for Damage to Pipeline Facilities
Caused by the Passage of Hurricanes,'' ADB-2015-02, 80 FR 36042
(June 23, 2015); ``Pipeline Safety: Potential for Damage to Pipeline
Facilities Caused by Flooding, River Scour, and River Channel
Migration,'' ADB-2015-01, 80 FR 19114 (Apr. 9, 2015); ``Pipeline
Safety: Potential for Damage to Pipeline Facilities Caused by
Flooding,'' ADB-2013-02, 78 FR 41991 (July 12, 2013); ``Pipeline
Safety: Potential for Damage to Pipeline Facilities Caused by
Flooding,'' ADB-11-04, 76 FR 44985 (July 27, 2011).
\71\ IPCC, Seneviratne, S.I., N. Nicholls et al., ``Managing the
Risks of Extreme Events and Disasters to Advance Climate Change
Adaptation'' at 113 (2012), https://www.ipcc.ch/site/assets/uploads/2018/03/SREX-Chap3_FINAL-1.pdf.
\72\ U.S. Envtl. Prot. Agency, ``What Climate Change Means for
Missouri'', EPA 430-F-16-027, at 1 (Aug. 2016), https://19january2017snapshot.epa.gov/sites/production/files/2016-09/documents/climate-change-mo.pdf (noting that over the last half
century, average annual precipitation in most of the Midwest has
increased by 5 to 10 percent).
\73\ See A. Park Williams et al., ``Rapid Intensification of the
Emerging Southwestern North American Megadrought in 2020-2021,'' 12
Nature Climate Change 232-234 (2022).
\74\ U.S. Envtl. Prot. Agency, ``What Climate Change Means for
Missouri,'' at 1.
\75\ U.S. Envtl. Prot. Agency, ``Climate Impacts in the
Midwest,'' Climate Change Impacts, https://climatechange.chicago.gov/climate-impacts/climate-impacts-midwest
(last visited Feb. 25, 2023).
---------------------------------------------------------------------------
Extremely high temperatures can also pose integrity threats to
certain materials. In March 2012, PHMSA issued advisory bulletin ADB-
2012-03 regarding the potential for degradation of Driscopipe8000
pipes, which were produced from 1979 through 1997.\76\ All reported
occurrences of in-service degradation and leaks related to
Driscopipe8000 pipes were installed in the desert region of the
southwestern United States, particularly in the Mojave Desert region in
Arizona, California, and Nevada. The ambient temperatures in the
southwestern United States are very high (typically over 100 degrees
Fahrenheit) and may contribute to issues for plastic piping. Driscopipe
Series 7000 and 8000 HDPE pipe exposed to prolonged elevated
temperatures may degrade as a result of thermal oxidation. One of the
largest producers of polyethylene piping products in North America, has
noted that ``the mechanism for this oxidation appears to be the
depletion of the thermal stabilizer, which has been shown to occur over
time in high ambient temperature conditions.'' \77\ PHMSA has reminded
operators through ADB-2012-03 that they should monitor the performance
of their plastic piping.
---------------------------------------------------------------------------
\76\ 77 FR at 13388.
\77\ Performance Pipe, ``Driscopipe[supreg] 8000 Pipe
Degradation in High Temperature Applications'' https://www.cpchem.com/sites/default/files/2020-05/DriscopipeDegradation.pdf
(last visited Mar. 1, 2023).
---------------------------------------------------------------------------
Following the Merrimack Valley incident, PHMSA reviewed its current
DIMP regulations for areas where additional clarification could improve
the safety of gas distribution pipelines. As climate change increases
the frequency of extreme weather events and natural forces that can
impact the integrity of pipelines, PHMSA proposes to add clarity to the
DIMP regulations to ensure that operators are considering these threats
when evaluating risks. Operators would, therefore, need to consider and
take appropriate action to address the impacts of extreme weather as a
threat, regardless of whether they had experienced such events in their
pipelines' history, while still recognizing regional differences. PHMSA
expects operators to continue evaluating reasonably available
information regarding changing operating environments (i.e., climate)
and the regional impacts of extreme weather on their pipeline.
c. PHMSA's Proposal To Amend Sec. 192.1007(b)--DIMP--Identify
Threats--Natural Forces Including Extreme Weather and Geohazards
PHMSA proposes to amend Sec. 192.1007(b) to specify that operators
must include the threat of extreme weather and geohazards as
subcategories under the threat category of ``natural forces.'' This
amendment would ensure that operators consider the threat of extreme
weather under the DIMP regulations. Once identified as a threat under
Sec. 192.1007(b), operators would be required to consider how
potential extreme weather events could increase the likelihood of
failure. They would also need to consider the potential consequences of
such a failure, as required in Sec. 192.1007(c), and ensure that they
identify risk-reduction measures and implement them under Sec.
192.1007(d). PHMSA expects that operators would not limit their
[[Page 61763]]
consideration of the threat of extreme weather solely on past normal
weather patterns but would also consider any anticipated increases in
extreme weather conditions and fluctuations. This proposed requirement
would improve safety by ensuring that operators address the impacts of
climate change and protect the reliability and integrity of their
pipeline systems, even if operators have yet to experience these issues
on their systems.
4. DIMP--Identify Threats (Sec. 192.1007(b))--Age of the System, Pipe,
and Components
a. Current Requirements--DIMP--Identify Threats--Age of the System,
Pipe, and Components
Section 192.1007(b) includes a generic threat category of ``other
issues that could threaten the integrity of [a] pipeline,'' which
operators should use to identify threats that do not fit into the other
threat categories. When performing their risk analysis, Sec.
192.1007(c) states that operators ``may subdivide [their] pipeline into
regions with similar characteristics.'' PHMSA has observed operators
using age as a method of subdividing their pipeline segments when
performing the risk analysis. Further, PHMSA's annual report form,
PHMSA F 7100.1-1, requires operators to identify the miles of pipeline
by decade of installation. Section 192.1007(b) does not, however,
specifically require that operators consider the age of a pipe or
components when identifying threats to pipeline integrity.
b. Need for Change--DIMP--Identify Threats--Age of the System, Pipe,
and Components
Over time, all pipeline systems are subject to time-dependent
degradation processes threatening pipeline integrity. Pipelines made
from ferrous materials (steel, wrought iron, cast iron, etc.) are all
susceptible to oxidation corrosion over time. Plastic and composite
materials used in pipelines are subject to photodegradation if exposed
to sunlight. Joints, fittings, and welds connecting various pipeline
components can be subject to dissimilar materials corrosion or chemical
degradation of bonding agents and sealants. And the longer the
timeline, the more any gas pipeline components are exposed to a variety
of phenomena--e.g., from internal mechanical stresses, changes in
temperature, changes in external loads (including external force
damage)--that threaten pipeline integrity, exacerbate existing material
weaknesses, or accelerate time-dependent degradation processes.
Age can impact and potentially modify each of the threats an
operator identifies in Sec. 192.1007(b). The potential threat to
pipeline integrity posed by age depends on the age of the pipeline
components of which it is comprised. PHMSA understands the cumulative
effect of those age-related threats to integrity across an entire
pipeline are not merely the sum of age-related, component-specific
threats; rather, those threats can magnify or exacerbate one another
when integrated within a pipeline system. For example, one component's
failure due to time-dependent degradation processes can strain other
components throughout the system (e.g., by releasing corrosion products
that can damage other, newer components within the system). PHMSA
further notes that trending failure rates by age can be a useful tool
for revealing degraded performance throughout a pipeline system.
Similarly, the overall age of the pipeline system can provide more
opportunities for safety-critical gaps in material records. Poor
recordkeeping with respect to a pipeline component dating from a
certain time period may threaten not only pipeline integrity on that
segment, but also other components of the same pipeline installed at a
different time period.
Age can also be expressed in terms of vintage of pipes or
components. Specific manufacturing techniques and materials used during
certain periods of time can result in similar characteristics among
pipes and components of a given vintage. The vintage of pipes or
components can interact with other threats, including materials,
equipment failures, or natural forces. For example, pipe installed
earlier than 1950 has disproportionately high susceptibility to
problems from cold weather and freezing, which could interact with the
threat of natural forces. The greater susceptibility of pre-1950 pipe
is thought to be due to inferior low-temperature ductility of the
steels of the era and the methods used to join pipe at the time (such
as electric arc welds, acetylene welds, couplings, and threaded
collars).\78\ Additionally, as described in section IV.A.1 (materials),
some of the early plastic piping products manufactured from the 1960s
and into the early 1980s are more susceptible to brittle-like cracking
(also known as slow-crack growth) than newer materials.\79\
---------------------------------------------------------------------------
\78\ M.J. Rosenfeld, ``Cold Weather Can Play Havoc On Natural
Gas Systems'' 242 Pipeline & Gas J. 1 (Jan. 2015), https://pgjonline.com/magazine/2015/january-2015-vol-242-no-1/features/cold-weather-can-play-havoc-on-natural-gas-systems.
\79\ Brittle-like cracking failures occur under conditions of
stress intensification. Stress intensification is more common in
fittings and joints.
---------------------------------------------------------------------------
Even though time-dependent degradation processes are widely
understood threats to the integrity of pipeline systems, as discussed
earlier, Sec. 192.1007(b) does not specifically state that operators
must account for the age of the system, pipe, and components in
identifying threats. Increasing failure rates have been observed in
older gas distribution infrastructure that has certain attributes.\80\
The increasing failure rate typically occurs toward the end of life and
accelerates the rate by which the reliability decreases. This behavior
is typically attributed to cumulative degradation that occurs in the
system over its service period. Trending failure rates by system age
can reveal degrading performance.
---------------------------------------------------------------------------
\80\ PHMSA, ``Pipeline Replacement Background'' (Apr. 26, 2021),
https://www.phmsa.dot.gov/data-and-statistics/pipeline-replacement/pipeline-replacement-background.
---------------------------------------------------------------------------
Recent incidents have illustrated that operators may be
inadequately identifying and managing threats related to the age of
components on their systems. For example, in its risk analysis, Atmos
used a commercially available software that did not explicitly consider
the age of the pipeline segments, instead grouping them into failure
categories based on similar attributes, such as material and coating.
Although such an approach may have been compliant with current
regulations, this approach to risk analysis disregards how the age
could contribute to failures. Following the 2018 Atmos incidents, the
NTSB recommended that Gas Piping Technology Committee develop guidance
and identify steps operators can take to ensure that their gas
distribution IM programs appropriately consider threats that degrade a
system over time.\81\ By adopting such a practice, operators would
recognize the full threat based on the impact of age and prioritize
remediating or replacing segments of the pipe and components that pose
more acute threats. PHMSA therefore proposes to revise Sec.
192.1007(b) to explicitly identify age as a factor in addressing
threats to integrity.
---------------------------------------------------------------------------
\81\ NTSB/PAR-21/01 at 82.
---------------------------------------------------------------------------
c. Proposal To Amend Sec. 192.1007(b)--DIMP--Identify Threats--Age of
the System, Pipe, and Components
PHMSA proposes to amend Sec. 192.1007(b) to clarify that operators
[[Page 61764]]
must, when identifying the threats on its distribution system, also
consider the age of the system, piping, and components in identifying
threats.\82\ For example, once an operator identifies a time-dependent
threat exists on their pipeline, such as corrosion, the operator would
then consider how the age of the pipe, or the components, could
influence the severity of the threat. All things equal, an older pipe
or component exposed to the threat of corrosion could carry additional
risk compared to newer pipe. Similarly, for time-independent threats,
such as natural forces, the operator would consider how the age of the
pipeline or components would expose the pipeline to multiple threats
over its lifetime, a threat that may evolve or increase over time.
PHMSA's proposal would ensure that the DIMP regulations explicitly
account for how the age of the system, pipes, and components contribute
to a pipeline's integrity degrading over time.
---------------------------------------------------------------------------
\82\ See Am. Soc'y of Mech. Eng's, ANSI B31.8S-2004, ``Managing
System Integrity of Gas Pipelines,'' at sec. 2 (Jan. 14, 2005).
---------------------------------------------------------------------------
5. DIMP--Evaluate and Rank Risk (Section 192.1007(c))
a. Current Requirements--DIMP--Evaluate and Rank Risk
Section 192.1007(c) requires that operators evaluate and rank the
risks associated with their distribution pipeline systems. This
evaluation must consider each applicable current and potential threat,
the likelihood of failure associated with each threat, and the
potential consequences of such a failure. Operators may subdivide their
distribution systems into regions (areas within a distribution system
consisting of mains, services, and other appurtenances) that have
similar characteristics and reasonably consistent risks, and for which
similar actions would be effective in reducing risk.
Through enforcement guidance, PHMSA recommended that operators
develop weighted factors for each threat specific to their system
depending upon their unique operating environment.\83\ PHMSA has
further stressed that it may be inadequate for operators to conclude
that a pipeline is not subject to any particular threat based solely on
the fact that it has not experienced a pipeline failure attributed to
the threat.\84\ PHMSA has used enforcement guidance to clarify that if
operators conclude that a particular threat is not applicable to
sections of their pipeline, then operators should document the basis
for drawing that conclusion.\85\ This basis should consider the
pipeline's failure history, design, manufacturing, construction,
operation, and maintenance.
---------------------------------------------------------------------------
\83\ DIMP Guidance at 22.
\84\ DIMP Guidance at 23.
\85\ DIMP Guidance at 18, 57.
---------------------------------------------------------------------------
b. Need for Change--DIMP--Evaluate and Rank Risk
Recent incidents have demonstrated the importance of operators
adequately evaluating and ranking risks on their systems and in their
DIMP plans. For example, as demonstrated by the 2018 Merrimack Valley
and other incidents investigated by the NTSB, some operators have not
been adequately evaluating the risk of overpressurization, and thus not
taking appropriate mitigating measures to account for those risks.\86\
Overpressurization incidents--in particular on low-pressure gas
distribution systems--merit mitigation because they have a high-
consequence. As previously noted, CMA had knowledge of the risks of an
overpressurization, updated their procedures, and still did not take
appropriate action to mitigate the risks. Similarly, the Atmos incident
in Texas demonstrated how operators can underestimate the risks
associated with the presence of leak-prone materials.
---------------------------------------------------------------------------
\86\ NTSB/PAR-19/02 at 18-21, 39-40, 48.
---------------------------------------------------------------------------
PHMSA is required by law to ensure that operators' DIMP plans
evaluate the presence and risks associated with cast iron piping and
the threat of overpressurization on low-pressure gas distribution
systems (49 U.S.C. 60109(e)(7)). PHMSA is also required to prohibit
operators, when evaluating risks related to the operation of a low-
pressure gas distribution system, from determining that there are no
potential consequences associated with low-probability events unless
that determination is supported by ``engineering analysis or
operational knowledge.'' PHMSA must also ensure that operators of gas
distribution systems consider factors other than past observed
``abnormal operating conditions''--as that term is defined at Sec.
192.803--when ranking risks and identifying measures to mitigate those
risks.
c. PHMSA's Proposal To Amend Sec. 192.1007(c)--DIMP--Evaluate and Rank
Risk
PHMSA proposes to redesignate the general requirements of Sec.
192.1007(c) under a new paragraph (c)(1). These general requirements
still require operators to consider the identified threats proposed in
Sec. 192.1007(b) as they evaluate and rank risks.
i. Certain Pipe Materials With Known Issues
PHMSA proposes to amend Sec. 192.1007(c) by creating a new Sec.
192.1007(c)(2) to specify that operators must evaluate the risks
resulting from pipelines constructed with certain materials (including
cast iron, bare steel, unprotected steel, wrought iron, and historic
plastics with known issues) when such materials are present in their
pipeline systems. Overall, these proposed requirements would improve
safety by codifying in DIMP requirements some of the known, industry-
wide threats if the materials that have exhibited these threats are
present in the operator's systems, even if operators have not yet
experienced any of these issues on their systems.
ii. Evaluate and Rank Risk: Low-Pressure Distribution Systems
PHMSA also proposes to amend Sec. 192.1007(c) by creating a new
Sec. 192.1007(c)(3) applicable to low-pressure distribution systems.
Consistent with the mandate in 49 U.S.C. 60109(e)(7), PHMSA proposes to
require operators of low-pressure gas distribution systems to evaluate
``the risks that could lead to or result from the operation of a low-
pressure distribution system at a pressure that makes the operation of
any connected and properly adjusted low-pressure gas burning equipment
unsafe.'' For the purposes of this NPRM, PHMSA determines that
``unsafe'' in this context means that gas flowing into the downstream
equipment is at a pressure beyond the rated supply pressure specified
by the manufacturer of that equipment. This amendment would ensure that
operators are addressing the risks on their pipeline that could result
in an overpressurization.
In evaluating the risks to low-pressure distribution systems, the
mandate in 49 U.S.C. 60109(e)(7)(B) requires PHMSA to ensure that
operators consider ``factors other than past observed abnormal
operating conditions [. . .] in ranking risks.'' This includes any
abnormal operating conditions (AOCs) that operators have experienced
(i.e., observed) on their system and any unobserved AOCs that could
occur on their system (i.e., an overpressurization on a low-pressure
system), including any known industry threats, risks, or hazards, as
identified by an operator from available sources (e.g., PHMSA advisory
bulletins, PHMSA incident and accident reports, PHMSA and NTSB accident
reports, State pipeline safety regulatory actions, and operator
knowledge sharing). PHMSA proposes
[[Page 61765]]
in Sec. 192.1007(c)(3)(i) to require operators of low-pressure systems
to evaluate risks to their systems in accordance with the mandate. This
amendment would ensure that operators are reviewing their past observed
operational performance to evaluate the risks on their systems. This
amendment would also ensure that operators are considering risks even
if they have yet to experience those risks on their systems. For
example, if an operator has not experienced an overpressurization on
its system, that operator must still consider the risks of an
overpressurization on its system.
The mandate in 49 U.S.C. 60109(e)(7)(B) also states that operators
may not determine that low probability events have no potential
consequences without a supporting determination. PHMSA proposes
integrating this mandate by adding a new paragraph Sec.
192.1007(c)(3)(ii) that will direct operators to evaluate the potential
consequences associated with low-probability events, unless a
determination--supported and documented by an engineering analysis or
other equivalent analysis incorporating operational knowledge--
demonstrates that the event results in no potential consequences (and
therefore no potential risk).
An engineering analysis would include documentation of the
engineering principles used to calculate the flows, pressures, and
other parameters of the piping and systems to calculate the actual
downstream pressure. This engineering analysis would also include
documentation of the methods used to determine that the system cannot
fail and cause overpressurization, including any data and assumptions
(including mitigation and control measures) utilized by the operator.
This engineering analysis may necessarily include degrees of measurable
operational knowledge regarding specific pipeline characteristics and
evidence from that analysis combined with documentable known pipeline
characteristics. An operator that determines there are no potential
consequences from a low-probability event must document all these
reasons as part of its ``engineering analysis'' submitted to PHMSA
according to Sec. 192.18 with sufficient detail as listed in Sec.
192.1007(c)(3)(ii)(A)-(F).
Because the statute requires operators to make an affirmative
determination that there are no potential consequences associated with
low probability events and recognizing that some operators might not
have fully considered the risk of low-probability events based solely
on operational knowledge, PHMSA proposes that any operational knowledge
relied upon must include with it a quantifiable assessment and support
the operator's determination with a level of rigor equal to that of an
engineering analysis. This operational knowledge could be included as
part of the proposed regulatorily required ``engineering analysis, or
an equivalent analysis,'' as used in Sec. 192.1007(c)(3)(ii). For
example, should an operator determine that a release of gas from the
pipeline, such as a leak, has no potential consequences, the operator
should include documentation demonstrating that many scenarios were
considered (such as a leak with ignition or gas migration under nearby
pavement) and that no potential consequences were identified in any of
those potential scenarios. This amendment would ensure that operators
do not dismiss material risks without a meaningful evidentiary basis,
and PHMSA or pertinent State authorities would have the opportunity to
review and consider the validity of the operator's determination when
reviewing DIMP plans.
State regulatory authorities already review operators' DIMP plans
during regular inspections. Because incorrectly determining that a
potential threat has no consequences would have serious public safety
impacts, however, PHMSA understands there is a compelling policy reason
for an operator's determination that a low-frequency event entails zero
risk be reviewed by those State regulatory authorities as well as
PHMSA. Therefore, if operators choose to apply the proposed exception
in Sec. 192.1007(c)(3)(ii), they must notify PHMSA and the appropriate
State Authority in accordance with Sec. 192.18 within 30 days of
making this determination that there are no potential consequences
associated with the low-probability event. The notification must
include information such as the date the determination was made (to
ensure compliance with the proposed timeline), descriptions of the low-
probability events being considered, and a description of the logic
supporting the determination, including information from an engineering
analysis or an equivalent analysis incorporating operational knowledge.
Further, this notification should contain a description of any
preventive and mitigative measures, including any measures considered
but not taken, as determined through the engineering analysis or an
equivalent analysis incorporating operational knowledge. The
notification should also include a description of the low-pressure
system, including, at a minimum, miles of pipe, number of customers,
number of district regulators supplying the system, and other relevant
information. In addition, operators must provide a written statement
summarizing the documentation it evaluated and how the conclusion that
there would be no potential consequences associated with the low-
probability event was reached. This documentation could include the
inspection and maintenance history of the pipeline segment, incident
reports, any leak repair data, and any failure investigations or
abnormal operations records. Providing this information would be
critical in ensuring that operators robustly evaluated methods of
reducing risk and that the operator did not ignore any material factors
in their engineering analysis or an equivalent analysis incorporating
operational knowledge.
In a new Sec. 192.1007(c)(3)(iii), PHMSA proposes to require that
in evaluating and ranking risks in their DIMP plans, operators of low-
pressure gas distribution systems must evaluate the configuration of
their primary and any secondary overpressure protection installed at
the district regulator stations, the availability of gas pressure
monitoring at or near overpressure protection equipment, and the
likelihood of any single event that immediately or over time could
result in an overpressurization of the low-pressure system (see amended
Sec. 192.195(c)). Operators' overpressure protection configurations
vary--some include a combination of relief valves, monitoring
regulators, or automatic shutoff valves. Other operators have real-time
monitoring devices located at the district regulator station, while yet
others rely on telemetering devices. Some operators, as demonstrated by
the events of September 13, 2018, may have an overpressure protection
configuration that can be defeated by a single event, such as
excavation damage, natural forces, an equipment failure, or incorrect
operations. This amendment would ensure that operators are evaluating
their existing overpressure protection system for inadequacies or
additional risks that could result in an overpressurization of the
system.
[[Page 61766]]
6. DIMP--Identify and Implement Measures To Address Risks (Section
192.1007(d))
a. Current Requirements--DIMP--Identify and Implement Measures To
Address Risks
Section 192.1007(d) requires operators to determine and implement
measures designed to reduce the risks from failure of their gas
distribution pipeline systems following the identification of threats
(in accordance with Sec. 192.1007(b)) and the evaluation and ranking
of risks (in accordance with Sec. 192.1007(c)). Section 192.1007(d)
also requires that these risk mitigation measures include an effective
leak management program (unless all leaks are repaired when found).
Although the specific process is not defined in Sec. 192.1007(d),
PHMSA has issued guidance material to support the implementation of
these requirements.
In the guidance material, PHMSA states that operators should have a
documented list of measures to reduce risks identified on their
pipeline system.\87\ The process for identifying risk mitigation
measures must be based on identified threats to each pipeline segment
and the risk analysis. Operators should rank pipeline segments and
group segments that represent the highest risk as the most important
candidates for which measures are taken to reduce risk. The operator
should ensure that the highest priority measures for reducing risk are
for the highest-ranked segments as indicated by the risk analysis.
Because the design and operation of gas distribution systems are so
diverse, no single risk control method is appropriate in all cases.
Therefore, the objective of Sec. 192.1007(d) is to ensure that each
operator has documented and described existing and proposed measures to
address the unique risks to its system and that the operator has
evaluated and prioritized actions to reduce risks to pipeline
integrity.
---------------------------------------------------------------------------
\87\ DIMP Guidance at 28.
---------------------------------------------------------------------------
b. Need for Change--DIMP--Identify and Implement Measures To Address
Risks
Proper implementation of a DIMP plan should result in aggressive
oversight and replacement of higher-risk infrastructure. For example,
there are many benefits to replacing old, cast-iron, low-pressure
distribution pipes with newer materials, such as modern plastic pipe.
Replacement projects, however, entail their own risks to public safety
and the environment that need to be balanced against the risks
associated with leaving a pipeline segment undisturbed. Poorly managed
construction projects can result in property damage and personal
injury, and replacement activity can include blowdowns to the
atmosphere of methane gas that contribute to climate change. Work on
existing pipeline facilities can also cause a catastrophic
overpressurization, as was the case in CMA's 2018 incident. Operators
must manage those risks while still implementing preventive and
mitigative measures that would reduce the risk of identified threats.
In 2020, PHMSA issued an advisory bulletin to remind operators of
the possibility of failure due to an overpressurization on low-pressure
distribution systems.\88\ In that advisory bulletin, PHMSA reminded
operators of the existing DIMP regulations and recommended that per
Sec. 192.1007(d), operators take additional actions to reduce risks if
they found their current overpressure protection design to be
insufficient. PHMSA also identified for operators that ``[t]here are
several ways that operators can protect low-pressure distribution
systems from overpressure events,'' such as:
---------------------------------------------------------------------------
\88\ See ``Pipeline Safety: Overpressure Protection on Low-
Pressure Natural Gas Distribution Systems,'' ADB-2020-02, 85 FR
61097 (Sept. 29, 2020).
---------------------------------------------------------------------------
1. Installing a full-capacity relief valve downstream of the low-
pressure regulator station, including in applications where there is
only worker-monitor pressure control;
2. Installing a ``slam shut'' device;
3. Using telemetered pressure recordings at district regulator
stations to signal failures immediately to operators at control
centers; and
4. Completely and accurately documenting the location for all
control (i.e., sensing) lines on the system.
As discussed earlier, subsequent to the 2018 Merrimack Valley
incident, PHMSA was required by statute to ensure that operators of
low-pressure gas distribution systems evaluate the risk of
overpressurization in their DIMP plans. (49 U.S.C. 60109(e)(7)(A)(ii)).
For existing low-pressure systems, operators already have a mechanism
in place--their DIMP--to evaluate their systems to ensure they can
identify and implement measures to minimize the risk imposed by any
inadequate overpressure protection.
c. PHMSA's Proposal To Amend Sec. 192.1007(d)--DIMP--Identify and
Implement Measures To Address Risks
PHMSA proposes to amend Sec. 192.1007(d) to establish additional
criteria for operators to evaluate when identifying and implementing
measures to address risks identified in DIMP plans. PHMSA's proposal
would require operators--when identifying and implementing measures--to
specifically account for risks associated with the age of the pipe, the
age of the system, the presence of pipes with known issues, and
overpressurization of low-pressure distribution systems. PHMSA is
adding these specific risks to Sec. 192.1007(d) because they were the
subject of recent incidents, as discussed earlier. This amendment would
ensure that operators are not only identifying these specific threats
(in Sec. 192.1007(b)), but also implementing measures to address those
risks. In a new Sec. 192.1007(d)(2), PHMSA is proposing to explicitly
require operators of existing low-pressure systems to take certain
actions to prevent and mitigate the risk of an overpressurization that
could be the result of any single event or failure. These actions
include identifying, maintaining, and (if necessary) obtaining
traceable, verifiable, and complete records that document the
characteristics of the pipeline that are critical to ensuring proper
pressure controls for the system. PHMSA discusses the criteria for
these pressure control records in section IV.F of this NPRM.
In addition to this recordkeeping requirement, in a new Sec.
192.1007(d)(2), PHMSA proposes that operators must confirm and document
that each district regulator station meets the design standards in
Sec. 192.195(c)(1)-(3) or take the following actions: (1) identify
preventative and mitigative measures based on the unique
characteristics of their system to minimize the risk of
overpressurization on low-pressure systems, or (2) upgrade their
systems to meet design standards in Sec. 192.195(c)(1)-(3). PHMSA
discusses the criteria for this proposed upgrade in section IV.H of
this NPRM. Should an operator choose to identify preventative and
mitigative measures based on the unique characteristics of their system
to minimize the risk of overpressurization, PHMSA proposes that the
operator notify PHMSA and State or local pipeline authorities no later
than 90 days in advance of implementing any alternative measures. PHMSA
proposes that an operator must make this notification in accordance
with Sec. 192.18, which would include a description of the operator's
proposed alternative measures, identification, and location of
facilities to which the measures would be applied, and a description of
how the measures would
[[Page 61767]]
ensure the safety of the public, affected facilities, and environment.
