operators maintain liaison with and contact the appropriate public
safety answering point (i.e., 9-1-1 emergency call center), if such a
service is available, in the event of pipeline emergencies. In lieu of
communicating with individual fire, police, or other public entities,
operators may instead establish liaison with appropriate local
emergency coordinating agencies, such as 9-1-1 emergency call centers
or county emergency managers, as appropriate.
    PHMSA is requiring, through this final rule, that operators learn
the responsibilities, resources, jurisdictional areas, and emergency
contact telephone numbers for each Federal, State, and local government
organization that may respond to a pipeline emergency involving their
pipeline facilities, and inform such officials of the operator's
ability to respond to and communicate during pipeline emergencies.
PHMSA has not changed the existing requirements for operators to
maintain liaison with fire, police, and other public officials, as
appropriate.
    In conjunction with the definition of the ``notification of
potential rupture,'' PHMSA has in this final rule codified at Sec.
192.615(a)(12) language within the NPRM expressing its expectation that
operators will, upon notification of a potential rupture, identify
whether there is indeed a rupture by reference to their written
procedures. At a minimum, the procedures must specify the sources of
information, operational factors, and other criteria that the operator
will use to evaluate a notification of a potential rupture as an actual
rupture. Those written procedures should also incorporate procedures
for waiver of any requirements for specific pipeline personnel to
conduct on-scene investigation of a potential rupture if an operator
receives one or more of the following: Multiple or recurring instrument
indications (pressure readings, alarms, etc.) of potential ruptures;
pressure drops significantly in excess of the minimum thresholds in
Sec.  192.635(a)(1); or reports of rupture indicia from on-scene,
credible sources (e.g., on or off-duty pipeline operator personnel,
sheriff or police officers, fire department personnel, or other
emergency response personnel).

Sec.  192.617 Investigation of Failures and Incidents

    In this final rule, PHMSA has revised Sec.  192.617 to define the
elements that an operator must incorporate when conducting a post-event
analysis of ruptures and other failure events involving the activation
of RMVs or alternative equivalent technology.
    The revision requires the operator to identify potential preventive
and mitigative 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 include, but not be limited to,
detection and mitigation actions, response time, valve location, valve
actuation, and SCADA system performance. Upon completing the post-event
analysis, the operator must 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. In accordance with this section, an
operator must also complete a summary of the post-incident or -failure
review within 90 days of the incident. The operator must conduct
quarterly status reviews until the investigation is complete and a
final post-incident summary is prepared. The final post-incident
summary and all other reviews and analyses produced under the
requirements of this section must be reviewed, dated, and signed by the
operator's appropriate senior executive officer. Further, an operator
must keep the final post-incident summary, all investigation and
analysis documents used to prepare it, and records of lessons learned
for the useful life of the pipeline. The requirements to produce a
summary report are not applicable to gas distribution and Types B and C
gathering pipelines.
    PHMSA has also modified the existing failure and incident
investigation requirements at Sec.  192.617 to require operators
subject to that provision to incorporate lessons learned from those
investigations into their written procedures, including personnel
training and qualification programs, and design, construction, testing,
maintenance, operations, and emergency procedure manuals and
specifications. PHMSA has otherwise not made changes to the existing
requirements in this section for operators of gas pipelines to
establish procedures for analyzing incidents and failures.

