provide an equivalent level of safety to an RMV. The NPRM's proposal
reflected PHMSA's belief it would be reasonable to apply a 40-minute
valve closure standard to provide time (if needed) for operators to get
personnel on-site to close any necessary manual valves.
    As discussed elsewhere in this document, both the GPAC and the LPAC
each unanimously voted to characterize a shortened valve closure time
as ``technically feasible, reasonable, cost-effective, and
practicable'' provided that the NPRM's prescriptive timeframe for
rupture identification was eliminated. PHMSA acknowledges that a faster
valve-closure standard would provide additional environmental and
public safety benefits and has revised this final rule to require a 30-
minute maximum valve-closure time, measured from rupture
identification--with an emphasis that this is a ceiling whereas the
actual requirement is ``as soon as is practicable.'' As noted by some
of the commenters, many operators indicate ``worst case scenarios'' of
15 minutes.
    Accordingly, PHMSA is requiring any RMVs and alternative equivalent
technology installed pursuant to this final rule be closed ``as soon as
practicable'' but no later than 30 minutes following the identification
of a rupture. In addition, as suggested in comments from PST, those
operators that have indicated in their spill response plans a valve
closure time of less than 30 minutes during a worst-case discharge
would still have to operate such valves in the time indicated in their
spill response plan (see Sec.  194.105(b)(1)). If an operator chooses
to install ASVs as RMVs, they must conduct flow modeling for the
applicable pipeline segments and any laterals that feed the pipeline
segment to ensure that the ASV will close within 30 minutes or less
following rupture identification. The flow modeling must include the
anticipated maximum, normal, or any other flow volumes, pressures, or
other operating conditions (including extreme fluctuations in weather
that might affect operating pressures) that may be, or are anticipated
to be, encountered during the year, not to exceed a period of 15
months, and it must be modeled for the flow between the RMVs or
alternative equivalent technologies, and any looped pipelines or gas
receipt tie-ins. If operating conditions change in a way that could
affect the ASV set pressures and the valve closure time after rupture
identification, an operator must conduct a new flow model and reset the
ASV set pressures prior to the next review for ASV set pressures in
accordance with Sec.  192.745. The flow model must include a pressure
drop/time chart or graph for the segment containing the ASV if a
rupture event occurs and must show rupture segment isolation as soon as
is practicable and within 30 minutes of rupture identification. An
operator must conduct this flow modeling prior to making flow condition
changes in a manner that could assure that the 30-minute valve closure
time is achievable. If an operator does not perform this flow modeling
correctly, the set pressure could be too low, thus rendering a 30-
minute closure time unachievable.
    When conducting flow modeling for ASVs, operators should also
consider what type of rupture may occur on their system, especially
whether the rupture may be a pipe-body type or a seam-type failure. The
flow model detection for a rupture should be based on 0.5 times the
pipe diameter (or less) pipe area when sizing the pressure drop for a
rupture.
    Operators also have the option, in lieu of installing RMVs, to
install alternative equivalent technology with an advance notification
to PHMSA in accordance with Sec. Sec.  192.18 and 195.18. An operator
must include, for PHMSA's review, a site-specific technical and safety
evaluation in its notice consisting of the following information, as
well as any other information requested by PHMSA in its review of the
notification: Design, construction, maintenance, and operating
procedures; technology design and operating characteristics such as
operation times (closure times for manual valves); service reliability
and life; accessibility to operator personnel; nearby population
density; and potential consequences to the environment and the public.
Where the operator proposes to use manual valves as alternative
equivalent technology, its notification to PHMSA must also demonstrate
that installation of an RMV would be economically, technically, or
operationally infeasible by reference to factors such as access to
communications and power; terrain; prohibitive cost; component and
labor availability; ability to secure required access rights and
permits; and accessibility to operator personnel for installation and
maintenance.
    As discussed above, PHMSA is requiring an ``as soon as is
practicable'' valve closure time (with an absolute ceiling of 30
minutes), measured from rupture identification pursuant to an
operator's written procedures, in conjunction with eliminating the 10-
minute rupture identification timeframe. Shortening the time it takes
for an operator to close a RMV or alternative equivalent technology
provides a better mitigation standard to protect the public and the
environment from the consequences of a rupture. PHMSA notes that it has
seen evidence of operators being able to isolate looped pipeline
systems in less than 10 minutes--this rule should help ensure this
timeframe is widely achievable. Operators of hazardous liquid pipelines
must also consider the shut-down times they use when calculating worst-
case discharges in accordance with Sec.  194.105 and be able to close
RMVs within that timeframe if it is less than 30 minutes.
    For gas pipelines, some commenters suggested allowing operators to
exceed the 30-minute closure standard if using manual valves as
alternative equivalent technology in non-HCA, Class 1 locations, if the
operator submits a notification demonstrating that installing an RMV
would be economically, technically, or operationally infeasible. Given
that non-HCA Class 1 locations are largely rural areas, PHMSA believes
such a provision would be warranted if the operator could demonstrate
they could not install

a compliant valve or technology in those locations. In this final rule
at Sec.  192.636(g), PHMSA specifies that an operator seeking an
exemption from the rule's RMV and alternative equivalent technology 30-
minute operation requirement would, within its request submitted under
Sec.  192.18, have to provide PHMSA for its review, inter alia, with an
estimated closure time of any manual valve employed as an alternative
equivalent technology. PHMSA has not included procedural machinery for
such an exemption from that operation requirement for manual valves
used as alternative equivalent technology in non-HCA Class 2 locations
in this final rule, however, because those locations would pose a
greater risk to public safety: By definition, Class 2 locations have a
minimum of 10 houses and up to 45 houses in the class location unit
near the pipeline. The final rule incorporates at Sec.  195.419(g) an
analogous procedure for certain hazardous liquid pipelines
(specifically, those that are neither in, nor could affect, an HCA)
whereby an operator can request an exemption from the 30-minute
operation requirement at Sec.  195.419(b) when employing a manual valve
as an alternative equivalent technology; those pipelines, too, pose a
lower risk to public safety and environment from hazardous liquid
pipeline segments which are located in, or could affect, an HCA.
    In this final rule, PHMSA does not authorize operators, in
conjunction with emergency responders, to leave RMVs or alternative
equivalent technologies open for rupture mitigation or safety during
emergency response, without first forwarding to PHMSA pursuant to
Sec. Sec.  192.18 or 195.18 such a request and developing appropriate
written procedures. PHMSA believes that the need to isolate ruptures is
paramount--precisely to be able to afford maximum safety for an
emergency response as well as for mitigation purposes--and that RMVs
and alternative equivalent technologies should be closed as soon as
practicable. Any discussions occurring with emergency responders while
an incident is occurring could lead to unjustified delays in isolating
ruptures. If an operator has not established the need in their
operating procedures for not closing valves prior to a rupture, the
emergency responder(s) would probably not have the appropriate
information to make such a decision promptly. Commenters at the GPAC
meeting noted that there might be instances where leaving RMVs or
alternative equivalent technologies open during emergencies was
warranted, such as when the pipeline was the sole product source for a
power plant or a hospital, or where closing a RMV or alternative
equivalent technology would then have an adverse economic impact on
other customers downstream. PHMSA has determined that, in situations
such as these, the potential risks associated with interruption of gas
supply to particular end users will generally outweigh the value of
more quickly mitigating the nearly certain catastrophic consequences of
a pipeline rupture. PHMSA notes that a rupture may itself result in
interruption of service to critical facilities and electric generators,
regardless of response actions taken by operators. Further, PHMSA notes
that bi-directional product flow or the residual volume of product
downstream of a ruptured pipeline segment can provide operators with
time to isolate the ruptured pipeline segment while also redirecting
product flow as necessary to ensure that any disruption to downstream
facilities would be minimized. PHMSA also contemplates operators will
appropriately plan for the aforementioned contingencies.
    Based on the GPAC discussion, however, PHMSA has provided in this
final rule a mechanism for an operator to forward to PHMSA such a
request. Accordingly, an operator of a gas pipeline may request
pursuant to Sec.  192.18 to plan to leave an RMV or alternative
equivalent technology open for more than 30 minutes following rupture
identification if the operator can demonstrate to PHMSA that closing
that RMV or alternative equivalent technology would be detrimental to
public safety. Such a request must be coordinated in advance with
appropriate local emergency responders, and the operator and applicable
emergency responders must agree that it would be safe to leave the
valve open. If PHMSA grants such a request to an operator, that
operator would be required to have written procedures for determining
when to leave a RMV or alternative equivalent technology open,
including all plans for communicating with local emergency responders
during a rupture event during which the RMV or alternative equivalent
technology would be left open, and including measures by which the
operator would minimize environmental impacts.
    Regarding the comments requesting clarification on the meaning of
``other mitigative actions,'' PHMSA intended this phrase to require
that operators take whatever action is appropriate to mitigate the
event, in addition to closing the appropriate RMVs or alternative
mitigative technologies. The specific actions PHMSA would expect an
operator to take would be dependent on each unique rupture scenario and
may include, but are not limited to, the closure of valves on laterals
used for receipt or delivery and communication with product receipt and
delivery customers.

E. RMVs

1. Summary of Proposal
    In the NPRM, for gas pipelines, PHMSA proposed to require that all
valves on newly constructed or entirely replaced onshore gas
transmission and gathering pipelines that have diameters greater than
or equal to 6 inches be ASVs, RCVs or an alternative equivalent
technology. Operators seeking to use manual valves as an alternative
equivalent technology would also need to demonstrate to PHMSA's
satisfaction that installing an ASV or RCV was economically,
technically, or operationally infeasible. PHMSA proposed to define the
statutory phrase ``entirely replaced'' as being where an operator
replaces 2 or more contiguous miles of pipeline with new pipe. All
valves installed per this proposal would meet the new rupture-
mitigation standards proposed and isolate a ruptured pipeline segment
within 40 minutes of rupture identification. PHMSA also proposed that
new or entirely replaced laterals contributing 5 percent of the total
volume of the applicable gas line shut-off segment would also require
RMVs.
    For hazardous liquid pipelines, PHMSA similarly proposed to require
that all valves on newly constructed and entirely replaced onshore
hazardous liquid pipelines that have diameters greater than or equal to
6 inches be RCVs, ASVs, or an alternative equivalent technology. PHMSA
proposed to permit operators to install manually or locally operated
valves as alternative equivalent technology only when there were
economic, technical, or operational feasibility issues precluding the
installation of ASVs or RCVs and proposed to require operators to
notify PHMSA as well. All valves installed under this proposal would
meet the new rupture-mitigation standards proposed in Sec.  195.418 and
isolate a ruptured pipeline segment as soon as practicable, but within
40 minutes of rupture identification. Similar to gas transmission
lines, new or entirely replaced laterals contributing 5 percent of
hazardous liquid volume would also be required to install RMVs.
    PHMSA also defined the term ``shut-off segment'' in the NPRM as the
segment of applicable pipe between the RMVs closest to the upstream and