This notification would ensure that operators are keeping PHMSA and
State authorities informed of alternative measures to address risk.
This amendment would apply to existing low-pressure systems that have
evaluated and identified inadequate overpressure protections in
accordance with Sec. 192.1007(c).
PHMSA has also proposed to amend Sec. 192.18 to reflect this
proposed change by including a reference to Sec. 192.1007. Should an
operator choose to implement an alternative method of minimizing
overpressurization, PHMSA proposes that the operator notify PHMSA and
State or local pipeline authorities no later than 90 days in advance of
implementing any alternative measures. PHMSA proposes that operators
must make this notification in accordance with Sec. 192.18, which
would include a description of the operators' proposed alternative
measures, identification, and location of facilities to which the
measures would be applied, and a description of how the measures would
ensure the safety of the public, affected facilities, and environment.
This notification would ensure that operators are keeping PHMSA and
State authorities informed of alternative measures to address risk.
PHMSA proposes these amendments pursuant to 49 U.S.C. 60102(t) and
60109(e)(7). The proposed amendments would reinforce the recommended
actions from PHMSA's 2020 advisory bulletin in which PHMSA identified
for operators of low-pressure distribution systems the risks inherent
to those systems and the preventative or mitigative measures they
should implement to address the risk of overpressurization. PHMSA
expects that operators may already be complying with many of these
practices subsequent to issuance of the advisory bulletin, which set
forth PHMSA's existing policy and interpretation of the current DIMP
requirements. In this NPRM, PHMSA proposes to codify this existing
policy and interpretation in its regulations.
This amendment is also aligned with the NTSB's clarification to
recommendation P-19-14 that PHMSA would not have to require that
existing low-pressure gas distribution systems be completely
redesigned; rather, PHMSA may satisfy the recommendation by requiring
operators to add additional protections, such as slam-shut or relief
valves, to existing district regulator stations or other appropriate
locations in the system.\89\
---------------------------------------------------------------------------
\89\ NTSB clarified this in an official correspondence to PHMSA
on July 31, 2020. NTSB, ``Safety Recommendation P-19-014'' (July 31,
2020), https://data.ntsb.gov/carol-main-public/sr-details/P-19-014.
---------------------------------------------------------------------------
7. DIMP--Small LPG Operators (Section 192.1015)
a. Current Requirements--DIMP and Annual Reporting for Small LPG
Operators
A ``small LPG operator'' is currently defined at Sec. 192.1001 as
an operator of a liquefied petroleum gas (LPG) distribution pipeline
system that serves fewer than 100 customers from a single source. Small
LPG operators are treated differently in the DIMP regulations than
larger operators and they follow their own set of DIMP requirements in
Sec. 192.1015 that reflect the relative simplicity of these pipeline
systems. The current DIMP requirements for small LPG operators in Sec.
192.1015 are less extensive than for other gas distribution systems,
but still provide operator personnel direction for implementing their
DIMP plans. Currently, under Sec. 191.11, operators of small LPG
systems are not required to submit an annual report to PHMSA.
b. Need for Change--DIMP--Applicability for Small LPG Operators
In the 2009 DIMP Final Rule, PHMSA imposed requirements for small
LPG operators similar to those for other operators but with more
limited requirements for documentation, consistent with how these
operators are treated throughout the pipeline safety regulations. PHMSA
did not require operators to report performance measures as they do not
file annual reports. Although the DIMP requirements for small LPG
operators are similar to those applicable to other operators, PHMSA
codified them separately under Sec. 192.1015, emphasizing that DIMPs
for small LPG operators should reflect the relative simplicity of their
pipeline systems.
On January 11, 2021, PHMSA issued a final rule titled ``Pipeline
Safety: Gas Pipeline Regulatory Reform,'' \90\ which among other
things, excepted master meters from the DIMP requirements. During the
development of that rule, PHMSA received several comments in support of
extending that exception to small LPG operators. For example, the
National Association of Pipeline Safety Representatives (NAPSR)
suggested that small gas distribution utilities with 100 or fewer
customers--including small LPG operators--should be excepted from the
DIMP requirements, stating that many master meter systems, small
distribution systems, and small LPG systems typically have no threats
beyond the minimum threats listed in Sec. 192.1015(b)(2). Various
other commenters, including the National Propane Gas Association
(NPGA), AmeriGas, and Superior Plus Propane, voiced support for
excepting small LPG operators from the DIMP requirements. The Pipeline
Safety Trust did not oppose an exception from DIMP requirements for
master meter systems in that rulemaking, only urging PHMSA and its
State partners to ensure that master meter operators are managing the
integrity risks to their systems outside the context of a DIMP plan. In
response, PHMSA in the Gas Regulatory Reform Final Rule stated, ``that
the decision about whether to extend the DIMP exception to [other]
facilities or to all distribution systems with fewer than 100 customers
would benefit from additional safety analysis and notice and comment
procedures prior to further consideration.'' PHMSA went on to say that
it would ``continue to evaluate the issue of DIMP requirements for
small LPG systems and, if appropriate, propose changes in a future
rulemaking[.]'' \91\
---------------------------------------------------------------------------
\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).
---------------------------------------------------------------------------
[[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\
---------------------------------------------------------------------------
\94\ NPGA Petition at 3.
---------------------------------------------------------------------------
NPGA reiterated that PHMSA further noted in the 2021 Gas Regulatory
Reform Final Rule that the agency's experience indicated the analysis
and documentation requirements of DIMP had little safety benefit for
this type of operator and that focusing on more fundamental risk
mitigation activities has more safety benefits than implementing a DIMP
for this class of operators. NPGA went on to reiterate PHMSA's position
in the Gas Regulatory Reform Final Rule (as discussed above), where
PHMSA indicated that exempting master meter operators from subpart P
would result in cost savings for master meter operators without
negatively impacting safety. NPGA stated that PHMSA had previously
expressed its intention to address small LPG systems in a future
rulemaking and added that this change would not conflict with the
Administration's aims of reducing methane emissions.\95\
---------------------------------------------------------------------------
\95\ NPGA Petition at 3-5. PHMSA notes that LPG releases are not
themselves generally considered to be releases of GHGs.
---------------------------------------------------------------------------
PHMSA has reviewed and considered NPGA's petition and agrees with
its assertion that small LPG systems do not present the same complexity
or incur the same risks as large networks of pipeline systems crossing
hundreds of miles. Therefore, PHMSA addresses NPGA's petition through
this proposed rule and continued oversight through partnership with
State agencies.
PHMSA has concluded that its existing approach requiring small LPG
operators to comply with limited DIMP requirements offers little public
safety benefit. Small LPG operators by definition have limited systems
serving a small number of customers; in fact, NAPSR data suggests that
there are only between 3,800 and 5,800 multi-user systems nationwide,
with most serving fewer than 50 customers (often well below 50
customers).\96\ Small LPG systems are also more simple systems--less
piping and fewer components that could fail--that are inherently less
susceptible to loss of pipeline integrity than large gas distribution
systems. Further, PHMSA incident data indicate that small LPG systems
entail relatively low public safety risks. PHMSA's incident data
suggest small LPG systems average less than one incident involving a
fatality or serious injury per year. Incidents reported by operators to
PHMSA from 2010 through 2017 include 10 incidents, seven injuries, and
approximately $2 million in property damage.\97\ No fatalities have
been reported since 2006. Incorporating fire events from the National
Fire Incident Reporting System with the PHMSA incident data suggests
that the number of incidents involving LPG distribution systems
averages in the single digits per year. And, because releases of LPG
are not themselves generally considered GHG emissions, continued
regulation of small LPG systems pursuant to PHMSA's DIMP requirements
provides little benefit for mitigating climate change.
---------------------------------------------------------------------------
\96\ NAS Study at 83.
\97\ NAS Study at 41, Table 3-4.
---------------------------------------------------------------------------
PHMSA understands that even limited DIMP requirements can place a
significant compliance burden on small LPG operators and administrative
burdens on PHMSA and State regulatory authorities--which in turn can
detract from other safety efforts. A 2018 study issued by the NAS found
that there is significant regulatory uncertainty among small LPG
operators regarding whether PHMSA's DIMP regulations apply at all--
resulting in many such operators neither understanding they are obliged
to comply with PHMSA regulations nor being regularly inspected by State
regulatory authorities.\98\
---------------------------------------------------------------------------
\98\ The NAS Study identified as a source of much of that
regulatory uncertainty the varied interpretations of ``public
place'' used at Sec. 192.1(b)(5) to determine if certain petroleum
gas systems are subject to PHMSA's 49 CFR part 192 regulations. NAS
Study at 87-88.
---------------------------------------------------------------------------
Given their small size and the relative simplicity of their
systems, as discussed in the preceding paragraphs, and the significant
compliance burden that DIMP requirements impose on such entities with
limited safety benefit, PHMSA has determined that it is more
appropriate to exempt small LPG operators from DIMP requirements but
impose an annual reporting requirement on these operators.
c. PHMSA's Proposal To Exempt Small LPG Operators From DIMP
Requirements and Extend Annual Reporting Requirements to Small LPG
Systems
PHMSA proposes to add a new Sec. 192.1003(b)(4) and delete
existing Sec. 192.1015 to remove small LPG operators from DIMP
requirements but extend annual reporting requirements to these
operators. With small LPG operators removed from DIMP requirements at
Sec. 192.1015, the definition of small LPG operators in Sec. 192.1001
becomes redundant and therefore PHMSA would also remove it from DIMP.
In developing this proposal, PHMSA considered the comments made in the
Gas Regulatory Reform Final Rule on the topic of the application of
DIMP requirements to small LPG operators, the NPGA's petition for
rulemaking, the NAS study, and PHMSA's incident data. PHMSA has
preliminarily determined that continuing to impose DIMP requirements
(even in the abbreviated form pursuant to existing Sec. 192.1015) on
small LPG systems that have been proven by PHMSA incident data to
entail inherently limited public safety risks imposes outsized
compliance burdens on operators and administrative burdens on PHMSA and
State regulatory authorities.\99\ At the same time, extending the
annual reporting requirement to these operators is intended to ensure
that PHMSA will maintain the ability to identify and respond to
systemic or emerging issues on those systems.
---------------------------------------------------------------------------
\99\ Nor does PHMSA expect that small LPG operators would
experience improvements in pipeline safety from the regulatory
amendments that PHMSA is proposing in this NPRM for other (larger)
gas distribution operators. For example, PHMSA's incident data from
2010 through 2021 shows 12 incidents involving propane gas. In
reviewing those incidents, PHMSA found that the age, material type,
and operations of low-pressure distribution systems were not
relevant to small LPG operators serving fewer than 100 customers;
nor did those incidents involved an exceedance of MAOP.
---------------------------------------------------------------------------
PHMSA does not expect that this proposed exception from DIMP
requirements would adversely impact public safety. As discussed above,
PHMSA understands the public safety benefits attributable to existing,
limited DIMP requirements for small LPG operators are limited. PHMSA
will be able to retain regulatory oversight of small LPG operator
systems through
[[Page 61769]]
other requirements within 49 CFR part 192, including the proposed
annual reporting requirement and the incident reporting requirements at
49 CFR part 191.
To improve the information available to PHMSA and State regulatory
authorities for identifying and addressing systemic public safety
issues from small LPG systems, PHMSA is proposing to revise Sec.
191.11 to require operators of small LPG systems to submit annual
reports using newly designated form PHMSA F 7100.1-2. These annual
reports would require operators of small LPG systems to report the
location and number of customers served by their distribution pipeline
systems, as well as the disposition of any discovered leaks. PHMSA
expects that through an annual reporting requirement, PHMSA would also
be able to provide better data to the public on small LPG systems,
which the agency could assess and may ultimately inform a future
rulemaking. PHMSA also expects that its proposal to require annual
reporting for small LPG operators may help alleviate the confusion
noted by the NAS Study regarding whether those operators are subject to
PHMSA regulations at 49 CFR part 192.
PHMSA expects the extension of its part 191 annual reporting
requirements to small LPG systems would be reasonable, technically
feasible, cost-effective, and practicable. The information PHMSA
collects on its current annual report form for gas distribution
operators (Form F7100.1-1) does not require significant technical
expertise or particularly expensive equipment to populate; small LPG
operators may also reduce their burdens further by contracting with
vendors to operate and perform maintenance on their systems and
complete annual report forms. PHMSA also expects that the forthcoming
annual report form (PHMSA F 7100.1-2) specific to small LPG operators
will be a further simplified version of the current annual report form.
Additionally, PHMSA notes that the information it expects will be
collected within that simplified annual report form--operator corporate
information, length and composition of the system, leaks on that
system, etc.--is minimal information that a reasonably prudent small
LPG operator would maintain in ordinary course given that their systems
transport pressurized (natural, flammable, toxic, or corrosive) gasses.
Viewed against those considerations and the compliance costs estimated
in section V.D herein and the PRIA, PHMSA expects the new annual
reporting requirement for these operators will be a cost-effective
approach to ensuring PHMSA has adequate information to monitor the
public safety and environmental risks associated with small LPG systems
that would no longer be subject to DIMP requirements. Lastly, PHMSA
expects that the compliance timeline proposed for this new reporting
requirement--which would begin with the first annual reporting cycle
after the effective date of any final rule issued in this proceeding
(which would necessarily be in addition to the time since publication
of this NPRM)--would provide affected operators ample time to compile
requisite information and familiarize themselves with the new annual
report form (and manage any related compliance costs).
B. State Pipeline Safety Programs (Sections 198.3 and 198.13)
1. Current Requirements--State Programs and Use of SICT
PHMSA relies heavily on its State partners for inspecting and
enforcing the pipeline safety regulations. The pipeline safety
regulations provide that States may assume safety authority over
intrastate pipeline facilities, including gas pipeline, hazardous
liquid pipeline, and underground natural gas storage facilities through
certifications and agreements with PHMSA under 49 U.S.C. 60105 and
60106. States may also act as an interstate agent on behalf of DOT to
inspect interstate pipeline facilities for compliance with the pipeline
safety regulations pursuant to agreement with PHMSA.
To support states' pipeline safety programs, PHMSA provides grants
to reimburse up to 80 percent of the total cost of the personnel,
equipment, and activities reasonably required by the State agency to
conduct its safety programs during a given calendar year. 49 CFR part
198 contains regulations governing grants to aid State pipeline safety
programs. PHMSA also maintains ``Guidelines for States Participating in
the Pipeline Safety Program'' (``Guidelines''), which contains guidance
for how State pipeline safety programs should conduct and execute their
delegated responsibilities.\100\ The Guidelines promote consistency
among the many State agencies that participate under certifications and
agreements and are updated on an annual basis.
---------------------------------------------------------------------------
\100\ PHMSA, ``Guidelines for States Participating in the
Pipeline Safety Program'' (Jan. 2022), https://www.phmsa.dot.gov/sites/phmsa.dot.gov/files/2020-07/2020-State-Guidelines-Revision-with-Appendices-2020-5-27.pdf.
---------------------------------------------------------------------------
In 2017, PHMSA adopted within its Guidelines the State Inspection
Calculation Tool (SICT), a tool that helps states conduct an inspection
activity needs analysis for regulatory oversight of every operator
subject to its jurisdiction, for the purpose of establishing a base
level of inspection person-days \101\ needed to maintain an adequate
pipeline safety program.\102\ In the SICT, each State agency considers
the type of inspection it needs to conduct (e.g., standard,
comprehensive, integrity management, operator qualification, damage
prevent activities, drug and alcohol); analyzes each operator's system
for several risk factors (e.g., cast iron pipe, replacement
construction activity, compliance issues); assigns each operator a risk
ranking based on the risk factors (e.g., leak prone pipe would have a
higher score than modern, coated, and cathodically protected pipe); and
lists other unique concerns and considerations (e.g., travel distance
to conduct the inspection) applicable to each operator.\103\ Each State
agency proposes an inspection activity level for each operator, which
is subsequently peer-reviewed before being finalized by PHMSA. PHMSA
expects that each State agency will dedicate a minimum of 85 inspection
person-days for each of its full-time pipeline safety inspectors for
pipeline safety compliance activities each calendar year.\104\ PHMSA
considers a State agency's inspection activity level, among several
other factors, when awarding grants to State pipeline safety programs.
---------------------------------------------------------------------------
\101\ PHMSA proposes below that an inspection person-day means
``all or part of a day, including travel, spent by State agency
personnel in on-site or virtual evaluation of a pipeline system to
determine compliance with Federal or State Pipeline Safety
Regulations.''
\102\ The SICT is located on PHMSA's access restricted database
portal.
\103\ Instructions for how to use the SICT and inspection
activity needs analysis examples are in the Guidelines.
\104\ This 85-day requirement is not tied to each individual
inspector. It is an 85-day average over all inspectors.
---------------------------------------------------------------------------
2. Need for Change--State Programs and Use of the SICT
A State is authorized to enforce safety standards for intrastate
pipeline facility or intrastate pipeline transportation if the State
submits annually to PHMSA a certification that complies with 49 U.S.C.
60105(b) and (c). As amended in 2020, the certification includes a
requirement that each State agency have the capability to sufficiently
review and evaluate the adequacy of each distribution system operator's
DIMP plan, emergency response plan, and operations, maintenance, and
emergency procedures, as well as ``a
[[Page 61770]]
sufficient number of employees'' to help ensure the safe operations of
pipeline facilities, as determined by the SICT. (49 U.S.C. 60105(b)).
PHMSA updates Guidelines and its evaluation process annually to ensure
that State agencies are meeting the certification requirements.\105\
---------------------------------------------------------------------------
\105\ PHMSA anticipates issuing updated Guidance to reflect the
changes to the Pipeline Safety Grant Program.
---------------------------------------------------------------------------
In certifying that the State has a ``sufficient number of
employees'', the State must use the SICT to account for:
1. The number of miles of gas and hazardous liquid pipelines in the
State, including the number of miles of cast iron and bare steel
pipelines;
2. The number of services in the State;
3. The age of the gas distribution systems in the State; and
4. Environmental factors that could impact the integrity of the
pipeline, including relevant geological issues.
Currently, the SICT accounts for the size (e.g., mileage, service
line count, etc.) of each operator's system; type of operator and
product being transported; risk factors of material composition,
including but not limited to, the presence of cast iron and bare steel;
and environmental factors that could impact the integrity of a
pipeline, including geological issues. Total miles of gas and hazardous
liquid pipelines in a State and the age of gas distribution systems
are, however, only implicitly considered. To comply with the mandate,
PHMSA proposes to codify within its regulations the use of the SICT for
establishing inspection person-days and update the SICT to explicitly
include the total gas or hazardous liquid pipeline mileage in the State
and the age of a gas distribution system as a factor for consideration.
3. PHMSA's Proposal To Codify the Use of the SICT in Pipeline Safety
Regulations
This NPRM proposes amendments to the pipeline safety regulations at
49 CFR part 198 to codify use of the SICT by all PHMSA's State partners
holding certifications or agreements per 49 U.S.C. 60105 or 60106.
Specifically, PHMSA proposes to revise Sec. 198.3 to add definitions
for ``inspection person-day'' and ``State Inspection Calculation Tool''
and by revising Sec. 198.13 to include the use of the SICT for
determining inspection person-days. PHMSA proposes to define
``inspection person-day'' to mean ``all or part of a day, including
travel, spent by State agency personnel in on-site or virtual
evaluation of a pipeline system to determine compliance with Federal or
State Pipeline Safety Regulations.'' PHMSA will continue to permit
travel to be included for inspection person-days even if travel
requires a full day before or after the inspection because some states
cover a large geographical area that requires substantial travel time
and a State agency's staffing requirement could be impacted if travel
is not considered. PHMSA will also continue to allow inspection person-
days to be counted for those individuals who have not completed
training requirements but who assist in inspections if they are
supervised by a qualified inspector. PHMSA proposes to define the term
``State Inspection Calculation Tool (SICT)'' to mean ``a tool used to
determine the required minimum number of annual inspection person-days
for a State agency.'' These proposed definitions are consistent with
those in the Guidelines.
PHMSA is required to promulgate regulations to require that a State
authority with a certification under 49 U.S.C. 60105 has a sufficient
number of qualified inspectors to ensure safe operations, as determined
by the SICT and other factors determined appropriate by the Secretary.
(49 U.S.C. 60105 note). Pursuant to this legal requirement, PHMSA
proposes revising Sec. 198.13(c)(6) to state that when allocating
funding and considering various performance factors, PHMSA considers
the number of State inspection person-days, ``as determined by the SICT
and other factors.'' These amendments would codify PHMSA's current
practice of using the SICT in the determination of the minimum number
of inspection person-days each State must dedicate to inspections in a
given calendar year.
C. Emergency Response Plans (Section 192.615)
The pipeline safety regulations require operators to have written
procedures for responding to emergencies involving their pipeline
systems to ensure a coordinated response to a pipeline emergency. This
response includes communicating with fire, police, and other public
officials promptly. Through a final rule issued on April 8, 2022,
titled ``Requirement of Valve Installation and Minimum Rupture
Detection Standards'', PHMSA extended that emergency communication for
all gas pipeline operators to include a public safety answering point
(PSAP; i.e., 9-1-1 emergency call center).\106\ Among other changes,
the Valve Rule amended Sec. 192.615(a) to ensure proper communication
with PSAPs, requiring operators to immediately and directly notify
PSAPs upon notification of a potential rupture. However, the Valve Rule
requirements were not in effect at the time of the Merrimack Valley
incident.
---------------------------------------------------------------------------
\106\ 87 FR at 20940, 20973.
---------------------------------------------------------------------------
Subsequent to the 2018 Merrimack Valley incident, 49 U.S.C. 60102
was amended to improve the emergency response and communications of gas
distribution operators during gas pipeline emergencies in several ways.
Specifically, 49 U.S.C. 60102(r) was added, which requires PHMSA to
promulgate regulations ensuring that gas distribution operators develop
written emergency response procedures for notifying and communicating
with emergency response officials as soon as practicable from the time
of confirmed discovery of certain gas pipeline emergencies; communicate
with the public during and after such a gas pipeline emergency; and
establish an opt-in system for operators to rapidly communicate with
customers. Gas distribution operators must make their updated emergency
response plans available to PHMSA or the relevant State regulatory
agency within 2 years after the final rule is issued, and every 5 years
thereafter (49 U.S.C. 60108(a)(3)).
PHMSA, in this NPRM, proposes building on the Valve Rule's changes
to emergency response plan requirements through additional changes to
ensure prompt and effective emergency response coordination. For all
gas pipeline operators subject to Sec. 192.615,\107\ PHMSA proposes to
expand the requirements to have procedures for a prompt and effective
response to include emergencies involving notification of potential
ruptures, a release of gas that results in a fatality, and any other
emergencies deemed significant by the operator, with similar
requirements to notify PSAPs in those instances. PHMSA understands
these proposed amendments of existing emergency response plan
requirements as applicable to all part 192-regulated pipelines would be
reasonable, technically feasible, cost-effective, and practicable. The
proposed changes are common-sense, incremental supplementation of
current requirements regarding the content and execution of emergency
response plans for gas pipeline operators.
[[Page 61771]]
Implementation of the proposed requirements should not require special
expertise or investment in expensive new equipment; PHMSA expects that
some operators may already comply with these proposed requirements
either voluntarily or due to similar requirements imposed by State
pipeline safety regulators. And insofar as these incremental proposed
additions to emergency planning requirements are consistent with
historical PHMSA guidance, industry operational experience, and the
lessons learned from incidents such as the Merrimack Valley incident,
they are precisely the sort of actions a reasonably prudent operator of
any gas pipeline facility would maintain in ordinary course given that
their systems transport commercially valuable, pressurized (natural
flammable, toxic, or corrosive) gasses. Viewed against those
considerations and the compliance costs estimated in the PRIA, PHMSA
expects its proposed amendments are a cost-effective approach to
achieving the commercial, public safety, and environmental benefits
discussed in this NPRM and its supporting documents. Lastly, PHMSA
understands that its proposed compliance timeline--one year after
publication of a final rule (which would necessarily be in addition to
the time since publication of this NPRM)--would provide operators ample
time to implement requisite changes to their procedures (and manage any
related compliance costs).
---------------------------------------------------------------------------
\107\ PHMSA notes that Sec. 192.9(d) does not currently require
compliance with Sec. 192.615 for Type B gathering lines, however
PHMSA has proposed, in another rulemaking, to amend Sec. 192.9(d)
to require Type B gas gathering operators to comply with Sec.
192.615. See 88 FR at 31952-53, 31955-56.
---------------------------------------------------------------------------
PHMSA proposes additional requirements for gas distribution
operators. First, those operators would be subject to an expanded list
of emergencies that includes unintentional releases of gas with
significant associated shutdown of customer services. Second, gas
distribution operators must establish written procedures for
communications with the general public during an emergency, and
continue communications through service restoration and recovery
efforts, to inform the public of the emergency and service restoration
and recovery efforts. Third, gas distribution operators would be
required to develop and implement for their customers an opt-in or opt-
out notification system to provide them with direct communications
during a gas pipeline emergency. PHMSA understands its proposed
amendments enhancing existing emergency response plan requirements
would be reasonable, technically feasible, cost-effective, and
practicable for affected gas distribution operators. PHMSA expects that
some gas distribution operators may already comply with these
requirements either voluntarily or due to similar requirements imposed
by State pipeline safety regulators. PHMSA also expects that operators
will already have (due to the need to bill their customers) the
requisite contact information needed to implement voluntary opt-in or
opt-out notification systems; as explained below, some operators may
also be able to leverage existing emergency notification systems
maintained by local and State government officials in satisfying this
proposed requirement. PHMSA further notes that its proposed
enhancements for emergency communications are precisely the sort of
minimal actions a reasonably prudent operator of gas distribution
pipeline facility would undertake in ordinary course to protect each of
(1) the public safety, given that their systems transport pressurized
(natural, flammable, toxic, or corrosive) gasses; and (2) their
customers, given the economic cost to those customers from interruption
of supply. Viewed against those considerations and the compliance costs
estimated in the PRIA, PHMSA expects its proposed amendments will be a
cost-effective approach to achieving the public safety and
environmental benefits discussed in this NPRM and its supporting
documents. Lastly, PHMSA understands that its proposed compliance
timeline--between 12 to 18 months after publication of a final rule
(which would necessarily be in addition to the time since publication
of this NPRM)--would provide operators ample time to implement
requisite changes to their procedures and procure necessary personnel
and vendor services (and manage any related compliance costs).
Finally, PHMSA is requesting comments on whether it should require
gas distribution operators to follow incident command systems (ICS)
during an emergency response. PHMSA may consider whether to include
this requirement in any final rule in this proceeding. The sections
below discuss each of these proposals in more detail.
1. Emergency Response Plans--First Responders
a. Current Requirements--Emergency Response Plans--Notifying PSAPs,
First Responders, and Public Officials
Section 192.615(a) requires that each gas pipeline operator have
written procedures for responding to gas pipeline emergencies,
including for how operators are expected to communicate with fire,
police, and other appropriate public officials before and during an
emergency. The Valve Rule revised Sec. 192.615(a)(2) to add direct
communication with PSAPs in response to gas pipeline emergencies and
required operators to establish and maintain an adequate means of
communication with PSAPs.\108\ Further, the Valve Rule revised Sec.
192.615(a)(8) to require operators to notify these entities and
coordinate with them during an emergency. This communication to the
appropriate PSAPs must occur immediately and directly upon receiving a
notification of potential rupture to coordinate and share information
to determine the location of any release.\109\ The Valve Rule also
revised Sec. 192.615(c) to require each operator establish and
maintain liaison with the appropriate PSAPs ``where direct access to a
9-1-1 emergency call center is available from the location of the
pipeline, as well as fire, police, and other public officials'' to
coordinate responses and preparedness planning.