Sec.  192.634 Transmission Lines: Onshore Valve Shut-Off for Rupture
Mitigation

    This section requires operators to install and use RMVs or
alternative equivalent technology on newly constructed and entirely
replaced onshore gas pipeline segments with diameters of 6 inches or
greater. Such valves would be required to be operational within 14 days
following placing the pipeline segment into service unless the operator
has submitted for PHMSA review, in accordance with Sec.  192.18, a
notification that operation of the RMV or alternative equivalent
technology within that 14-day timeframe is not economically,
technically, or operationally feasible. An operator may also submit for
PHMSA review, in accordance with the notification procedures in Sec.
192.18, a request for extension of the valve installation compliance
deadline requirements of Sec.  192.179 and this section demonstrating
that installation of an RMV or alternative equivalent technology in
connection with particular near-term construction and replacement
projects would be economically, technically, or operationally
infeasible (e.g., by reference to prohibitive costs, difficulty in
securing required access rights and permits, and component/labor
availability).
    For the purposes of the RMV and alternative equivalent technology
installation requirements, PHMSA created a definition for a ``shut-off
segment,'' which is a pipeline segment that is entirely located between
at least two RMVs or alternative equivalent technologies. If any
crossover or lateral pipe for commodity receipts or deliveries connects
to the shut-off segment between the upstream-most and downstream-most
RMVs or alternative equivalent technologies, the shut-off segment also
extends to valves on those crossover connections or laterals used for
receipt or delivery so that, when all valves are closed, there is no
flow path for commodity to be transported from outside the shut-off
segment to the rupture site. Laterals that

connect to shut-off segments and that contribute less than 5 percent of
the total shut-off segment volume may have RMVs or alternative
equivalent technologies installed at locations other than mainline
receipt or delivery points. A shut-off segment can include multiple
HCAs, and operators are not required to select the closest valve to the
shut-off segment as an RMV or alternative equivalent as long as the
proper valve spacing is maintained.
    The requirements of this section apply to all applicable pipe
replacement projects, even those that do not otherwise directly involve
the addition or replacement of a valve. Consistent with the
requirements for RMV and alternative equivalent technology
installation, this section does not apply to pipe segments in Class 1
or Class 2 locations that have a PIR less than or equal to 150 feet.
    This section also establishes valve spacing for RMVs and
alternative equivalent technologies installed in accordance with this
section, where the distance between such RMVs and alternative
equivalent technologies must not exceed 8 miles in Class 4 locations,
15 miles in Class 3 locations, and 20 miles in all other locations.
    Operators using a manual valve as an alternative equivalent
technology in lieu of an RMV for the purposes of this section must
appropriately locate personnel to ensure valve shut-off in accordance
with this section and the RMV performance requirements in Sec.
192.636.

Sec.  192.635 Notification of Potential Rupture

    In this section, PHMSA provides the criteria for a ``notification
of potential rupture,'' as that term is defined in Sec.  192.3.

Sec.  192.636 Transmission Lines: Valve Capabilities

    In this section, PHMSA establishes the operational requirements for
RMVs and alternative equivalent technologies. Following the
``notification of potential rupture,'' an operator must, after
identifying a rupture, close such valves as soon as practicable, but no
later than within 30 minutes (measured from rupture identification).
Operators may request to plan to leave RMVs or alternative equivalent
technologies open for longer than 30 minutes following rupture
identification if the operator previously has coordinated the plan with
appropriate local emergency responders, notified PHMSA, and adequately
demonstrated to PHMSA that closing such valves or technologies would be
detrimental to public safety.
    RMVs and alternative equivalent technologies must be capable of
being monitored or controlled by remote or on-site personnel, operated
during all operating conditions, and monitored for valve status.
Operators using ASVs as RMVs do not need to monitor those valves
remotely if the operator has the capability to monitor pressures or gas
flow rate on the pipeline in order to identify and locate a rupture
pursuant to the requirements of this rulemaking.
    Operators of pipelines in Class 1, non-HCAs may request, within
their notification under Sec.  192.18 seeking PHMSA review for
installation of manual valves as alternative equivalent technologies as
contemplated by this final rule, an exemption from the valve operation
requirements of Sec.  192.636(b). Operators seeking such an exemption
must provide for PHMSA review within that notification the closing
times for those manual valves.