downstream endpoints of an HCA, a Class 3 location, or a Class 4
location so that the entirety of these areas is between RMVs. Multiple
HCAs, Class 3 locations, or Class 4 locations can be contained in a
single shut-off segment, and all valves installed on a shut-off segment
are RMVs. While PHMSA did not specifically define the term ``rupture-
mitigation valve'' in the NPRM, it used that term in the NPRM to
describe the ASVs, RCVs, or alternative equivalent technology installed
to mitigate ruptures.
    For the proposed construction and replacement requirements, PHMSA
proposed an implementation timeframe of 12 months following the
effective date of the rule.
2. Comments Received
(i) ``Rupture-Mitigation Valve'' and Related Definitions
    API/AOPL, GPA Midstream, Magellan Midstream Partner, L.P., and TC
Energy Corporation recommended that PHMSA add a definition of an RMV
for clarity. These industry commenters stated that the definition of an
RMV should explicitly include check valves within its scope and also
specify the purpose served by these valves, which is to minimize the
volume of product released following a rupture and mitigate the safety
and environmental consequences of a rupture. API/AOPL and GPA Midstream
added that the definition of an RMV should include automated valves,
alongside ASVs and RCVs, per the GAO report. Other commenters,
representing hazardous liquid pipelines operators, noted that the
definition should also contain EFRDs for hazardous liquid pipelines.
    PHMSA also received several comments regarding the use of
additional technologies and practices. Regarding valve types, industry
commenters suggested PHMSA should allow operators to use a ``locked-
out'' or ``tagged-out'' manual valve as an alternative equivalent
technology at crossovers, and allow operators to use a check valve as
an RMV for laterals used for receipt or delivery, provided that the
check valve is positioned to stop product flow into the shut-off
segment. Further, industry commenters suggested that PHMSA should add
language to the final rule to confirm that locally actuated ASVs would
be an acceptable alternative for RMVs and that operators could select
any pipeline (mainline or lateral) or station valve as an RMV as long
as it complied with the RMV spacing requirements.
    Commenters also had suggestions for definitions related to RMVs,
including ``shut-off segment'' and ``entirely replaced.'' For ``shut-
off segment,'' commenters recommended defining that term and provided
assorted editorial suggestions for the definition. Similar comments
were made for the term ``entirely replaced.''
    Additionally, for the term ``entirely replaced,'' industry
commenters noted that PHMSA discussed the definition for the term in
the preamble text but did not include it in the regulatory text. They
asserted that the definition that PHMSA uses for ``entirely replaced''
in the NPRM is not consistent with the plain meaning of that term, as
meaning ``in every way possible; completely.'' Based on that
interpretation of the definition of ``entirely replaced,'' these
commenters stated that replacing a portion of a pipeline would not
constitute an ``entirely replaced'' pipeline and suggested that, based
on PHMSA's definition, ``entirely replaced'' could create an incentive
to make poor engineering decisions based on the potential consequences
of a segment being ``completely'' replaced.
    The PST stated that PHMSA provided no explanation for how it
arrived at the 2-mile threshold or whether recent replacement projects
were tallied to see how many recent projects that distance would
include or exclude. The PST asserted that choosing a shorter distance
would include more replacement projects and would therefore result in
more of the Nation's pipeline systems having the additional protection
of ASVs or RCVs. The PST also stated that because 2 miles is a long
distance, it seems an easier distance to design around to avoid
application of this rule. Therefore, the PST suggested PHMSA establish
the definition of ``entirely replaced'' based on a replacement length
of 600 contiguous feet or a length of more than 600 feet of any
contiguous 1,000 feet, which would be a distance longer than a single
integrity repair might require but short enough to capture smaller
replacement projects. The PST stressed the importance of this
definition due to limitations on changing design and construction
requirements on existing pipeline systems. Similarly, other commenters
from the general public suggested that PHMSA should reduce the distance
for replacement that triggers valve installation to 1 mile of
contiguous pipeline.
    At the Committee meetings on July 22 and 23, 2020, discussions
focused on the practicability of NPRM's proposed definition of
``entirely replaced.'' Pipeline operators generally supported the 2-
mile element of the definition as striking an appropriate balance
between safety benefits and practical difficulties (e.g., obtaining
land access rights and permits) associated with installing new RMVs on
replacement pipelines--provided PHMSA clarify (1) the length of the
pipeline from which the 2 miles of replaced pipe would be calculated
was less than each operator's entire system, and (2) the timeframe over
which those pipeline replacements would be conducted so as to
accommodate pipeline maintenance planning cycles. The Committees
unanimously recommended that PHMSA revise the final rule so that the
``entirely replaced'' standard applies to multiple replacements that,
in the aggregate, exceed 2 miles of pipeline within a 5-contiguous-mile
length within a 24-month period. The Committees also unanimously
recommended PHMSA allow check valves and valves on crossover piping
that are locked and tagged closed in accordance with operating
procedures to be used as RMVs. Committee members noted that check
valves could already be considered an ASV based on their design, and
that check valves have been used effectively in hazardous liquid
pipeline systems.
(ii) RMV Applicability
    NAPSR and other commenters requested PHMSA clarify whether the
proposed requirements would be applicable to low-stress systems, noting
that rupture risk is greatly reduced for systems that operate at less
than 20 or 30 percent of SMYS.
    Similarly, the industry associations requested that PHMSA except
pipelines from the RMV installation requirements where the PIR of those
pipelines is less than 150 feet. They stated that pipeline diameter
alone is not an accurate indicator of the potential consequences of a
rupture, as many pipelines with diameters ranging from 6 inches to 12
inches operate at pressures low enough that the impact of a rupture
would be minimal. The industry associations noted that a pipeline's PIR
reflects both the pipeline size and the operating pressure, and it is
therefore a better measure of potential consequence than diameter
alone. Further, the industry associations noted that the 2019 Gas
Transmission Final Rule \41\ used a PIR of less than or equal to 150
feet to establish less-stringent requirements for aspects of MAOP
reconfirmation and pressure reductions.
---------------------------------------------------------------------------

    \41\ 84 FR 52180 (Oct. 1, 2019).
---------------------------------------------------------------------------

    Commenters representing hazardous liquid pipeline operators
similarly requested that PHMSA exempt pipeline segments that could not
affect HCAs

from the requirement for installing RMVs to create the greatest benefit
for the rule using an HCA-focused approach consistent with the risk-
based philosophy of the Federal Pipeline Safety Regulations.
    For both gas and hazardous liquid pipelines, industry commenters
requested that PHMSA clarify whether the 5 percent volume contribution
for determining the need for RMVs on laterals is based on flow rate or
total volume.
    At the Committee meetings on July 22 and 23, 2020, the Committees
recommended that PHMSA consider exceptions from the RMV installation
requirement for pipelines with SMYS of 30 percent or less and for all
gas transmission and gas gathering pipelines with a PIR equal to or
less than 150 feet (not for pipeline segments in Class 4 locations)
considering cost-benefit issues and while maintaining the integrity of
the rule. For hazardous liquid pipelines, the Committees recommended
that PHMSA consider exceptions for pipelines 30 percent of SMYS or
less.
    Further, the GPAC recommended PHMSA consider an exception for Type
A gas gathering pipelines of 12 inches or less and Type B gas gathering
pipelines. Both the GPAC and the LPAC recommended that PHMSA consider
the appropriateness of applying this rulemaking, or a separate
rulemaking, to gathering lines.
(iii) Timeframe for RMVs To Be Operational and Implementation Period
    With regard to the timeframe for making RMVs operational following
operators placing pipelines into service, INGAA et al. requested that
PHMSA provide operators with 14 days rather than the 7-day period
proposed. They stated that several safety and operational activities
must take place following the introduction of gas into a new pipeline
segment, including the testing of control and communication systems,
evaluating system constraints, and conducting management of change
processes, which could require more than 7 days to conduct. Some
commenters from industry also suggested that PHMSA change the
implementation period for new construction from 12 months after the
effective date to 24 months.
    At the GPAC and LPAC meetings on July 22 and 23, 2020, the
Committees unanimously recommended that PHMSA change the implementation
period of the rule to 24 months after publication date for gas
transmission and gas gathering pipelines, and consider reducing the
implementation of the rule to be between 12 and 18 months for hazardous
liquid pipelines. On both Committees, members representing the public
(including PST) were initially reluctant to provide longer periods of
time for the implementation of the rule. However, PHMSA noted during
the meeting that the NPRM already provided a compliance period of 12
months after the 6-month effective date of the rule, which would have
provided a compliance date of 18 months after the rule's publication.
Members of the Committees representing industry (including Enbridge,
National Grid, Marathon Pipeline, Colonial Pipeline, DCP Midstream, and
PECO) noted that there could be significant lead time required for
obtaining actuators for valves for larger-diameter pipelines, and
recommended longer implementation times for the rule. As a result of
this discussion, the committee ultimately recommended the 24-month
implementation period. Additionally, for hazardous liquid pipelines,
the LPAC also unanimously recommended PHMSA change the timeframe to
activate RMVs after construction from 7 days to 14 days because of
practicability concerns.
(iv) Notifications
    Commenters representing hazardous liquid pipeline operators stated
that PHMSA should align the various notification requirements
throughout the rulemaking, including those for ``other [alternative
equivalent] technology'' requests, with other part 195 notification
requirements. Regarding such notifications, the PST requested that
PHMSA clarify what criteria or standards are needed to justify the
determination and provide for an equivalent level of safety. Commenters
also requested that this notification period operate similarly to how
PHMSA has created notifications for gas pipeline operators; namely,
that unless an operator receives a specific objection from PHMSA or a
request for more review time before the 90-day period has passed, the
operator can install the technology under the assumption that PHMSA has
no objection.
    INGAA et al. also recommended PHMSA revise the rule so that the
notification process for alternative technology such as manual valves
applies to all locations, asserting that operators installing new or
replaced pipelines in remote areas are likely to use this process.
    At the Committee meetings on July 22 and 23, 2020, the LPAC and
GPAC each unanimously recommended that PHMSA add specificity on
standards for PHMSA review of ``other technology'' and manual valve
notifications. The LPAC also unanimously recommended PHMSA incorporate
the notification requirements of Sec.  192.18 into the final rule and
make a similar provision for hazardous liquid pipelines.
3. PHMSA Response
(i) ``Rupture-Mitigation Valve'' and Related Definitions
    PHMSA notes that there was concern regarding the clarity of the
terms RMV, ``shut-off segment,'' and ``entirely replaced,'' and PHMSA
has revised those terms in this final rule.
    For the definition of an RMV, PHMSA has made it explicit that such
a valve is an ASV or an RCV. Commenters from industry requested PHMSA
allow the use of certain valve technologies to satisfy the proposed RMV
or alternative equivalent technology installation requirement. In this
final rule, PHMSA is clarifying that a valve on crossover piping that
is locked and tagged closed in accordance with operating procedures
would qualify as an alternative equivalent technology. PHMSA notes
that, for other technologies (such as check valves) that commenters
from industry had suggested should be generally considered alternative
equivalent technologies, PHMSA included a pre-installation notification
procedure for alternative equivalent technologies and will consider
requests to use such technologies on a case-by-case, site-specific
basis. When determining the appropriateness of alternative equivalent
technologies for a particular site, PHMSA will consider technical and
safety information submitted by an operator including, but not limited
to, design, construction, maintenance, and operating procedures;
technology design and operating characteristics such as operation times
(closure times for manual valves); service reliability and life;
accessibility to operator personnel; nearby population density; and
potential consequences to the environment and the public.
    The definition of a ``shut-off segment,'' as it pertains to RMVs
and alternative equivalent technologies, has been clarified in this
final rule as well. These segments are only relevant when RMVs or
alternative equivalent technologies are installed pursuant to this
final rule for Class 3 and Class 4 locations for gas pipelines, as well
as HCAs (or on pipeline segments that could affect HCAs, in the case of
hazardous liquid pipelines) for gas and hazardous liquid pipelines.
Shut-off

segments are defined as segments of pipe located between the upstream
mainline valve closest to the upstream endpoint of the new or entirely
replaced Class 3, Class 4, or HCA segment, and the downstream mainline
valve closest to the downstream endpoint of the new or entirely
replaced Class 3, Class 4, or HCA segment. Shut-off segments can
include crossover or lateral pipe depending on where that pipe connects
to the specific shut-off segment. Single shut-off segments can include
multiple Class 3, Class 4, or HCA pipeline segments.
    Pertaining to the definition of ``entirely replaced,'' it was not
PHMSA's intent to require the addition of RMVs or alternative
equivalent technologies for small maintenance replacements, such as at
road crossings or anomaly repairs where the pipe is replaced. PHMSA did
note throughout the NPRM that it was considering ``entirely replaced''
to mean the replacement of 2 contiguous miles of pipe. Some commenters
representing the public noted that pipeline operators may try to
schedule replacement activities and pipeline segment lengths to
circumvent the replacement mileage threshold. PHMSA determined that
this concern is mitigated by the recommendations of the Committees to
clarify that the RMV and alternative equivalent technology installation
requirements would apply to those replacement projects where 2 or more
miles of pipeline, in the aggregate, are replaced within any 5
contiguous miles within any 24-month period. PHMSA is aware that
sourcing valves might take a long lead time, and that waiting to
install a valve, at any location, could be deleterious to safety.
Requiring the installation, or automation, where applicable, of valves
where relatively larger construction projects are taking place will
facilitate operators obtaining and installing the RMVs or alternative
equivalent technologies required by this final rule. Accordingly, in
this final rule, PHMSA has introduced specific definitions for
``entirely replaced onshore transmission pipeline segments'' and
``entirely replaced onshore hazardous liquid or carbon dioxide pipeline
segments'' meaning those gas and hazardous liquid pipeline replacement
projects where 2 or more miles of pipe have been replaced within any 5
contiguous miles of pipe within any 24-month period.
(ii) RMV Applicability
    Certain commenters from the industry and the industry associations
requested various exemptions for the RMV and alternative equivalent
technology installation requirements, including pipelines that operated
at pressures below 30 percent of SMYS. Pipelines operating at pressures
below 30 percent of SMYS have ruptured in the past, and low operating
pressure is not a guarantee that the pipe will not rupture. However,
PHMSA is aware of data that would indicate that pipelines operating at
pressures lower than 20 percent of SMYS are at less risk of rupturing.
A study on pipelines that ruptured while operating at low hoop stresses
that was published in 2013 noted that, within the 5-year window of the
study, there were seven pipeline ruptures occurring on pipelines
operating at a pressure below 20 percent SMYS.\42\ The authors of the
study noted that, while these are not highly likely events, the
likelihood is not so low where certain conditions could be present that
they do not need to be considered in an operator's IM plans.
---------------------------------------------------------------------------