---------------------------------------------------------------------------
\108\ PHMSA expects that ``maintaining adequate means of
communication'' should include, but not be limited to, considering
the frequency of communication, changes to the nature of the
emergency, changes to previously liaised information, and updates to
other emergency response information, as determined by the operator.
\109\ 87 FR at 20983.
---------------------------------------------------------------------------
Further, PHMSA issued an advisory bulletin in 2012 (ADB-2012-09)
regarding communications between pipeline operators and PSAPs.\110\ In
the advisory bulletin, PHMSA reminded operators that they should notify
PSAPs of indications of a pipeline facility emergency, including an
unexpected drop in pressure, an unanticipated loss of SCADA
communications, or reports from field personnel. In the advisory
bulletin, PHMSA recommended that pipeline operators immediately contact
the PSAPs of the communities in which such indications occur.
Furthermore, the advisory bulletin noted that operators should have the
ability to immediately contact PSAPs along their pipeline routes if
there is an indication of a pipeline emergency to determine if the PSAP
has information that may help the operator confirm whether a pipeline
emergency is occurring or to provide assistance and information to
public safety personnel who may be responding to the event. The
revisions to Sec. 192.615 in the Valve Rule essentially codified this
advisory.
[[Page 61772]]
PHMSA notes that indications of a gas pipeline emergency, including
unexpected pressure drops or reports from field personnel, might be a
notification of potential rupture under amended Sec. 192.615, which
would require the direct and immediate notification of the appropriate
PSAP.
---------------------------------------------------------------------------
\110\ ``Pipeline Safety: Communication During Emergency
Situations,'' ADB-2012-09, 77 FR 61826 (Oct. 11, 2012). PHMSA also
issued draft FAQs on 9-1-1 notification on July 8, 2021.
``Frequently Asked Questions on 911 Notifications Following Possible
Pipeline Ruptures,'' 86 FR 36179 (July 8, 2021). If PHMSA were to
finalize the proposed revisions for these emergency plan provisions
in a subsequent final rule, PHMSA would withdraw the draft 9-1-1
notification FAQs as redundant.
---------------------------------------------------------------------------
b. Need for Change--Emergency Response Plans--Notifying PSAPs, First
Responders, and Public Officials
During the initial response to the 2018 Merrimack Valley incident,
the three fire departments in the affected municipalities were
inundated with emergency calls from residents and businesses reporting
fires and explosions and requesting assistance shortly after 4 p.m. on
September 13, 2018. Around that same time, the CMA technician reported
smoke and explosions. However, it was not until nearly 4 hours later at
7:43 p.m. that the president of CMA declared a ``Level 1'' emergency
under CMA's emergency response plan. Lawrence's deputy fire chief told
NTSB investigators that, during the incident response, he attempted to
contact CMA through the station dispatch to get a status update to see
if CMA had the gas incident under control but did not receive updates
from the company until hours later. About 2 hours after the initial
fires, Lawrence's deputy fire chief assumed the gas company had
resolved the incident.\111\ The Andover fire chief recognized the
events occurring were gas-related and contacted CMA through a regular
dispatch number to provide status updates so the fire department could
relay information to the public. He told NTSB investigators that CMA
did call him back more than 4 hours later, while also acknowledging the
delay was likely caused by the number of emergency calls CMA received.
---------------------------------------------------------------------------
\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.
---------------------------------------------------------------------------
The NTSB report noted that CMA had emergency response plans but did
not implement their plans in a manner that would allow them to
effectively respond to such a large incident, explaining that
ambiguities within the operator's emergency response plans could have
contributed to the poor emergency response in that incident.
Specifically, the NTSB pointed out that the operator's emergency
response plans suggested that notification could be discretionary, as
those procedures stated that when an overpressurization of the system
occurs, there ``may be a need'' to communicate with local government
officials and emergency management agencies, as well as with fire and
police departments.\112\ According to the NTSB report, the NiSource
emergency plan also stated that it is ``imperative for all entities
involved to remain informed of each other's activities,'' and that
CMA's Incident Commander (IC), (in this case, the field operations
leader (FOL)) was required to establish appropriate contacts for
communication purposes throughout the incident. However, during the
initial hours of the event, the IC did not establish these requisite
communication contacts because the IC was involved with shutting down
the natural gas system. And although CMA representatives went to
emergency responder staging areas and emergency operations centers, the
NTSB report noted that CMA representatives could not address many of
the questions from emergency responders because the representatives
were not prepared with thorough and actionable information. As a result
of the lack of timely, thorough, and actionable information on the
circumstances of the overpressurization event, emergency responders
unnecessarily evacuated areas, straining limited emergency response
resources, and creating confusion among the public. The NTSB concluded
that CMA was not adequately prepared with the resources necessary to
assist emergency management services with the emergency response.
---------------------------------------------------------------------------
\112\ NTSB/PAR-19/02 at 46.
---------------------------------------------------------------------------
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\
---------------------------------------------------------------------------
\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).
---------------------------------------------------------------------------
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\
---------------------------------------------------------------------------
\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.
---------------------------------------------------------------------------
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.
---------------------------------------------------------------------------
\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.
---------------------------------------------------------------------------
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.
---------------------------------------------------------------------------
\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\
---------------------------------------------------------------------------
\119\ FEMA, ``Lesson 3: Communicating in an Emergency'' (Feb.
2014), https://training.fema.gov/emiweb/is/is242b/instructor%20guide/ig_03.pdf.
---------------------------------------------------------------------------
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\
---------------------------------------------------------------------------
\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.
---------------------------------------------------------------------------
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\
---------------------------------------------------------------------------
\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.
---------------------------------------------------------------------------
\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.
---------------------------------------------------------------------------
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\
---------------------------------------------------------------------------
\124\ Merrimack Valley After Action Report at 46.
---------------------------------------------------------------------------
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\
---------------------------------------------------------------------------
\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.
---------------------------------------------------------------------------
\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.
---------------------------------------------------------------------------
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.
---------------------------------------------------------------------------
\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.
---------------------------------------------------------------------------
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\
---------------------------------------------------------------------------
\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.
---------------------------------------------------------------------------
Typically, local authorities handle most incidents using the
communications systems, dispatch centers, and incident personnel within
their jurisdiction. For larger and more complex incidents, however,
response efforts may rapidly expand to multi-jurisdictional or multi-
disciplinary efforts requiring outside resources and support.
Widespread use of ICSs could allow the efficient integration of outside
resources and enable personnel from anywhere in the Nation to
participate in the incident-management structure. Regardless of the
size, complexity, or scope of the incident, the use of an ICS could
benefit pipeline operators.
PHMSA is considering an ICS-based system in this rulemaking to
provide safety benefits. However, PHMSA has preliminarily determined
further input from the public would be beneficial in assessing the
feasibility of doing so, as well as the best practices that would
[[Page 61777]]
inform such a regulatory standard. Specifically, PHMSA is considering
requirements under Sec. 192.615 for operators of gas distribution
pipelines to follow ICS procedures in response to gas pipeline
emergencies. For example, PHMSA could require that operators of gas
distribution pipelines develop written procedures in accordance with
ICS tools and practices. An example of an ICS practice would be to
identify the roles and responsibilities of emergency responders and
communicate those responsibilities to designated personnel, which would
be similar to the current requirements in Sec. 192.615(c). PHMSA
recognizes the benefit of pipeline operators using ICS for gas pipeline
emergencies, as such an approach can help hone and maintain skills
needed to coordinate response efforts effectively, even as poor
implementation of an ICS may hinder effectiveness. For example, in the
Merrimack Valley incident, both the operator and emergency responders
had an ICS in their respective emergency response manuals; however, the
ICS procedures were implemented with mixed results. While State and
local emergency responders were able to effectively manage, organize,
and coordinate the activities of multiple agencies serving in the
emergency response by following the ICS, the NTSB concluded that CMA's
Incident Commander (IC) struggled to manage the multiple competing
priorities, such as communicating with affected municipalities,
updating emergency responders, and shutting down the natural gas
distribution system, which adversely affected the IC's ability to
complete tasks in a timely manner.\132\ The Merrimack Valley incident
underscores that effective execution of an ICS is still dependent upon
each operator's ability to implement the practices during a crisis.
---------------------------------------------------------------------------
\132\ NTSB/PAR-19/02 at 45-47, 48-49.
---------------------------------------------------------------------------
PHMSA is also considering, if it determines to adopt requirements
for operators of gas distribution pipelines to follow ICS procedures in
response to gas pipeline emergencies, requiring operators to train
personnel on ICS tools and practices. PHMSA expects that to develop an
ICS for a response to gas pipeline emergencies, operator personnel
would need to undergo extensive training and coordination exercises
with first responders, and local and State public safety officials.
FEMA provides free resources for implementing and training on ICS on
their website.\133\ Because this training is free, PHMSA expects there
should be no upfront costs to provide training, however, there would be
a burden in terms of time for operators to (1) take these trainings and
(2) incorporate ICS tools and practices into their training and
emergency response procedures. Further, the ICS tools and guidance are
designed to be integrated into an organization's existing
infrastructure, so PHMSA would not expect operators to have to hire
additional personnel to meet a new requirement in its regulations for
an ICS. PHMSA seeks comment on these assumptions.
---------------------------------------------------------------------------
\133\ FEMA, ``National Incident Management System'' (May 24,
2022), https://www.fema.gov/emergency-managers/nims.
---------------------------------------------------------------------------
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.
---------------------------------------------------------------------------
\134\ 49 CFR 192.603(b).
---------------------------------------------------------------------------
2. Need for Change--O&M Manuals--Overpressurization
Clearly written procedures aid in the successful execution of tasks
and processes necessary to ensure a gas distribution pipeline system is
operated and maintained in a safe manner. Overpressurizations, while
rare, can cause a pipeline failure if not addressed in a timely manner.
Including measures
[[Page 61778]]
in O&M manuals to respond to indications of an overpressurization can
help ensure a timely, effective response.
As demonstrated by the Merrimack Valley incident, operators of gas
distribution pipelines must be prepared to recognize and respond to
overpressurization indications, as these events can have significant
consequences for public safety and the environment. PHMSA regulations
have a requirement in Sec. 192.605(b)(5) for operators to have
procedures for ``starting up and shutting down any part of the pipeline
in a manner designed to assure operation within the MAOP limits
prescribed by this part, plus the build-up allowed for operation of
pressure-limiting and control devices.'' To further reduce the
likelihood of future incidents like the 2018 Merrimack Valley incident,
however, PHMSA proposes to amend Sec. 192.605 to ensure that operators
explicitly account for overpressurization in their O&M procedures.
Subsequent to the 2018 Merrimack Valley incident, 49 U.S.C. 60102
was amended to require PHMSA to undertake a new rulemaking that would
require operators of gas distribution systems to update their
operations, maintenance, and emergency plans to include procedures for
specific actions to be taken on receipt of an indication of an
overpressurization on their systems. Those actions include an order of
operations for immediately reducing pressure in, or shutting down
portions of, the gas distribution system, if necessary. (49 U.S.C.
60102(s)). Amendments to 49 U.S.C. 60108 require gas distribution
operators to make their updated O&M manuals available to PHMSA or the
relevant State regulatory agency within 2 years after any final rule is
issued and every 5 years thereafter.
3. Proposal To Amend Sec. 192.605--O&M Manuals--Overpressurization
In this NPRM, PHMSA proposes to amend Sec. 192.605 to require that
operators of gas distribution pipelines establish procedures for
responding to, investigating, and correcting the cause of
overpressurization indications as soon as practicable. This will
include specific actions to take and an order of operations for
immediately reducing pressure in portions of the gas distribution
system affected by the overpressurization, shutting down that portion,
or taking other actions as necessary.
A timely response to an overpressurization event will require
operators to promptly recognize overpressurization indications.
Operator procedures would need to document potential overpressurization
indications based on the design and operating characteristics of their
systems. For example, a common indication of an overpressure condition
would be an increase in pressure or flow rate outside of normal
operating limits--but precisely how much a pressure change outside
normal conditions would exceed MAOP will depend on the characteristics
of that system.
PHMSA also proposes to require that an operator's procedures must
document specific actions and the sequence of events various personnel
must follow in response to an overpressurization indication. Those
procedures should contain clear statements of authority for relevant
operator personnel to undertake particular actions both on initial
receipt of notification of an overpressurization indication and
subsequent confirmation that an overpressurization condition exists or
is imminent.\135\ An example would include the actions a controller in
the monitoring center (i.e., SCADA system) would take and the protocols
to follow when in receipt of a pressure alarm indicating an
overpressurization. Similarly, field personnel may witness
overpressurization indications such as fires, explosions, control lines
damage during excavation, instrumentation or valve failures, or the
activation of safety valves. Operators must develop procedures for
those personnel to recognize the signs of an overpressurization as well
as identify the steps they should take in response (such as applying a
stop-work authority, reducing the pressure, isolating portions of the
gas distribution system, and notifying emergency responders). The
operator must also provide training on these procedures to ensure that
personnel--including field personnel and construction workers--are able
to recognize the indications of an overpressurization and respond
appropriately.\136\
---------------------------------------------------------------------------
\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.
---------------------------------------------------------------------------
Operators must also develop and document procedures for, as soon as
practicable, investigating and correcting the cause of an
overpressurization or an overpressurization indication. While the
amendments proposed throughout this NPRM, if adopted, are expected to
prevent or reduce the frequency of future overpressurizations, they may
still occur. If an operator experiences an overpressurization or any
indication that an overpressurization could occur, PHMSA proposes to
require operators to investigate and correct the cause(s) of the
overpressurization or overpressurization indication. During their
investigation, operators could find a mode of failure common to other
parts of their systems and take action to prevent or mitigate a
potential overpressurization, such as promptly repairing or replacing
parts of the system.
PHMSA proposes the requirements described above to ensure operators
have clear direction as to what procedures are necessary to prevent
catastrophic overpressurizations similar to that of the Merrimack
Valley incident and to improve the safety of gas distribution systems
generally. PHMSA also expects this proposed amendment of subpart L
requiring distribution operators to update O&M manuals to address
overpressure scenarios would reinforce the updates to DIMP plans
proposed elsewhere in this NPRM. PHMSA expects that this amendment
would improve pipeline safety by bringing additional awareness to gas
distribution pipeline operators and personnel regarding
overpressurization indications. This amendment would also ensure
operators establish procedures for monitoring and controlling gas
pressure should they detect an indication of an overpressurization.
PHMSA further proposes to respond to the risk of overpressurization in
an operator's O&M manuals through adopting an MOC process, as discussed
below.
PHMSA understands these proposed requirements for enhancements of
gas distribution operators' O&M manuals to address a well-understood
threat to pipeline integrity would be reasonable, technically feasible,
cost-effective, and practicable for gas distribution operators. PHMSA
expects that some gas distribution operators may already be complying
with these requirements either voluntarily (e.g., in response to the
Merrimack Valley incident), as a result of similar requirements imposed
[[Page 61779]]
by State pipeline safety regulators, or pursuant to their DIMPs. PHMSA
further notes that its proposed enhancements of baseline expectations
for O&M manual contents are precisely the sort of minimal actions a
reasonably prudent operator of gas distribution pipeline facility would
adopt in ordinary course to protect public safety given that their
systems transport pressurized (natural, flammable, toxic, or corrosive)
gasses typically within or in close proximity to population centers.
Viewed against those considerations and the compliance costs estimated
in the PRIA, PHMSA expects its proposed amendments will be a cost-
effective approach to achieving the public safety and environmental
benefits discussed in this NPRM and its supporting documents. Lastly,
PHMSA understands that its proposed compliance timeline--one year after
publication of a final rule (which would necessarily be in addition to
the time since publication of this NPRM)--would provide operators ample
time to implement requisite changes to their O&M manuals (and manage
any related compliance costs).
E. Operations and Maintenance Manuals (Section 192.605)--Management of
Change
1. Current Requirements--O&M Manuals--Management of Change (MOC)
There are no current requirements in the pipeline safety
regulations for operators of gas distribution pipelines to follow
management of change (or MOC) processes in their operations and
maintenance activity. While not specifically an MOC process, the
operator qualification provisions in Sec. 192.805(f) require that
changes that affect covered tasks be communicated to individuals
performing these tasks. As such, operators may have in place some type
of process for reviewing changes, including whether such changes will
impact O&M procedures and those performing the procedures. Further, gas
transmission pipelines located in a high consequence area have an MOC
requirement in Sec. 192.911(k), which adopts an MOC process outlined
in the American Society of Mechanical Engineers/American National
Standards Institute (ASME/ANSI) standard B31.8S, section 11.\137\ The
192.911(k) requirement, however, applies only to operators of gas
transmission pipelines subject to subpart O integrity management
requirements (i.e., high-consequence areas, which are not applicable to
gas distribution pipelines).
---------------------------------------------------------------------------
\137\ Am. Soc'y of Mech. Eng's, ANSI B31.8S-2004, ``Managing
System Integrity of Gas Pipelines'' (Jan. 14, 2005).
---------------------------------------------------------------------------
2. Need for Change--O&M Manuals--MOC
Inadequately reviewed or documented design, construction,
maintenance, or operational changes can seriously impact pipeline
integrity. MOC procedures are designed to prevent such impacts. In the
Merrimack Valley incident, NTSB investigators discovered omissions in
CMA's engineering work package and construction documentation for the
South Union Street project and that the work package was completed
without a proper constructability review. NTSB investigators reviewed
the engineering plans that CMA used during the construction work and
found that the CMA engineers did not document the location of regulator
control lines.\138\ Had CMA accurately documented the regulator control
lines, engineers and work crews would have been able to relocate them
prior to abandoning the pipeline main.
---------------------------------------------------------------------------
\138\ NTSB/PAR-19/02 at 16.
---------------------------------------------------------------------------
CMA did not employ MOC processes for its maintenance and
construction operations. Instead, CMA's engineering department relied
on simple checklists in its workflow documentation. The NTSB determined
that if NiSource had adequately employed a MOC process, it could have
identified potential risk of overpressurization of its system from a
common mode of failure as a result of the South Union Street project
construction activity and employed control measures to prevent or
mitigate the Merrimack Valley incident. As a result, the NTSB
recommended in P-18-8 that NiSource apply an MOC process to all changes
to adequately identify system threats that could result in a common
mode of failure.\139\
---------------------------------------------------------------------------
\139\ NTSB/PAR-19/02 at 51.
---------------------------------------------------------------------------
NTSB also stated that CMA did not identify the omission of
regulator control lines from its engineering work package during its
constructability review of that documentation. Constructability
reviews--an element of MOC processes--are recognized and accepted as a
necessary engineering practice for the execution of construction
services. If properly implemented, constructability reviews provide
structured reviews of construction plans and specifications to ensure
functionality, sustainability, and safety, thus reducing the potential
for shortcomings, omissions, inefficiencies, conflicts, or errors. The
NTSB concluded that the CMA constructability review process was not
sufficiently robust to detect the omission of a work order to relocate
the sensing lines. The NTSB identified that part of the failure of the
process was likely due to the absence of a review by a critical
department (CMA's measurement and regulation or M&R department).
Despite there being at least two constructability reviews for the South
Union Street project, the M&R department did not participate. The NTSB
stated that a comprehensive constructability review, which would
require all pertinent departments to review each project, along with
the endorsement by a professional engineer (PE), would likely have
identified the omission of the regulator control lines, thereby
preventing the error that led to the Merrimack Valley incident. As a
result of its investigation, the NTSB recommended that NiSource revise
its constructability review process to ensure that all pertinent
departments review construction documents for accuracy and
completeness, and that the documents or plans be endorsed by a PE prior
to commencing work.
Subsequent to the 2018 Merrimack Valley incident, PHMSA was
required by statute to update its regulations to require gas
distribution operators to include in their O&M manuals an MOC process
which must apply to ``significant technology, equipment, procedural,
and organizational changes to the distribution system[.]'' (49 U.S.C.
60102(s)(2)). This provision also requires that operators ``ensure that
relevant qualified personnel, such as an engineer with a professional
engineer licensure, subject matter expert, or other employee who
possesses the necessary knowledge, experience, and skills regarding
natural gas distribution systems, review and certify construction plans
for accuracy, completeness, and correctness.'' In addition, 49 U.S.C.
60108 requires gas distribution operators to make their updated O&M
manuals available to PHMSA or the relevant State regulatory agency
within 2 years after the final rule is issued in this proceeding and
every 5 years thereafter.
3. Proposal To Amend Sec. 192.605 To Require an MOC Process
Pursuant to 49 U.S.C. 60102(s), PHMSA proposes to require that gas
distribution operators update their O&M manuals to include a detailed
MOC process.\140\ Under this proposal,
[[Page 61780]]
operators would be required to apply an MOC process to technology,
equipment, procedural, and organizational changes that may impact the
integrity or safety of the gas distribution system. Specifically,
operators must apply an MOC process to changes to their pipeline
systems, organization, and O&M procedures in connection with the (1)
installation, modification, or replacement of, or upgrades to,
regulators, pressure monitoring locations, or overpressure protection
devices; (2) modifications to alarm set points or upper/lower trigger
limits on monitoring equipment; (3) introduction of new technologies
for overpressure protection into the system; (4) revisions, changes to,
or introduction of new standard operating procedures for design,
construction, installation, maintenance, and emergency response; and
(5) other changes that may impact the integrity or safety of the gas
distribution system. PHMSA notes that although most of the occasions
for changes to operator pipelines and procedures listed above are
directed toward reducing the potential for overpressurization, it
expects that MOC processes will also help reduce the risk of other
incidents on gas distribution pipelines. Towards that end, PHMSA
proposes savings language (``other changes that may impact the
integrity or safety of the gas distribution systems'') that would
require operators to employ a MOC process in connection with changes to
their systems and procedures in connection with high-risk activities.
---------------------------------------------------------------------------
\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.
---------------------------------------------------------------------------
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.
---------------------------------------------------------------------------
\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.
---------------------------------------------------------------------------
In developing this proposed requirement, PHMSA reviewed NTSB
recommendation P-19-16, which called on states to require that all
future gas infrastructure projects require licensed PE approval and
stamping.\142\ This NPRM in no way prohibits states from applying a
higher standard than that provided in the Federal regulations.
Additionally, PHMSA acknowledges that a PE could provide the best
assurance of high-quality review of construction plans. PHMSA is
uncertain as to the availability of those personnel resources in all
states or for all gas distribution operators, however, and any shortage
of licensed PEs could cause delays in the construction or remediation
of integrity issues. Other qualified professionals, such as experienced
engineers or subject matter experts, may have an equivalent level of
experience or skills without holding the licensure. PHMSA is proposing
this amendment pursuant to 49 U.S.C. 60102(s), which contemplates a
larger pool of personnel qualified to perform these reviews and
certifications than just licensed PEs. Nevertheless, PHMSA expects that
when operators evaluate construction projects, operators consider
assigning qualified personnel with experience commensurate to the
complexity of each project and its potential impacts on public safety
and the environment. The most complex and riskiest projects should be
reviewed by a licensed PE, if available, while less complex or routine
construction projects may be suitable for review by qualified personnel
who do not hold such a credential. PHMSA welcomes comments on the
availability of PE licensure in various jurisdictions and the
appropriateness of review by other, non-licensed qualified individuals.
---------------------------------------------------------------------------
\142\ NTSB/PAR-19/02 at 50.
---------------------------------------------------------------------------
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).
---------------------------------------------------------------------------
\143\ ASME/ANSI, B31.8S-2004, ``Managing System Integrity of Gas
Pipelines, Supplement to B31.8'' (Jan. 14, 2005) (incorporated by
reference under Sec. 192.7).
---------------------------------------------------------------------------
PHMSA is also requesting comments on whether it should promulgate
the MOC requirement described above, adopt the industry standard ASME/
ANSI B31.8S for gas distribution operators, or both.\144\ PHMSA has
adopted ASME/ANSI B31.8S for gas transmission operators subject to 49
CFR, part 192, subpart O integrity management requirements.
Specifically, PHMSA at Sec. 192.911(k) requires operators of certain
gas transmission pipelines to develop and follow an MOC process, as
outlined in ASME/ANSI B31.8S, section 11, that addresses technical,
design, physical, environmental, procedural, operational, maintenance,
and organizational changes to the pipeline or processes, whether
permanent or temporary. While provisions in section 11 of ASME/ANSI
B31.8S outline formal elements of an MOC process resembling the
elements within the regulatory text proposed in this NPRM, other
provisions of ASME/ANSI B31.8S section 11, such as (b)(1), are specific
to changes in population that may be more appropriate for gas
transmission operators required to identify high consequence areas
(HCAs) along their pipeline. But the HCA concept does not apply to gas
distribution operators, and as noted above, PHMSA expects it can
capture the public safety and environmental benefits from MOC processes
by adopting the regulatory text proposed in this NPRM without
incorporating by reference ASME/ANSI B31.8S directly. Nevertheless,
PHMSA requests comments on whether adoption within a final rule of a
similar approach for gas distribution operators would provide better
protection for public safety and the environment, and otherwise be
technically feasible, cost-effective, and practicable.
---------------------------------------------------------------------------
\144\ On January 15, 2021, PHMSA issued the NPRM, ``Periodic
Updates of Regulatory References to Technical Standards and
Miscellaneous Amendments,'' which included a proposal to replace the
incorporated by reference ASME/ANSI B31.8S 2004 edition to the 2016
edition. 86 FR 3938, 3944 (Jan. 15, 2021). PHMSA reviewed both 2004
and 2016 editions for consideration in this rulemaking.
---------------------------------------------------------------------------
F. Gas Distribution Recordkeeping Practices (Section 192.638)
1. Current Requirements--Recordkeeping
Operators must collect and maintain records about their gas
distribution pipelines in compliance with requirements of 49 CFR part
192, including those governing DIMPs. Section 192.1007(a) requires
operators to identify reasonably available information necessary to
develop an understanding of the characteristics of their pipelines,
identify applicable threats, and analyze the risk associated with the
threats. Section 192.1007(a)(3) requires that operators have a plan to
collect information needed to conduct the risk analysis required in
DIMP. Section 192.1007(a)(5) requires operators to capture and retain
information on any new pipeline installed, including, at a minimum, the
location of the pipeline and the material of which it is constructed.
In addition to keeping records as part of complying with DIMP
requirements, an operator must also consider the data it needs to
comply with the various recordkeeping requirements in 49 CFR part 192,
such as those for pipeline design, testing and construction (Sec.
192.517); corrosion control (Sec. 192.491); customer notification
(Sec. 192.16); uprating (Sec. 192.553); surveying, patrolling,
monitoring, inspections, operations, maintenance, and emergencies
(Sec. Sec. 192.603 and 192.605); and operator qualification (Sec.
192.807). Sections 192.603(b) and 192.605 further require that each
operator establish a written operating and maintenance plan that meets
the requirements of the pipeline safety regulations and keep records
necessary to administer the plan. Sections 192.603(b) and 192.605(e)
require operators to maintain current records and maps of the location
of their facilities for use in operations, maintenance, and emergency
response activities (e.g., surveillance, leak surveys, cathodic
protection, etc.). Further, Sec. 192.605 requires that operators make
construction records, maps, and the pipeline's operating history
available to appropriate operating personnel. Therefore, if an operator
requires maps as a record to properly administer its O&M procedures
consistent with Federal safety requirements, these maps must be
maintained by the operator.
Additionally, operators must keep records related to the design and
installation of their pipeline components, including protection against
overpressurization under 49 CFR part 192, subparts L and M.\145\ These
records would include valve failure position and capacity records,
which include information operators used when designing the system to
ensure sufficient overpressure protection.
---------------------------------------------------------------------------
\145\ See Sec. Sec. 192.603(b), 192.605(b)(1), and subpart M
(incorporating Sec. Sec. 192.199 and 192.201).
---------------------------------------------------------------------------
2. Need for Change--Recordkeeping
Maintaining accurate and reliable records is critical for safe
operation, maintenance, pipeline integrity management, and emergency
response. Records of the physical components on a gas distribution
system, such as regulators, valves, and underground piping (including
control lines), are necessary for an operator to have the basic
knowledge of its system needed to maintain control of system pressure.