Sec.  192.745 Valve Maintenance: Transmission Lines

    In this final rule, PHMSA is revising Sec.  192.745 by adding
paragraphs (c), (d), and (e) to incorporate the maintenance,
inspection, and operator drills required to ensure operators can close
an RMV or alternative equivalent technology as soon as practicable, but
no more than 30 minutes, after identification of a rupture. PHMSA is
finalizing initial validation drill requirements and requirements for
periodic validation tests for any manually or locally operated valve
installed as an alternative equivalent technology in lieu of an RMV.
Operators are not required to close the valves fully during such
drills; a closure of 25 percent, at a minimum, is sufficient to be
compliant, unless the operator has information that requires additional
closure requirements for the valve to be compliant with the
requirement. If the 30-minute-maximum closure time cannot be achieved
during the drill, the operator must revise their response efforts and
repair any valves to achieve compliance as soon as practicable but no
later than 12 months after the drill. Operators may request, pursuant
to the notification procedure at Sec.  192.18, an extension of the 12-
month repair timeline if such repair within 12 months would 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). Alternative valve shut-off measures must be in place
within 7 days of a failed drill. In accordance with Sec.  192.631(c)
and (e), operators must also conduct a point-to-point verification
between SCADA displays, sensors, communications equipment, and any RCVs
installed in accordance with Sec. Sec.  192.179 or 192.634.
    Per this final rule, each operator is required to identify
corrective actions and lessons learned resulting from the validation
and confirmation drills and share and implement them across its entire
network of pipeline systems.

Sec.  192.935 What additional preventive and mitigative measure must an
operator take?

    In this final rule, PHMSA is revising Sec.  192.935(c) to clarify
the requirements for conducting RMV evaluations for HCAs, particularly
when an operator installs such valves as preventive and mitigative
measures to improve response times for pipeline ruptures and mitigate
the consequences of a rupture. RMVs installed in accordance with this
section must meet all other RMV requirements in part 192.
    PHMSA is also requiring that risk analyses and assessments
conducted under this section be reviewed by the operator and certified
by a senior executive of the company. Review and certification must
occur at least once per calendar year, with the period between reviews
not to exceed a period of 15 months, and must also occur within 3
months of an incident or a safety-related condition. Such analyses and
assessments must consider new or existing operational and integrity
matters that could affect rupture-mitigation processes and procedures.

V. Section-by-Section Analysis for Changes to 49 CFR Part 195 for
Hazardous Liquid Pipelines

Sec.  195.2 Definitions

    Section 195.2 provides definitions for various terms used
throughout part 195. 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.
195.2 to define the ``notification of potential rupture'' in terms of
notification of, or observation by, an operator of indicia specified in
Sec.  195.417.
    Once an operator is notified of a potential rupture, they must
identify the 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. The final rule at Sec.  195.402 requires that
operators must document, in their operations manual, 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 technologies on certain pipeline
segments, including those that are ``entirely replaced onshore
hazardous liquid or carbon dioxide pipeline segments.'' RMVs are
defined in this rulemaking to mean ASVs or RCVs that a pipeline
operator uses to minimize the volume of hazardous liquid or carbon
dioxide released from the pipeline and to minimize the consequences of
a rupture. PHMSA has defined entirely replaced onshore hazardous liquid
or carbon dioxide 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.  195.11 What is a regulated rural gathering line and what
requirements apply?

    Section 195.11 contains the requirements for regulated rural
gathering pipelines carrying hazardous liquid or carbon dioxide. In
this final rule, PHMSA is specifying that the only regulated rural
gathering pipelines that are required to install RMVs or alternative
equivalent technologies are those pipelines subject to Sec.
195.260(e), which requires the installation of RMVs or alternative
equivalent technologies on pipelines that span water crossings more
than 100 feet wide, from high water mark to high water mark.

Sec.  195.18 How To Notify PHMSA

    In this final rule, operators can notify PHMSA in advance of their
intent to use a technology, compliance timeline, or method that differs
from that listed in the regulations, when that option is specifically
provided in the regulatory text. PHMSA retains discretion under Sec.
195.18 to reject, as appropriate, such requests. Accordingly, PHMSA has
revised this section to provide for a consistent notification procedure
across part 195 whenever an operator is required to notify PHMSA as a
part of a requirement of this final rule. This provision is similar to
the notification procedure created for part 192.