    \42\ Rosenfeld & Fassett ``Study of Pipelines that Ruptured
While Operating at a Hoop Stress Below 30% SMYS;'' Pipeline Pigging
and Integrity Management Conference (Feb. 13-14, 2013).
---------------------------------------------------------------------------

    Additionally, according to PHMSA's 2019 annual report data, the
population of natural gas and hazardous liquid pipelines that operate
at these pressures are a small portion of the aggregate mileage of
those types of pipelines across the United States.\43\ Consistent with
other, current regulatory requirements, PHMSA believes it is reasonable
to add certain exemptions for pipeline segments operating at lower
stress levels. For natural gas pipelines, PHMSA presented data during
the GPAC meeting showing a correlation between pipelines operating at
lower stresses and pipelines with smaller PIRs. Given that natural gas
pipelines that would have a PIR of less than 150 feet would typically
be either pipelines of smaller diameter that would not be subject to
the requirements of this rulemaking, or larger pipelines operating at
lower stresses, PHMSA believes it would be feasible to exempt such
pipelines from the RMV and alternative equivalent technology
installation requirements if those pipelines are in Class 1 or Class 2
locations. PHMSA did not accept the GPAC's recommendation to provide an
exception, based on the pipeline's PIR, for gas transmission and
gathering pipelines in Class 3 locations. Pipelines in Class 3
locations are by definition adjacent to population centers: A Class 3
location is where there are 46 or more buildings for human occupancy
within the class location unit, or where there is a building or area
that is occupied by 20 or more persons on at least 5 days a week for 10
weeks in any 12-month period. PHMSA has determined that, while it might
be less likely that a gas pipeline operating at lower stresses in a
Class 3 location would rupture, the potential consequences to public
safety and the environment are still unacceptable.
---------------------------------------------------------------------------

    \43\ Seven percent of the gas transmission mileage operates at
pressures below 20 percent of SMYS, which equates to approximately
21,000 miles out of 302,000 miles. For hazardous liquid pipelines, 3
percent of the total mileage operates as pressures less than 20
percent of SMYS, which equals 6,750 miles out of a total of 225,000
miles.
---------------------------------------------------------------------------

    For hazardous liquid pipelines, PHMSA notes that there are
currently regulatory requirements for low-stress pipelines in rural
areas. By definition (at Sec.  195.12), these pipelines operate at
stress levels equal to or less than 20 percent of SMYS. The
environmental consequences of a hazardous liquid spill can linger for
many years, and hazardous liquids can travel far from the initial
accident site to affect other areas as well. Therefore, counter to the
LPAC recommendation, PHMSA is not providing hazardous liquid pipelines
that operate at lower stresses an exemption from the RMV installation
and usage requirements of this rulemaking.
    Some commenters (including TC Energy and the industry associations)
requested PHMSA provide exemptions from RMV installation requirements
for, or otherwise exclude, gas pipelines in Class 1 and Class 2
locations, and for hazardous liquid pipelines that are outside of HCAs.
PHMSA notes that, for hazardous liquid pipelines, there are many
locations, such as non-navigable waterway crossings, that could
experience significant consequences from an accident even though they
are not defined as HCAs. For gas pipelines, there have been many
instances where a Class 1 location in which a pipeline has been
installed has later experienced so much population growth that it has
grown into a Class 3 location. Requiring operators to install RMVs and
alternative equivalent technology on Class 1, Class 2, and non-HCA
infrastructure is prudent and provides future generations with a
baseline level of public and environmental safety that can accommodate
changes in population density.
    As discussed earlier in this rulemaking, PHMSA considered the
recommendations the Committees made regarding the applicability of this
rulemaking to gathering pipelines. For gas pipelines, PHMSA determined
that the risk profile of Type A gas gathering pipelines was
considerable enough not to impose a broad exception to the rule's
requirements, as these pipelines tend to operate at higher pressures
and are in Class 2, Class 3, or Class 4 locations,

where there are more concentrated populations. However, based on risk
profile, PHMSA did create a general exemption from the RMV and
alternative equivalent technology installation requirements in this
rulemaking for Type A gas gathering pipelines in Class 2 locations with
a PIR of 150 feet or less. Operators of Type A gas gathering pipelines
that have a PIR of 150 feet or less in a Class 2 location are not
required to install RMVs or alternative equivalent technology in
accordance with this rulemaking. PHMSA considered the GPAC's
recommendation applicable to Type B gathering lines and determined that
a broad exemption from the RMV and alternative equivalent technology
requirements would be warranted, given the fact that Type B gas
gathering pipelines, by definition, operate at hoop stresses less than
20 percent of SMYS. Pipelines operating at pressures that low are less
likely to rupture. As noted above, PHMSA will carefully monitor data
from these lines to inform future rulemaking.
    For hazardous liquid pipelines, PHMSA noted earlier that regulated
hazardous liquid gathering pipelines would be required to install and
use RMVs and alternative equivalent technologies in accordance with
this rulemaking, as hazardous liquid gathering pipelines that are in
non-rural areas are required to comply with the entirety of part 195.
However, PHMSA is exempting regulated rural gathering pipelines from
the RMV and alternative equivalent technology requirements of this
rulemaking unless they cross bodies of water greater than 100 feet
wide, as ruptures on regulated rural gathering pipelines would
generally involve less risk to public safety and property than non-
rural gathering lines, and ruptures on regulated rural gathering lines
that cross large bodies of water have the potential to cause more
significant environmental damage. Regarding the comment that PHMSA
should clarify whether the 5 percent volume contribution for
determining the need for RMVs on laterals is based on flow rate or
total volume, Sec.  192.634(b)(3) states that the 5 percent volume
contribution is based on total volume.
(iii) Timeframe for RMVs To Be Operational and Implementation Period
    Regarding the timeframe for making RMVs and alternative equivalent
technologies operational, PHMSA has determined that 14 days is more
appropriate than the proposed 7 days given that (as noted in the
comment submitted by INGAA et al.) a number of activities must take
place after a pipeline has been placed into service but before an RMV
is fully operational--PHMSA understands the scale and number of those
activities make completion within the proposed 7-day timeline
impracticable. Accordingly, PHMSA has adjusted that timeframe in this
final rule. PHMSA has also provided a procedural machinery for
operators to request an extension beyond 14 days if completion of
necessary activities for a valve to become operational is not
economically, technically, or operationally feasible (e.g., due to
prohibitive costs, labor or component shortages, or required permitting
or access rights).
    Regarding the implementation date for RMV and alternative
equivalent technology installation, PHMSA notes the confusion several
commenters had regarding the implementation date and the effective date
of the rule. In this final rule, PHMSA is clarifying the implementation
date for RMV and alternative equivalent technology installation by
stating that pipelines and pipeline segments installed or entirely
replaced beginning 12 months after the publication date of the final
rule will be required to have RMVs or alternative equivalent
technologies. PHMSA believes 12 months is a reasonable implementation
period for RMV and alternative equivalent technology installation
rather than the 24 months recommended by the Committees as it should
provide operators with sufficient lead time to source RMV or
alternative equivalent technology for planning construction and
replacement projects without causing substantial implementation delay.
Further, as shown in the RIA, PHMSA has found that much new pipeline
construction is already obtaining and installing RMVs. If a gas or
hazardous liquid pipeline operator anticipates it will not be able to
meet this compliance timeframe, it may request from PHMSA, in
accordance with Sec. Sec.  192.18 and 195.18, respectively, additional
time to comply because of economic, technical, or operational
feasibility constraints (e.g., labor or component availability
constraints and lead times, prohibitive cost, permitting requirements,
or obtaining requisite access rights) with respect to its near-term
construction and replacement projects. Per the procedures at Sec. Sec.
192.18 and 195.18, PHMSA has discretion to grant or deny an operator's
request based on the information that the operator provides.
(iv) Notifications
    Regarding the notification requirements for RMV and alternative
equivalent technology installation, PHMSA acknowledges that aligning
the notification process with the recently finalized Sec.  192.18 would
be beneficial. Accordingly, PHMSA has done so in this final rule for
both hazardous liquid and gas pipelines. For gas pipelines, this means
that PHMSA has cross-referenced the notification requirements in this
final rule to Sec.  192.18 to provide for, and build upon, the
notification process that is in that section. For hazardous liquid
pipelines, because there was no corresponding notification section,
PHMSA has created a new Sec.  195.18 in this final rule that functions
similarly to Sec.  192.18. For any notifications related to the RMV and
alternative equivalent technology requirements of this rulemaking,
Sec.  195.18 provides a consistent process where operators submit in
advance of installation the pertinent, requested information to PHMSA,
and PHMSA has 90 days in which to review and respond to the request. If
an operator does not receive a letter of objection or a request from
PHMSA for more time or information for PHMSA to complete its review of
the request within 90 days of the notification, then the operator may
use the alternative technology, method, compliance timeline, or valve
spacing that is being requested. Similar to the notification response
process for part 192, PHMSA's objection will specify the reasons PHMSA
does not approve of the proposed alternative technology, method,
compliance timeline, or valve spacing, while a request from PHMSA for
more time to review the request will extend the notification review
period beyond 90 days. Further, to establish a verifiable record, it is
PHMSA's policy to send a formal ``no objection'' letter or email,
either before or after the 90-day review period, when PHMSA does not
object to an operator's request in the notification.

F. Valve Spacing & Location

1. Summary of Proposal
    In the NPRM, PHMSA proposed to require RMVs or alternative
equivalent technologies installed on newly constructed or entirely
replaced gas and hazardous liquid pipelines to be spaced at certain
intervals. For gas pipelines, PHMSA proposed that the distance between
RMVs or alternative equivalent technologies must not exceed 8 miles for
Class 4 locations, 15 miles for Class 3 locations, and 20 miles for
Class 1 and Class 2 locations in HCAs. For hazardous liquid pipelines,
PHMSA proposed RMV and alternative equivalent technology spacing of 15
miles for HCAs and 7\1/2\ miles for HVL lines in populated HCAs. PHMSA
also