Mapping of all gas systems enables proper planning of system upgrade
activities, maintenance, and protection of the system from excavation
damage. Knowing the location of control lines is critically important
to preventing incidents on low-pressure distribution systems because
they can be easily damaged during excavation activities or
inadvertently taken out of service, as demonstrated by the Merrimack
Valley incident. Further, mapping of all gas systems, such as
documenting the location of shutoff valves, could improve the response
time during an emergency. In the event of an incident or other
emergency, being able to locate and operate valves is critical to
achieving the effective shutdown and isolation of any sections of a gas
distribution system. Incomplete, inaccurate, unreliable, or
inaccessible records hinder the safe operation of a pipeline, reduce
the effectiveness of the integrity assessment (as required under DIMP
regulations), and impede timely emergency response.
The 2018 Merrimack Valley incident illustrated how incomplete
records of gas distribution systems can lead to or exacerbate safety
issues. One of the issues identified in the NTSB's report was that the
engineers responsible for developing CMA's construction plan did not
have all the records necessary to plan the construction project
correctly, such as control line drawings and location information.
Further, the CMA engineers knew that even if they had access to the
records regarding the location of the control lines, the records CMA
maintained were often outdated, and thus potentially inaccurate and
incomplete.\146\ For example, for the Winthrop regulator station, the
records had the location of the control lines as
[[Page 61782]]
they existed around May 2010; however, CMA installed a new control line
around September 2015 and never updated its records to reflect the
change. Without access to accurate maps and drawings of the system, CMA
did not include control line maps or procedures for handling control
line removal in the construction plan. CMA then passed along an
inaccurate and incomplete construction plan to the contractor doing the
work. As a result, NTSB recommended that NiSource review and ensure
that all records and documentation of its natural gas systems are
traceable, reliable, and complete.
---------------------------------------------------------------------------
\146\ NTSB/PAR-19/02 at 16-17.
---------------------------------------------------------------------------
The Merrimack Valley incident further illustrated how the lack of
accurate maps of pipeline systems can inhibit effective emergency
response. During the emergency response to the overpressurization, the
operator took too long to provide maps of the low-pressure system to
emergency response officials, who needed street maps showing the layout
of the natural gas distribution system to understand where the affected
customers were located. CMA did not provide the information requested
until hours after the overpressurization began. The emergency
responders emphasized to the NTSB that the absence of this information
impeded their emergency response and public safety decision-making.
Without maps of the low-pressure system, the ICs managing emergency
response had to evacuate thousands of people from their homes,
including people in unaffected areas, out of an abundance of caution.
Subsequent to the 2018 Merrimack Valley incident, 49 U.S.C. 60102
was amended to ensure that operators keep better, more complete records
(such as maps that include the location of control lines and other
critical infrastructure) and make those available to the emergency
responders and public officials who need them. Specifically, 49 U.S.C.
60102(t)(1) directs PHMSA to issue regulations that require
distribution pipeline operators to identify and manage ``traceable,
reliable, and complete'' maps and records of critical pressure-control
infrastructure, and update other records needed for risk analysis.
Operators must update their records ``on an opportunistic basis.''
These records must be accessible to all personnel responsible for
performing or overseeing relevant construction or engineering work.
Pursuant to 49 U.S.C. 60102(t)(1), PHMSA proposes to amend its
regulations to supplement existing requirements pertaining to gas
distribution operators' recordkeeping critical to pressure control on
their systems. The proposal would require operators to collect or
generate complete, reliable, and accurate records if they are not
available, and make the records accessible to the personnel who need
them.
3. Proposal To Add a New Sec. 192.638--Records: Distribution System
Pressure Controls
PHMSA proposes a new Sec. 192.638 to specify that an operator of a
gas distribution system must identify and maintain traceable,
verifiable, and complete records documenting the characteristics of the
pipeline critical to ensuring proper pressure controls.\147\
---------------------------------------------------------------------------
\147\ As discussed elsewhere in the preamble, PHMSA also
proposes to introduce a cross-reference to this new Sec. 192.638
within its existing DIMP plan knowledge management requirements at
Sec. 192.1007(a)(3).
---------------------------------------------------------------------------
In 2019, PHMSA introduced a regulatory amendment requiring gas
transmission records pertaining to MAOP to be ``traceable, verifiable,
and complete.'' \148\ 49 U.S.C. 60102(t)(1) similarly requires PHMSA to
require operators to identify and manage ``traceable, reliable, and
complete'' records. PHMSA understands that the phrase ``traceable,
reliable, and complete,'' as used in 49 U.S.C. 60102(t)(1) is
substantively the same standard with respect to the quality and
accessibility of records maintained as the ``traceable, verifiable, and
complete'' language adopted in the 2019 final rule for gas transmission
pipelines.\149\ PHMSA interprets ``reliable'' as used in 49 U.S.C.
60102(t)(1) to mean the same as ``verifiable'' as used in the 2019 rule
because both verifiable and reliable would mean to prove that a record
is trustworthy and authentic. A record is considered reliable if it is
verifiable and vice versa. PHMSA's proposed Sec. 192.638 recordkeeping
requirement is intended to encompass any records essential to pressure
control on a system and not just pertain to MAOP or material property
and attribute verification activities. PHMSA would require operators to
identify what records they currently have that document the
characteristics of the pipeline that are ``critical to ensuring proper
pressure controls'' for the system.
---------------------------------------------------------------------------
\148\ ``Pipeline Safety: Safety of Gas Transmission Pipelines:
MAOP Reconfirmation, Expansion of Assessment Requirements, and Other
Related Amendments,'' 84 FR 52180 (Oct. 1, 2019).
\149\ Compare 192.607 (requiring ``traceable, verifiable, and
complete records'' of certain material properties and attributes)
and 192.624 (requiring ``traceable, verifiable, and complete
records'' for MAOP confirmation) with 49 U.S.C. 60102(t) (requiring
gas distribution operators identify and manage ``traceable,
reliable, and complete records . . . critical to ensuring proper
pressure controls for a gas distribution system . . . .'').
---------------------------------------------------------------------------
In Sec. 192.638(a), PHMSA identifies the types of records that it
proposes are critical to ensuring proper pressure control for a gas
distribution system. These records include: (1) current location
information (including maps and schematics) for regulators, valves, and
underground piping (including control lines); (2) attributes of the
regulator(s), such as set points, design capacity, and the valve
failure position (open/closed); (3) the overpressure protection
configuration; and (4) other records deemed critical by the operator.
Regarding item (1), operators generally keep records, such as maps
and schematics, when designing their system and district regulator
stations. Operators should also have records of selected regulators,
valves, and other gas pressure control equipment based on several
factors, for the purpose of determining, for example, the overall
capacity and future flow requirements of the system.
Regarding item (2), records related to the attributes of the
regulators' set points, design capacity, and valve failure position are
necessary to ensure that the design of the district regulator station
can protect the distribution system from overpressurization. For
example, demands on the system may change over time due to customer
usage, weather, or maintenance requirements. Operators can use design
capacity records to validate and revalidate that their systems are
capable of meeting changing customer demands and weather dynamics.
Regarding item (3), maintaining records for the overpressure
protection configuration are necessary for the safe operation of the
pipeline and for performing a robust risk analysis required under DIMP
regulations. As demonstrated by the 2018 Merrimack Valley incident,
certain overpressure protection configurations on low-pressure
distribution systems (i.e., redundant worker-monitor regulators) alone
are inadequate for preventing an overpressurization. Requiring
operators to keep records of their systems' overpressure configurations
will ensure that operators will be able to identify any higher-risk
configurations in their systems. Once identified, operators can
properly assess the overall risk to their systems and take preventive
or mitigative actions to reduce the likelihood or consequences of a
potential failure.
Regarding item (4), PHMSA proposes that operators must have
traceable, verifiable, and complete records for any records they deem
critical but that were
[[Page 61783]]
not mentioned in the list provided by PHMSA. This general requirement
would ensure that operators keep records based on the unique
characteristics of their system.
When taking inventory of the records described above, operators
must identify if those records are traceable (e.g., can be clearly
linked to original information about, or changes to, a pipeline
segment, facility, or district regulator station), verifiable (e.g.,
their information is confirmed by other complementary but separate
documentation), and complete (e.g., as evidenced by a signature, date,
or other appropriate marking such as a corporate stamp or seal). This
amendment would improve the completeness and accuracy of the records
needed during normal operations, emergency response activities, and
risk analyses.
In Sec. 192.638(b), PHMSA proposes to require that if an operator
does not yet have traceable, verifiable, and complete records, then the
operator must develop a plan for collecting those records. PHMSA also
proposes to revise Sec. 192.605 to ensure that operators have
procedures for implementing the new recordkeeping requirements proposed
in Sec. 192.638. Because the availability and form of records, as well
as records retention practices, will vary among operators, PHMSA
proposes that operators must identify what records they need to collect
under this requirement.
In Sec. 192.638(c), PHMSA proposes that operators must collect
records needed to meet this standard on an opportunistic basis, which
is defined as occurring during normal operations conducted on the
pipeline including (but not limited to) design, construction,
operations, or maintenance activities. PHMSA notes that its proposed
language in paragraph (c) mirrors the language at Sec. 192.1007(a)(3)
governing operator knowledge management in connection with a
performance of the risk analysis within their DIMPs. PHMSA expects this
approach will minimize compliance burdens on operators, as they would
be able to collect or generate records through existing regulatory
mechanisms such as DIMPs or annual inspections. PHMSA also proposes to
revise Sec. 192.1007(a)(3) so that it references Sec. 192.638(c).
This would require operators to identify records specified in Sec.
192.638(c) that they could collect as part of their DIMP plan.
In Sec. 192.638(d), PHMSA proposes to require that operators
ensure the records required in this section are accessible to personnel
performing or overseeing design, construction, operations, and
maintenance activities. In the 2018 Merrimack Valley incident, the
engineering staff did not have access to the maps containing control
line information and were unaware if the department had access to such
records. This lack of access and awareness resulted in the omission of
critical information that should have been considered through a proper
risk analysis under their DIMPs. Therefore, PHMSA proposes to add a
requirement for operators to provide the personnel responsible for
planning and performing work on critical infrastructure with the
records they need to perform their work safely and effectively.
Operators should note that access would extend to the qualified
employees monitoring the gas pressure (as proposed in Sec. 192.640).
PHMSA expects that during a construction activity, these qualified
personnel may need records such as maps of control lines to effectively
monitor the safety of excavation activities around gas distribution
systems.
In Sec. 192.638(e), PHMSA proposes to require that once a record
is generated or collected under this section, that operators must keep
the record for the life of the pipeline. This will help facilitate
traceability of records as required by 49 U.S.C. 60102(t).
In Sec. 192.638(f), PHMSA specifies that the requirements in this
section would not apply to master meter systems, liquefied petroleum
gas (LPG) distribution pipeline systems that serve fewer than 100
customers from a single source, or any individual service line directly
connected to a transmission, gathering, or production pipeline that is
not operated as part of a distribution system. As discussed above,
small LPG operators are relatively simple, low-risk systems affecting a
finite (generally small) number of customers such that the public
safety and environmental benefits from imposing new requirements on
these systems would be limited. Similar reasoning applies to master
meter systems. PHMSA understands that compliance costs generally are
felt more acutely by small LPG operators and master meter system
operators. PHMSA does not expect that these operators would have the
means (e.g., access to detailed maps and GIS tools) to be able to
comply with the recordkeeping requirements proposed in this NPRM. For
individual service lines, the consequences of an overpressurization are
smaller relative to a district regulator station. Given the relatively
low public safety and environmental benefits from extending the new
Sec. 192.638 recordkeeping requirements to those operators, PHMSA
proposes to except those systems from the new recordkeeping requirement
at Sec. 192.638. Nevertheless, PHMSA does encourage these excepted
operators to, where applicable, follow the recordkeeping specifications
proposed in this NPRM.
Overall, PHMSA expects that its proposed new Sec. 192.638 would
ensure that operators are documenting and maintaining records of how
their critical pressure controlling facilities operate so that they can
review and assess their performance over time. Keeping complete and
accurate records for the life of these assets could help improve
operators' risk analyses, as required by DIMP regulations, and thus
improve the overall integrity of gas distribution pipelines.
PHMSA also understands this proposed requirement for gas
distribution operators to identify and maintain traceable, accurate,
and complete records documenting system characteristics pertinent to
pressure control would be reasonable, technically feasible, cost-
effective, and practicable. As explained above, the proposed
requirement is analogous to material property documentation
requirements elsewhere in PHMSA regulations (e.g., Sec. 192.607) for
gas transmission systems. And PHMSA understands that some gas
distribution operators may already comply with this proposed
requirement either voluntarily (e.g., to minimize losses of
commercially valuable commodities, in response to the Merrimack Valley
incident and NTSB recommendations, or consistent with broadly
applicable, consensus industry standards such as ASME/ANSI B31.8S
\150\), as a result of similar requirements imposed by State pipeline
safety regulators, or as risk mitigation measures pursuant to their
DIMPs. Indeed, the sort of records subject to this proposed requirement
are precisely the sort of records that a reasonably prudent operator of
gas distribution pipeline facility would in ordinary course already
have identified and be maintaining to protect the public given that
their systems transport pressurized (natural, flammable, toxic, or
corrosive) gasses typically within or in close proximity to population
centers. Viewed against those considerations and the compliance costs
estimated in the PRIA, PHMSA expects its proposed amendments will be a
cost-effective approach to achieving the commercial, public safety, and
environmental benefits discussed in this NPRM and its
[[Page 61784]]
supporting documents. Lastly, PHMSA understands that its proposed
compliance timeline--one year after publication of a final rule (which
would necessarily be in addition to the time since publication of this
NPRM)--would provide operators ample time to review and compile
pertinent existing records and develop and implement procedures to
generate or obtain missing records on a going-forward basis (and manage
any related compliance costs).
---------------------------------------------------------------------------
\150\ ASME/ANSI, B31.8S-2004, ``Managing System Integrity of Gas
Pipelines, Supplement to B31.8'' (Jan. 14, 2005) (incorporated by
reference under Sec. 192.7).
---------------------------------------------------------------------------
G. Distribution Pipelines: Presence of Qualified Personnel (Sections
192.640 and 192.605)
1. Current Requirements--Procedures for Qualified Personnel Monitoring
Gas Pressure
Currently, PHMSA does not require operators to have procedures for
monitoring gas pressure with qualified persons and equipment capable of
ensuring pressure control and having the ability to shut off the flow
of gas. There are other provisions related to personnel qualification
included in 49 CFR part 192, subpart N, which contain requirements for
operators of gas pipelines to develop a qualification program to
qualify employees for certain covered tasks. Covered tasks include
those activities that affect the operation or integrity of the
pipeline. PHMSA defines ``Qualified'' in Sec. 192.803 to mean that
``an individual has been evaluated and can: (a) [p]erform assigned
covered tasks; and (b) [r]ecognize and react to abnormal operating
conditions.''
2. Need for Change--Distribution Pipelines: Presence of Qualified
Personnel
Gas pipelines are often monitored in a control room by controllers
using computer-based equipment, such as a SCADA system, that records
and displays operational information about the pipeline system, such as
pressures, flow rates, and valve positions. Some SCADA systems are used
by controllers to operate pipeline equipment remotely or automatically;
in other cases, controllers may dispatch other personnel to operate
equipment in the field. For those operators whose systems are not
capable of remote or automatic shut down or pressure control, control
room operators may have to respond to overpressure indications by
communicating to field personnel to go to the location of the suspected
event, gather additional information to determine if there is an
emergency, and initiate response actions, if needed. This process
creates delays in identifying and responding to overpressurization
indications on gas distribution systems.
During the Merrimack Valley incident, the SCADA controller
responded to a high-pressure alarm by contacting the field technician
who could adjust the flow of gas at the Winthrop regulator station.
CMA's system had remote pressure monitoring but no remote or automatic
shutoff. It took 30 minutes from the time CMA's SCADA controller
noticed an alarm to the time when the field technician began to adjust
the flow of gas. NTSB investigators learned that, at one time, CMA
required that a technician monitor any gas main revision work that
required depressurizing the main.\151\ Per those historical procedures,
the technician would use a gauge to monitor the pressure readings on
the impacted main and would communicate directly with the crew
performing the work. If a pressure anomaly occurred, the technician
could quickly act to prevent an overpressurization event. CMA offered
no explanation to the NTSB as to why this procedure was phased out.
---------------------------------------------------------------------------
\151\ NTSB, Safety Recommendation Report PSR-18-02, ``Natural
Gas Distribution System Project Development and Review (Urgent)'' at
6 (Nov. 24, 2018), https://www.ntsb.gov/investigations/AccidentReports/Reports/PSR1802.pdf.
---------------------------------------------------------------------------
As a result of the incident, the NTSB recommended in P-18-9 that
NiSource, Inc., develop and implement control procedures during
modifications to gas distribution mains to mitigate the risks
identified during MOC operations, and stated that gas main pressures
should be continually monitored during these modifications and that
assets should be placed at critical locations to immediately shut down
the system if abnormal operations are detected. PHMSA agrees with
NTSB's recommendation and concludes that requiring these procedures
could benefit safety for all gas distribution operators. Further, PHMSA
believes that operators can mitigate the consequences of the
overpressurization by requiring qualified personnel capable of shutting
off the gas to monitor the gas pressure during construction associated
with installations, modifications, replacements, or upgrades on gas
distribution mains that could result in overpressurization.
Subsequent to the 2018 Merrimack Valley incident, PHMSA was
directed to issue regulations requiring qualified personnel of a gas
distribution system operator, with the ability to ensure proper
pressure control and shut off, or limit gas pressure should
overpressurization occur, monitor gas pressure at district regulator
stations during certain times. (49 U.S.C. 60102(t)(2)). The mandate
specifies that those times are during any construction project that has
the potential to cause an overpressurization, including projects such
as tie-ins or abandonment of distribution mains. These requirements do
not apply if a district regulator station has a monitoring system and
the capability of remote or automatic shutoff. Further, amendments to
49 U.S.C. 60108 now require gas distribution operators to make their
updated O&M manuals available to PHMSA or the relevant State regulatory
agency within 2 years after any final rule is issued and every 5 years
thereafter.
3. Proposal To Add a New Sec. 192.640 Distribution Pipelines: Presence
of Qualified Personnel
In a new Sec. 192.640, PHMSA proposes an additional layer of
safety at district regulator stations during construction projects by
requiring qualified personnel to be present, monitor the gas pressure,
and have the capability to shut off the flow of gas during an
overpressurization event. This provision, including each of the below
proposed parts, would not apply if an operator already has equipped
that district regulator station with a remote pressure monitoring
system that has the capability for remote or automatic shutoff.\152\
---------------------------------------------------------------------------
\152\ This exception will be reflected by addition of new
paragraph (d).
---------------------------------------------------------------------------
In paragraph (a), PHMSA proposes that operators of a distribution
system must conduct an evaluation of planned and future installation,
modification, or replacement of, or upgrade construction projects and
identify any potential for an overpressurization to occur at a district
regulator station. Operators must perform this evaluation before
performing activities that could result in an overpressurization. PHMSA
recognizes that not every construction project performed on a gas
distribution system has the same risk profile and not all would require
on-site gas monitoring by a qualified employee. However, the pre-
construction evaluation must occur regardless to assess the probability
of an overpressurization. Some construction projects clearly entail a
potential for overpressurization, such as tie-ins and abandonment of
distribution pipelines and mains, because work is done while part of
the gas system remains active. Similarly, the consequences of
overpressurization during construction projects may increase when that
work is on low-pressure gas distribution systems where customers do not
have
[[Page 61785]]
secondary pressure regulation at their individual meter.
In paragraph (b), PHMSA proposes that once the evaluation is
complete, if an operator has determined that a construction project
activity presents a potential for overpressurization, then the operator
must ensure that at least one qualified employee or contractor with the
capability to shut off the flow of gas is present at that district
regulator station to monitor the gas pressure during the construction
project activity. This will result in safer construction activities on
gas distribution pipelines by requiring operators to ensure that
resources have been deployed to effectively mitigate risks the operator
had determined exist.
Under this proposal, the employee or contractor must be qualified
to monitor the gas pressure in accordance with 49 CFR, part 192,
subpart N. Subpart N already requires that operators ensure on-site
personnel, such as maintenance crew members and inspectors, are
qualified by training and experience to perform covered tasks. Further,
subpart N requires that operators qualify these individuals to ensure
that covered tasks are conducted in a safe, reliable manner in
compliance with regulatory standards. In complying with this new
proposal, operators would need to qualify employees and contractors
responsible for monitoring the gas pressure during construction to
perform various tasks, such as reading and understanding gas monitoring
equipment; responding to abnormal operating conditions (see Sec.
192.805), including overpressurization indications; shutting off or
reducing the pressure to the system; implementing any stop-work
authority granted by the operator; and notifying appropriate emergency
response personnel should an incident occur. They should also be
qualified on the relevant proposed new O&M requirements discussed in
subsection IV.D and E.
In paragraph (c), PHMSA proposes to require that, when monitoring
the system as described in this section, the qualified personnel should
be provided, at a minimum, information regarding the location of all
valves necessary for isolating the pipeline system and pressure control
records (see Sec. 192.638). Providing access to this information could
be essential to an employee or contractor performing their gas
monitoring responsibilities effectively and help shorten the response
time to emergency indications. For example, a qualified employee
responsible for monitoring the gas pressure may need to access valves
on the system so that they can shut off the flow of gas, isolate the
pipeline system, or otherwise mitigate the consequences of an incident.
Similarly, a qualified employee responsible for monitoring the gas
pressure may need to have more extensive maps of the entire gas system
to identify an affected area and detailed information--such as a
specific regulator's set point--to determine if a system is operating
abnormally. The records proposed in Sec. 192.638 would provide this
information and must be accessible to qualified personnel who monitor
gas pressure.
Further, under paragraph (c), PHMSA proposes that operators must
also ensure that qualified employees monitoring the gas pressure have
information regarding emergency response procedures. PHMSA expects such
information would include the contact information of the appropriate
emergency response personnel. Should field personnel recognize an
emergency condition, it is critical for those personnel to have updated
emergency contacts and to know what to do and how to respond in an
emergency. PHMSA expects operators would already have general emergency
contact information in an emergency response plan under Sec. 192.615;
however, given that these qualified personnel may be the first to
witness overpressurization indications, PHMSA believes it is essential
they have immediate access to this information on site during their
activities.
Some operators may already provide qualified employees with ``stop-
work authority'' to halt work that does not conform to specifications
or if they observe unsafe activities on the job site. Although this
authority is not required to be given to all qualified employees under
proposed Sec. 192.640, it is recommended. Where operators have granted
this authority to these qualified personnel monitoring the gas
pressure, operators should ensure these employees are trained to
recognize unsafe, abnormal conditions that are consistent with an
overpressurization.
Overall, the proposals in Sec. 192.640 would reduce the time to
respond to an overpressurization by ensuring qualified employees are on
site or at an alternative location, and that they are capable of
actively monitoring the gas pressure during certain construction
project activities. Should an overpressurization occur, these qualified
employees would be able to respond (i.e., shutting off or reducing the
flow of gas) and thereby mitigate the impact. Under PHMSA's proposal,
the qualified employees would be trained to recognize
overpressurization indications and be able to respond more quickly.
This should mitigate some of the impact of an overpressurization and
improve the response time of the operator.
PHMSA also understands that this proposed new requirement would be
reasonable, technically feasible, cost-effective, and practicable for
gas distribution operators. That operators should evaluate construction
projects on their systems to determine whether they could result in an
overpressurization at a district regulator station and then ensure that
personnel are present who can monitor pressure and prevent such a
condition during the work is a common-sense, best practice within
industry--whose value was underscored by the Merrick Valley incident
and subsequent NTSB recommendation P-18-9. Indeed, PHMSA understands
that some operators may already employ compliant maintenance and
construction protocols in ordinary course. For other operators,
integration of this new requirement within their procedures could be
accomplished via supplementation rather than material revisions; the
proposed new staffing requirements for construction activity would not
require unique skills or equipment to which operators would not have
access. Viewed against those considerations and the compliance costs
estimated in the PRIA, PHMSA expects its proposed amendments will be a
cost-effective approach to achieving the public safety and
environmental benefits discussed in this NPRM and its supporting
documents. Lastly, PHMSA understands that its proposed compliance
timeline--one year after publication of a final rule (which would
necessarily be in addition to the time since publication of this
NPRM)--would provide operators ample time to develop procedures
implementing this new regulatory requirement (and manage any related
compliance costs).
4. Proposal To Amend Sec. 192.605 Procedures for Qualified Personnel
Monitoring Gas Pressure
PHMSA proposes to revise Sec. 192.605, by adding paragraph
(b)(13), to ensure gas distribution operators have procedures for
implementing the monitoring requirements in the proposed Sec. 192.640.
During construction projects on a gas distribution system, qualified
personnel may need to perform their monitoring or shutdown activities
in a specific sequence. Doing work out of sequence may result in an
overpressurization or exacerbate an emergency. For this reason, it is
critical to pipeline safety that operators have written procedures for
personnel performing the construction activity monitoring requirements
proposed in
[[Page 61786]]
Sec. 192.640 to follow. This amendment would ensure that operators
must provide qualified personnel with clear procedures for how to
perform their responsibilities in a safe manner, and specifically how
to monitor for abnormal operating conditions that could lead to an
overpressurization.
PHMSA also understands that this proposed new requirement would be
reasonable, technically feasible, cost-effective, and practicable for
gas distribution operators. As noted above, many operators may already
have compliant procedures; those operators lacking such procedures
should be able to develop new procedures (or supplement existing
procedures) with relatively little difficulty. Viewed against those
considerations and the compliance costs estimated in the PRIA, PHMSA
expects its proposed amendments are a cost-effective approach to
achieving the public safety and environmental benefits discussed in
this NPRM and its supporting documents. Lastly, PHMSA understands that
its proposed compliance timeline--one year after publication of a final
rule (which would necessarily be in addition to the time since
publication of this NPRM)--would provide operators ample time to
develop procedures implementing this new regulatory requirement (and
manage any related compliance costs).
H. District Regulator Stations--Protections Against Accidental
Overpressurization (Sections 192.195 and 192.741)
1. Background--Overpressure Protection
Gas distribution systems are designed to operate at or below an
MAOP. As discussed earlier, a district regulator station is a pressure-
reducing facility that receives gas from a high-pressure source (such
as a transmission line) and delivers it to a distribution system at a
pressure suitable for the demands on the system. An overpressurization
occurs when the pressure of the system rises above the set point of the
devices controlling its pressure. Pressure regulating and control
devices (housed in these district regulator stations) keep the systems'
pressure under their MAOP and at or below the desired set point. These
devices act as overpressure protection. Because of varying conditions
and requirements, there are no standard designs for distribution
systems or overpressure protection on such systems. However, among the
common approaches to overpressure protection in use today are the
following: (1) pressure relief valves, (2) a worker and monitor
regulator system, and (3) automatic or remote shutoff (or ``slam-
shut'') valves.
Pressure relief valves provide overpressure protection by venting
excess gas into the atmosphere and can be used alone or in combination
with other methods of overpressure protection. If the relief valve
senses that the downstream pressure has exceeded a set point, then the
relief valve automatically begins to open to relieve excess gas
pressure in the system. If activated, the relief valve protects from
overpressurization while allowing gas to flow at a safe pressure,
maintaining normal service to customers. In general, the relief valve
is a highly reliable device for overpressure protection. Relief valves
also provide benefits with respect to alerting or warning operator
personnel or the public that an emergency has occurred because (1)
these devices are loud if operated at or near a full discharge of
excess gas pressure, and (2) the smell of the odorized gas that is
vented is also noticeable. However, pressure relief valves entail their
own potential public safety harms through their release of gas--which
can sometimes ignite--into the atmosphere when activated. Venting of
gas to the atmosphere by a relief valve also entails environmental
risks: a primary component of natural gas is methane, an ignitable,
potent greenhouse gas. For these reasons, section 114 of the PIPES Act
of 2020 (codified at 49 U.S.C. 60108(a)(2)(D)(ii)) contains a self-
executing requirement for operators of gas distribution pipelines to
have a written plan to minimize releases of natural gas--such as by
venting from relief valves--from their systems.\153\
---------------------------------------------------------------------------
\153\ See ``Pipeline Safety: Statutory Mandate to Update
Inspection and Maintenance Plans to Address Eliminating Hazardous
Leaks and Minimizing Releases of Natural Gas from Pipeline
Facilities,'' ADB-2021-01, 86 FR 31002 (June 10, 2021).