Sec.  195.258 Valves: General

    In this final rule, PHMSA is requiring the installation of RMVs or
alternative equivalent technologies on certain pipelines. This section
specifies that operators must install RMVs, or alternative equivalent
technologies, on onshore hazardous liquid or carbon dioxide pipeline
segments with diameters greater than or equal to 6 inches that are
constructed, or meet the definition of entirely replaced onshore
hazardous liquid or carbon dioxide 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 Sec.  195.260, and all alternative equivalent
technologies installed in accordance with this section must meet the
operational requirements of RMVs outlined in Sec.  195.419. These
installation requirements for entirely replaced onshore hazardous
liquid or carbon dioxide pipeline segments only apply to those pipeline
replacement projects that involve the addition, replacement, or removal
of an existing 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.  195.18. 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 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.  195.18, 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 required access rights and permits, and
component/labor availability).

Sec.  195.260 Valves: Location

    Section 195.260 finalizes requirements for the location of valves
on newly constructed and entirely replaced onshore hazardous liquid or
carbon dioxide pipelines, where such pipeline segments installed after
April 10, 2023, must have valve spacing that does not exceed 15 miles
for pipelines that could affect HCAs, as that term is defined in Sec.
195.450. For those pipelines that could not affect HCAs, the valve
spacing requirements for such pipelines cannot exceed 20 miles. An
operator installing valves that protect HCAs must install those valves
at locations determined through the operator's process for identifying
preventive and mitigative measures established pursuant to Sec.
195.452(i) and Appendix C, Section B of part 195. An operator may
submit for PHMSA review, in accordance with the notification procedures
in Sec.  195.18, a request for extension of the compliance deadline for
valve installation and spacing in this section. That notification must
demonstrate that the compliance timeline for valve spacing required by
this final rule would be economically, technically, or operationally
infeasible in connection with particular near-term construction and
replacement projects (e.g., 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).
    PHMSA has also revised the valve location requirements for those
pipelines that cross waterways that are more than 100 feet wide from
high water mark to high water mark. Accordingly, in this final rule,
operators must install valves at locations outside of the 100-year
flood plain or otherwise install valves that are equipped with control
equipment that would not be made inoperable by flood conditions.\49\
Additionally, the maximum spacing between valves protecting multiple

adjacent water crossings cannot exceed 1 mile.
---------------------------------------------------------------------------

    \49\ A 100-year flood plain is an area that has a 1-in-100
chance of having a flood event that could be equaled or exceeded in
any 1 year, and it has an average recurrence interval of 100 years.
100-year flood plains are determined by the Federal Emergency
Management Agency, which operates the official flood hazard Mapping
Service Center in support of the National flood insurance program,
and they offer flood zone maps online. If another agency, such as a
State authority, is responsible for determining the 100-year flood
plain for the area where the pipeline is located, the operator
should use those resources and documents.
---------------------------------------------------------------------------

    In this section, PHMSA has also finalized spacing requirements for
HVL pipelines in high-population areas or other populated areas, as
defined in Sec.  195.450. These pipelines must have a maximum valve
spacing of 7\1/2\ miles if they have been constructed or where 2 or
more miles of pipeline have been replaced within a span of 5 contiguous
miles within a 24-month period, following April 10, 2023. The maximum
valve spacing for HVL pipelines can be increased by 1.25 times the
distance to a maximum of a 9\3/8\-mile spacing if the operator submits
for PHMSA review, in accordance with Sec.  195.18, within its
notification (1) an evaluation of the safety of the alternative
spacing, 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; and (2) a demonstration that the installation of a valve at
the otherwise-required spacing is economically, technically or
operationally infeasible (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).
    Additionally, operators may notify PHMSA, using the procedure at
Sec.  195.18, if, in particular cases, the valve installation or valve
spacing requirements of certain paragraphs of this section are not
necessary to achieve an equivalent level of safety at a particular
site. That notification must include a supporting technical and 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.