proposed valve spacing of 20 miles for hazardous liquid pipelines not
in HCAs and spacing of a maximum of 1 mile for pipelines at water
crossings of greater than 100 feet in width so that the valve is
located outside of the flood plain, or the actuators and controls were
otherwise unaffected by floodwaters.
    In Sec. Sec.  192.634 and 195.418, PHMSA also proposed that
operators would, in HCAs and Class 3 and Class 4 locations for gas
pipelines, install RMVs or alternative equivalent technologies upstream
and downstream of new construction and replacements longer than 2
contiguous miles regardless of whether the project involved a valve
installation.
    PHMSA also proposed to modify the IM requirements for both gas and
hazardous liquid pipelines to specify that RMVs or alternative
equivalent technologies installed to protect HCAs must meet the design,
operation, testing, maintenance, and rupture mitigation requirements
proposed elsewhere in the NPRM.
2. Comments Received
(i) Spacing
    The PST and the NTSB stated the maximum RMV and alternative
equivalent technology spacing intervals proposed in the NPRM might not
be sufficient to mitigate the consequences of a ruptured pipeline, with
the PST expressing concern that 15- and 20-mile spacing is too far,
especially for large-diameter pipelines.
    For hazardous liquid pipelines, commenters representing the
pipeline industry generally did not support a universal mileage
threshold for maximum valve spacing without considering the
feasibility, practicability, and public safety benefits associated with
installing a valve at a particular location. Magellan Midstream
Partners L.P. specifically requested PHMSA consider valve spacing that
relies on operator programs providing for pipeline-specific evaluations
on optimization of valve spacing to reduce the magnitude of potential
releases within HCAs. Similarly, commenters representing the hazardous
liquid pipeline industry requested PHMSA provide a process for
operators to request alternative valve spacing distances for situations
where an operator determines the installation of additional valves
would not provide additional public safety or where installation is
otherwise infeasible.
    API, AOPL, and GPA Midstream also suggested that PHMSA's proposal
for the maximum valve spacing for HVL pipelines was too stringent at 7
\1/2\ miles and that a 10-mile distance for valves on HVL pipelines
would better align PHMSA requirements with standards established in
Canada that would be more appropriate for pipelines in the United
States. API, AOPL, and GPA Midstream suggested that a 7 \1/2\-mile
spacing for HVL pipelines was appropriate only for those pipelines in
HCAs. Commenters also noted that the Canadian standard provides
operators with a 25 percent spacing flexibility when determining valve
locations, and the commenters recommended PHMSA provide a similar
allowance.
    The PST expressed confusion regarding the NPRM language related to
RMV and alternative equivalent technology spacing, suggesting that
their interpretation of the proposed regulatory text would allow RMVs
and alternative equivalent technology to be spaced at distances greater
than the current valve spacing requirements at Sec.  192.179. By
contrast, their expectation is that PHMSA's intent is to require more
valves at closer spacing intervals than the current rules, or at most,
at the same spacing. The PST requested PHMSA clarify whether new valve
spacing requirements would be equal to or more stringent than currently
required.
    At the GPAC meeting on July 22, 2020, the Committee unanimously
recommended that PHMSA specify that the spacing requirements in Sec.
192.634 apply to replacement projects covered by Sec.  192.179. At the
LPAC meeting on July 23, 2020, the Committee unanimously recommended
that PHMSA add a 25 percent tolerance to the spacing of HVL pipelines
and add a notification procedure to allow operators of hazardous liquid
pipelines to obtain relief from the valve spacing requirements on a
case-by-case basis.
(ii) Location
    INGAA et al. noted that using an automated valve in a remote area
may create a comparatively higher reliability risk than using an
automated valve in a more populated area, noting that if a
communications failure, power loss, or other malfunction causes an
automated valve in a remote area to close unnecessarily, it may take
the operator hours to arrive at the valve and restore service, leading
to an extended loss of gas supply. They also stated that, in locations
where an operator employs an RCV to meet the proposed installation
requirement in a Class 1 or Class 2 location, it will take more time
for the operator to acquire information about a potential rupture event
in remote areas. Further, INGAA et al. stated that operators require
significant information about a potential rupture event before making
the critical decision to close an RCV, as closing a valve prematurely
can have the same disruptive impacts to customers as a rupture.
    INGAA et al. also noted that limiting the RMV and alternative
equivalent technology installation requirements to pipelines in HCAs
and Class 3 and Class 4 locations would also improve the clarity of the
rulemaking, stating that the rule, as written, is confusing. INGAA et
al. suggested PHMSA revise Sec.  192.179 to clarify that Class 1 and
Class 2 locations outside of HCAs do not require RMVs or alternative
equivalent technologies to be installed unless the replacement project
involves a valve. INGAA et al. noted that this ``opportunistic
approach'' appears to have been PHMSA's intent in the proposal, and it
differed from their understanding of the rule's application to
replacement projects in HCAs and Class 3 and Class 4 locations. Other
commenters had similar suggestions and requested PHMSA revise cross-
references throughout the rule for clarity. Commenters representing
hazardous liquid pipeline operators made a similar comment pertaining
to the proposals for hazardous liquid pipelines.
    API and AOPL also requested that PHMSA clarify the requirements for
the placement of valves near water crossings, recommending that PHMSA
base the valve spacing requirements on the size of a 100-year flood
plain.
    Operators of both gas and hazardous liquid pipelines recommended
that PHMSA explicitly state that a shut-off segment must contain the
new or replaced HCA segment or Class 3 or Class 4 segment where RMVs or
alternative equivalent technologies are installed. Related to shut-off
segments, these operators also asked PHMSA to clarify whether
operational block valves would be permitted within a shut-off segment,
and if an RMV or alternative equivalent technology would need to be the
nearest valve to the shut-off segment. Some commenters noted that
requiring valves within the endpoints of certain segments might create
valve spacing more stringent than the current valve spacing
requirement. Further, INGAA et al. questioned if an RMV or alternative
equivalent technology is needed at the termination of a pipeline.
    For hazardous liquid pipelines, several commenters requested PHMSA
clarify what a ``flood plain'' is for the purposes of valve spacing at
water crossings, with some commenters suggesting PHMSA specify
operators must use the 100-year flood plain. The PST requested PHMSA
clarify what

``flood conditions'' meant. Similarly, certain commenters, including
Magellan, requested that PHMSA remove the 1-mile limitation on water
crossings or provide for alternative spacing if that mile is within the
flood plain.
    PHMSA also received comments requesting that it remove the proposed
requirement to locate valves within 7\1/2\ miles of the endpoint of an
HCA segment.
    At the Committee meetings on July 22 and 23, 2020, the Committees
unanimously recommended that PHMSA:

    (1) Clarify that replacement projects in non-HCA Class 1 and
Class 2 locations do not require RMVs or alternative equivalent
technology unless the replacement project involves a valve.
Throughout industry public comments, this was what was referred to
as the ``opportunistic approach.'' For hazardous liquid pipelines,
the LPAC recommended PHMSA revise the rule to clarify the same
concept for pipelines in non-HCA locations.
    (2) Specify that proposed valve spacing requirements related to
pipeline replacements and RMV and alternative equivalent technology
installation requirements do not apply to pipelines in non-HCA Class
1 and Class 2 locations.
    (3) Specify that a ``shut-off segment'' must contain the newly
constructed or replaced HCA or Class 3 or Class 4 pipeline segment.
    (4) Specify that RMVs or alternative equivalent technology would
not be required at the downstream termination of a pipeline.
Further, specify that operational block valves are allowed within a
shut-off segment and RMVs and alternative equivalent technology need
not be the nearest valve to a shut-off segment.
    (5) For hazardous liquid pipelines, specify the 100-year flood
plain at hazardous liquid pipeline water crossings.
3. PHMSA Response
(i) Spacing
    PHMSA believes the valve spacing it proposed in the NPRM for both
gas and hazardous liquid pipelines is appropriate. For new gas pipeline
construction, spacing of RMVs and alternative equivalent technology
will follow existing requirements at Sec.  192.179(a) determining
distance by reference to class location: 2.5-mile intervals in Class 4
locations, 4-mile intervals in Class 3 locations, 7.5-mile intervals in
Class 2 locations, and 10-mile intervals in Class 1 locations. For
replacement projects on gas pipelines, PHMSA's experience with how
operators implement a ``one-class bump'' when a pipeline's class
location changes support the final rule's spacing approach. Per the
current requirements following a class location change, an operator can
base a pipeline's MAOP on a specified design factor multiplied by the
test pressure for the new class location as long as the corresponding
hoop stress does not exceed certain percentages of the SMYS of the pipe
and as long as the pipeline has been tested for a period of 8 hours or
longer in accordance with Sec.  192.611(a)(1). This approach has been
practical for operators where single-step class location changes occur.
Operators performing one-class bumps leave the existing infrastructure
in place, which means that, even though the class location has changed,
the design standards of the original pipeline are still being used. In
addition to wall thickness and steel strength, this applies to the
spacing of the valves along the segment as well. For example, operators
have been able to use Class 1 spacing standards for valves on a
pipeline segment that has changed from a Class 1 to a Class 2 if the
operator has followed the appropriate procedures in Sec.  192.611.
PHMSA is extending this same methodology to replacement RMV and
alternative equivalent technology spacing for gas pipelines by allowing
operators to use the maximum valve spacing of a class below the class
location of the replacement project. In practice, this means that
replacement projects requiring RMVs or alternative equivalent
technology in Class 4 locations can have RMVs or alternative equivalent
technology spaced at a maximum of 8 miles, replacement projects
requiring RMVs or alternative equivalent technology in Class 3
locations can have RMVs or alternative equivalent technology spaced at
a maximum of 15 miles, and replacement projects in Class 1 and Class 2
locations can have RMVs or alternative equivalent technology spaced at
a maximum of 20 miles. If the RMV or alternative equivalent technology
spacing is greater than the spacing for the next class location, a new
RMV or alternative equivalent technology is required. Going forward,
PHMSA will monitor data in these locations to ensure such spacing does
not create an undue risk to people or the environment.
    According to PHMSA's data from 2015 to 2019, hazardous liquid
pipeline operators have constructed or replaced 4,708 miles of pipeline
that is 6 inches or greater in diameter, and they have installed a
total of 673 valves on that pipeline mileage for an average of 1 valve
for every 7 miles. Therefore, PHMSA does not believe it is onerous to
finalize minimum valve spacing standards at every 15 miles for pipeline
segments in, or which could affect, HCAs and at every 20 miles for
pipeline segments that could not affect HCAs. However, a hazardous
liquid pipeline operator may request an exemption from these
requirements if it can demonstrate to PHMSA in accordance with the
notification procedures in Sec.  195.18, that installing an RMV or
alternative equivalent technology as otherwise required by Sec.
195.260 would be economically, technically, or operationally infeasible
by reference to factors such as access to communications and power;
terrain; prohibitive cost; component and labor availability; ability to
secure access rights and necessary permits; and lack of accessibility
to operator personnel for installation and maintenance. That notice
must also include a safety evaluation of deviation from this final
rule's spacing requirements that references technical and safety
factors including, but not limited to, the following: Design,
construction, maintenance, and operating procedures for pertinent
pipeline segments; potential consequences to the environment and the
public from a rupture on the pertinent pipeline segments; and
mitigation measures (e.g., operating times for isolation valves) in the
event of a rupture.
    Concerning the proposed spacing for HVL pipeline segments, PHMSA
based the valve spacing requirements on the recommended spacing in
American Society of Mechanical Engineers (ASME) B31.4, ``Pipeline
Transportation Systems for Liquids and Slurries,'' an industry standard
that has existed for many decades. PHMSA does not believe that
permitting broad tolerance from the HVL valve spacing requirements in a
manner similar to the Canadian standard commenters referenced is
appropriate, as PHMSA prescribed this valve spacing standard only in
high-population areas or other populated areas as defined by Sec.
195.450 where there would be significant populations in need of
additional protection. However, in accordance with the LPAC
recommendation, PHMSA has provided in this final rule a method for
operators to request (in accordance with Sec.  195.18 and subject to
PHMSA review) an increase, by 25 percent, of the maximum valve spacing
intervals for HVL pipeline segments in high-population areas or other
populated areas should the installation of a valve at a particular
location not be economically, technically or operationally feasible.
Operators would, in connection with that notice, submit a safety
evaluation referencing technical and safety factors including, but not
limited to, the following: Design, construction, maintenance, and
operating procedures