---------------------------------------------------------------------------
A worker and monitor regulator system is a type of pressure control
and overpressure protection configuration that involves two pressure
reducing valves (e.g., control or pilot valves) installed in a
series.\154\ One regulator valve controls the pressure of gas to the
downstream system. The second regulator valve remains on standby with a
slightly higher set point and only begins operating in the event of a
malfunction of the first regulator or another failure results in
pressure exceeding the set point of the first regulator. If the first,
primary regulator (the ``worker'' regulator) cannot control the
pressure, the second regulator (the ``monitor''), which senses the
rising downstream pressure, automatically begins to operate to maintain
the pressure downstream at a gas pressure slightly higher than normal,
albeit still within safe operation. Sometimes an operator will also
install a small relief valve downstream to act as a ``token relief'' or
an alarm to alert the operator that the regulator has failed.
---------------------------------------------------------------------------
\154\ There are a few types of monitor regulating, all of which
operate substantially similarly as described herein: working
monitor, series regulation, and relief monitoring.
---------------------------------------------------------------------------
When working properly, a worker and monitor regulator system should
not interrupt service if an overpressurization occurs. An advantage of
the worker and monitor regulator system is that it does not result in
venting large volumes of gas to the atmosphere, thereby reducing public
safety and environmental harms. Unlike with pressure relief valves, the
pressure reducing valves used in the worker and monitor regulator
system described above are not self-operated; instead, control lines
are installed in this type of system. Control lines (often called
``sensing'' or ``impulse'' lines) are small-diameter pipes that
transmit the signal pressure from the tie-in point on the downstream
piping line to the pressure regulating device. When the downstream
pressure decreases, the regulator opens wider to allow more gas to
flow. The regulator valve remains open until it senses an increase in
pressure or the demand of the downstream pressure has been met. Control
lines must be protected against breakage because the regulator will
open wide if the control lines are cut or damaged because the regulator
will not detect that the demand has been met, it will remain open,
allowing gas to flow freely. This could result in full upstream
pressure being forced into the low-pressure system, resulting in a
catastrophic situation as seen in the Merrimack Valley incident.
A third type of overpressure protection is automatic shutoff
devices. In the event of an overpressurization indication or event, an
automatic shutoff device completely shuts off the gas flow to the
system until the operator determines the cause of the malfunction and
resets the device. In many cases, an automatic shutoff device is used
as a secondary form of overpressure protection.
2. Current Requirements--Overpressure Protection
Section 192.195 describes the minimum requirements for protection
against accidental overpressurization. Section 192.195(a) requires that
``each pipeline that is connected to a gas
[[Page 61787]]
source so that the [MAOP] could be exceeded as the result of pressure
control failure or of some other type of failure, must have pressure
relieving or pressure limiting devices that meet the requirements of
Sec. Sec. 192.199 and 192.201.'' \155\ Section 192.195(b) adds that
``[e]ach distribution system that is supplied from a source of gas that
is at a higher pressure than the [MAOP] for the system must--(1) [h]ave
pressure regulation devices capable of meeting the pressure, load, and
other service conditions that will be experienced in normal operation
of the system, and that could be activated in the event of failure of
some portion of the system; and (2) [b]e designed so as to prevent
accidental overpressuring.'' This pipeline safety regulation has
existed in 49 CFR part 192 since its inception.\156\
---------------------------------------------------------------------------
\155\ Except as provided in Sec. 192.197, which only applies to
high-pressure gas distribution systems.
\156\ See ``Establishment of Minimum Standards,'' 35 FR 13248,
13264 (Aug. 19, 1970).
---------------------------------------------------------------------------
Section 192.199 describes the minimum requirements for the design
of pressure relief and limiting devices. Section 192.199(g) states that
``[w]here installed at a district regulator station to protect a
pipeline system from overpressuring, [the pressure relief or pressure-
limiting device must] be designed and installed to prevent any single
incident such as an explosion in a vault or damage by a vehicle from
affecting the operation of both the overpressure protective device and
the district regulator[.]''
Section 192.201 describes the minimum requirements for the required
capacity of pressure-relieving and -limiting stations. Section
192.201(a)(1) requires that ``[i]n a low-pressure distribution system,
the pressure may not cause the unsafe operation of any connected and
properly adjusted gas utilization equipment.'' Section 192.201(c)
requires that ``[r]elief valves or other pressure limiting devices must
be installed at or near each regulator station in a low-pressure
distribution system, with a capacity to limit the maximum pressure in
the main to a pressure that will not exceed the safe operating pressure
for any connected and properly adjusted gas utilization equipment.''
Section 192.203(b)(9) adds that ``[e]ach control line must be protected
from anticipated causes of damage and must be designed and installed to
prevent damage to any one control line from making both the regulator
and the over-pressure protective device inoperative.'' PHMSA has
clarified through its enforcement guidance that an occurrence of
overpressurization may be indicative of an equipment failure or design
flaw.\157\
---------------------------------------------------------------------------
\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.
---------------------------------------------------------------------------
In addition, Sec. 192.739 describes the minimum requirements for
the inspection and testing of pressure-limiting and regulating
stations. Section 192.739 requires annual inspection and testing of
each pressure limiting or regulating stations, including relief
devices. The inspection and tests should determine that the station is:
(1) in good mechanical condition; (2) adequate from the standpoint of
capacity and reliability of operation for the service in which it is
employed; (3) except as provided in Sec. 192.739(b) applicable to
certain steel pipelines, set to control or relieve at the correct
pressure consistent with the pressure limits of Sec. 192.201(a); and
(4) properly installed and protected from dirt, liquids, or other
conditions that might prevent proper operation. These requirements are
intended to address inspection and testing of pressure-limiting and
regulator stations necessary to maintain safe pressures on the gas
distribution system.
Section 192.741 describes minimum requirements for the telemetering
or recording gauges on pressure-limiting and regulating stations.
Section 192.741(a) states that ``[e]ach distribution system supplied by
more than one district pressure regulating station must be equipped
with telemetering or recording pressure gauges to indicate the gas
pressure in the district.'' Section 192.741(b) requires that, ``[o]n
distribution systems supplied by a single district pressure regulating
station, the operator shall determine the necessity of installing
telemetering or recording gauges in the district, taking into
consideration the number of customers supplied, the operating
pressures, the capacity of the installation, and other operating
conditions.''
3. Need for Change--Overpressure Protection
The pipeline safety regulations governing overpressure protection
of low-pressure distribution systems have not changed since their
inception in the 1970s. For years, low-pressure gas distribution
systems, like CMA's system in the Merrimack Valley, have relied on
overpressure protection systems like the redundant worker and monitor
regulators to regulate and control the pressure and flow of gas. While
these overpressure protection methods are safe under normal operating
conditions, this method of overpressure protection on low-pressure
distribution systems can be too easily defeated, as recent events with
a common mode of failure have demonstrated. PHMSA's proposed change to
regulations governing overpressure protection is intended to facilitate
the operation of gas distribution systems to avoid catastrophic
overpressurization.
According to the NTSB's report, the low-pressure system in
Merrimack Valley met the requirements for overpressure protection
contained in Sec. 192.195 (Protection Against Accidental
Overpressuring) and Sec. 192.197 (Control of the Pressure of Gas
Delivered from High-pressure Distribution Systems). ``At each of the 14
regulator stations feeding natural gas into [CMA's] low-pressure
system, there were two regulators [(i.e., a worker and monitor
regulator system)] installed in a series to control the natural gas
flow from the high-pressure [. . .] system.'' \158\ The worker
regulator and the monitor regulator were set to limit the pressure to a
maximum safe value to the customer. But the system nonetheless failed.
After reviewing accidents investigated by the NTSB over the past 50
years, as well as prior NiSource incidents, the NTSB found that this
scheme for overpressure protection can be defeated by a common mode of
failure, like operator error or equipment failure.\159\
---------------------------------------------------------------------------
\158\ NTSB/PAR-19/02 at 39.
\159\ NTSB/PAR-19/02 at 39-40.
---------------------------------------------------------------------------
CMA's overpressurization was not an isolated event. For example, on
January 28, 1982, in Centralia, MO, high-pressure natural gas entered a
low-pressure natural gas distribution system after a backhoe damaged
the regulator control line at the Missouri Power and Light Company's
district regulator station.\160\ Because the regulator no longer sensed
system pressure, the regulator opened, and high-pressure natural gas
entered customer piping systems. In some cases, this resulted in high
pilot-light flames that ignited fires in buildings. In other cases, the
pilot-light flames were blown out, allowing natural gas to escape
within the buildings. Of the 167 buildings affected by the
overpressurization, 12 were destroyed and 32 sustained moderate to
heavy damage. Five occupants suffered minor injuries.
---------------------------------------------------------------------------
\160\ NTSB, Accident Report PAR-82/03, ``Missouri Power and
Light Company Natural Gas Fires, Centralia, Missouri, January 28,
1982'' (Aug. 24, 1982).
---------------------------------------------------------------------------
The NTSB investigated one other incident in 1977 that was nearly
identical to the 2018 incident in
[[Page 61788]]
Merrimack Valley. Both incidents occurred when a cast-iron main with
control lines attached was isolated as part of a pipe replacement
project. On August 9, 1977, natural gas under high pressure entered a
Southern Union Gas Company's low-pressure natural gas distribution
pipeline and overpressurized a system serving more than 750 customers
in a 7-block area in El Paso, TX. The gas company was replacing a
section of 10-inch cast-iron low-pressure natural gas main containing
the pressure-sensing control lines for a nearby upstream regulator
station and its monitor and isolated it between two valves with a
temporary bypass installed. Southern Union Gas Company was aware that
the isolated section contained the control lines but did not realize
the potential hazard of isolating the pressure-sensing control lines,
which would make the two regulators inoperative. Without the ability to
sense the actual pressure in the gas main, the regulators allowed the
pressure to build up and overpressurized the rest of the affected
system. The problem was corrected before causing any fatalities or
major injuries.\161\
---------------------------------------------------------------------------
\161\ NTSB, Safety Recommendation(s) P-77-43 (Dec. 9, 1977),
https://www.ntsb.gov/safety/safety-recs/RecLetters/P77_43.pdf.
---------------------------------------------------------------------------
As a result of its investigation of the CMA overpressurization
event, as well as a review of multiple overpressurizations that
occurred as the result of a common mode of failure, the NTSB
recommended in P-19-14 that PHMSA revise 49 CFR part 192 to require
additional overpressure protection for low-pressure natural gas
distribution systems that cannot be defeated by a single operator error
or equipment failure. NiSource also took action to remove this
vulnerable design on their systems. On December 14, 2018, the CEO of
NiSource committed to the NTSB that they would install automatic
pressure control equipment, referred to as ``slam-shut'' devices, on
every low-pressure system throughout their operating area.\162\ These
devices provide another level of control and protection, as they
immediately shut off gas to the system when they sense operating
pressure that is too high or too low. That measure exceeds current
Federal requirements.
---------------------------------------------------------------------------
\162\ Sec. and Exch. Comm'n, Form 10-Q Quarterly Report,
``NiSource, Inc.'' at 42 (Oct. 30, 2019), https://www.sec.gov/Archives/edgar/data/1111711/000111171119000041/ni-2019930x10q.htm.
---------------------------------------------------------------------------
Subsequent to the 2018 CMA incident, PHMSA was required by statute
to issue regulations ensuring that distribution system operators
minimize the risk of a common mode of failure at low-pressure district
regulator stations, monitor the gas pressure of a low-pressure system,
and install overpressure protection safety technology at low-pressure
district regulator stations. (49 U.S.C. 60102(t)(3)). The mandate also
provides that if it is not operationally possible to install such
technology, PHMSA's regulations must provide that operators would have
to develop and follow plans that would minimize the risk of an
overpressurization.
After reviewing NTSB's recommendations, the CMA and other related
incidents, and the requirements of 49 U.S.C. 60102(t)(3), PHMSA
proposes additional requirements to improve the design standard for
overpressure protection on low-pressure distribution systems. Gas
distribution systems that use only regulators and control lines as the
means to prevent overpressurization are not sufficient protection from
overpressurization events. Therefore, PHMSA is proposing additional
layers of protection specific to low-pressure distribution systems to
set a safer design standard for these systems.
4. Proposal To Amend Sec. 192.195--Overpressure Protection
Consistent with 49 U.S.C. 60102(t)(3), PHMSA proposes to amend
Sec. 192.195 to impose three additional requirements for each district
regulator station that serves a low-pressure distribution system.
First, each district regulator station must consist of at least two
methods of overpressure protection (such as a relief valve, monitoring
regulator, or automatic shutoff valve) appropriate for the
configuration and location of the station. Under this proposal,
operators have options for meeting the new requirements for
overpressure protection. For example, one option is for operators of
low-pressure distribution systems to install a full relief valve
downstream of existing overpressure protections. Another option is to
install an automatic shutoff valve. In that case, for operators with
the worker and monitor regulator set up, the addition of an automatic
shutoff valve downstream of the existing setup would stop the flow of
gas if an overpressurization occurred and both regulators failed.
Further, some automatic shutoff valves have the capability to activate
if the system experiences an underpressurization.\163\ PHMSA discussed
these additional options in the overpressure protection advisory
bulletin (ADB-2020-02), but there are other configurations that would
be suitable as well.
---------------------------------------------------------------------------
\163\ An underpressurization could occur if there is a pipeline
rupture downstream, which is a risk during excavation.
---------------------------------------------------------------------------
PHMSA proposes this two-method requirement as mandatory for
district regulator stations that are new, replaced, relocated, or
otherwise changed after the effective date of the final rule. For all
other systems, PHMSA proposes to amend Sec. 192.1007(d)(2)(ii) to
require operators to ensure district regulator stations have two
methods of overpressure protection consistent with proposed Sec.
192.195(c)(1), or identify and notify PHMSA of alternative preventive
and mitigative measures. PHMSA finds that this approach meets the
mandate found at 49 U.S.C. 60102(t)(3)(iii) and (iv) for all district
regulator stations to have at least two methods of overpressure
protection technology appropriate for the configuration and siting of
the station, while allowing for alternate action where PHMSA determines
it is not operationally possible to have such secondary relief. PHMSA
concludes that it is operationally possible for operators to include at
least two methods of overpressure protection in new, replaced,
relocated, or otherwise changed district regulator stations. And, for
existing district regulator stations, PHMSA recognizes that there may
be unique cases where it is not operationally possible to have a second
measure, in which circumstance an operator may notify PHMSA under Sec.
192.1007(d)(2)(ii)(B) of the alternative measures to minimize the risk
of an overpressure event.
Second, PHMSA proposes that each district regulator station that
services a low-pressure system must minimize the risk of
overpressurization that could be caused by any single event (such as
excavation damage, natural forces, equipment failure, or incorrect
operations) that either immediately or over time affects the safe
operation of more than one overpressure protection device. PHMSA notes
that 49 U.S.C. 60102(t)(3) requires the promulgation of regulations
that minimize the risk of gas pressure exceeding the MAOP from a common
mode of failure. PHMSA interprets the statutory term ``common mode of
failure'' to mean a failure where a single common cause could
immediately or over time cause multiple failures that result in an
overpressurization on a downstream distribution system. PHMSA's
interpretation of ``common mode of failure'' is intended to ensure that
operators are identifying as many potential failure modes in their
systems as possible.
[[Page 61789]]
This practice of identifying potential common modes of failure will
be particularly important for operators of low-pressure gas
distribution systems, whose designs make them more vulnerable to
overpressurization. For example, hydrotesting upstream of the district
regulator station could cause moisture to be injected into the gas
system, which then could cause the working and monitor regulators to
freeze up before the gas distribution operator responds. Construction
work upstream of the district regulator station could cause
contaminants like metal shavings to be introduced into the gas system,
which then could damage the working and monitor regulator diaphragms
before the gas distribution operator could respond. Oil, hydrates, or
high sulfides that enter the gas system could affect both the working
and monitoring regulators before the gas distribution operator could
respond. A contractor or third party could damage both downstream
control lines at the same time. And, as seen in the 2018 Merrimack
Valley incident, connecting a new main to the district regulator
station without connecting the control lines to the new piping could
result in an overpressurization. In its proposed Sec. 192.195(c)(2),
PHMSA provides examples of single events that could cause a common mode
of failure, such as excavation damage, natural forces, equipment
failure, or incorrect operations. While operators are best positioned
to identify other scenarios that could introduce a common mode of
failure on their unique gas distribution systems, applying any of the
design standards described in this proposed amendment could eliminate
most of the common modes of failure described in this paragraph and in
Sec. 192.195(c)(2) by providing additional redundancy in the gas
distribution system.
Third, pursuant to 49 U.S.C. 61012(t)(3), PHMSA proposes in Sec.
192.195(c)(3) to require that low-pressure distribution systems have
remote monitoring of gas pressure at or near the location of
overpressure protection devices. Remote monitoring in this context
means that the device is capable of monitoring the gas pressure near
the location of overpressure protection devices and remotely displaying
the gas pressure to operator personnel in real time. Low-pressure gas
distribution operators are already required to have devices such as
telemetering or recording gauges that record gas pressure (see
Sec. Sec. 192.199 and 192.201). However, the current telemetering and
recording device requirements in Sec. 192.741 do not require active
monitoring and some of these devices employed under Sec. Sec. 192.199,
192.201, and 192.741 are not designed to provide real-time awareness or
notification of potential overpressurizations. Installing these real-
time monitoring devices will improve an operator's ability to receive
timely overpressurization indications, thereby giving operator
personnel an opportunity to avoid or mitigate adverse consequences.
Accordingly, PHMSA also proposes a conforming change in a new Sec.
192.741(d) to specify that operators of low-pressure distribution
systems that are new, replaced, relocated, or otherwise changed
beginning one year after the publication of any final rule in this
proceeding must monitor the gas pressure in accordance with Sec.
192.195(c)(3).
These three new design standards would be applicable to low-
pressure distribution systems that are new, replaced, relocated, or
otherwise changed beginning one year after the publication of any final
rule in this proceeding. A modification to either the low-pressure
system or the district regulator station made on or after the
compliance date above would require an operator to meet the proposed
new design standards described in this section. For example, as
operators upgrade their low-pressure systems as part of the cast iron
replacement program or implement mitigating measures to address the
risk of overpressurization through the DIMP requirements in Sec.
192.1007, they would be required to ensure those upgrades meet the
proposed design standard in Sec. 192.195(c). PHMSA would not expect
operators performing routine maintenance to upgrade their systems to
meet the proposed design standard.
PHMSA understands this proposed requirement for gas distribution
operators to incorporate in their design of low-pressure distribution
systems the overpressure protection measures described above would be
reasonable, technically feasible, cost-effective, and practicable.
These proposed enhanced design and installation requirements would be
applicable only to certain gas distribution operators--those with
district regulators serving low-pressure systems--and then only when
components within their systems are new, replaced, relocated, or
otherwise changed. Affected operators would therefore be able to
integrate these common-sense, proposed safety enhancements within
larger construction, installation, and replacement projects. Indeed,
some low-pressure gas distribution system operators may already be
complying with this proposed requirement either as a voluntarily for
commercial reasons (to minimize the loss of a valuable commodity), as a
safety practice (implementing lessons learned from the Merrimack Valley
incident and NTSB recommendation P-19-14) or as a mitigation measure
pursuant to their DIMP. Viewed against those considerations and the
compliance costs estimated in the PRIA, PHMSA expects its proposed
amendments will be a cost-effective approach to achieving the
commercial, public safety, and environmental benefits discussed in this
NPRM and its supporting documents. Lastly, PHMSA understands that its
proposed compliance timeline--one year after publication of a final
rule (which would necessarily be in addition to the time since
publication of this NPRM)--would provide operators ample time to
incorporate these requirements in plans for new, replaced, relocated,
or otherwise changed low pressure distribution systems (and manage any
related compliance costs).
I. Inspection: General (Section 192.305)
1. Current Requirements--Inspections
Section 192.305 (Inspection: General) states that ``[e]ach
transmission line or main must be inspected to ensure that it is
constructed in accordance with this part.''
2. Need for Change--Inspections
On November 29, 2011, PHMSA issued an NPRM that included a proposal
to modify the requirements contained in Sec. 192.305 to specify that a
gas transmission pipeline or distribution main cannot be inspected by
someone who participated in its construction.\164\ This addressed
concerns expressed by State and Federal regulators and was based in
part on a 2011 NAPSR resolution calling for revisions to Sec. 192.305
to provide that contractors who install a transmission pipeline or
distribution main should be prohibited from inspecting their own work
for compliance purposes.\165\ At the time, Sec. 192.305 had simply
provided that each transmission pipeline or distribution main must be
inspected to ensure that it was constructed in accordance with 49 CFR
part 192. In a final rule issued on March 11, 2015, PHMSA amended Sec.
192.305 to specify that a pipeline operator may not use the same
operator personnel to perform a required
[[Page 61790]]
inspection who also performed the construction task that required
inspection.\166\
---------------------------------------------------------------------------
\164\ ``Pipeline Safety: Miscellaneous Changes to Pipeline
Safety Regulations,'' 76 FR 73570 (Nov. 29, 2011). On July 11, 2012,
the Gas Pipeline Advisory Committee (GPAC) recommended that PHMSA
adopt this amendment.
\165\ NAPSR, Resolution CR-1-02, Doc. No. PHMSA-2010-0026-0002
(Dec. 15, 2011).
\166\ ``Pipeline Safety: Miscellaneous Changes to Pipeline
Safety Regulations,'' 80 FR 12762, 12779 (Mar. 11, 2015).
---------------------------------------------------------------------------
PHMSA received petitions for reconsideration of various elements of
the March 2015 final rule, including petitions from the American Public
Gas Association (APGA) and other stakeholders raising concern about the
construction inspection requirement in Sec. 192.305 for smaller
operators for whom it may be particularly difficult to have different
personnel perform construction and inspection activities.\167\ The APGA
petition noted that utilities with only one qualified crew who work
together to construct distribution mains would not have anyone working
for the utility available and qualified to perform the inspection under
the amended language, which could significantly increase the costs for
those utilities by requiring small utilities to contract with third
parties for such inspections.\168\ In 2015, according to the APGA, 585
municipal gas utilities had 5 or fewer employees. The APGA stated that
its concerns would be alleviated by a clarification stating a two-man
utility crew may inspect each other's work and comply with the
amendment to Sec. 192.305.
---------------------------------------------------------------------------
\167\ APGA, ``Petition for Clarification or in the Alternative
Reconsideration of the American Public Gas Association,'' Doc. No.
PHMSA-2010-0026-0055, at 4 (Apr. 10, 2015); American Gas
Association, ``Request for Effective Date Extension for Construction
Inspection Changes and Petition for Reconsideration of `Pipeline
Safety: Miscellaneous Changes to Pipeline Safety Regulations,'' Doc.
No. PHMSA-2010-0026-0056 (Apr. 10, 2015); NAPSR, ``NAPSR Request for
Delay in the Effective Date of Amended Rule 192.305 on Construction
Inspection,'' Doc. No. PHMSA-2010-0026-0059 (July 28, 2015).
\168\ APGA, ``Petition for Clarification or in the Alternative
Reconsideration of the American Public Gas Association,'' Doc. No.
PHMSA-2010-0026-0055, at 4 (Apr. 10, 2015).
---------------------------------------------------------------------------
NAPSR, on the other hand, submitted a petition criticizing the
March 2015 final rule for not limiting the Sec. 192.305 prohibition to
contractor personnel inspecting the work performed by their own
company's crews, contending that such an approach would not resolve the
potential conflict of interest that had been the occasion for its 2011
resolution.\169\ NAPSR added that prohibition should not apply to an
operator's own construction personnel as NAPSR believed they would have
less of an incentive to accept poor quality work when conducting an
inspection than a contractor inspecting his colleagues' work. NAPSR
asked for a delay in the effective date of the final rule relative to
Sec. 192.305 until PHMSA had reviewed the rule and worked with NAPSR
to address its concerns.
---------------------------------------------------------------------------
\169\ NAPSR, ``NAPSR Request for Delay in the Effective Date of
Amended Rule 192.305 on Construction Inspection,'' Doc. No. PHMSA-
2010-0026-0059 (July 28, 2015).
---------------------------------------------------------------------------
PHMSA responded to the petitions for reconsideration of the March
2015 final rule on September 30, 2015, and, in recognition of the
concerns expressed, indefinitely delayed the effective date of the
Sec. 192.305 amendment.\170\ Because other proposed amendments in this
NPRM may impact the number of inspections and construction activities
on gas distribution mains, PHMSA believes it is appropriate to re-
examine this issue.
---------------------------------------------------------------------------
\170\ ``Pipeline Safety: Miscellaneous Changes to Pipeline
Safety Regulations: Response to Petitions for Reconsideration,'' 80
FR 58633, 58634 (Sept. 30, 2015).
---------------------------------------------------------------------------
3. Proposal To Amend Sec. 192.305--Inspections
In this NPRM, PHMSA proposes to remove the existing suspension of
Sec. 192.305, relocate the existing regulatory language adopted in the
March 2015 final rule to a new paragraph (a), and add a new paragraph
(b) addressing concerns raised in APGA's petition for reconsideration
pertaining to the potential impact on small operators.
If adopted, PHMSA's proposed Sec. 192.305(a) would require each
gas transmission pipeline (along with each offshore gas gathering, and
Types A, B, and C gathering pipelines pursuant to Sec. 192.9) and
distribution main that is newly installed, replaced, relocated, or
otherwise changed beginning one year after the publication of a final
rule to be inspected to ensure that it is constructed in accordance
with the requirements of this subpart, using different personnel to
conduct the inspection than had performed the construction activity.
This requirement--which would lift the suspension of the regulatory
amendments adopted in the March 2015 final rule--was the subject of
extensive consideration in PHMSA's earlier notice and comment
rulemaking (including during a meeting of the Gas Pipeline Advisory
Committee (GPAC)).\171\
---------------------------------------------------------------------------
\171\ PHMSA incorporates by reference in this proceeding
pertinent materials from the administrative record in the earlier
proceeding. Those materials can be found in Doc. No. PHMSA-2010-
0026.
---------------------------------------------------------------------------
PHMSA understands that the public safety and environmental risks
associated with releases from Type C gathering pipelines, a category
created in a final rule issued in November 2021 \172\ and thus not
included in the 2015 assessment of cost-effectiveness, technical
feasibility, and practicability, are similar to the risks associated
with other part 192-regulated gas gathering pipelines (which generally
transport unprocessed natural gas containing higher percentages of
volatile organic compounds, corrosives, and hazardous airborne
pollutants than processed natural gas transported in other pipelines).
PHMSA therefore proposes to subject Type C gathering pipelines to the
inspection requirements at Sec. 192.305(a). PHMSA expects to have
operator-reported data after the reporting cycle completes in spring of
2023 for these newly regulated gathering lines.\173\ To address this
uncertainty, PHMSA estimates that most Type C lines are operated by
operators of other part 192-regulated gathering pipelines such that
they are already included in the 2015 assessment of this regulatory
requirement for other lines.\174\ PHMSA explains this estimate in
greater length in the associated preliminary regulatory impact
analysis.
---------------------------------------------------------------------------
\172\ ``Pipeline Safety: Safety of Gas Gathering Pipelines:
Extension of Reporting Requirements, Regulation of Large, High-
Pressure Lines, and Other Related Amendments,'' 86 FR 63266 (Nov.
15, 2021).
\173\ PHMSA's preliminary review of the incoming reported data
supports its estimates in the PRIA for Type C lines.
\174\ See Preliminary Regulatory Impact Analysis, available in
the docket for this rulemaking.