Sec.  195.402 Procedural Manual for Operations, Maintenance, and
Emergencies

    In this final rule, PHMSA revised Sec.  195.402 to require that
emergency procedures provide for rupture mitigation in response to a
rupture event. PHMSA is also requiring that operators maintain liaison
with and contact the appropriate public safety answering point (i.e.,
9-1-1 emergency call center), if such a service is available, in the
event of pipeline emergencies. In lieu of communicating with individual
fire, police, or other public entities, operators may instead establish
liaison with appropriate local emergency coordinating agencies, such as
9-1-1 emergency call centers or county emergency managers, as
appropriate.
    PHMSA is requiring, through this final rule, that operators must
learn the responsibilities, resources, jurisdictional areas, and
emergency contact telephone numbers for each Federal, State, and local
government organization that may respond to a pipeline emergency
involving their pipeline facilities, and inform such officials of the
operator's ability to respond to and communicate during pipeline
emergencies. PHMSA has not changed the existing requirements for
operators to maintain liaison with fire, police, and other public
officials, as appropriate.
    In conjunction with the definition of a ``notification of potential
rupture,'' PHMSA has in this final rule codified at Sec.  195.402(e)(4)
language within the NPRM expressing its expectation that operators
will, upon notification of a potential rupture, identify whether there
is indeed a rupture by reference to written procedures. At a minimum,
the procedures must specify the sources of information, operational
factors, and other criteria that the operator will use to evaluate a
notification of a potential rupture as an actual rupture. Those written
procedures should also incorporate procedures for waiver of any
requirements for specific pipeline personnel to conduct on-scene
investigation of a potential rupture if an operator receives one or
more of the following: Multiple or recurring instrument indications
(pressure readings, alarms, etc.) of potential ruptures; pressure drops
significantly in excess of the minimum thresholds in Sec.
195.417(a)(1); or reports of rupture indicia from on-scene, credible
sources (e.g., on or off-duty pipeline operator personnel, sheriff or
police officers, fire department personnel, or other emergency response
personnel).
    Further, PHMSA has revised this section to define the elements that
an operator must incorporate when conducting a post-accident or -
failure analysis of ruptures and other accident and failure events
involving the activation of RMVs or alternative equivalent
technologies. PHMSA has not made changes, otherwise, to the existing
requirements in this section for operators of hazardous liquid and
carbon dioxide pipelines to establish procedures for analyzing
accidents and failures.
    The revision requires the operator to identify potential preventive
and mitigative measures that could be taken to reduce or limit the
release volume and damage from similar events in the future. The post-
incident review would include but not be limited to detection and
mitigation actions, response time, valve location, valve actuation, and
SCADA system performance. Upon completing the post-accident analysis,
the operator must 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. In accordance with this section, an operator must also
complete a summary of the post-incident review within 90 days of the
incident, and, while the investigation is pending, conduct quarterly
status reviews until the investigation is complete and a final post-
incident summary is prepared. The final post-incident summary and all
other reviews and analyses produced under the requirements of this
section must be reviewed, dated, and signed by the operator's
appropriate senior executive officer. Further, an operator must keep
the final post-incident summary, all investigation and analysis
documents used to prepare it, and records of lessons learned for the
useful life of the pipeline. The requirements to produce a summary
report are not applicable to gas distribution pipelines.
    PHMSA has also modified the failure and accident investigation
requirements at Sec.  195.402 to require operators subject to that
provision to incorporate lessons learned from those investigations into
their written procedures, including personnel training and
qualification programs, and design, construction, testing, maintenance,
operations, and emergency procedure manuals and specifications.

Sec.  195.417 Notification of Potential Rupture

    In this section, PHMSA provides the criteria for a ``notification
of potential rupture,'' as that term is defined in Sec.  195.2.

Sec.  195.418 Valves: Onshore Valve Shut-Off for Rupture Mitigation

    This section requires operators to install or use RMVs or
alternative equivalent technologies on many newly