for pertinent pipeline segments; potential consequences to the
environment and the public from a rupture on the pertinent pipeline
segments; and mitigation measures in the event of a rupture. If PHMSA
grants the request, the operator is required to keep the records
necessary to support such a determination for the useful life of the
pipeline.
    PHMSA considered the comments regarding the clarity of the proposed
valve spacing regulations and the interplay of the various sections of
the NPRM when drafting this final rule. PHMSA attempted to simplify the
regulatory text by dividing the RMV sections into installation
requirements and performance requirements. PHMSA also attempted to
consolidate notification requirements broadly by establishing a
notification section in part 195, similar to that established in part
192 in the 2019 Gas Transmission Final Rule, and cross-referencing to
these sections whenever a notification might be required in the
regulations. In addition to reducing the amount of regulatory text,
these sections also provide for a more consistent notification process
across the regulated community.
(ii) Location
    PHMSA notes that the proposed RMV and alternative equivalent
technology requirements for gas pipelines in Class 1 and Class 2
locations were intended to apply only to new construction and those
replacement projects where 2 or more miles were being replaced and
which involved a valve. This was unlike the proposed requirements for
gas pipe replacements in excess of 2 miles in HCAs and Class 3 and
Class 4 locations, which, as proposed, would have needed upstream and
downstream RMVs or alternative equivalent technology regardless of
whether the project impacted an existing valve. Therefore, PHMSA is
clarifying in this final rule that operators are to take the
``opportunistic'' approach suggested in the comments and are required
to install RMVs or alternative equivalent technology during pipe
replacement projects in non-HCA Class 1 or Class 2 areas only if the
replacement project involves the addition, replacement, or removal of a
valve. As previously discussed, this requirement does not apply to
those Class 1 or Class 2 locations that have a PIR of 150 feet or less.
For hazardous liquid pipelines, the same approach applies to those
replacements in non-HCA locations.
    Commenters questioned whether a newly constructed or entirely
replaced pipeline segment in an HCA was supposed to be included within
a shut-off segment for the purposes of the NPRM. PHMSA intended the
shut-off segment to include the entire new or replaced pipeline segment
in (or, for hazardous liquid lines, which could affect) an HCA and has
clarified that intent in the regulatory text of this final rule by
stating so explicitly in Sec. Sec.  192.634 and 195.418. Similarly,
some commenters from the hazardous liquid pipeline industry also
questioned whether requiring an RMV or alternative equivalent
technology within 7\1/2\ miles of the endpoint of a hazardous liquid
pipeline segment in or which could affect an HCA would ultimately
reduce the existing valve spacing. PHMSA did not intend for such a
measure to reduce valve spacing and determined that the requirement is
duplicative of similar preventative and mitigative requirements set
forth in Sec.  195.452. As such, PHMSA has determined that the proposed
requirement may have been unnecessary and has deleted it from this
final rule.
    INGAA et al. also requested PHMSA clarify whether an RMV or
alternative equivalent technology is needed at the termination of a
pipeline. Per this final rule, an RMV or alternative equivalent
technology is needed at the termination of a pipeline, and PHMSA is
clarifying that an operator may use a manual compressor station valve
at a continuously manned station as an alternative equivalent
technology; PHMSA understands that the logical termination of a
pipeline might be within a station, and a valve there could also be
used as an RMV or alternative equivalent technology to help isolate a
rupture on the pipeline system. Such a valve used as an alternative
equivalent technology would not require an advance notification to
PHMSA pursuant to Sec. Sec.  192.18 or 195.18, but, as with any
alternative equivalent technology, it must be able to be closed as soon
as is practicable and absolutely within 30 minutes after the rupture
identification and comply with the applicable provisions of this final
rule.
    Further, PHMSA also received questions regarding whether
operational block valves are permitted within a shut-off segment and
whether an RMV or alternative equivalent technology needs to be the
nearest valve to the shut-off segment. In the NPRM, PHMSA stated that
``all valves in a shut-off segment'' needed to be RMVs or alternative
equivalent technology. However, it was PHMSA's intent that operational
block valves be allowed within a shut-off segment as long as the RMV or
alternative equivalent technology is within the valve spacing
requirements. As such, PHMSA has removed that phrase from this final
rule; the section now states the requirements for installing RMVs or
alternative equivalent technologies, and it leaves open the possibility
that an operator can install additional block valves on a shut-off
segment between compliant and appropriately spaced RMVs or alternative
equivalent technologies. PHMSA is also clarifying in this final rule
that RMVs or alternative equivalent technologies do not need to be the
nearest valve to the shut-off segment, and has specifically stated this
in the RMV and alternative equivalent technology installation sections
at Sec. Sec.  192.634 and 195.418.
    Regarding comments about the installation of RMVs or alternative
equivalent technologies near river crossings and flood plains, PHMSA
notes that, based on the comments it received, it has made explicit in
this final rule that such valves must be installed outside of the 100-
year flood plain of the body or bodies of water, or the valves must
have actuators and other control equipment installed so as to not be
impacted by flood conditions, or the equipment might be elevated to a
level where they will not be impacted by flood conditions. PHMSA
considers ``flood conditions'' to be where water is at a high enough
level near the valve so that it, or the related electronics, would not
operate. Flood conditions also can include debris carried by
floodwaters that could affect the equipment. For multiple water
crossings, PHMSA structured the proposed requirements to provide
operators the flexibility to install valves near sites where there are
multiple water crossings and where there might be potential access
issues between water crossings. This mechanism is consistent with
approvals PHMSA has granted operators under the existing authority and
process at Sec.  195.260. In this final rule, PHMSA is requiring
operators to locate valves upstream and downstream of the first and
last of multiple water crossings so that the total distance between the
upstream-most valve and the downstream-most valve does not exceed 1
mile, rather than requiring an operator to install RMVs or alternative
equivalent technologies on either side of each water crossing where
there are multiple water crossings.

G. Valve Status Monitoring

1. Summary of Proposal
    In the NPRM, PHMSA proposed to require operators to monitor or
otherwise control RMVs or alternative equivalent technologies using
remote or

on-site personnel. This monitoring or control would include the valve
status, the upstream and downstream product pressures, and product flow
rates during normal, abnormal, and emergency operations. PHMSA also
proposed to require operators be able to monitor the status of valves
during rupture events.
2. Comments Received
    Several commenters, including INGAA et al., questioned whether
remote monitoring of ASVs was required, as those valves would be set to
respond automatically to rupture events and not require additional
input.
    INGAA et al. also requested that PHMSA allow operators to monitor
pressure or flow rates in lieu of valve status if they were unable to
monitor valve status. PHMSA was also asked to clarify whether operators
would need to monitor remotely the flows and pressures through manually
operated RMVs after they close. Further, PHMSA was also asked to
remove, on efficiency grounds, the proposed requirement for operators
to station personnel at a manually operated RMV site for continuous
monitoring.
    At the Committee meetings on July 22 and 23, 2020, the Committees
unanimously recommended that PHMSA specify that an operator does not
need to monitor ASV status if the operator can monitor pressures or
flows in the pipeline segment to be able to identify and locate a
rupture. This differed from the proposed language in that, as worded,
an operator would have been required to monitor ASV status in addition
to pressures and flows. The Committees also unanimously recommended
PHMSA provide a similar allowance for manual valves.
3. PHMSA Response
    PHMSA maintains that an operator's ability to monitor the upstream
and downstream pressures around RMVs and alternative equivalent
technologies is important to identify ruptures effectively and mitigate
incidents. As such, PHMSA expects all valves installed as RMVs and as
alternative equivalent technologies to monitor pressures upstream and
downstream of those valves at all times. However, if operators can
monitor upstream and downstream pressures around manual valves that are
being used as alternative equivalent technologies or ASVs in real-time
so that they can identify and locate a rupture, operators do not need
to station personnel at a site where a manually operated alternative
equivalent technology has been installed or continually monitor ASV
status. In accordance with the Committee recommendations on this issue,
PHMSA has specified in this final rule that, if an operator can
remotely monitor either pressures or flows in real-time at an ASV or a
manual shut-off valve such that they can identify and locate a rupture,
the operator does not need to monitor valve status continually, nor are
operators required to monitor the pressures on manual valves being used
as alternative equivalent technology once those valves are closed in
response to a rupture.

H. Class Location Changes

1. Summary of Proposal
    In the NPRM, PHMSA proposed to clarify the valve spacing
requirements of Sec.  192.179 and to apply the RMV and alternative
equivalent technology installation requirement and rupture-mitigation
requirements to pipelines where segments of pipe (of any length) were
replaced to meet MAOP requirements following a class location change.
As proposed, operators would need to install necessary RMVs or
alternative equivalent technology within 24 months of the class
location change.
2. Comments Received
    INGAA et al., GPA Midstream, and the KOGA, expressed concern over
the proposed Sec.  192.610 requirements and recommended revisions to
the rule language. INGAA et al. indicated that class location change
pipe replacements produce minimal pipeline safety benefits because they
involve less than 75 miles of transmission pipe per year, and the
replaced pipe is often in safe, operable condition.
    GPA Midstream called for PHMSA to establish specific valve
installation requirements for class-location-related pipeline
replacements. They claimed that under PHMSA's interpretation of the
current regulations at Sec. Sec.  192.13(b) and 192.179, operators must
comply with valve installation requirements for new pipelines if a
segment is replaced in response to a class location change; but that
this is contrary to the original intent of the regulations, imposes
unreasonable compliance burdens, and discourages pipeline replacements.
    INGAA et al. noted that, because the vast majority of class change
pipe replacements are less than 2 miles in length, the proposed Sec.
192.610 would require the installation of at least one manual valve for
many pipe replacements where the class location changes from a Class 1
to a Class 3. INGAA et al. estimated that it costs $600,000 to $800,000
for an operator to install a new manual valve on an existing pipeline
ranging from 24 to 36 inches in diameter, and therefore, the annual
cost for installing manual valves under this proposed provision could
exceed $100 million per year. Therefore, INGAA et al. suggested that,
for class location change pipe replacements that involve less than 2
contiguous miles of pipe but more than 2,000 feet of pipe, PHMSA should
provide operators the option to automate an existing upstream and
downstream valve so that the distance between such automated valves
would not exceed 20 miles, which is the current spacing requirements
for valves on pipelines in Class 1 locations. INGAA et al. stated that
this would be consistent with the approach that PHMSA has proposed for
replacements greater than or equal to 2 contiguous miles in Class 1 and
Class 2 locations that are also HCAs. They further stated that
retaining the valve spacing requirements for Class 1 locations is
appropriate for class location change pipe replacements that do not
meet the 2-mile ``entirely replaced'' definition and will mitigate the
need to install a new valve for most class location change pipe
replacements.
    Similarly, other industry commenters, including GPA Midstream and
TC Energy Corporation, stated that PHMSA should exclude short pipe
replacements from proposed Sec.  192.610, noting that when an operator
is removing a short section of pipe, there may not be an appropriate
location in that short area to install a new valve, which can make
complying with the valve spacing provisions impractical. Further, these
commenters suggested that operators frequently replace short sections
of existing pipe to repair potentially injurious conditions found to be
affecting that pipe. They stated that many of these maintenance
replacements are not ``pipe replacement projects,'' generally only
affect small sections of the pipeline, and in some cases, must be
conducted immediately to ensure public safety. They argue that
operators must be reasonably able to repair such pipeline defects
without installing additional valves, stating that requiring all pipe
replacements, no matter how small, to comply with valve spacing
requirements applicable to new pipe construction would increase cost
and regulatory complexity and may reduce an operator's incentive or
ability to complete voluntary assessments and remediation. As such,
PHMSA was asked to exclude pipe replacements that were less than 2,000
feet from the RMV and alternative equivalent technology installation
requirements.
    AFPM stated that the requirement to update and install the required
valves to match the class location requirements

within 24 months of the class location change may not be feasible in
all circumstances due to factors outside the control of the operator,
such as local permitting. AFPM also suggested that PHMSA should
incorporate a process to account for such uncontrollable delays.
    At the GPAC meeting on July 22, 2020, the GPAC unanimously
recommended that PHMSA specify that the valve spacing in Sec.  192.634
would, pursuant to Sec.  192.610, be applicable to class location
changes resulting in the replacement of an aggregate of 2 or more miles
of pipe within any 5 contiguous miles, and consider implementing a
timeframe of 24 months for compliance from the change in class
location. Following discussion of the potential that high installation
costs from application of valve spacing requirements to replacement of
smaller pipeline segments may discourage pipeline replacement projects,
the GPAC also unanimously recommended PHMSA exclude pipeline
replacements less than 1,000 feet within 1 contiguous mile from the
valve installation requirements. Finally, the Committee unanimously
recommended (after discussion of the costs and practical difficulties
associated with obtaining land rights necessary to install RMVs on
pipelines on segments less than 2 miles in length) that, for pipeline
replacements due to class location changes that are between 1,000 feet
and 2 miles, PHMSA should allow operators to automate the existing
valves with automatic or remote-control actuators and pressure sensors,
with a maximum spacing of 20 miles, which they asserted would be
consistent with the operational capability proposed in Sec.  192.634.
3. PHMSA Response
    PHMSA intended for the RMV and alternative equivalent technology
requirements, including those for valve spacing proposed in Sec.
192.634, to be applicable to class location changes for cases where the
operator chose to replace pipe to meet the MAOP requirements of the new
class location. The proposal was attempting to clarify that, in the
event of pipe replacement due to a class location change, operators
must install valves that comply with the existing valve spacing
requirements at Sec.  192.179(a) for the new class location.\44\
---------------------------------------------------------------------------

    \44\ In the Matter of Viking Gas Transmission, Final Order,
C.P.F. No. 32102 (May 1, 1998).
---------------------------------------------------------------------------

    In addition to finalizing that proposal in this final rule for
class location-based pipeline replacements of 2 or more miles within
any 5 contiguous miles over a 24-month period, PHMSA is also allowing
operators to comply with this section by installing or using existing
RMVs when a class location changes (i.e., from Class 1 to a Class 2 or
a Class 2 to a Class 3) so that the distance between RMVs does not
exceed 20 miles. This allowance considers several public comments in
addition to a corresponding discussion and recommendation from the
GPAC. INGAA et al. noted that the NPRM seemed to require the
installation of manual valves on pipelines where the class location had
changed. However, this was not PHMSA's intent. The automation of
existing valves to protect a pipeline segment where the class location
has changed is to provide a higher measure of public and environmental
safety than the installation of additional manual valves, given that
automated valves will be able to be closed more quickly than manual
valves in the event of an emergency.
    PHMSA acknowledges that there may be instances where the RMV and
alternative equivalent technology installation requirements might not
be appropriate for very short sections of pipe that are being replaced
under Sec.  192.610. As such, PHMSA is providing in this final rule an
exception from the RMV and alternative equivalent technology
installation requirements for short pipeline replacements that are less
than 1,000 feet in length within 1 contiguous mile. For pipe
replacements that occur when class locations change and that range from
1,000 feet to 2 miles in length, PHMSA believes that operators could
automate existing valves with RCV or ASV technologies and corresponding
pressure sensors that would be consistent with the operational
requirements and valve spacing requirements of proposed Sec.  192.634.
As discussed in the paragraph above, PHMSA has modified this final rule
accordingly.