---------------------------------------------------------------------------
Additionally, PHMSA has evaluated concerns raised in APGA and other
petitioners' reconsideration petitions, and PHMSA proposes to add a
paragraph (b) that would provide an exception to the construction
inspection requirement for gas distribution mains for small gas
distribution operators for whom complying with paragraph (a) may prove
difficult due to their limited staffing. Specifically, PHMSA proposes
to allow operator personnel involved in the same construction task to
inspect each other's work on mains when the operator could otherwise
comply with the construction inspection requirement in paragraph (a) of
this section only by using a third-party inspector. This justification
must be documented and retained for the life of the pipeline. This
exception is in acknowledgment that, as highlighted by APGA, there are
times when only one or two people are available to perform a task and
the current requirements may be overly burdensome for smaller gas
distribution operators. PHMSA proposes to limit this exception to
distribution operators because it understands that: (1) many of these
operators are likely to have a limited number of employees, thereby
necessitating reliance on contractor personnel; and (2) the public
safety risks from delays in undertaking safety-improving construction
projects
[[Page 61791]]
(because of a lack of qualified inspection personnel) on these
pipelines would be particularly compelling given their (typical)
location near or within population centers. PHMSA believes this
proposed amendment addresses concerns raised in APGA's petitions for
reconsideration regarding the unintended burdens of the March 2015
rulemaking on small operators.
PHMSA acknowledges that NAPSR, in its 2011 resolution and petition
for reconsideration of the March 2015 final rule, called for limiting
the prohibition to contractor personnel inspecting the work of their
own crew, as NAPSR does not view an ``inherent conflict of interest''
arising from operator-employed personnel doing the same.\175\ PHMSA
agrees with NAPSR that a lack of independence in inspection activity
raises public safety concerns but disagrees that there is a material
distinction in risk between those personnel directly employed by the
operator and those third-party personnel contracted by the operator.
Further, creating such a distinction could diminish the scope of the
safety benefit while placing burden on smaller operators who rely on
contractors for a large portion of their construction work. Therefore,
PHMSA does not see a reasoned basis to discriminate between operator
personnel and contracted personnel for the purposes of this inspection.
---------------------------------------------------------------------------
\175\ See NAPSR, Res. 2015-01, ``A Resolution Seeking Suspension
of the Effective Date of a Recently Adopted Federal Final Rule, and
Reconsideration of that Rule,'' at 2 (Sept. 3, 2015), https://www.napsr.org/resolutions.html.
---------------------------------------------------------------------------
PHMSA understands this proposed amendment to restore a previously
approved (but now suspended) requirement that post-construction
inspections be performed by personnel other than those who performed
the construction work being inspected would be reasonable, technically
feasible, cost-effective, and practicable for all affected operators.
That requirement reflects the proposition--reflected in industry best
practice--that an independent second set of eyes inspecting a
construction project provides more robust assurance of work product
quality than allowing construction personnel to inspect their own work.
Although PHMSA acknowledges that this proposed requirement could entail
additional compliance burdens (in terms of costs and stretching limited
personnel resources) for some operators, PHMSA believes those burdens
would be manageable because (1) all operators could account for them at
the project planning phase in a way that allows them to control costs
or secure requisite supplemental personnel (or contractors), and (2)
small gas distribution system operators whose limited personnel
resources would make them dependent on (potentially expensive)
contractors would be excepted from this requirement. Viewed against
those considerations and the compliance costs estimated in the PRIA,
PHMSA expects its proposed amendments will be a cost-effective approach
to achieving the commercial, public safety, and environmental benefits
discussed in this NPRM and its supporting documents. Lastly, PHMSA
understands that its proposed compliance timeline--one year after
publication of a final rule (which would necessarily be in addition to
the time since publication of this NPRM)--would provide operators ample
time to implement requisite changes to their procedures and obtain
access to inspection personnel for near-term installation projects (as
well as manage any resulting compliance costs).
J. Records: Tests (Sections 192.517 and 192.725)
1. Current Requirements--Records: Tests
Section 192.517(b) applies to all gas pipeline operators and states
that ``[e]ach operator must maintain a record of each test required by
Sec. Sec. 192.509 [pipelines operating below 100 psig], 192.511
[service lines], and 192.513 [plastic pipelines], respectively, for at
least 5 years.'' Section 192.725(a) states that ``each disconnected
service line must be tested in the same manner as a new service line,
before being reinstated.'' \176\
---------------------------------------------------------------------------
\176\ Paragraph (b) provides an exception to paragraph (a) for
any part of the original service line used to maintain continuous
service during testing if provisions are made to maintain continuous
service.
---------------------------------------------------------------------------
2. Need for Change--Records: Tests
On October 7, 2021, NAPSR submitted a resolution seeking that PHMSA
amend Sec. 192.517(b) in several ways. NAPSR recommended PHMSA amend
its regulations to require operators to retain test documentation under
Sec. 192.517(b) for the life of the corresponding pipeline segment as
opposed to the current 5 years.\177\ The resolution also requested that
PHMSA require operators to retain for the life of the pipeline ``the
test pressure documentation created within the five years prior'' to
any such amendment. Additionally, NAPSR requested that PHMSA require
additional, more detailed, information be documented as part of these
test records. PHMSA agrees that the detailed recordkeeping content and
retention requirements suggested by NAPSR will improve consistency and
promote public safety and protection of the environment.
---------------------------------------------------------------------------
\177\ NAPSR, Res. 2021-02, ``A Resolution Seeking a Modification
of 49 CFR 192.517(b) to Require Certain Distribution Pipeline
Pressure Test Information Be Documented and to Require the Retention
of Test Documentation for Distribution Pipelines for the Lifetime of
the Corresponding Pipeline Segment,'' Doc. No. PHMSA-2021-0046-0005
(Oct. 7, 2021). This extended retention period would include records
of tests establishing an MAOP, as NAPSR explains in its petition:
``PHMSA has set forth regulations requiring the availability and use
of pipeline pressure documentation to establish the maximum
allowable operating pressure (MAOP) of pipelines, including short
segments of replaced or relocated pipe, prior to placing them in
service within Subpart L of 49 CFR 192, specifically 49 CFR
192.619.''
---------------------------------------------------------------------------
NAPSR also requested that PHMSA add Sec. 192.725 (``Test
requirements for reinstating service lines'') to the list of required
test records in Sec. 192.517(b). It reasoned that Sec. 192.603(b),
which requires operators to keep records necessary to administer the
procedures established under Sec. 192.605, is potentially in conflict
with Sec. 192.517. PHMSA clarifies that the requirement in Sec.
192.725 to perform a test ``in the same manner as a new service line''
is meant to direct an operator to conduct a test required for a new
service line in accordance with 49 CFR part 192, subpart J. A test
performed to meet Sec. 192.725 does not constitute a new type of test
for purposes of identifying recordkeeping requirements for such a test.
PHMSA expects an operator to select the appropriate test in subpart J
to meet the testing requirement of Sec. 192.725, which includes
meeting the corresponding recordkeeping requirements of Sec. 192.517.
For that reason, PHMSA does not propose to include Sec. 192.725 in the
list of tests identified within Sec. 192.517.
3. Proposal To Amend Sec. 192.517--Records: Tests
PHMSA proposes to amend Sec. 192.517 to require that records of
tests covered by Sec. 192.517(b) (i.e., tests performed according to
Sec. 192.509, 192.511, and 192.513) be retained for the life of the
pipeline. This amendment would be applicable to all gas pipeline
operators. PHMSA would require operators to retain the records for all
tests presently being retained under the existing language of Sec.
192.517(b) from the preceding five years, which under the proposal
would then be retained for the life of the pipeline. PHMSA also
proposes to require that the records of these tests include, at a
minimum, sufficient information to document the test, including
information about the
[[Page 61792]]
operator, the individual or any company used to perform the test,
pipeline segment being tested, test date, medium, pressure, duration,
and any leaks or failures noted and their disposition. Retaining tests
for the life of the pipeline, instead of the current retention period
of 5 years, ensures that records are available whenever repairs are
necessary, or should an incident occur, records are available to
support an operator's inspection and investigation into the root cause
of a failure. Further, PHMSA currently requires (per Sec. 192.603(b)
and Sec. 192.605) operators to keep MAOP records for life of facility
but MAOP records established by Sec. 192.517(b) tests are just 5
years. PHMSA believes that these changes will improve the quality and
availability of test records, including records of leaks occurring
during testing activities and MAOP establishment records.
PHMSA understands this proposed amendment of an existing record
retention requirement to be reasonable, technically feasible, cost-
effective, and practicable. The proposed changes are incremental
supplementation of current requirements regarding recording and
retaining record of pressure tests operators are already required to
conduct. The proposed amendments require operators to document
information they may already be obtaining through the required tests
under this current requirement, more clearly states that information
which operators should record from the tests and extends the retention
period; PHMSA expects some operators may already be in their
substantial compliance with this proposed requirement. Viewed against
those considerations and the compliance costs estimated in the PRIA,
PHMSA expects its proposed amendments will be a cost-effective approach
to achieving the commercial, public safety, and environmental benefits
discussed in this NPRM and its supporting documents. Lastly, PHMSA
understands that its proposed compliance timeline--one year after
publication of a final rule (which would necessarily be in addition to
the time since publication of this NPRM)--would provide operators ample
time to implement requisite changes to their procedures to ensure
identification or generation of pertinent records (and manage any
related compliance costs).
4. Proposal To Amend Sec. 192.725--Test Requirements for Reinstating
Service Lines
PHMSA proposes to revise Sec. 192.725 to clarify that ``tested in
the same manner as a new service line'' in the existing regulation
means ``tested in accordance with subpart J of this part'', by
inserting that clarifying language within a parenthetical. PHMSA
understands that this proposed revision merely clarifies an existing
requirement and is therefore technically feasible and practicable.
PHMSA further notes that its proposed compliance timeline--one year
after publication of a final rule (which would necessarily be in
addition to the time since publication of this NPRM)--would provide
operators ample time to implement updates, if any are needed, to their
procedures.
K. Miscellaneous Amendments Pertaining to Part 192--Regulated Gas
Gathering Pipelines (Sections 192.3 and 192.9)
1. Current Requirements--Gas Gathering
Among the regulatory amendments adopted in the April 2022 Valve
Rule were enhanced emergency planning and notification requirements
applicable to all part 192-regulated gas pipeline operators subject to
Sec. 192.615, to include new references to public safety answering
points (such as 9-1-1 call centers) and a requirement for those
operators to update their written procedures to provide for timely
rupture identification; certain new, implementing definitions at Sec.
192.3 applicable to all part 192-regulated gas pipelines; and within a
new Sec. 192.635, a definition of the term ``notification of potential
rupture'' applicable to those part 192-regulated pipelines subject to
that provision.
The D.C. Circuit, however, vacated those new requirements as to gas
gathering pipelines in a decision issued in May 2023.\178\ PHMSA
subsequently issued a Technical Correction codifying the court's
decision by introducing exceptions to the above provisions restricting
their application to the part-192 regulated gas gathering pipelines to
which they had applied.\179\ Specifically, the Technical Correction
introduced language in each of the Sec. 192.3 definitions adopted in
the Valve Rule (``entirely replaced onshore transmission pipeline
segments''; ``notification of potential rupture''; and ``rupture-
mitigation valve (RMV)'') excepting all part 192-regulated gas
gathering pipelines from those definitions. The Technical Correction
also introduced a series of exceptions within the regulatory cross-
reference provision at Sec. 192.9 preventing application of the Valve
Rule's amendments at Sec. Sec. 192.615 and 192.635 regarding emergency
response and notification and rupture identification procedures to each
of offshore gas gathering pipelines (Sec. 192.9(b)) as well as onshore
Types A (Sec. 192.9(c)) and C (Sec. 192.9(e)) gas gathering
pipelines.
---------------------------------------------------------------------------
\178\ GPA Midstream Assn. v. Dep't of Transp., 67 F.4th 1188,
1201 (D.C. Cir. 2023).
\179\ 88 FR at 50058, 50060-61 (Aug. 1, 2023).
---------------------------------------------------------------------------
2. Need for Change--Gas Gathering
Written emergency planning and notification procedures are critical
tools for the safe operation of any gas pipeline. Offshore, Type A, and
Type C gas gathering pipelines had--consistent with the risks to public
safety and the environment posed by an emergency involving those high-
pressure, gas pipeline facilities \180\--been subject to extensive
emergency planning and notification requirements before issuance of the
Valve Rule in April 2022. Those long-standing safety standards include
requirements for operators to have written emergency procedures for
notifying, establishing, and maintaining communications with fire,
police, and other public officials (Sec. 192.615(a)(2) and (8); Sec.
192.615(c)); taking actions necessary to minimize hazards to public
safety from the emergency (Sec. 192.615(a)(6)); and directing operator
control room response actions in an emergency (Sec. 192.615(a)(11)).
---------------------------------------------------------------------------
\180\ See, e.g., ``Gas Gathering Line Definition; Alternative
Definition for Onshore Lines and New Safety Standards--Final Rule,''
71 FR 13292, 13296-97 (Mar. 15, 2006) (discussing safety basis for
broadly extending part 192 requirements for gas transmission lines
to Type A gas gathering pipelines); 86 FR at 63284-85 (discussing
safety basis for extending Sec. 192.615 requirements to high-
pressure, large-diameter Type C gas gathering pipelines).
---------------------------------------------------------------------------
The amendments to Sec. 192.615 introduced in the Valve Rule were
modest refinements to those long-standing emergencies response planning
and notification requirements. The Valve Rule explained its amendments
to Sec. 192.615(a)(2), (a)(8), and (c) adding language requiring
notification of, and communication with, public safety answering points
(PSAPs) or emergency coordination agencies ensure notifications of
pipeline emergencies are channeled to resources best positioned to
alert first responders and coordinate response efforts across multiple
jurisdictions that may be affected by a pipeline emergency.\181\ The
Valve Rule also made a pair of incremental changes to Sec.
192.615(a)(6)'s requirement that operator procedures provide for taking
certain actions--emergency shutdown or pressure reduction--to minimize
public safety risks. The first change was to add language (``including,
but not limited to . . .'') clarifying that operator procedures could
provide for actions
[[Page 61793]]
other than system shutdown or pressure reduction in an emergency,
thereby granting operators greater flexibility in designing response
actions best capable of minimizing hazards in a pipeline emergency;
this includes the additionally enumerated action of valve shut-off. The
second change included a reference to environmental hazards. Among
those hazards operator procedures must minimize, reflecting the fact
that the mechanism for public safety and environmental harms (namely,
the release of gas from a pipeline) is identical.
---------------------------------------------------------------------------
\181\ 87 FR at 20969-70, 20973.
---------------------------------------------------------------------------
The Valve Rule also made several regulatory amendments to address
the time-dependent \182\ risks to public safety and the environment
posed by ruptures on gas pipelines. First, the Valve Rule added at
Sec. 192.3 (which in turn references a new Sec. 192.935) the new term
``notification of potential rupture'' codifying commonly-understood
indicia of a rupture.\183\ The Valve Rule also added a pair of
requirements ensuring timely identification of, and response to, this
particular emergency in which every second lost can increase public
safety and environmental consequences: a new Sec. 192.615(a)(12)
requiring operators develop procedures for confirming actual ruptures
following reports of the indicia listed in the new definition of
``notification of potential rupture'', as well as language at Sec.
192.615(a)(8) introducing a new requirement for immediate and direct
notification of PSAPs on an operator's notification of a potential
rupture.\184\ Similarly, PHMSA enhanced a longstanding requirement at
Sec. 192.615(a)(11) governing emergency procedures for control room
personnel by adding a cross-reference to newly-adopted provisions
pertaining to rupture mitigation valves at Sec. Sec. 192.634 and
192.636.
---------------------------------------------------------------------------
\182\ The severity of harms to public safety and the environment
from a rupture on a gas pipeline depend (inter alia) on the volume
of gas released, the duration of the release, and the time before
mitigation/response actions are initiated and completed.
\183\ 87 FR at 20949-52, 20972, 20972.
\184\ 87 FR 20952-53.
---------------------------------------------------------------------------
Lastly, the Valve Rule adopted certain other definitions of terms
(``entirely replaced onshore transmission segment''; and ``rupture-
mitigation valve'') employed in its regulatory amendments.
3. Proposal To Amend Sec. Sec. 192.3 and 192.9--Emergency Procedures
and Notification; Rupture Identification Procedures
PHMSA proposes several amendments to restore certain emergency
planning, notification, and rupture identification procedures vacated
by the D.C. Circuit with respect to gas gathering pipelines. First,
PHMSA proposes to delete from each of the Sec. 192.3 definitions
introduced in the Technical Correction language disclaiming application
of those terms to any part 192-regulated gas gathering line.\185\
Second, PHMSA proposes to delete from Sec. 192.9 similar language
excluding application of the Valve Rule's amendments to Sec. 192.615
discussed in section IV.K.2 above to offshore gas gathering (Sec.
192.9(b)), Type A (Sec. 192.9(c)), and Type C (Sec. 192.9(e)) gas
gathering lines. This proposal is focused on application of these
emergency response provisions to gathering lines; PHMSA is not,
however, proposing in this rulemaking to restore application to part
192-regulated gas gathering lines of other regulatory amendments
adopted in the Valve Rule pertaining to rupture mitigation valve
installation, operation, and maintenance.
---------------------------------------------------------------------------
\185\ PHMSA understands that in so doing, the Sec. 192.635
definition of ``notification of potential rupture'' referenced
within Sec. 192.3 would apply to all part 192-regulated gas
gathering pipelines as well.
---------------------------------------------------------------------------
As explained in section IV.K.2 above, the Valve Rule's amendments
to Sec. 192.615 are incremental improvements on existing requirements
applicable to offshore, Type A, and Type C gas gathering pipelines.
Some of those amendments are broad in scope and are applicable to any
emergency on those gas gathering pipelines; others are specific to
ruptures on those pipelines. And each of those amendments is a common-
sense, baseline expectation ensuring operator emergency planning and
notification procedures are directed toward timely and effective
response and mitigation of risks to public safety and the environment.
PHMSA understands these proposed amendments would be reasonable,
technically feasible, cost-effective and practicable for affected gas
gathering pipeline operators. The restoration of definitions at Sec.
192.3 are not themselves operative provisions entailing compliance
burdens for operators; several of those definitions, moreover, are used
in operative provisions inapplicable to gas gathering pipelines. And
although the restored applicability of the Valve Rule's revisions to
Sec. 192.615 could entail additional compliance burdens for affected
gas gathering operators, some operators may already incorporate the
required content in their pipelines' emergency planning and
notification procedures; indeed, such procedures are precisely the sort
of procedures a reasonably prudent operator of any gas pipeline
facility would maintain in ordinary course given that their systems
transport commercially valuable, pressurized (natural flammable, toxic,
or corrosive) gasses. Viewed against those considerations and the
compliance costs estimated in the PRIA, PHMSA expects its proposed
amendments will be a cost-effective approach to achieving the public
safety, and environmental benefits discussed in this NPRM and its
supporting documents. Lastly, PHMSA understands that its proposed
compliance timeline--one year after publication of a final rule (which
would necessarily be in addition to the time since publication of this
NPRM)--would provide operators ample time to implement requisite
changes to their procedures (as well as manage any resulting compliance
costs).
V. Regulatory Analyses and Notices
A. Authority for This Rule
This proposed rule is published under the authority of the
Secretary of Transportation delegated to the PHMSA Administrator
pursuant to 49 CFR 1.97. Among the statutory authorities delegated to
PHMSA are those set forth in the Federal Pipeline Safety Statutes (49
U.S.C. 60101 et seq.). 49 U.S.C. 60102 grants authority to issue
standards for the transportation of gas via any part 192-regulated
gathering pipelines to protect public safety and the environment; and
49 U.S.C. 60102(b)(5) specifies that PHMSA must consider both public
safety and environmental benefits.
This NPRM proposes to implement several provisions of the PIPES Act
of 2020, including those codified at 49 U.S.C. 60102, 60105, 60106, and
60109. Section 60102 authorizes the Secretary of Transportation to
issue regulations governing the design, installation, inspection,
emergency plans and procedures, testing, construction, extension,
operation, replacement, and maintenance of gas pipeline facilities,
including gas transmission, gas distribution, offshore gas gathering,
and Types A, B, and C gas gathering pipelines, each of which would be
subject to various proposed requirements in this NPRM. Sections 60105
and 60106 permit States to assume safety authority over intrastate
pipelines, including gas and hazardous liquid pipelines, and
underground natural gas storage facilities through certifications or
agreements with PHMSA, while section 60107 authorizes the Secretary to
establish requirements governing award of grants supporting
[[Page 61794]]
State pipeline safety programs. Additionally, 49 U.S.C. 60117
authorizes the Secretary of Transportation to direct operators of those
gas pipeline facilities to submit reports to PHMSA to inform PHMSA's
regulatory oversight activities. As described above, 49 U.S.C. 60102,
60105, and 60109 also require the Secretary to issue regulations
updating PHMSA regulations in 49 CFR parts 192 and 198.
B. Executive Orders 12866 and 14094; DOT Regulatory Policies and
Procedures
Executive Order 12866 (``Regulatory Planning and Review''), as
amended by Executive Order 14094 (``Modernizing Regulatory Review''),
requires that agencies ``should assess all costs and benefits of
available regulatory alternatives, including the alternative of not
regulating.'' \186\ Agencies should consider quantifiable measures and
qualitative measures of costs and benefits that are difficult to
quantify. Further, Executive Order 12866 requires that agencies
maximize net benefits (including potential economic, environmental,
public health and safety, and other advantages; distributive impacts;
and equity), unless a statute requires another regulatory approach.
Similarly, DOT Order 2100.6A (``Rulemaking and Guidance Procedures'')
requires that regulations issued by PHMSA and other DOT Operating
Administrations should consider an assessment of the potential
benefits, costs, and other important impacts of the proposed action and
should quantify (to the extent practicable) the benefits, costs, and
any significant distributional impacts, including any environmental
impacts.
---------------------------------------------------------------------------
\186\ E.O. 12866 is available at 58 FR 51735 (Oct. 4, 1993);
E.O. 14094 is available at 88 FR 21879 (Apr. 6, 2023).
---------------------------------------------------------------------------
Executive Order 12866 (as amended by Executive Order 14094) and DOT
Order 2100.6A require that PHMSA submit ``significant regulatory
actions'' to the Office of Management and Budget (OMB) for review. The
proposed rule has been determined to be significant under section 3(f)
of Executive Order 12866 (as amended by section 1(b) of Executive Order
14094) and DOT Order 2100.6A and was reviewed by the Office of
Information and Regulatory Affairs (OIRA) within OMB.
Consistent with Executive Order 12866 (as amended by Executive
Order 14094) and DOT Order 2100.6A, PHMSA has prepared a PRIA assessing
the benefits and costs of the proposed rule as well as reasonable
alternatives. PHMSA estimates the proposed rule will result in
unquantified public safety and environmental benefits associated with
preventing and mitigating incidents on gas distribution and other part
192-regulated gas pipeline facilities. PHMSA estimates annualized costs
of $110 million per year (using a 3 percent discount rate) due to costs
associated with the proposed requirements for updating emergency
response plans, updating O&M manuals, keeping records, gas monitoring
by qualified employees, and assessing and upgrading district regulator
stations. For the full cost/benefit analysis, please see the PRIA in
the rulemaking docket. PHMSA seeks comment on the PRIA, its approach,
and the accuracy of its estimated costs and benefits.
C. Environmental Justice
Executive Order 12898 (``Federal Actions to Address Environmental
Justice in Minority Populations and Low-Income Populations''),\187\
directs Federal agencies to take appropriate and necessary steps to
identify and address disproportionately high and adverse effects of
Federal actions on the health or environment of minority and low-income
populations to the greatest extent practicable and permitted by law.
DOT Order 5610.2C (``U.S. Department of Transportation Actions to
Address Environmental Justice in Minority Populations and Low-Income
Populations'') establishes departmental procedures for effectuating
Executive Order 12898 promoting the principles of environmental justice
through full consideration of environmental justice principles
throughout planning and decision-making processes in the development of
programs, policies, and activities--including PHMSA rulemaking.
---------------------------------------------------------------------------
\187\ 59 FR 7629 (Feb. 16, 1994).
---------------------------------------------------------------------------
PHMSA has evaluated this NPRM under DOT Order 5610.2C and Executive
Order 12898 and has preliminarily determined it will not cause
disproportionately high and adverse human health and environmental
effects on minority and low-income populations. The proposed rule is
facially neutral and national in scope; it is neither directed toward a
particular population, region, or community, nor is it expected to
result in any adverse environmental or health impact any particular
population, region, or community. Rather, PHMSA anticipates the
rulemaking will reduce the safety and environmental risks associated
with losses of integrity on gas pipeline facilities--particularly gas
distribution pipelines in urban or rural areas posing higher risks due
to their vintage, material, and proximity to minority and low-income
communities in the vicinity of those pipelines.\188\ Lastly, as
explained in the draft environmental assessment in the rulemaking
docket, PHMSA anticipates that the regulatory amendments in this
proposed rule will yield greenhouse gas emissions reductions, thereby
reducing the risks posed by anthropogenic climate change to minority
and low-income, populations, underserved and other disadvantaged
communities. This finding is consistent with the most recent
Environmental Justice Executive Order 14096--Revitalizing Our Nation's
Commitment to Environmental Justice for All, by achieving several goals
including continuing to deepen the Administration's whole of government
approach to environmental justice and to better protect overburden
communities from pollution and environmental harms.
---------------------------------------------------------------------------
\188\ See, e.g., Luna & Nicholas, ``An Environmental Justice
Analysis of Distribution-Level Natural Gas Leaks in Massachusetts,
USA,'' 162 Energy Policy 112778 (Mar. 2022); Weller et al.,
``Environmental Injustices of Leaks from Urban Natural Gas
Distribution Systems: Patterns Among and Within 13 U.S. Metro
Areas,'' Environ. Sci & Tech. (May 11, 2022).
---------------------------------------------------------------------------
D. Regulatory Flexibility Act
The Regulatory Flexibility Act, as amended by the Small Business
Regulatory Flexibility Fairness Act of 1996 (5 U.S.C. 601 et seq.),
generally requires Federal agencies to prepare an initial regulatory
flexibility analysis (IRFA) for a proposed rule subject to notice-and-
comment rulemaking under the Administrative Procedure Act. 5 U.S.C.
603(a).\189\ Executive Order 13272 (``Proper Consideration of Small
Entities in Agency Rulemaking'') \190\ obliges agencies to establish
procedures promoting compliance with the Regulatory Flexibility Act;
DOT's implementing guidance is available on its website.\191\
---------------------------------------------------------------------------
\189\ Agencies are not required to conduct an IRFA if the head
of the agency certifies that the proposed rule will not have a
significant impact on a substantial number of small entities. 5
U.S.C. 605.
\190\ 67 FR 53461 (Aug. 16, 2002).
\191\ DOT, ``Rulemaking Requirements Concerning Small
Entities'', https://www.transportation.gov/regulations/rulemaking-requirements-concerning-small-entities (last updated May 18. 2012).
---------------------------------------------------------------------------
This NPRM was developed in accordance with Executive Order 13272
and DOT guidance to ensure compliance with the Regulatory Flexibility
Act and provide appropriate consideration of the potential impacts of
the rulemaking on small entities. PHMSA conducted an IRFA, which has
been made available in the docket for this rulemaking and is summarized
below. A description of the reasons why
[[Page 61795]]
PHMSA is considering this action and a succinct statement of the
objectives of, and legal basis for, the proposed rule are described
elsewhere in the preamble for this rule and not repeated here. PHMSA
seeks comment on whether the proposed rule, if adopted, would have a
significant economic impact on a significant number of small entities.
Description and Estimate of the Number of Small Entities to Which the
Proposed Rule Would Apply
PHMSA analyzed privately owned entities (inclusive of investor-
owned entities) that could be impacted by the rule, which include
companies with natural gas extraction, pipeline transportation, and
natural gas distribution businesses, as well as entities with another
primary business. PHMSA determined whether these entities were small
entities based on the size of the parent entity and using the relevant
SBA size standards set out in Table 43 of the PRIA. PHMSA also analyzed
publicly owned entities that could be impacted by the rule, including
State, municipal, and other political subdivision entities. Publicly
owned entities with population less than 50,000 are considered small.
PHMSA identified 1,239 gas distribution parent entities and
determined that of these parent entities, 92 percent (1,135 parent
entities) are classified as ``small'' based on the relevant criteria
listed above. PHMSA also identified 831 gas transmission and gathering
parent entities in this analysis that do not also operate distribution
systems. Of these gas transmission and gas gathering parent entities,
82 percent are classified as ``small'' (681 parent entities). Because
PHMSA did not have sufficient information to individually categorize
master meter operators or operators of small LPGs by size, PHMSA
conservatively made the over-inclusive decision to consider all master
meter operators and operators of small LPGs to be small entities for
purposes of its analysis.