constructed and entirely replaced onshore hazardous liquid or carbon
dioxide pipeline segments with diameters of 6 inches or greater. Such
valves would be required to be operational within 14 days of placing
the pipeline segment into service unless the operator has submitted for
PHMSA review, in accordance with the notification procedure at Sec.
195.18, a request for extension demonstrating that operation of that
RMV or alternative equivalent technology within that 14-day timeframe
is not economically, technically, or operationally feasible. The
requirements of this section apply to all applicable pipe replacement
projects, even those that do not otherwise directly involve the
addition or replacement of a valve.
    For the purposes of the RMV and alternative equivalent technology
installation requirements, PHMSA created a definition for a ``shut-off
segment,'' which is a pipeline segment that is entirely located between
at least two RMVs or alternative equivalent technologies. If any
crossover or lateral pipe for commodity receipts or deliveries connects
to the shut-off segment between the upstream-most and downstream-most
RMV or alternative equivalent technology, the shut-off segment also
extends to valves on those crossover connections or laterals, whether
those laterals are used for receipt or delivery, so that, when all
valves are closed, there is no flow path for commodity to be
transported from outside the shut-off segment to the rupture site.
Laterals that connect to shut-off segments and that contribute less
than 5 percent of the total shut-off segment volume may have RMVs or
alternative equivalent technologies installed at locations other than
mainline receipt or delivery points. A shut-off segment can include
multiple HCAs, and operators are not required to select the closest
valve to the shut-off segment as an RMV or alternative equivalent
technology as long as the proper valve spacing is maintained.
    This section also establishes valve spacing for RMVs or alternative
equivalent technology installed in accordance with this section, where
the distance between such RMVs and alternative equivalent technologies
must not exceed 15 miles for lines carrying non-HVLs, and 7\1/2\ miles
for lines carrying HVLs. The maximum valve spacing intervals for RMVs
and alternative equivalent technologies on pipelines carrying HVLs may
be increased by 1.25 times the spacing distance to a maximum of 9\3/8\
miles, subject to review by PHMSA of an operator's request
demonstrating that installation of a valve at a 7-mile to a 7\1/2\-mile
spacing is economically, technically, or operationally infeasible.
    Operators using a manual valve as an alternative equivalent
technology in lieu of an RMV for the purposes of this section must
appropriately designate and locate personnel near the valve to ensure
valve shut-off in accordance with this section and the RMV performance
requirements in Sec.  195.419.

Sec.  195.419 Valve Capabilities

    In this section, PHMSA establishes the operational requirements for
RMVs and alternative equivalent technologies installed pursuant to this
final rule. Following a ``notification of potential rupture,'' an
operator must identify whether a rupture is occurring on their system
and close RMVs and alternative equivalent technologies as soon as
practicable, but no later than within 30 minutes of rupture
identification, or, if applicable, no later than the shut-down times
used in calculating a worst-case discharge in accordance with Sec.
194.105(b)(1), whichever shut-off time is a shorter time interval.
    RMVs and alternative equivalent technologies must be capable of
being monitored or controlled by remote or on-site personnel, operated
during all operating conditions, and monitored for valve status.
Operators using ASVs as RMVs do not need to monitor those valves
remotely if the operator has the capability to monitor pressures or
product flow rate on the pipeline in order to identify and locate a
rupture.
    Operators of pipelines in non-HCAs or of segments that could not
affect an HCA may submit for PHMSA review, within a notification under
Sec.  195.18 requesting installation of manual valves as an alternative
equivalent technology, an exemption from the valve operation
requirements of Sec.  195.419(b). An operator seeking such an exemption
must provide for PHMSA review within that notification the closing
times for those manual valves.

Sec.  195.420 Valve Maintenance

    In this final rule, PHMSA is revising Sec.  195.420 to incorporate
the maintenance, inspection, and operator drills required to ensure
operators can close an RMV or alternative equivalent technology
installed under this final rule as soon as practicable, but within 30
minutes following rupture identification or within their shut-down
times used in calculating the worst-case discharge in accordance with
Sec.  194.105(b)(1), whichever is a shorter time interval. PHMSA is
finalizing initial validation drill requirements and requirements for
periodic confirmation drills for any manually or locally operated valve
used as an alternative equivalent technology in lieu of an RMV.
Operators are not required to close the valves fully during such
drills; a closure of 25 percent, at a minimum, is sufficient to be
compliant. If the 30-minute-maximum closure time cannot be achieved
during the drill, or shorter time pursuant to its part 194 worst-case
discharge calculations, the operator must revise their response efforts
and repair any valves to achieve compliance as soon as practicable but
no later than 12 months after the drill. Operators may request,
pursuant to the notification procedure at Sec.  195.18, an extension of
the 12-month repair timeline if such repair within 12 months would 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). Alternative valve shut-off measures must be in place
within 7 days of a failed drill. For each RCV installed under
Sec. Sec.  195.258(c) or 195.418, the operator must conduct a point-to-
point verification between SCADA displays, the installed valves,
sensors, and communications equipment in accordance with Sec.
195.446(c) and (e), or perform an equivalent verification.
    Per this final rule, operators are required to identify corrective
actions and lessons learned resulting from the validation and
confirmation drills and share and implement them across its entire
network of pipeline systems.