I. Valve Maintenance

1. Summary of Proposal
    In the NPRM, PHMSA proposed to revise Sec. Sec.  192.745 and
195.420 to require operators perform inspections, maintenance, and
drills on RMVs to ensure that they can be closed as soon as practicable
but within 40 minutes of identifying a rupture. Among other
requirements, PHMSA proposed operators perform point-to-point
verification tests for RMVs that are ASVs or RCVs and perform initial
validation drills and periodic confirmation drills for manual or
locally operated valves an operator identified as RMVs. PHMSA also
proposed that operators would be required to identify corrective
actions and lessons learned from the validation and confirmation drills
and share and implement those lessons learned throughout their pipeline
systems. As proposed, operators would be required to repair or
remediate inoperable valves within 6 months following a failed drill,
with the operator designating a temporary alternate compliant valve
within 7 days of a failed drill.
2. Comments Received
    Some commenters, including INGAA et al., stated PHMSA should remove
the proposed requirement for point-to-point testing because it is
already required under the control room management requirements in
Sec. Sec.  192.631 and 195.446. This comment applied to the proposed
regulations for both gas and hazardous liquid pipelines.
    Operators requested that PHMSA clarify that annual drills are not
required for every manual valve and that the drills for ``locally-
actuated'' valves would exclude ASVs and RCVs. Further, commenters
indicated that PHMSA should provide more specificity regarding the
random drill selection process.
    INGAA et al. commented that PHMSA should clarify that operators are
not required to fully close manual or locally actuated valves during
drills. TPA and AFPM expressed this same concern, with AFPM stating
that such a requirement might cause significant disruptions when the
applicable pipeline is the primary source of feedstock for a major
manufacturing facility. INGAA et al. suggested PHMSA allow operators to
perform tabletop drills to meet the drill response time requirement.
    The Clean Air Council stated that the final rule should include
provisions for pipeline operators to perform regular drills to ensure
they can comply with the rupture response regulations, test the
performance of their equipment, and ensure that pipeline personnel will
be trained and skilled in responding to an emergency properly. They
noted that while ASVs and RCVs will cut the response time down in a
rupture event, having trained operating personnel is also important,
stating that PHMSA should include provisions wherein a key responsible
individual within the company is identified whose responsibility it is
to train new personnel on the rupture response procedures within a
certain period of new personnel being hired. They stated that PHMSA
should require operators to report on how such training would be
conducted and in what period the new individuals are trained, noting
that this

would create accountability for an otherwise unknown factor in pipeline
management that would decrease the likelihood that operators may fail
in carrying out rupture response procedures in a timely manner. They
also noted that with adding in electrical connections and cellular
communications with new valves, additional maintenance schedules and
procedures will need to be developed for this added complexity.
Similarly, the PST supported the proposed requirements for testing,
maintenance, drills, and the incorporation of lessons learned into
operator procedures.
    INGAA et al. stated that PHMSA should reconsider the proposed
maintenance requirements for when an RMV or alternative equivalent
technology installed under the final rule is unable to achieve the
proposed performance standard. Specifically, they suggested PHMSA
should revise the NPRM by providing operators 12 months to repair,
replace, or install new RMVs when an RMV or alternative equivalent
technology is not operating correctly or otherwise cannot achieve the
40-minute response time requirements. This concern was echoed by other
industry commenters, who suggested various compliance timeframes. INGAA
et al. also stated that PHMSA should allow a notification process when
it would not be practicable for an operator to repair or replace an RMV
or alternative equivalent technology within 12 months.
    GPA Midstream noted that operators should be required to make
repairs or replacements as soon as practicable but no later than the
time provided in their procedures for conducting operations,
maintenance, and emergency activities. GPA Midstream also stated that a
7-day timeframe may not be sufficient to locate and designate an
alternative valve to serve as a substitute for a damaged or otherwise
inoperable RMV or alternative equivalent technology. They requested
that PHMSA revise the provision to allow 14 days for designating an
alternative compliant valve. This concern was echoed by individual
operators, who suggested different compliance periods for implementing
alternative valve measures.
    Other commenters also noted that the proposed 6 months for
implementing alternate shut-off valve measures is inadequate because it
fails to account for right-of-way acquisition, the time needed to
obtain necessary environmental clearance and permits, and extended lead
times for the procurement of transmission valves. More specifically, TC
Energy requested that PHMSA clarify what is meant by ``alternative
compliant valve,'' noting that, because of the proposed 6-month
compliance deadline for completing maintenance or replacing a RMV or
alternative equivalent technology, it is apparent that ``compliant'' is
not intended to refer to proximity or spacing or whether a designated
``alternative valve'' is automated or is manual. TC Energy suggested
that PHMSA should direct operators to designate an alternative shut-off
valve and document an interim response plan until the primary RMV or
alternative equivalent technology is repaired or replaced.
    API/AOPL and GPA Midstream also suggested that PHMSA should revise
the maintenance procedures to allow operators to obtain an authorized
alternative response time.
    At the Committee meetings on July 22 and 23, 2020, the Committees
unanimously recommended that PHMSA delete the requirement for point-to-
point testing because it duplicates requirements in the existing
control room management regulations in both parts 192 and 195.
    Regarding the drill requirements, the Committees unanimously
recommended that PHMSA clarify that annual drills apply only to
manually operated valves and involve the manual operation of a local
actuator or by hand, and not to ASVs or RCVs. Further, the Committees
unanimously recommended specifying that a 25 percent valve closure is
sufficient to demonstrate the successful completion of the response
time validation drill for manually operated valves.
    The Committees also unanimously recommended PHMSA provide operators
with a notification process to justify a need to extend the timeframes
for repair and establishing alternate RMVs, if necessary. Further, the
Committees unanimously recommended PHMSA consider adjusting the
timeframe for repairs to 12 months but as soon as practicable, rather
than the proposed 6 months. Certain members of the Committees
representing the public (including Pipeline Safety Trust) expressed a
preference to keep the timeframe for repairs at 6 months. However,
other members of the Committees representing industry (including
Enbridge, Williams, Consumers Energy, Marathon Pipeline, and PECO)
noted that 12 months might be more appropriate given difficulties with
supplier access to inventory and procurement issues. Additionally, the
Committees unanimously recommended that PHMSA specify that alternative
compliant valves identified through this process would not be required
to comply with the valve spacing requirements for RMVs.
3. PHMSA Response
    PHMSA acknowledges that the proposed point-to-point testing
requirements were already a part of the control room management
regulations at Sec. Sec.  192.631 and 195.446. However, PHMSA believes
restating the provision in the valve maintenance requirements will
provide additional clarity and will improve compliance and
enforceability. Therefore, PHMSA has chosen to retain the language in
this final rule.
    Regarding the proposed manual valve drill requirements, PHMSA
intended the annual drills to apply to manually operated valves used as
alternative equivalent technology only, and not ASVs or RCVs. PHMSA
expects such a drill would include the manual operation of a local
actuator or closing the valve via a hand-wheel. PHMSA confirms that
annual drills are not required for every manual valve. Rather, an
annual drill is required for one randomly selected manual valve in each
of the operator's field work units. The way that an operator determines
which manual valves would be randomly selected is at the discretion of
the operator, but the selection method must be included in an
operator's written procedures so it can be subject to inspection.
    PHMSA has determined that full closure of valves is not necessary
for the purposes of the valve maintenance requirements of this final
rule. Accordingly, PHMSA has revised the provision to require, at a
minimum, a 25 percent closure of the valve. PHMSA recognizes that
overcoming inertia is likely to be the most difficult work in getting a
valve to operate. Therefore, PHMSA has determined that a 25 percent or
more closure is sufficient to demonstrate the valve's operability and
functionality while allowing pipeline operators to maintain service
without major interruptions.
    Additionally, in this final rule, PHMSA is not allowing operators
to perform tabletop drills to verify response times for manually
operated valves. PHMSA believes that a tabletop drill would not be
sufficient for ensuring that the valve is working, which is the intent
of the provision. Operators need to ensure that manual valves being
used as an alternative equivalent technology for the purposes of this
rulemaking can be arrived at and physically operated so that they
function as intended, achieving full closure within the maximum valve-
closure time of this rulemaking. A paper exercise cannot effectively
confirm real-

time travel time to a valve location or the time it will take operator
personnel to close a particular valve manually, given conditions that
could occur during a rupture.
    Regarding the measures operators must take after a failed drill,
PHMSA believes that a 7-day timeframe for identifying alternative shut-
off measures and a 6-month timeframe for valve repair are appropriate.
Because the purpose of an RMV or alternative equivalent technology is
to mitigate the consequences of a rupture, should one occur, the longer
a valve stays non-functional or the longer it takes an operator to
identify alternative measures increases the potential rupture
consequences to the area near the impacted pipeline segment. In light
of the comments and Committee recommendations for extending the repair
period to 12 months given the likely delays involved in scoping and
executing required repairs, PHMSA understands that there operators may
need repair timeframes longer those identified in the NPRM; PHMSA has,
therefore, extended the repair period to 12 months. PHMSA has also
provided an advance notification process in this final rule for
operators to request (before the repair is undertaken) an extension of
that 12-month repair period by demonstrating to PHMSA that repair
according to the final rule's timeline will be economically,
technically, or operationally infeasible (e.g., by reference to
prohibitive costs, difficulty in securing required access rights and
permits, long procurement lead times, and component/labor
availability). However, PHMSA declines to offer a similar notification
process in connection with identification of alternative shut-off
measures following a failed drill, as prompt identification of those
alternatives are essential for ensuring that the public and the
environment are not unprotected from a rupture for extended periods of
time.
    PHMSA did not intend that any valves operators would identify as an
alternative compliant RMV or equivalent technology based on a failed
drill would need to comply with the valve spacing requirements of the
rulemaking, and PHMSA is not requiring that in this final rule. PHMSA
is requiring, however, that any alternative compliant RMV or equivalent
technology would contain the entire shut-off segment and comply with
the 30-minute valve closure standard of this rulemaking.
    Some commenters requested PHMSA enhance the proposed maintenance
and drill requirements to cover valve-related specialized equipment and
periodic personnel training and management programs. PHMSA notes that
these requirements are already included in the Federal Pipeline Safety
Regulations, including under the operator qualification and control
room management regulations.

J. Failure Investigations

1. Summary of Proposal
    In the NPRM, PHMSA proposed to revise the regulations applicable to
gas and hazardous liquid pipelines to define the elements that an
operator must incorporate when conducting analyses of incidents and
other releases and failures involving the activation of RMVs and
alternative equivalent technologies, namely ruptures.
    The proposed revisions would require the operator to identify
potential P&M measures that could be taken to reduce or limit the
release volume and damage from similar events in the future. The post-
incident or -failure review would address factors associated with this
rulemaking, including but not limited to detection and mitigation
actions, response time, valve location, valve actuation, and SCADA
system performance. Upon completing the post-incident or -failure
analysis, the operator would be required to develop and implement the
lessons learned throughout its suite of procedures, including in
pertinent operator personnel training and qualification programs, and
in design, construction, testing, maintenance, operations, and
emergency procedure manuals and specifications.
2. Comments Received
    INGAA et al. stated that PHMSA should remove the references to
``failures'' in Sec.  192.617, as ``failure'' is not defined in parts
191 or 192, and it is unclear if the section accounts for abnormal
operations that do not result in a rupture. Similar comments were made
by representatives of hazardous liquid pipeline operators, requesting
that ``failure'' be changed to ``accident'' to be more consistent with
the part 195 regulations.
    INGAA et al. added that the prescriptive post-incident requirements
proposed in Sec.  192.617 are fit-for-purpose following a rupture but
are unnecessary and overly burdensome following an abnormal operation.
Other commenters from industry noted that the investigation
requirements seemed to be duplicative of existing accident and incident
reporting requirements and suggested that PHMSA remove the proposed
investigation requirements from the final rule.
    GPA Midstream stated that the proposal for operators to prepare and
follow procedures for conducting failure and incident investigations
should be stated in a new, separate paragraph, and the proposed
requirement to incorporate any lessons learned into appropriate part
192 procedures can be consolidated in another paragraph. They further
stated that PHMSA could eliminate the other additional language
proposed in the section (including sending the failed pipe, component,
or equipment to a laboratory for testing), because it is unnecessary.
Similarly, Magellan Midstream Partners, L.P., as well as other industry
commenters, suggested that PHMSA should remove the proposed
requirements for failure analysis because it is not appropriate or
effective for an operator to send all failed pipe, components, or
equipment for laboratory testing and examination. Further, several of
these industry commenters requested PHMSA specify that the
implementation of any lessons learned and any additional P&M measures
following an incident would be required only if they are reasonable and
practicable.
    INGAA et al. and GPA Midstream stated that the proposed
documentation and recordkeeping requirements for failure investigations
are unnecessary, with INGAA et al. stating that the requirements appear
to be duplicative of requirements currently under PHMSA's incident
reporting requirements. GPA Midstream stated that, to avoid imposing
undue burdens on pipeline operators, the senior executive review and
lifetime recordkeeping requirements PHMSA proposed should only apply to
the final analysis prepared at the conclusion of the investigation
rather than preliminary analyses. GPA Midstream and API/AOPL commented
that such a requirement would create an additional recordkeeping burden
without improving safety, with API requesting PHMSA delete the proposed
requirement. AFPM provided similar comments.
    The PST stated that PHMSA should amend Sec.  192.617(c) to require
that the results of an operator's post-incident review be incorporated
into operators' procedures, not just read and kept, as it appears to be
proposed. INGAA et al. stated that they support the incorporation of
post-incident lessons learned as an important aspect of pipeline safety
management systems. However, INGAA et al. added there may be some
circumstances where an incident investigation would not yield a change
to procedures, for example, some third-party damage incidents, and
PHMSA should require operators to