Description of Projected Reporting, Recordkeeping, and Other Compliance
Requirements of the Proposed Rule, Including an Estimate of the Classes
of Small Entities Which Would Be Subject to the Requirement and the
Type of Professional Skills Necessary for Preparation of the Report or
Record
PHMSA analyzed the costs of compliance for the small gas
distribution, gas transmission and gathering, and master meter and
small LPG operators. PHMSA assessed the annualized cost for gas
distribution operators based on the number of services, and provided a
minimum, average, and maximum annualized cost estimate for each size
category. For small gas distribution operators with 100,000 or fewer
services, PHMSA calculated annualized estimated compliance costs that
ranged from $8,051 to $10,528 depending on the cost scenario and
discount rate.\192\ For gas transmission and gathering operators, PHMSA
calculated minimum, average, and maximum annualized estimated
compliance costs that ranged from $44 to $52,029 depending on the cost
scenario, industry type (transmission or gathering), and discount rate.
For small master meter systems, PHMSA estimated pre-tax annualized
compliance costs for individual operators from $4,421 to $4,590,
depending on the discount rate. For small LPG systems, PHMSA estimated
pre-tax annualized compliance costs for individual operators from
$4,764 to $4,928, again depending on the discount rate.
---------------------------------------------------------------------------
\192\ See PRIA Table 45.
---------------------------------------------------------------------------
PHMSA then calculated cost-to-revenue ratios using the calculated
compliance costs of each small parent entity. PHMSA estimated that 98
percent of small gas distribution parent entities will face after-tax
compliance costs of less than 1 percent of revenue under all evaluated
cost scenarios. PHMSA estimated that 80 to 82 percent of small gas
transmission parent entities operators will incur after-tax compliance
costs of less than 1 percent of revenue. Under the maximum cost
scenario, PHMSA estimates that 1 percent of small parent entities will
incur compliance costs above 1 percent but below 3 percent of revenue.
Under this maximum cost scenario, PHMSA also estimates that one small
parent entity will incur compliance costs above 3 percent of revenue.
However, PHMSA believes the maximum cost scenario is unlikely, as it
assumes the entirety of estimated new and replaced lines are
attributable to a single operator.\193\ For master meter operators and
operators of small LPGs, PHMSA calculated the break-even value of
annual revenue that would be required for their calculated after-tax
compliance costs to be 1 percent and 3 percent of revenue. For master
meter operators, PHMSA estimated that revenue would need to be $442,122
or less for compliance costs to be 1 percent of revenue and that
revenue would need to be $147,374 or less for compliance costs to be 3
percent of revenue. For operators of small LPGs, PHMSA estimated that
revenue would need to be $476,357 or less for compliance costs to be 1
percent of revenue and that revenue would need to be $158,786 or less
for compliance costs to be 3 percent of revenue.
---------------------------------------------------------------------------
\193\ For the other 18% of operators, PHMSA did not have
sufficient data to calculate the revenue percentage for the
compliance costs of the rule at this time. PHMSA seeks comment on
compliance costs generally, but in particular for transmission and
gathering operators for which sufficient data was not available.
---------------------------------------------------------------------------
Relevant Federal Rules Which May Duplicate, Overlap or Conflict With
the Proposed Rule
PHMSA did not identify any Federal rules that may duplicate,
overlap, or conflict with the proposed rule. In Section 7.6 of the PRIA
accompanying this NPRM, PHMSA provides details on other Federal
regulations that may impact operators of gas pipelines.
Description and Analysis of Significant Alternatives to the Proposed
Rule Considered
PHMSA analyzed a number of alternatives to the NPRM, which are
described in detail in Section 2 of the PRIA accompanying this NPRM. In
addition to retaining the status quo and not issuing the proposal,
which PHMSA determined would fail to satisfy PIPES Act mandates to
improve safety and update PHMSA regulations, PHMSA also analyzed:
1. Retaining DIMP requirements for small LPG operators and imposing
the updated DIMP requirements of this NPRM on those same operators.
2. Extending to all part 192-regulated pipelines an exception that
currently allows, for distribution mains only, distribution operator
personnel involved in the same construction task to inspect each
other's work.
3. An alternative compliance date.
4. Imposing an ICS requirement for emergency response.
5. Requiring all future construction projects associated with
installations, modifications, replacements, or system upgrades on gas
distribution pipelines to have licensed professional engineer approval
and stamping.
6. Requiring gas distribution operators to develop and follow an
MOC process as outlined in ASME/ANSI B31.8S.
PHMSA did not identify any viable alternative that could accomplish
the stated objectives of applicable statutes while further minimizing
any significant economic impact of the proposed rule on small entities.
As discussed in more detail elsewhere in this preamble and in Section 2
of the PRIA for this NPRM, PHMSA determined that these requirements
could result in reductions in safety benefits that were not justified
by any potential cost savings (e.g., the proposal
[[Page 61796]]
to extend the exception for distribution mains that allows distribution
operator personnel to inspect each other's work on the same
construction task to all part-192 regulated pipelines) or impose costs
on small entities that were not justified by any increased safety
benefits. PHMSA therefore declined to propose these alternatives but
seeks comment on them in this proposed rule.
E. Executive Order 13175: Consultation and Coordination With Indian
Tribal Governments
PHMSA analyzed this proposed rule in accordance with the principles
and criteria contained in Executive Order 13175 (``Consultation and
Coordination with Indian Tribal Governments'') \194\ and DOT Order
5301.1A (``Department of Transportation Programs, Policies, and
Procedures Affecting American Indians, Alaska Natives, and Tribes'').
Executive Order 13175 requires agencies to ensure meaningful and timely
input from Tribal government representatives in the development of
rules that significantly or uniquely affect Tribal communities by
imposing ``substantial direct compliance costs'' or ``substantial
direct effects'' on such communities, or the relationship or
distribution of power between the Federal Government and Tribes.
---------------------------------------------------------------------------
\194\ 65 FR 67249 (Nov. 6, 2000).
---------------------------------------------------------------------------
PHMSA assessed the impact of the proposed rule and does not expect
it will significantly or uniquely affect Tribal communities or Indian
Tribal governments. The proposed rule's regulatory amendments are
facially neutral and will have broad, national scope. PHMSA, therefore,
does not expect this rule to significantly or uniquely affect Tribal
communities, impose substantial compliance costs on Native American
Tribal governments, or mandate Tribal action. And insofar as PHMSA
expects the NPRM will improve safety and reduce environmental risks
associated with gas distribution pipelines, PHMSA expects it will not
entail disproportionately high adverse risks for Tribal communities.
Therefore, PHMSA concludes that the funding and consultation
requirements of Executive Order 13175 and DOT Order 5301.1A do not
apply to this proposed rule.
While PHMSA is not aware of specific Tribal-owned business entities
that operate part 192-regulated gas pipelines, any such business
entities could be subject to direct compliance costs as a result of
this proposed rule. PHMSA seeks comment on the applicability of
Executive Order 13175 to this proposed rule and the existence of any
Tribal-owned business entities operating pipelines affected by the
proposed rule (along with the extent of such potential impacts).
F. Paperwork Reduction Act
Pursuant to 5 CFR 1320.8(d), PHMSA is required to provide
interested members of the public and affected agencies with an
opportunity to comment on information collection and recordkeeping
requests. If adopted, the proposals in this rulemaking would impose new
notification and recordkeeping requirements for all part 192-regulated
pipelines, including gas distribution, gas transmission and gathering
pipelines.
PHMSA proposes to require gas distribution operators to review
their integrity management plans to ensure that the plans identify
specific threats such as: (1) certain materials, such as cast iron and
other piping with known issues, (2) the age of each component of the
operator's pipelines along with the overall age of its system, (3)
overpressurization of low-pressure systems, and (4) extreme weather and
geohazards. PHMSA also proposes that, when identifying and implementing
measures to address those risks, operators must address (at a minimum)
the risks associated with each of the following: the presence of known
issues, the age of each part of a pipeline along with the overall age
of the system, and (for operators of low-pressure gas distribution
systems) overpressurization. PHMSA plans to revise the ``Pipeline
Safety: Integrity Management Program for Gas Distribution Pipelines''
information collection that is currently approved under OMB Control No.
2137-0625 to include this new requirement. Since pipeline operators are
already required to review and update their integrity management plans
on a regular basis, PHMSA expects operators to incur minimal burden in
complying with this information collection request.
PHMSA also proposes to repeal the requirement for operators of
small LPGs to participate in the distribution integrity management
program. Based on a recent study, PHMSA estimates there are as many as
4,492 small LPG operators. PHMSA proposes to create a new form, PHMSA
Form 7100.1-2, to collect limited data from these operators of small
LPGs on an annual basis. As a result, PHMSA expects the burden of the
``Pipeline Safety: Integrity Management Program for Gas Distribution
Pipelines'' information collection under OMB Control No. 2137-0625 to
be reduced and the burden for information collection under OMB Control
No. 2137-0522 for the collection of annual and incident report data to
increase due to the creation of the new form. Specifically, PHMSA
expects each small LPG operator to spend 6 hours, annually, completing
the new report form, resulting in an increase of 4,492 responses and
26,952 hours to the overall burden for the information collection under
OMB Control No. 2137-0522. For the information collection under OMB
Control No. 2137-0625, PHMSA previously estimated there were 2,539
operators of small LPG systems. Consequently, PHMSA expects the burden
of that currently approved collection to be reduced by 2,539 responses
and 66,014 hours due to the removal of small LPG operators. PHMSA also
plans to revise the ``Gas Distribution Annual Report Form F7100.1-1''
information collection currently approved under OMB Control No. 2137-
0629 to include the newly proposed requirements. For gas distribution
pipelines, PHMSA proposes to collect additional information such as the
number and miles of low-pressure service pipelines, including their
overpressure protection methods.
PHMSA proposes codifying within the pipeline safety regulations its
State Inspection Calculation Tool (SICT). The SICT is one of many
factors used to help states determine the base level amount of time
needed for administering adequate pipeline safety programs and is a
consideration when PHMSA awards grants to states supporting those
programs. PHMSA plans to revise the ``Gas Pipeline Safety Program
Performance Progress Report'' and ``Hazardous Liquid Pipeline Safety
Program Performance Progress Report'' information collection currently
approved under OMB Control No. 2137-0584 to account for the burden
incurred by state representatives to report data via the SICT.
Operators are required to maintain records pertaining to various
aspects of their pipeline systems. Under the proposals in this
rulemaking, PHMSA would expand the recordkeeping requirements for all
gas pipeline operators. Operators would be required to revise their
emergency response plans to include procedures ensuring prompt and
effective response by adding emergencies involving a release of gas
that results in a fatality, as well as any other emergency deemed
significant by the operator. In the event of a release of gas resulting
in one or more fatalities, all operators would also be required to
immediately and directly notify emergency response officials upon
receiving notice of the same. For distribution pipeline operators only,
[[Page 61797]]
PHMSA's proposed expansion of the list of emergencies discussed above
would also include the unintentional release of gas and shutdown of gas
service to 50 or more customers (or 50 percent of its customers if it
has fewer than 100 total customers). Operators would need to
immediately and directly notify emergency response officials on
receiving notice of the same.
PHMSA also proposes a series of regulatory amendments requiring gas
distribution operators to update their emergency response plans to
improve communications with the public during an emergency. First,
PHMSA proposes to introduce a new requirement for gas distribution
operators to establish and maintain communications with the general
public as soon as practicable during an emergency. Second, PHMSA
proposes to add a new requirement for gas distribution pipeline
operators to develop and implement, no later than 18 months after the
publication of any final rule in this proceeding, an opt-in system to
keep their customers informed of the status of pipeline safety in their
communities should an emergency occur. PHMSA also proposes a new
requirement for gas distribution operators to notify their customers
and public officials in certain instances. PHMSA plans to create a new
information collection to cover these notification requirements for gas
distribution operators. PHMSA will request a new Control Number from
OMB for these information collections. PHMSA will submit these
information collection requests to OMB for approval based on the
proposed requirements in this rule.
Operators would also be required to review and update their O&M
manuals as needed pursuant to the proposal. Gas distribution operators
would also be required to document and maintain records on their MOC
processes and additional safety procedures. Further, PHMSA proposes
that all gas distribution pipeline operators identify and maintain
traceable, verifiable, and complete maps and records documenting the
characteristics of their systems that are critical to ensuring proper
pressure controls for their gas distribution pipeline systems and to
ensure that those records are accessible to anyone performing or
supervising design, construction, and maintenance activities on their
systems. PHMSA proposes to specify that these required records include
(1) the maps, location, and schematics related to underground piping,
regulators, valves, and control lines; (2) regulator set points, design
capacity, and valve-failure mode (open/closed); (3) the system's
overpressure-protection configuration; and (4) any other records deemed
critical by the operator. PHMSA proposes to require that the operator
maintain these integrity-critical records for the life of the pipeline
because these records are critical to the safe operation and pressure
control of a gas distribution system. PHMSA plans to revise the
``Recordkeeping Requirements for Gas Pipeline Operators'' information
collection currently approved under OMB Control No. 2137-0049 to
include the newly proposed recordkeeping requirements. PHMSA expects
the impact to be minimal and absorbed by the currently approved burden
for this information collection.
The information collections in this proposed rule would be required
through the proposed amendments to the pipeline safety regulations, 49
CFR 190-199. The following information is provided for each information
collection: (1) Title of the information collection; (2) OMB control
number; (3) Current expiration date; (4) Type of request; (5) Abstract
of the information collection activity; (6) Description of affected
public; (7) Estimate of total annual reporting and recordkeeping
burden; and (8) Frequency of collection. The information collection
burden under the proposed rule is estimated as follows:
1. Title: Pipeline Safety: Integrity Management Program for Gas
Distribution Pipelines.
OMB Control Number: 2137-0625.
Current Expiration Date: 5/31/2024.
Abstract: The pipeline safety regulations require operators of gas
distribution pipelines to develop and implement integrity management
(IM) programs. The purpose of these programs is to enhance safety by
identifying and reducing pipeline integrity risks. PHMSA requires
operators to maintain records demonstrating compliance with this
information collection for 10 years. PHMSA uses the information to
evaluate the overall effectiveness of gas distribution Integrity
Management requirements.
PHMSA proposes to repeal the requirement for operators of small
LPGs to participate in the distribution IM program. PHMSA previously
estimated that there were 2,539 operators of small LPG systems.
Consequently, PHMSA expects the burden of this information collection
to be reduced by 2,539 responses and 66,014 hours due to the removal of
small LPG operators.
Affected Public: Owners and operators of gas distribution
pipelines.
Annual Reporting Burden:
Total Annual Responses: 1,343.
Total Annual Burden Hours: 657,178.
Frequency of Collection: On occasion.
2. Title: Recordkeeping Requirements for Gas Pipeline Operators.
OMB Control Number: 2137-0049.
Current Expiration Date: 3/31/2025.
Abstract: This mandatory information collection request would
require owners and/or operators of gas pipeline systems to make and
maintain records in accordance with the requirements prescribed in 49
CFR part 192 and to provide information to the Secretary of
Transportation at the Secretary's request. Certain records are
maintained for a specific length of time while others are required to
be maintained for the life of the pipeline. PHMSA uses these records to
verify compliance with regulated safety standards and to inform the
agency on possible safety risks.
Affected Public: Operators of gas pipeline systems.
Annual Reporting Burden:
Total Annual Responses: 4,056,052.
Total Annual Burden Hours: 5,031,086.
Frequency of Collection: On occasion.
3. Title: Emergency Notification Requirements for Gas Operators.
OMB Control Number: Will Request from OMB.
Current Expiration Date: TBD.
Abstract: This information collection covers the requirement for
owners and operators of gas distribution pipelines to notify their
customers and public officials in the event of certain instances
pertaining to pipeline safety. PHMSA estimates there will be an average
of 75 incidents per year where gas distribution operators will need to
make such notifications. PHMSA expects gas distribution operators will
spend approximately 8 hours notifying the public in each instance,
resulting in an annual burden of 600 hours. PHMSA expects gas
distribution operators to spend an additional 2 hours per incident
notifying their customers, resulting in an added burden of 150 hours.
PHMSA also requires operators of all gas pipelines to notify and
communicate with emergency responders if gas is detected inside or near
a building; fire is located near or directly involving a pipeline
facility; and explosion occurs near or directly involving a pipeline
facility; or in the event of a natural disaster. Based on incident
report trends, PHMSA expects there to be 44 incidents (1 gas gathering,
16 gas transmission, 27 gas distribution) annually, which would require
gas operators to notify emergency responders. PHMSA estimates each
notification will take 2 hours per incident resulting in an annual
burden of 88 hours.
[[Page 61798]]
Affected Public: Owners and operators of gas pipelines.
Annual Reporting Burden:
Total Annual Responses: 194.
Total Annual Burden Hours: 838.
Frequency of Collection: On occasion.
4. Title: Annual and Incident Report for Gas Pipeline Operators.
OMB Control Number: 2137-0522.
Current Expiration Date: 03/31/2026.
Abstract: This mandatory information collection covers the
collection of data from operators of natural gas pipelines, underground
natural gas storage facilities, and liquefied natural gas (LNG)
facilities for annual reports. 49 CFR 191.17 requires operators of
underground natural gas storage facilities, gas transmission systems,
and gas gathering systems to submit an annual report by March 15 for
the preceding calendar year. The Gas Distribution NPRM proposes to
collect limited data from operators of small LPGs. PHMSA proposes to
create Form F7100.1-2. to collect this data, ``Small LPG Annual Report
Form F7100.1-2.'' The burden for this information collection is being
revised to account for this new data collection. PHMSA estimates that
4,492 small LPG operators will spend 6 hours annually completing this
new report resulting in an increase of 4,492 responses and 26,952 hours
to the currently approved burden for this information collection.
Affected Public: Owners and operators of gas distribution
pipelines.
Annual Reporting Burden:
Total Annual Responses: 7,813.
Total Annual Burden Hours: 122,763.
Frequency of Collection: Annually.
5. Title: Gas Pipeline Safety Program Performance Progress Report
and Hazardous Liquid Pipeline Safety Program Performance Progress
Report.
OMB Control Number: 2137-0584.
Current Expiration Date: 5/31/2025.
Abstract: 49 U.S.C. 60105 sets forth specific requirements a State
must meet to qualify for certification status to assume regulatory and
enforcement responsibility for intrastate pipelines, i.e., state
adoption of minimum Federal safety standards, state inspection of
pipeline operators to determine compliance with the standards, and
state provision for enforcement sanctions substantially the same as
those authorized by Chapter 601, Title 49 of the U.S. Code. A State
must submit an annual certification to assume responsibility for
regulating intrastate pipelines, and states who receive Federal grant
funding must have adequate damage prevention plans and associated
records in place. PHMSA uses this information to evaluate a State's
eligibility for Federal grants and to enforce regulatory compliance.
This information collection request requires a participating State to
annually submit a Gas Pipeline Safety Program Performance Progress
Report and Hazardous Liquid Pipeline Safety Program Performance
Progress Report to PHMSA's Office of Pipeline Safety (OPS) signifying
compliance with the terms of the certification and to maintain records
detailing a damage prevention plan for PHMSA inspectors whenever
requested. The purpose of the collection is to exercise oversight of
the grant program and to ensure that States are compliant with Federal
pipeline safety regulations. PHMSA is revising this information
collection to include the reporting of inspection data via the State
Inspection Calculation Tool (SICT). PHMSA expects 66 State
representatives to submit data pertaining to the number of safety
inspectors employed in their pipeline safety programs via the SICT.
PHMSA estimates that, on average, State representatives will spend 8
hours annually compiling and submitting SICT data.
Affected Public: Pipeline operators applying for State grants.
Annual Reporting Burden:
Total Annual Responses: 183.
Total Annual Burden Hours: 5,001.
Frequency of Collection: Annual.
6. Title: Annual for Gas Distribution Operators.
OMB Control Number: 2137-0629.
Current Expiration Date: 06/30/2026.
Abstract: This mandatory information collection request would
require operators of gas distribution pipeline systems to submit annual
report data to the Office of Pipeline Safety in accordance with the
regulations stipulated in 49 CFR part 191 by way of form PHMSA F
7100.1-1. The form is to be submitted once for each calendar year. The
annual report form collects data about the pipe material, size, and
age. The form also collects data on leaks from these systems as well as
excavation damages. PHMSA uses the information to track the extent of
gas distribution systems and normalize incident and leak rates.
The Gas Distribution NPRM proposes to revise the Annual Report for
Gas Distribution Operators, form PHMSA F 7100.1-1, to collect
additional information on gas distribution systems such as the number
and miles of low-pressure service pipelines, including their
overpressure protection methods.
The current approved burden for gas distribution operators to
complete this report is 20 hours, annually. As a result of the proposed
change, the burden for completing PHMSA F 7100.1-collection is being
increased by 6 hours annually, resulting in an overall burden of 26
hours, per annual report, for gas distribution operators.
Affected Public: Owners and operators of gas distribution
pipelines.
Annual Reporting Burden:
Total Annual Responses: 1,446.
Total Annual Burden Hours: 37,596.
Frequency of Collection: Annually.
Requests for a copy of these information collections should be
directed to Angela Hill via email at [email protected] or via
telephone (202) 366-4595.
Comments are invited on:
(a) The need for the proposed collection of information for the
proper performance of the functions of the agency, including whether
the information will have practical utility;
(b) The accuracy of the agency's estimate of the burden of the
revised collection of information, including the validity of the
methodology and assumptions used;
(c) Ways to enhance the quality, utility, and clarity of the
information to be collected;
(d) Ways to minimize the burden of the collection of information on
those who are to respond, including the use of appropriate automated,
electronic, mechanical, or other technological collection techniques;
and
(e) Ways the collection of this information is beneficial or not
beneficial to public safety.
Send comments directly to the Office of Management and Budget,
Office of Information and Regulatory Affairs, Attn: Desk Officer for
the Department of Transportation, 725 17th Street NW, Washington, DC
20503.
G. Unfunded Mandates Reform Act of 1995
The Unfunded Mandates Reform Act (UMRA, 2 U.S.C. 1501 et seq.)
requires agencies to assess the effects of Federal regulatory actions
on State, local, and Tribal governments, and the private sector. For
any NPRM or final rule that includes a Federal mandate that may result
in the expenditure by State, local, and Tribal governments, in the
aggregate of $100 million or more (in 1996 dollars) in any given year,
the agency must prepare, amongst other things, a written statement that
qualitatively and quantitatively assesses the costs and benefits of the
Federal mandate.
As explained further in the PRIA, PHMSA does not expect that the
proposed rule will impose enforceable duties on State, local, or Tribal
governments or on the private sector of $100 million or more (in 1996
dollars) in any one year. A copy of the PRIA is
[[Page 61799]]
available for review in the docket. Therefore, the requirement to
prepare a statement pursuant to UMRA does not apply.
H. National Environmental Policy Act
The National Environmental Policy Act of 1969 (NEPA, 42 U.S.C. 4321
et seq.) requires Federal agencies to prepare a detailed statement on
major Federal actions significantly affecting the quality of the human
environment. The Council on Environmental Quality's implementing
regulations (40 CFR parts 1500-1508) require Federal agencies to
conduct an environmental review considering (1) the need for the
action, (2) alternatives to the action, (3) probable environmental
impacts of the action and alternatives, and (4) the agencies and
persons consulted during the consideration process. DOT Order 5610.1C
(``Procedures for Considering Environmental Impacts'') establishes
departmental procedures for evaluation of environmental impacts under
NEPA and its implementing regulations.
PHMSA has completed a draft environmental assessment and expects
that an environmental impact statement will not be required for this
rulemaking because it will not have a significant impact on the human
environment. To the extent that the proposed rule could impact the
environment, PHMSA expects those impacts will be primarily beneficial
impacts from reducing the likelihood and consequences of incidents on
gas distribution pipelines and other part 192-regulated gas pipelines.
A copy of the draft environmental assessment is available in the
docket. PHMSA invites comment on the potential environmental impacts of
this proposed rule.
I. Executive Order 13132: Federalism
PHMSA has analyzed this proposed rule in accordance with the
principles and criteria contained in Executive Order 13132
(``Federalism'') \195\ and the Presidential Memorandum titled
``Preemption.'' \196\ Executive Order 13132 requires agencies to ensure
meaningful and timely input by State and local officials in the
development of regulatory policies that may have ``substantial direct
effects on the states, on the relationship between the national
government and the states, or on the distribution of power and
responsibilities among the various levels of government.''
---------------------------------------------------------------------------
\195\ 64 FR 43255 (Aug. 10, 1999).
\196\ 74 FR 24693 (May 22, 2009).
---------------------------------------------------------------------------
PHMSA does not expect this proposed rule will have a substantial
direct effect on State and local governments, the relationship between
the Federal Government and the States, or the distribution of power and
responsibilities among the various levels of government. The provisions
proposed involving SICT codify in regulation existing practice and do
not impose any noteworthy additional direct compliance costs on State
and local governments.
States are generally prohibited by 49 U.S.C. 60104(c) from
regulating the safety of interstate pipelines. States that have
submitted a current certification under 49 U.S.C. 60105(a) can augment
Federal pipeline safety requirements for intrastate pipelines regulated
by PHMSA but may not approve safety requirements less stringent than
those required by Federal law. A State may also regulate an intrastate
pipeline facility that PHMSA does not regulate.
In this instance, the preemptive effect of the proposed rule would
be limited to the minimum level necessary to achieve the objectives of
the statutory authority under which the proposed rule is promulgated.
While the 49 CFR part 192 safety requirements in this proposed rule
may, if adopted in a final rule, preempt some State requirements,
preemption arises by operation of 49 U.S.C. 60104, and this proposed
rule would not impose any regulation that has substantial direct
effects on the states, the relationship between the national government
and the states, or the distribution of power and responsibilities among
the various levels of government. Therefore, the PHMSA has determined
that the consultation and funding requirements of Executive Order 13132
do not apply to this proposed rule.
J. Executive Order 13211: Significant Energy Actions
Executive Order 13211 (``Actions Concerning Regulations That
Significantly Affect Energy Supply, Distribution, or Use'') \197\
requires Federal agencies to prepare a Statement of Energy Effects for
any ``significant energy action.'' Executive Order 13211 defines a
``significant energy action'' as any action by an agency (normally
published in the Federal Register) that promulgates or is expected to
lead to the promulgation of a final rule or regulation that (1)(i) is a
significant regulatory action under Executive Order 12866 or any
successor order, and (ii) is likely to have a significant adverse
effect on the supply, distribution, or use of energy; or (2) is
designated by OIRA as a significant energy action.
---------------------------------------------------------------------------
\197\ 66 FR 28355 (May 22, 2001).
---------------------------------------------------------------------------
This proposed rule is not anticipated to be a ``significant energy
action'' under Executive Order 13211. It is not likely to have a
significant adverse effect on the supply, distribution, or use of
energy. Further, the OIRA has not designated this proposed rule as a
significant energy action.
K. Privacy Act Statement
In accordance with 5 U.S.C. 553(c), DOT solicits comments from the
public to better inform its rulemaking process. DOT posts these
comments without edit, including any personal information the commenter
provides, to https://www.regulations.gov, as described in the system of
records notice (DOT/ALL-14 FDMS), which can be reviewed at https://www.dot.gov/privacy.
L. Regulation Identifier Number
A regulation identifier number (RIN) is assigned to each regulatory
action listed in the Unified Agenda of Regulatory and Deregulatory
Actions (Unified Agenda). The RIN contained in the heading of this
document can be used to cross-reference this action with the Unified
Agenda.
M. Executive Order 13609 and International Trade Analysis
Executive Order 13609 (``Promoting International Regulatory
Cooperation'') \198\ requires agencies to consider whether the impacts
associated with significant variations between domestic and
international regulatory approaches are unnecessary or may impair the
ability of American business to export and compete internationally. In
meeting shared challenges involving health, safety, labor, security,
environmental, and other issues, international regulatory cooperation
can identify approaches that are at least as protective as those that
are or would be adopted in the absence of such cooperation.