incorporate lessons learned and P&M measures only if appropriate and
practicable following an incident investigation. TPA generally echoed
these remarks.
    Further, INGAA et al. stated that they support distribution
operators incorporating post-incident lessons learned into their
procedures even though the rule stated it only applies to gas
transmission and hazardous liquid pipelines, but they recommended PHMSA
clarify that the requirements in Sec.  192.617(c) only apply to
transmission lines, since the broad definition of ``rupture'' in Sec.
192.3 could lead to Sec.  192.617(c) being interpreted to apply to both
gas distribution and gas transmission pipeline incidents.
    PST stated that, although the NPRM proposes operators incorporate
post-incident lessons into their procedures, the paragraph relating to
rupture and valve shut-off incident reviews does not include that same
requirement. They added that the section should be amended to include a
requirement that the results of the post-incident reviews be
incorporated into operator's procedures, not just read and kept.
    At the Committee meetings on July 22 and 23, 2020, the Committees
unanimously recommended that PHMSA clarify that the implementation of
lessons learned and additional P&M measures after incidents are
required only where they are found to be reasonable and practicable.
Additionally, the GPAC unanimously recommended that PHMSA specify that
general failure investigations under these sections would apply to gas
distribution pipelines; however, failure investigations specific to
RMVs would not apply to gas distribution pipelines.
3. PHMSA Response
    PHMSA acknowledges the comments stating that it should clarify the
terminology of its proposed regulatory amendments by using defined
terms, such as removing the use of the term ``failure'' in favor of
``incident'' or ``accident.'' However, PHMSA notes that existing
regulations at Sec.  192.617 address the investigation of failures on
gas lines, which is broader than reportable incidents. Similarly, the
term ``failure'' is used throughout parts 192 and 195 of the Federal
Pipeline Safety Regulations. Therefore, PHMSA has made no changes in
this final rule to the phrasing as it was originally proposed in the
NPRM, since the term ``failure'' is currently used throughout its
regulations.
    Other commenters suggested that the failure investigation
requirements would duplicate existing incident/accident reporting
requirements. PHMSA does not consider the failure investigation
requirements that were proposed and the existing incident/accident
reporting requirements to be duplicative, as the proposed failure
investigation requirements were intended to build on existing failure/
accident investigation requirements for gas and hazardous liquid
pipelines, and provide more thorough technical evaluation of valve
functionality and performance during the mitigation of an incident or
accident. PHMSA intended for operators to investigate ``failures,'' as
that term is used throughout parts 192 and 195 of its regulations, and
as it is defined in ASME B31.8S and ASME B31.4. PHMSA has, however,
revised the regulatory text in in this final rule to better convey that
intent.
    Similarly, some industry commenters, including Magellan, opposed
certain requirements in this section, especially with respect to
operators sending failed pipe, components, or equipment for laboratory
testing and examination. With respect to gas pipelines in particular,
PHMSA provides in this final rule additional specificity to the
existing regulation at Sec.  192.617, which states that ``each operator
shall establish procedures for analyzing accidents and failures,
including the selection of samples of the failed facility or equipment
for laboratory examination, where appropriate [. . .].'' The underlying
requirement remained unchanged, and PHMSA has finalized the clarifying
changes proposed in the NPRM in a way that will improve the ability to
identify and respond to safety issues that could be revealed in such
testing and examinations. PHMSA believes that regulatory language in
this final rule providing for parallel obligations for hazardous liquid
pipelines are similarly essential to its continuing regulatory
oversight of the safety of those pipelines.
    As for the scope of the proposed failure investigation requirements
for gas pipelines, because PHMSA included the amendments in the
existing regulations at Sec.  192.617(a) and (b), PHMSA intended those
proposed requirements to apply to distribution pipelines, which were
already subject to the existing requirements of that section. Because
proposed paragraphs (c) and (d) of that section addressed failure
investigations specific to the closure of RMVs or alternative
equivalent technologies, however, and RMVs or alternative equivalent
technologies were and are not required for gas distribution systems in
this rulemaking, operators of gas distribution pipelines are not
required to comply with those paragraphs as a result of this rule.
    INGAA et al. requested PHMSA clarify that the implementation of any
post-incident lessons-learned and any additional P&M measures be
required only where they are reasonable and practical. PHMSA would not
expect operators to implement P&M measures that were clearly
unreasonable or impractical. Regarding those measures, PHMSA did not
intend to cause any confusion with similar IM requirements by
referencing a term that is primarily used in the IM regulations.
Subsequently, in this final rule, PHMSA has changed this phrase from
``P&M measures'' to a more general phrase of ``operations and
maintenance'' measures to avoid confusion with separate IM-related
requirements.
    Several comments were submitted regarding senior executive
involvement for the certification of failure investigations. PHMSA
believes that senior executive certification is essential to ensuring a
failure investigation's quality and highlighting the importance of the
investigation results and their implementation into operations.

K. 9-1-1 Notification Requirements

1. Summary of Proposal
    In the NPRM, PHMSA proposed requirements related to operators
responding to pipeline ``emergencies'' that built on existing
regulations at Sec. Sec.  192.615 and 195.402. Specifically, PHMSA
proposed to require that an operator's emergency procedures provide for
rupture mitigation in response to a rupture event, and that operators
contact and maintain liaison with the appropriate public safety
answering point (9-1-1 emergency call center) in the event an
operator's pipeline ruptures.
2. Comments Received
    NAPSR stated that the term ``emergency'' is not defined within part
192, noting that, without a definition for ``emergency,'' operators may
make unnecessary notifications to the appropriate fire, police, and
public officials, and force responses to minor events instead of real
emergencies. NAPSR suggested that if PHMSA is changing this
specifically to address ruptures on gas transmission lines, then it may
be appropriate for PHMSA to reference ``rupture'' in the final rule
language instead of ``emergency.''
    TPA stated that the 10-minute requirement for contacting first
responders is duplicative and unnecessary, as existing emergency
procedures and damage prevention

procedures already contain requirements for the timely contact of
emergency responders and calls to 9-1-1 numbers. They recommended that
PHMSA remove this requirement from the rule. A member of the public
agreed that the time to declare a rupture following the first sign of a
problem should be no more than 10 minutes, and that emergency services
must be notified right away.
    The NTSB stated that the proposed changes to the emergency planning
regulations do not require immediate and direct notification to local
jurisdictions of possible ruptures as recommended by Safety
Recommendation P-11-9. They stated that the NPRM's clarifications for
when notification is required could unnecessarily delay operators
notifying local authorities and possibly exclude some ruptures from the
notification requirement, such as distribution systems or portions of
transmission systems that do not contain RMVs.
    AFPM stated that the language in the proposed sections is
unnecessarily prescriptive and the language should be simplified, as
the position title or function of the operator personnel that is
responsible for contacting the appropriate public safety answering
point is immaterial.
    AFPM stated that the use of ``may'' in the proposed revision to
require notification of ``each government organization that may respond
to a pipeline emergency'' vastly expands the universe of events for
which operators would have to provide notice and is an unrealistic
request. AFPM stated that the operator may not reasonably be able to
identify all the possible jurisdictions or agencies that may need to be
called upon. As such, AFPM recommended PHMSA allow an operator to
identify and coordinate with the agency identified by local or State
law as the lead agency in a pipeline emergency, or allow communication
with a regional coordinating agency (e.g., Office of Emergency
Management) to meet this requirement.
    AFPM stated that they support PHMSA's intent to require operators
to establish and maintain adequate means of communication with the
appropriate public safety officials, as previously established
relationships between operators and safety officials could help
mitigate the consequences of an incident.
    AFPM stated that they believe the use of ``and other public
officials'' in the proposed requirements is too vague and potentially
expansive. AFPM and INGAA et al. recommended that PHMSA should
explicitly note with whom operators should liaise, such as county
emergency managers, local emergency planning committees, or 9-1-1
agencies, and limit the requirement to those emergency response
agencies with primary jurisdiction for response to a pipeline incident.
INGAA et al. stated that this approach would be consistent with the
Pipeline Emergency Responder Initiatives that have been developed in
several States with the support of PHMSA.
    AFPM added that ``notifying the appropriate public safety answering
point (9-1-1 emergency call center), as well as fire, police, and other
public officials'' is redundant and possibly confusing in jurisdictions
where the 9-1-1 center is designated as the single point of emergency
services contact. AFPM recommended PHMSA allow 9-1-1 to be the single
point of contact for all jurisdictions for which the 9-1-1 center
serves as such.
    At the Committee meetings on July 22 and 23, 2020, the Committees
unanimously recommended that PHMSA state that communication with 9-1-1
applies to all ruptures without exception. For operators of pipelines
not located within 9-1-1 service areas or that otherwise have no public
safety answering points, the Committees unanimously recommended PHMSA
promulgate similar requirements. Further, the Committees unanimously
recommended that PHMSA allow operators to establish liaison with the
appropriate local emergency response coordinating agencies, such as 9-
1-1 emergency call centers or county emergency managers, in lieu of
communicating individually with each fire, police, or other public
entity, as was proposed in the NPRM.
    The Committees also unanimously recommended that PHMSA limit
certain sections of the regulations to emergency preparedness
activities and other sections to emergency response activities, rather
than combining the two as PHMSA did in the NPRM.
3. PHMSA Response
    The NTSB and the PST were concerned that the NPRM, as proposed,
could exclude certain ruptures from the notification requirements of
this section. PHMSA did not intend to include any exceptions from the
9-1-1 notification requirements of this rulemaking, including for those
pipelines where RMV or alternative equivalent technology closure is not
required, and does not believe the NPRM was worded as such. Further,
PHMSA has modified the language in the NPRM regarding when the 9-1-1
notification obligation has been triggered to reflect the substitution
in this final rule of the term ``notification of potential rupture''
for the NPRM's definition of ``rupture''; PHMSA expects this
substitution will reduce the time before response and mitigation
actions are taken. Ultimately, the requirement in this final rule for
9-1-1 notification applies to all notifications of potential ruptures
on all gas and hazardous liquid pipeline systems governed by the
emergency planning and procedure requirements at Sec. Sec.  192.615 and
195.402, respectively.
    Industry commenters requested that PHMSA include in the final rule
9-1-1 communication provisions for pipelines that are not located in
areas served by 9-1-1 call centers or that have no public safety
answering points. The emergency notification requirements in this final
rule require operators to establish adequate means of communication
with fire, police, and other public officials as needed, regardless of
whether they are affiliated with public safety answering points.
Operators must determine the jurisdictional areas, responsibilities,
resources, and emergency contact numbers for those government
organizations that may respond to pipeline emergencies involving their
pipeline facilities.
    To the points commenters made on liaising with the appropriate
local emergency coordinating entities and allowing coordination with a
lead agency if recognized by State and local law, PHMSA will note that
it did not propose to amend the long-standing requirements about
coordinating with local officials, including fire and police officials.
The NPRM intended to add the explicit requirement, when applicable, for
operators to call 9-1-1 after the notification of a potential rupture.
Per this final rule, to meet these requirements of this section,
operators may liaise with the appropriate emergency response
coordinating agencies, such as 9-1-1 emergency call centers or county
emergency managers, in lieu of communicating individually with each
fire, police, or other public entity. PHMSA believes that the
requirement to liaise with appropriate emergency response coordinating
agencies responds to the Committee recommendation for including
provisions for operators of pipeline segments outside of 9-1-1 or
public safety access point service areas.