International regulatory cooperation can also reduce, eliminate, or
prevent unnecessary differences in regulatory requirements.
---------------------------------------------------------------------------
\198\ 77 FR 26413 (May 4, 2012).
---------------------------------------------------------------------------
Similarly, the Trade Agreements Act of 1979 (Pub. L. 96-39), as
amended by the Uruguay Round Agreements Act (Pub. L. 103-465),
prohibits Federal agencies from establishing any standards or engaging
in related activities that create unnecessary obstacles to the foreign
commerce of the United States. For purposes of these requirements,
Federal agencies may participate in the establishment of international
standards so long as the standards have a legitimate domestic
objective, such as providing for safety,
[[Page 61800]]
and do not operate to exclude imports that meet this objective. The
statute also requires consideration of international standards and,
where appropriate, that they serve as the basis for U.S. standards.
PHMSA participates in the establishment of international standards to
protect the safety of the American public.
PHMSA assessed the effects of the proposed rule and expects that it
will not cause unnecessary obstacles to foreign trade.
N. Cybersecurity and Executive Order 14028
Executive Order 14028 (``Improving the Nation's Cybersecurity'')
\199\ directed the Federal government to improve its efforts to
identify, deter, and respond to ``persistent and increasingly
sophisticated malicious cyber campaigns.'' Accordingly, PHMSA has
assessed the effects of this NPRM to determine what impact the proposed
regulatory amendments may have on cybersecurity risks for pipeline
facilities and has preliminarily determined that this NPRM will not
materially affect the cybersecurity risk profile for pipeline
facilities.
---------------------------------------------------------------------------
\199\ 86 FR 26633 (May 17, 2021).
---------------------------------------------------------------------------
Operator DIMPs, O&M manuals and procedures, and facility design
standards are largely static materials; because those materials are not
means of manipulating pipeline operations in real-time, PHMSA's
proposed amendments of requirements governing those materials are
therefore unlikely to increase the risk of cybersecurity incidents.
Although other proposals within the NPRM--in particular, real-time
overpressurization monitoring and customer opt-in/opt-out emergency
communication systems--may offer more attractive targets for
cybersecurity incidents, PHMSA understands the incremental additional
risk from the NPRM's proposed regulatory amendments to be minimal.
Operator compliance strategies for these proposed requirements will be
subject to current Transportation Security Agency (TSA) pipeline
cybersecurity directives; \200\ PHMSA further understands Cybersecurity
& Infrastructure Security Agency (CISA) and the Pipeline Cybersecurity
Initiative (PCI) of the U.S. Department of Homeland Security conduct
ongoing activities to address cybersecurity risks to U.S. pipeline
infrastructure and may introduce other cybersecurity requirements and
guidance for gas pipeline operators.\201\ Lastly, because PHMSA expects
that this NPRM's proposed regulatory amendments (notably those
regarding emergency response planning) will reduce the severity of any
gas pipeline incidents that occur, this rulemaking could reduce the
public safety and the environmental consequences in the event of a
cybersecurity incident on a gas pipeline.
---------------------------------------------------------------------------
\200\ E.g., TSA, ``Ratification of Security Directive,'' 86 FR
38209 (July 20, 2021) (ratifying TSA Security Directive Pipeline-
2012-01, which requires certain pipeline owners and operators to
conduct actions to enhance pipeline cybersecurity).
\201\ See, e.g., CISA, National Cyber Awareness System Alerts,
https://www.cisa.gov/uscert/ncas/alerts (last accessed Feb. 1,
2023).
---------------------------------------------------------------------------
M. Severability
The purpose of this proposed rule is to operate holistically in
addressing a panoply of issues necessary to ensure safe operation of
regulate pipelines, with a focus on gas distribution pipelines'
protection against overpressurization events. However, PHMSA recognizes
that certain provisions focus on unique topics. Therefore, PHMSA
preliminarily finds that the various provisions of this proposed rule
are severable and able to function independently if severed from each
other. In the event a court were to invalidate one or more of the
unique provisions of any final rule issued in this proceeding, the
remaining provisions should stand, thus allowing their continued
effect.
List of Subjects
49 CFR Part 191
Liquefied petroleum gas, Pipeline reporting requirements.
49 CFR Part 192
District regulator stations, Emergency response, Gas monitoring,
Integrity management, Inspections, Gas, Overpressure protection,
Pipeline safety, Reporting and recordkeeping requirements.
49 CFR Part 198
State inspector staffing requirements.
For the reasons provided in the preamble, PHMSA proposes to amend
49 CFR parts 191, 192, and 198 as follows:
PART 191--TRANSPORTATION OF NATURAL AND OTHER GAS BY PIPELINE;
ANNUAL, INCIDENT, AND OTHER REPORTING
0
1. The authority citation for 49 CFR part 191 continues to read as
follows:
Authority: 30 U.S.C. 185(w)(3); 49 U.S.C. 5121, 60101 et seq.,
and 49 CFR 1.97.
0
2. Revise Sec. 191.11 to read as follows:
Sec. 191.11 Distribution system: Annual report.
(a) General. Except as provided in paragraph (b) of this section,
each operator of a distribution pipeline system, excluding a liquefied
petroleum gas system that serves fewer than 100 customers from a single
source, must submit an annual report for that system on DOT Form PHMSA
F 7100.1-1. Each operator of a liquefied petroleum gas system that
serves fewer than 100 customers from a single source must submit an
annual report for that system on DOT Form PHMSA F 7100.1-2. Reports
must be submitted each year, not later than March 15, for the preceding
calendar year.
(b) Not required. The annual report requirement in this section
does not apply to a master meter system, a petroleum gas system
excepted from part 192 in accordance with Sec. 192.1(b)(5), or an
individual service line directly connected to a production pipeline or
a gathering line other than a regulated gathering line as determined in
Sec. 192.8.
PART 192--TRANSPORTATION OF NATURAL AND OTHER GAS BY PIPELINE:
MINIMUM FEDERAL SAFETY STANDARDS
0
3. The authority citation for 49 CFR part 192 continues to read as
follows:
Authority: 30 U.S.C. 185(w)(3), 49 U.S.C. 5103, 60101 et seq.,
and 49 CFR 1.97.
Sec. 192.3 [Amended]
0
4. Amend Sec. 192.3, by removing the last sentence ``This definition
does not apply to any gathering line.'' from the definitions of
``Entirely replaced onshore transmission pipeline segments'',
``Notification of potential rupture'' and ``Rupture-mitigation valve
(RMV)''.
Sec. 192.9 [Amended]
0
5. Amend Sec. 192.9 by:
0
a. Removing from paragraph (b) the last sentence;
0
b. Removing from paragraph (c) the last sentence; and
0
c. Removing from paragraph (e)(1)(iv) the words ``effective as of
October 4, 2022.''
0
6. Amend Sec. 192.18 by revising paragraph (c) to read as follows:
Sec. 192.18 How to notify PHMSA.
* * * * *
(c) Unless otherwise specified, if an operator submits, pursuant to
Sec. Sec. 192.8, 192.9, 192.13, 192.179, 192.319, 192.506, 192.607,
192.619, 192.624, 192.632, 192.634, 192.636, 192.710, 192.712, 192.714,
192.745, 192.917, 192.921, 192.927, 192.933, 192.937, or
[[Page 61801]]
192.1007, a notification for use of a different integrity assessment
method, analytical method, compliance period, sampling approach,
pipeline material, or technique (e.g., ``other technology'' or
``alternative equivalent technology'') than otherwise prescribed in
those sections, that notification must be submitted to PHMSA for review
at least 90 days in advance of using the other method, approach,
compliance timeline, or technique. An operator may proceed to use the
other method, approach, compliance timeline, or technique 91 days after
submitting the notification unless it receives a letter from the
Associate Administrator for Pipeline Safety, or his or her delegate,
informing the operator that PHMSA objects to the proposal or that PHMSA
requires additional time and/or more information to conduct its review.
0
7. Amend Sec. 192.195 by adding paragraph (c) to read as follows:
Sec. 192.195 Protection against accidental overpressuring.
* * * * *
(c) Additional requirements for low-pressure distribution systems.
Each regulator station, serving a low-pressure distribution system,
that is new, replaced, relocated, or otherwise changed after [ONE YEAR
AFTER THE PUBLICATION DATE OF THE RULE] must include:
(1) At least two methods of overpressure protection (such as a
relief valve, monitoring regulator, or automatic shutoff valve)
appropriate for the configuration and siting of the station;
(2) Measures to minimize the risk of overpressurization of the low-
pressure distribution system that could be caused by any single event
(such as excavation damage, natural forces, equipment failure, or
incorrect operations), that either immediately or over time affects the
safe operation of more than one overpressure protection device; and
(3) Remote monitoring of gas pressure at or near the location of
overpressure protection devices.
0
8. Amend Sec. 192.305 by:
0
a. Lifting the stay of the section; and
0
b. Revising the section.
The revision reads as follows:
Sec. 192.305 Inspections: General.
(a) Each transmission pipeline and main that is new, replaced,
relocated, or otherwise changed after [ONE YEAR AFTER THE PUBLICATION
DATE OF THE RULE] must be inspected to ensure that it is constructed in
accordance with this subpart. Except as provided in paragraph (b) of
this section, an operator must not use operator personnel to perform a
required inspection if the operator personnel performed the
construction task requiring inspection. Nothing in this section
prohibits the operator from inspecting construction tasks with operator
personnel who are involved in other construction tasks.
(b) For the construction inspection of a main that is new,
replaced, relocated, or otherwise changed after [ONE YEAR AFTER THE
PUBLICATION DATE OF THE RULE], operator personnel involved in the same
construction task may inspect each other's work in situations where the
operator could otherwise only comply with the construction inspection
requirement in paragraph (a) of this section by using a third-party
inspector. This justification must be documented and retained for the
life of the pipeline.
0
9. Amend Sec. 192.517 by revising paragraph (b) to read as follows:
Sec. 192.517 Records.
* * * * *
(b) Each operator must maintain a record of each test required by
Sec. Sec. 192.509, 192.511, and 192.513 for the life of the pipeline.
(1) For tests performed before [ONE YEAR AFTER THE PUBLICATION DATE
OF THE FINAL RULE] for which records are maintained, the record must
continue to be maintained for the life of the pipeline.
(2) For tests performed on or after [ONE YEAR AFTER THE PUBLICATION
DATE OF THE FINAL RULE], the records must contain at least the
following information:
(i) The operator's name, the name of the employee responsible for
making the test, and the name of the company or contractor used to
perform the test.
(ii) Pipeline segment pressure tested.
(iii) Test date.
(iv) Test medium used.
(v) Test pressure.
(vi) Test duration.
(vii) Leaks and failures noted and their disposition.
0
10. Amend Sec. 192.605 by adding paragraphs (b)(13), (f), and (g) to
read as follows:
Sec. 192.605 Procedural manual for operations, maintenance, and
emergencies.
* * * * *
(b) * * *
(13) Implementing the applicable requirements for distribution
systems in paragraphs (f) and (g) of this section, Sec. 192.638, and
Sec. 192.640.
* * * * *
(f) Overpressurization. For distribution lines, the manual required
by paragraph (a) of this section must, no later than [ONE YEAR AFTER
THE PUBLICATION DATE OF THE RULE], include procedures for responding
to, investigating, and correcting, as soon as practicable, the cause of
overpressurization indications. The procedures must include the
specific actions and an order of operations for immediately reducing
pressure in or shutting down portions of the distribution system
affected by an overpressurization.
(g) Management of Change (MOC) Process. For distribution lines, the
manual required by paragraph (a) of this section must, no later than
[ONE YEAR AFTER THE PUBLICATION DATE OF THE RULE], include a detailed
MOC process for the following:
(1) Technology, equipment, procedural, and organizational changes,
including:
(i) Installations, modifications, replacements, or upgrades to
regulators, pressure monitoring locations, or overpressure protection
devices;
(ii) Modifications to alarm set points or upper/lower trigger
limits on monitoring equipment;
(iii) The introduction of new technologies for overpressure
protection into the system;
(iv) Revisions, changes, or the introduction of new standard
operating procedures for design, construction, installation,
maintenance, and emergency response;
(v) Other changes that may impact the integrity or safety of the
gas distribution system.
(2) Ensuring that personnel--such as an engineer with a
professional engineer license, a subject matter expert, or another
person who possesses the necessary knowledge, experience, and skills
regarding gas distribution systems--review and certify construction
plans associated with installations, modifications, replacements, or
system upgrades for accuracy and completeness before the work begins.
These personnel must be qualified to perform these tasks under subpart
N of this part.
(3) Ensuring that any hazards introduced by a change are
identified, analyzed, and controlled before resuming operations.
0
11. Amend Sec. 192.615 by:
0
a. Adding paragraphs (a)(3)(v) through (viii);
0
b. Revising paragraph (a)(8); and
0
c. Adding paragraphs (a)(13) and paragraph (d).
The additions and revision read as follows:
Sec. 192.615 Emergency plans.
(a) * * *
(3) * * *
[[Page 61802]]
(v) Notification of potential rupture (see Sec. 192.635).
(vi) Beginning no later than [ONE YEAR AFTER THE PUBLICATION DATE
OF THE FINAL RULE], release of gas that results in one or more
fatalities.
(vii) Beginning no later than [ONE YEAR AFTER THE PUBLICATION DATE
OF THE FINAL RULE], for distribution line operators only, unintentional
release of gas and shutdown of gas service to 50 or more customers or,
if the operator has fewer than 100 customers, 50 percent or more of its
total customers.
(viii) Beginning no later than [ONE YEAR AFTER THE PUBLICATION DATE
OF THE FINAL RULE], any other emergency deemed significant by the
operator.
* * * * *
(8) Notifying the appropriate public safety answering point (i.e.,
9-1-1 emergency call center) where direct access to a 9-1-1 emergency
call center is available from the location of the pipeline, and fire,
police, and other public officials, of gas pipeline emergencies to
coordinate and share information to determine the location of the
emergency, including both planned responses and actual responses during
an emergency. The operator must immediately and directly notify the
appropriate public safety answering point or other coordinating agency
for the communities and jurisdictions in which the pipeline is located
after receiving notice of a gas pipeline emergency under paragraph
(a)(3) of this section. The operator must coordinate and share
information to determine the location of any release, regardless of
whether the segment is subject to the requirements of Sec. Sec.
192.179, 192.634, or 192.636.
* * * * *
(13) For distribution line operators, beginning no later than [ONE
YEAR AFTER THE PUBLICATION DATE OF THE FINAL RULE], establishing and
maintaining communication with the general public in the operator's
service area as soon as practicable during a gas pipeline emergency on
a distribution line. The communication(s) must be in English, and any
other languages commonly understood by a significant number and
concentration of the non-English speaking population in the operator's
service area; be in one or more formats or media accessible to the
population in the operator's service area; continue through service
restoration and recovery efforts; and provide the following:
(i) Information regarding the gas pipeline emergency;
(ii) The status of the emergency (e.g., have the condition causing
the emergency or the resulting public safety risks been resolved);
(iii) Status of pipeline operations affected by the gas pipeline
emergency, and when possible, a timeline for expected service
restoration; and
(iv) Directions for the public to receive assistance.
The operator must provide updates when the information in Sec.
192.615(a)(13)(i) through (iv) changes.
* * * * *
(d) No later than [DATE 18 MONTHS AFTER THE PUBLICATION DATE OF THE
RULE], each distribution line operator must develop and implement a
system, including written procedures, that allows operators to rapidly
communicate with customers in the event of a gas pipeline emergency
under this section. The notification system must be voluntary for the
public, allowing customers to opt-in (or opt-out) to receiving
notifications from the system. The written procedures must provide for
the following:
(i) A description of the notification system and how it will be
used to notify customers of a gas pipeline emergency;
(ii) Who is responsible for the development, operation, and
maintenance of the system;
(iii) How information on the system is delivered to customers,
ensuring that all customers are notified of the existence of the system
and necessary steps if they wish to opt-in (or opt-out);
(iv) Description of the system-wide testing protocol, including the
testing interval (which must not be less than once per calendar year),
to ensure the system is functioning properly and performing
notifications as designed;
(v) Maintenance of the results of testing and operations history
for at least 5 years;
(vi) Details regarding how the operator ensures messages are
accessible in other languages commonly understood by a significant
number and concentration of the non-English speaking population in the
operator's area;
(vii) Message content, including updates as emergency conditions
change;
(viii) A process to initiate, conduct, and complete notifications;
and
(ix) Cybersecurity measures to protect the system and customer
information.
0
12. Add Sec. 192.638 to read as follows:
Sec. 192.638 Distribution lines: Records for pressure controls.
(a) An operator of a distribution system, except those identified
in paragraph (f) of this section, must, no later than [ONE YEAR AFTER
THE PUBLICATION DATE OF THE RULE], identify and maintain traceable,
verifiable, and complete records that document the characteristics of
its pipeline system that are critical to ensuring proper pressure
control. These records must include:
(1) Current location information (including maps and schematics)
for regulators, valves, and underground piping (including control
lines);
(2) Attributes of the regulator(s), such as set points, design
capacity, and the valve failure position (open/closed);
(3) The overpressure protection configuration; and
(4) Other records deemed critical.
(b) If an operator does not have traceable, verifiable, and
complete records as required by paragraph (a) of this section, the
operator must, no later than [ONE YEAR AFTER THE PUBLICATION DATE OF
THE RULE], identify and document those records needed and develop and
implement procedures for collecting those records.
(c) The records identified in paragraph (a) of this section must be
collected, generated, or updated on an opportunistic basis, as
specified in Sec. 192.1007(a)(3).
(d) An operator must ensure the records required by this section
are accessible to all personnel responsible for performing or
supervising design, construction, operations, and maintenance
activities.
(e) An operator must retain the records required in this section
for the life of the pipeline.
(f) Exception. This section does not apply to master meter systems,
liquefied petroleum gas (LPG) distribution pipeline systems that serve
fewer than 100 customers from a single source, or any individual
service line directly connected to a transmission, gathering, or
production pipeline that is not operated as part of a distribution
system.
0
13. Add Sec. 192.640 to read as follows:
Sec. 192.640 Distribution lines: Presence of qualified personnel.
(a) An operator of a distribution system must conduct a documented
evaluation of each construction project that begins after [ONE YEAR
AFTER THE PUBLICATION DATE OF THE RULE] to identify any potential
project activities during which an overpressurization could occur at a
district regulator station. This evaluation must occur before such
activities begin. Activities that may present a potential for
overpressurization include, but are not limited to, tie-ins,
abandonment of
[[Page 61803]]
distribution lines, and equipment replacement.
(b) If the evaluation in paragraph (a) of this section results in a
determination that a potential for overpressurization exists during
construction project activity, the operator must:
(1) Ensure that at least one person qualified according to subpart
N of this part is present at that district regulator station, or at an
alternative site, during the construction project activity that could
cause an overpressurization;
(2) Monitor gas pressure with equipment capable of ensuring proper
pressure controls; and
(3) Have the capability to promptly shut off the flow of gas or
control overpressurization at a district regulator station.
(c) When monitoring the system as described in this section, the
qualified personnel must be provided, at a minimum: information
regarding the location of all valves necessary for isolating the
pipeline system; pressure control records (see Sec. 192.638); the
authority to stop work (unless prohibited by operator procedures);
operations procedures under Sec. 192.605; and emergency response
procedures under Sec. 192.615.
(d) Exception. Distribution systems with a remote monitoring system
in effect with the capability for remote or automatic shutoff need not
comply with the requirements in paragraphs (a) through (c) of this
section.
0
14. Amend Sec. 192.725 by revising paragraph (a) to read as follows:
Sec. 192.725 Test requirements for reinstating service lines.
(a) Except as provided in paragraph (b) of this section, each
disconnected service line being restored to service on or after [ONE
YEAR AFTER THE PUBLICATION DATE OF THE RULE] must be tested in the same
manner as a new service line (i.e., tested in accordance with subpart J
of this part) before being restored to service.
* * * * *
0
15. Amend Sec. 192.741 by:
0
a. Revising the title of the section, and
0
b. Adding paragraph (d).
The revision and addition read as follows:
Sec. 192.741 Pressure limiting and regulating stations: Telemetering,
recording gauges, and other monitoring devices.
* * * * *
(d) On low-pressure distribution systems that are new, replaced,
relocated, or otherwise changed after [ONE YEAR AFTER THE PUBLICATION
DATE OF THE RULE], the operator must monitor the gas pressure in
accordance with Sec. 192.195(c)(3).
Sec. 192.1001 [AMENDED]
0
16. Amend Sec. 192.1001 by removing the definition of ``Small LPG
Operator.''
0
17. Amend Sec. 192.1003 by adding paragraph (b)(4) to read as follows:
Sec. 192.1003 What do the regulations in this subpart cover?
* * * * *
(b) * * *
(4) A system of a liquefied petroleum gas (LPG) distribution
pipeline that serves fewer than 100 customers from a single source.
0
18. Amend Sec. 192.1005 by revising the title of the section to read
as follows:
Sec. 192.1005 What must a gas distribution operator do to implement
this subpart?
0
19. Amend Sec. 192.1007 by revising paragraphs (a)(3), (b), (c), and
(d) to read as follows:
Sec. 192.1007 What are the required elements of an integrity
management plan?
* * * * *
(a) * * *
(3) Identify additional information needed and provide a plan for
obtaining that information over time (including the records specified
in Sec. 192.638(c)) through normal activities conducted on the
pipeline (for example, design, construction, operations, or maintenance
activities).
* * * * *
(b) Identify threats. The operator must consider the following
categories of threats to each gas distribution pipeline: corrosion
(including atmospheric corrosion); natural forces (including extreme
weather, land movement, and other geological hazards); excavation
damage; other outside force damage; material (including the presence
and age of pipes such as cast iron, bare steel, unprotected steel,
wrought iron, and historic plastics with known issues) or welds;
equipment failure; incorrect operations; overpressurization of low-
pressure distribution systems; and other threats that pose a risk to
the integrity of a pipeline. An operator must also consider the age of
the system, pipe, and components in identifying threats. An operator
must consider reasonably available information to identify existing and
potential threats. Sources of data may include, but are not limited to,
incident and leak history, corrosion control records (including
atmospheric corrosion records), continuing surveillance records,
patrolling records, maintenance history, and excavation damage
experience.
(c) Evaluate and rank risk.
(1) General. An operator must evaluate the risks associated with
its distribution pipeline. In this evaluation, the operator must
determine the relative importance of each threat and estimate and rank
the risks posed to its pipeline. This evaluation must consider each
applicable current and potential threat, the likelihood of failure
associated with each threat, and the potential consequences of such a
failure. An operator may subdivide its pipeline into regions with
similar characteristics (e.g., contiguous areas within a distribution
pipeline consisting of mains, services and other appurtenances, areas
with common materials, age, or environmental factors), and for which
similar actions likely would be effective in reducing risk.
(2) Certain pipe with known issues. An operator must, no later than
[ONE YEAR AFTER THE PUBLICATION DATE OF THE RULE], evaluate the risks
in the distribution system resulting from pipelines with known issues
based on the material (including, cast iron, bare steel, unprotected
steel, wrought iron, and historic plastics with known issues), design,
age, or past operating and maintenance history.
(3) Low-pressure Distribution Systems. An operator must, no later
than [ONE YEAR AFTER THE PUBLICATION DATE OF THE RULE], evaluate the
risks that could lead to or result from the operation of a low-pressure
distribution system at a pressure that makes the operation of any
connected and properly adjusted low-pressure gas burning equipment
unsafe. In the evaluation of risks, an operator must:
(i) Evaluate factors other than past observed abnormal operating
conditions (as defined in Sec. 192.803) in ranking risks, including
any known industry threats, risks, or hazards to public safety that
could occur on its system based on knowledge gained from available
sources;
(ii) Evaluate potential consequences associated with low-
probability events unless a determination, supported and documented by
an engineering analysis, or an equivalent analysis incorporating
operational knowledge, demonstrates that the event results in no
potential consequences and therefore no potential risk. An operator
must notify PHMSA and State or local pipeline safety authorities, as
applicable, in accordance with Sec. 192.18 within 30 days of making
such a determination. The notification must include the following:
(A) Date the determination was made;
(B) Description of the low-probability event being considered;
(C) Logic supporting the determination, including information
[[Page 61804]]
from an engineering analysis, or an equivalent analysis incorporating
operational knowledge;
(D) Description of any preventive and mitigative measures,
including any measures considered but not taken;
(E) Details of the low-pressure system applicable to the event that
results in no potential consequence and risk, including, at a minimum,
the miles of pipe, number of customers, number of district regulators
supplying the system, and other relevant information; and
(F) Written statement summarizing the documentation provided in the
notification.
(iii) Evaluation of the configuration of primary and any secondary
overpressure protection installed at district regulator stations (such
as a relief valves, monitoring regulators, or automatic shutoff
valves), the availability of gas pressure monitoring at or near
overpressure protection equipment, and the likelihood of any single
event (such as excavation damage, natural forces, equipment failure, or
incorrect operations), that either immediately or over time, could
result in an overpressurization of the low-pressure distribution
system.
(d) Identify and implement measures to address risks.
(1) General. An operator must identify and implement measures to
reduce the risks of failure of its distribution pipeline system. The
measures identified and implemented must address, at a minimum, risks
associated with the age of pipeline components, the overall age of the
system and components, the presence of pipes with known issues, and
overpressurization of low-pressure distribution systems. The measures
must also include an effective leak management program (unless all
leaks are repaired when found).
(2) Minimization of Overpressurization of Low-Pressure Distribution
Systems. An operator must, no later than [ONE YEAR AFTER THE
PUBLICATION DATE OF THE RULE], implement the following preventive and
mitigative measures to minimize the risk of overpressurization of a
low-pressure distribution system that could be the result of any single
event or failure:
(i) Identify, maintain, and obtain, if necessary, pressure control
records in accordance with Sec. Sec. 192.638 and 192.1007(a)(3).
(ii) Confirm and document that each district regulator station
meets the requirements of Sec. 192.195(c)(1) through (3). If an
operator determines that a district regulator station does not meet the
requirements of Sec. 192.195(c)(1) through (3), then by [ONE YEAR
AFTER THE PUBLICATION DATE OF THE RULE], the operator must take either
of the following actions:
(A) Upgrade the district regulator station to meet the requirements
of Sec. 192.195(c)(1) through (3), or
(B) Identify alternative preventive and mitigative measures based
on the unique characteristics of its system to minimize the risk of
overpressurization of a low-pressure distribution system. The operator
must notify PHMSA and State or local pipeline safety authorities, as
applicable, no later than 90 days in advance of implementing any
alternative measures. The notification must be made in accordance with
Sec. 192.18(c) and must include a description of proposed alternative
measures, identification and location of facilities to which the
measures would be applied, and a description of how the measures would
ensure the safety of the public, affected facilities, and environment.
* * * * *
Sec. 192.1015 [Removed]
0
20. Remove Sec. 192.1015.
PART 198--REGULATIONS FOR GRANTS TO AID STATE PIPELINE SAFETY
PROGRAMS
0
21. The authority citation for part 198 continues to read as follows:
Authority: 49 U.S.C. 60101 et seq.; 49 CFR 1.97.
0
22. Amend Sec. 198.3 by adding the definitions for ``Inspection
person-day'' and ``State Inspection Calculation Tool (SICT)'' in
alphabetical order to read as follows:
Sec. 198.3 Definitions.
* * * * *
Inspection person-day means all or part of a day, including travel,
spent by State agency personnel in on-site or virtual evaluation of a
pipeline system to determine compliance with Federal or State pipeline
safety regulations.
* * * * *
State Inspection Calculation Tool (SICT) means a tool used to
determine the required number of annual inspection person-days for a
State agency.
* * * * *
0
23. Amend Sec. 198.13 by revising paragraph (c)(6) to read as follows:
Sec. 198.13 Grant-allocation formula.
* * * * *
(c) * * *
(6) Number of state inspection person-days, as determined by the
SICT and other factors;
* * * * *
Issued in Washington, DC, on August 23, 2023, under authority
delegated in 49 CFR 1.97.
Alan K. Mayberry,
Associate Administrator for Pipeline Safety.
[FR Doc. 2023-18585 Filed 9-6-23; 8:45 am]
BILLING CODE 4910-60-P