L. Other

1. Summary of Proposal
    In the NPRM, PHMSA proposed to revise Sec. Sec.  192.935 and
195.452 to clarify the requirements for conducting ASV

and RCV evaluations for HCAs, particularly when RCVs and ASVs are
installed as P&M measures associated with improved response times for
pipeline ruptures. The proposed amendments would have required that
operators be able to evaluate and demonstrate that they could identify
a rupture within 10 minutes in accordance with the proposed rupture
identification regulations, meet the proposed RMV or alternative
equivalent technology closure standard of 40 minutes, and demonstrate
compliance with the proposed valve maintenance requirements.
2. Comments Received
    Regarding the installation of RMV technology in HCAs under Sec.
192.935, INGAA et al. recommended that PHMSA clarify the decisions
operators would be required to make, stating PHMSA proposed in the NPRM
that these decisions should consider the swiftness of rupture detection
capabilities, not leak detection capabilities. INGAA et al. and other
industry commenters also recommended that PHMSA remove the proposed
requirements in Sec.  192.935(c) because they appear to be duplicative
with the proposed requirements for RMV installation under Sec.
192.634. Similarly, Northern Natural Gas Company recommended that PHMSA
remove the proposed requirements at Sec.  192.935 because they are
already partially addressed by the investigation of failures and
incidents at Sec.  192.617.
    The PST supported PHMSA's proposed addition of performance measures
for the installation of EFRDs and their use as RMVs under Sec.
195.452. API/AOPL and GPA Midstream suggested that PHMSA should restate
that EFRDs installed under the IM regulations must meet the applicable
requirements in part 195 for RMVs, as this would simplify the
regulatory language.
    Northern Natural Gas Company noted that the use of automatic valves
may create cybersecurity vulnerabilities. A private citizen echoed this
sentiment, stating that PHMSA needs to address cybersecurity issues
related to sensors and control systems associated with RMVs, as such
issues could reduce the effectiveness of those valves. However, the
private citizen noted that Congress has not provided PHMSA, or the U.S.
DOT in general, with specific authority to regulate the cybersecurity
of pipeline infrastructure. That private citizen suggested that these
technologies should be protected from cyber-threats, and the failure of
cybersecurity protections should trigger the same reporting
requirements that accompany the failure of physical controls.
    The Clean Air Council suggested that PHMSA adjust the definition of
HCAs to be broader than areas with higher population density, stating
they believe that the environmental and historical value of certain
locations should be included in an evaluation whether a location is an
HCA.
3. PHMSA Response
    PHMSA was attempting to update the existing requirements for ASV
and RCV analysis in HCAs with the terminology and specific requirements
related to RMVs and alternative equivalent technology that were
proposed in the NPRM. PHMSA was proposing no new requirements other
than that, if operators performed a risk analysis indicating that an
ASV or an RCV would provide protection to an HCA or a could-affect HCA
pipeline segment, those valves that the operators installed would
essentially be RMVs and would need to comply with the 10-minute rupture
identification standard, the valve closure time, and the associated
maintenance requirements. PHMSA believes that the wording of the
section and duplication of those requirements, rather than cross-
references, may have confused readers. As such, in this final rule,
PHMSA has retained those same requirements while simplifying the
language to state that an RMV installed in accordance with Sec. Sec.
192.935 and 195.452 must comply with all of the other RMV requirements
in the respective parts of the regulations.\45\
---------------------------------------------------------------------------

    \45\ See Sec. Sec.  192.3, 192.9, 192.18, 192.179, 192.610,
192.615, 192.617, 192.634, 192.636, 192.745, and 192.935, as
appropriate, for gas transmission and gathering pipelines, and
Sec. Sec.  195.2, 195.11, 195.18, 195.258, 195.260, 195.402,
195.418, 195.419, 195.420, and 195.452, as appropriate, for
hazardous liquid pipelines.
---------------------------------------------------------------------------

    Regarding cybersecurity issues, PHMSA notes that the recent
cyberattack on the Colonial Pipeline underscores the urgency of public-
private collaboration to address international cybersecurity threats.
PHMSA is working with a coalition of its Federal partners, including
the Transportation Security Administration (TSA), to ensure that
pertinent regulatory regimes adequately address cybersecurity risks on
pipeline infrastructure. PHMSA notes that the TSA recently issued
security directives that will enable the Department of Homeland
Security (DHS) to better identify, protect against, and respond to
threats to critical operators in the pipeline sector. The TSA's initial
directive requires critical pipeline owners and operators to report
confirmed and potential cybersecurity incidents to the DHS
Cybersecurity and Infrastructure Security Agency (CISA) and to
designate a Cybersecurity Coordinator, to be available 24 hours a day,
7 days a week. It also requires critical pipeline owners and operators
to review their current practices as well as to identify any gaps and
related remediation measures to address cyber-related risks and report
the results to TSA and CISA within 30 days.\46\ A second Security
Directive requires owners and operators of TSA-designated critical
pipelines to implement specific mitigation measures to protect against
ransomware attacks and other known threats to information technology
and operational technology systems, develop and implement a
cybersecurity contingency and recovery plan, and conduct a
cybersecurity architecture design review.
---------------------------------------------------------------------------

    \46\ https://www.dhs.gov/news/2021/05/27/dhs-announces-new-cybersecurity-requirements-critical-pipeline-owners-and-operators.
---------------------------------------------------------------------------

    Changing the HCA definition is outside the scope of the rulemaking
and would require substantial technical analysis. However, in response
to congressional mandates in the ``Protecting Our Infrastructure of
Pipelines and Enhancing Safety Act of 2016'' (Pub. L. 114-183) and the
2020 PIPES Act, PHMSA has promulgated an Interim Final Rule (under RIN
2137-AF31) titled ``Pipeline Safety: Coastal Ecological Unusually
Sensitive Areas,'' to amend the definition of an ``unusually sensitive
area'' in part 195 for hazardous liquid pipelines to include the Great
Lakes, coastal beaches, and certain coastal waters explicitly as
ecological resources for the purposes of determining whether a pipeline
is in, or could affect, an HCA.\47\ Further, section 119 of the 2020
PIPES Act requires PHMSA to contract with the National Academy of
Sciences (NAS) for development of a study evaluating potential
regulatory amendments that would build on this final rule by requiring
installation of RMVs on existing natural gas pipelines in HCAs,
hazardous liquid pipelines in unusually sensitive areas, and hazardous
liquid pipelines in commercially navigable waterways. The NAS committee
has been formed and that committee is in the process of planning its
activities.\48\
---------------------------------------------------------------------------

    \47\ 86 FR 73173 (Dec. 27, 2021).
    \48\ NAS, ``Criteria for Installing Automatic and Remote-
Controlled Shutoff Valves on Existing Gas and Hazardous Liquid
Transmission Pipelines'' (last visited Nov. 23, 2021).

---------------------------------------------------------------------------

IV. Section-by-Section Analysis of Changes to 49 CFR Part 192 for Gas
Pipelines

Sec.  192.3 Definitions

    Section 192.3 provides definitions for various terms used
throughout part 192. Most of the requirements of this final rule would
be triggered by an operator identifying a rupture following the
notification of a potential rupture. Therefore, PHMSA is amending Sec.
192.3 to define the ``notification of potential rupture'' in terms of
notification of, or observation by, an operator of indicia specified in
Sec.  192.635 of an unintentional or uncontrolled release of a large
volume of gas from a pipeline.
    Once an operator is notified of a potential rupture, they must
identify a rupture, if one exists. Therefore, PHMSA has established a
concept of ``rupture identification'' to mean the point when a pipeline
operator has sufficient information reasonably to determine that a
rupture occurred. PHMSA believes this would occur following a
``notification of potential rupture,'' as that term has been defined in
this rulemaking, given that the operator would have been notified or
would have had notice of some indicia of a potential rupture per Sec.
192.635. The final rule at Sec.  192.615 requires that operators must
document, in their operations manual or written procedures, their
method for rupture identification. An operator, after identifying a
rupture, would be required to close the RMVs or alternative equivalent
technologies necessary to isolate the ruptured pipeline segment.
    As a part of this rulemaking, operators are required to install
RMVs or alternative equivalent technology on certain pipeline segments,
including those that are ``entirely replaced onshore pipeline
segments.'' RMVs are defined in this rulemaking to mean ASVs or RCVs
that a pipeline operator uses to minimize the volume of gas released
from the pipeline and to minimize the consequences of a rupture. PHMSA
has defined entirely replaced onshore transmission pipeline segments to
mean those pipeline replacement projects where 2 or more miles of
pipeline have been replaced within any length of 5 contiguous miles of
pipeline during any 24-month period.

Sec.  192.9 What requirements apply to gathering lines?

    In this final rule, PHMSA has clarified that the RMV and
alternative equivalent technology requirements being promulgated apply
to Type A gas gathering pipelines (not Types B or C gathering lines),
as these pipelines typically have risk profiles similar to transmission
pipelines.

Sec.  192.18 How To Notify PHMSA

    In this final rule, operators can notify PHMSA in advance of their
intent to use a technology, method, or compliance timeline that differs
from that listed in the regulations, when the option for notification
is specifically provided. PHMSA retains discretion under Sec.  192.18
to reject, as appropriate, such requests. Accordingly, PHMSA has
revised this section to provide for a consistent notification procedure
across part 192 whenever an operator is required to notify PHMSA as a
part of a requirement.

Sec.  192.179 Transmission Line Valves

    In this final rule, PHMSA is requiring the installation of RMVs or
alternative equivalent technologies on certain gas pipelines. This
section specifies that operators must install RMVs, or alternative
equivalent technologies, on onshore gas pipeline segments with
diameters greater than or equal to 6 inches that are newly constructed,
or meet the definition of entirely replaced onshore transmission
pipeline segments, after April 10, 2023. RMVs and alternative
equivalent technologies installed in accordance with this section must
meet the existing valve spacing requirements of this section, and all
RMVs and alternative equivalent technologies installed in accordance
with this section must meet the operational requirements outlined in
Sec.  192.636.
    These installation requirements do not apply to those pipeline
segments that are in Class 1 or Class 2 locations and that have a PIR
of less than or equal to 150 feet. Further, the installation
requirements for entirely replaced onshore pipeline segments only apply
to those pipeline replacement projects that involve the addition,
replacement, or removal of a valve.
    If an operator seeks to install alternative equivalent technology
pursuant to this section, the operator must, in advance of such
installation, submit a notification making such a request to PHMSA in
accordance with Sec.  192.18. The operator must include in that
notification a site-specific technical and safety evaluation
demonstrating that technology provides an equivalent level of safety to
an RMV by reference to factors including, but not limited to, the
following: Design, construction, maintenance, and operating procedures;
technology design and operational characteristics such as operation
times (closure times for manual valves); service reliability and life;
accessibility to operator personnel; nearby population density; and
potential consequences to the environment and the public.
    If an operator requests use of manual valves as an alternative
equivalent technology, the notification submitted to PHMSA must also
demonstrate the site-specific economic, technical, or operational
infeasibility of installing an RMV (e.g., by reference to factors such
as access to communications and power; terrain; prohibitive cost; labor
and component availability; ability to secure required land access
rights and permits; and accessibility to operator personnel for
installation and maintenance).
    An operator may also submit for PHMSA review, in accordance with
the notification procedures in Sec.  192.18, a project-specific request
for extension of the compliance deadline in this section. That
notification must demonstrate installation of an RMV or alternative
equivalent technology in connection with near-term construction and
replacement projects would be economically, technically, or
operationally infeasible (e.g., by reference to prohibitive economic
costs, difficulty in securing access rights, component/labor
availability and procurement lead times, or permitting requirements).
    An operator that replaces pipeline segments is not required to meet
the valve spacing requirements of this section if the distance between
each point on the pipeline and the nearest valve does not exceed 4
miles in Class 4 locations, 7\1/2\ miles in Class 3 locations, and 10
miles in all other locations.

Sec.  192.610 Change in Class Location: Change in Valve Spacing

    This section specifies RMV and alternative equivalent technology
requirements when a class location changes. In cases where pipeline
segments are entirely replaced, as that term is defined in Sec.  192.3,
to meet the maximum allowable operating pressure in accordance with
requirements for class location changes under Sec. Sec.  192.611,
192.619(a), and 192.620, then an operator must install valves,
including RMVs or alternative equivalent technology, as necessary to
comply with this part. An operator must install such valves within 24
months of the class location change.
    If an operator replaces less than 2 miles of pipe in a length of 5
contiguous miles of pipe during a 24-month period to comply with the
maximum allowable operating pressure requirements after a class
location changes, the operator must either: (1) Comply with the valve

spacing requirements at Sec.  192.179(a), or (2) install or use RMVs or
alternative equivalent technology so that the entirety of the replaced
pipeline segment is between 2 RMVs or alternative equivalent technology
and so that the distance between those valves does not exceed 20 miles.
Operators are not required to comply with this section if they replace
less than 1,000 feet of pipe within any single contiguous mile within
any 24-month period to comply with a class location change.

Sec.  192.615 Emergency Plans

    In this final rule, PHMSA revised paragraphs (a)(2), (a)(6),
(a)(8), (a)(11), and (a)(12) and the introductory text of (c) in Sec.
192.615 to require that emergency procedures provide for rupture
mitigation in response to a rupture event. PHMSA is also requiring that