Sec.  195.452 Pipeline Integrity Management in High Consequence Areas

    In this final rule, PHMSA is revising Sec.  195.452(i)(4) to
clarify the requirements for conducting emergency flow restricting
device evaluations for HCAs, particularly when an operator installs
such valves as preventive and mitigative measures to improve response
times for, and mitigate the consequences of, pipeline ruptures.
Emergency flow restriction devices that are installed in accordance
with this section must meet all RMV requirements in part 195.
    PHMSA is also requiring that risk analyses and assessments
conducted under this section be completed prior to placing into service
all onshore pipelines with diameters of 6 inches or greater and that
are constructed or that have had 2 or more miles of pipeline replaced
within 5 contiguous miles within a 24-month period after April 10,
2023. The implementation of emergency

flow restricting device findings for any RMVs installed must meet Sec.
195.418.

VI. Regulatory Analyses and Notices

A. Statutory/Legal Authority for This Rulemaking

    This final rule is published pursuant to the authority granted to
the Secretary of Transportation by the Federal Pipeline Safety Statutes
(49 U.S.C. 60101 et seq.). Section 60102(a) authorizes issuance of
regulations governing design, installation, inspection, emergency plans
and procedures, testing, construction, extension, operation,
replacement, and maintenance of pipeline facilities. The final rule
also implements a statutory mandate at 49 U.S.C. 60102(n) requiring the
Secretary to issue regulations requiring the installation of RMVs or
equivalent technology on new and entirely replaced transmission lines.
See also 49 U.S.C. 5103 (regulatory authority to prescribe regulations
for transportation of hazardous materials), and 30 U.S.C. 185(w)(3))
(authority to prescribe reporting requirements for pipelines traversing
Federal lands). The Secretary delegated these authorities to the PHMSA
Administrator in 49 CFR 1.97.

B. Executive Order 12866 and DOT Regulatory Policies and Procedures

    Executive Order 12866 (``Regulatory Planning and Review'') \50\
requires that ``agencies should assess all costs and benefits of
available regulatory alternatives, including the alternative of not
regulating. Agencies should consider quantifiable measures and
qualitative measures of costs and benefits that are difficult to
quantify.'' Further, Executive Order 12866 requires that ``agencies
should maximize net benefits (including potential economic,
environmental, public health and safety, and other advantages;
distributive impacts; and equity), unless a statute requires another
regulatory approach.'' Similarly, DOT Order 2100.6A (``Rulemaking and
Guidance Procedures'') requires that regulations issued by PHMSA and
other DOT Operating Administrations should consider an assessment of
the potential benefits, costs, and other important impacts of the
proposed action and should quantify (to the extent practicable) the
benefits, costs, and any significant distributional impacts, including
any environmental impacts.
---------------------------------------------------------------------------

    \50\ 58 FR 51735 (Oct. 4, 1993).
---------------------------------------------------------------------------

    This action has been determined to be significant under Executive
Order 12866. The final rule has been reviewed by the Office of
Management and Budget (OMB) in accordance with Executive Order 12866
and is consistent with the requirements of Executive Order 12866, 49
U.S.C. 60102(b)(5), and DOT Order 2100.6A. The Office of Information
and Regulatory Affairs (OIRA) has not designated this rule as a ``major
rule'' as defined by the Congressional Review Act (5 U.S.C. 801 et
seq.).
    Executive Order 12866 and DOT Order 2100.6A also require PHMSA to
provide a meaningful opportunity for public participation, which also
reinforces requirements for notice and comment under the Administrative
Procedure Act (5 U.S.C. 551 et seq.). Therefore, in the NPRM, PHMSA
sought public comment on its proposed revisions to the Federal Pipeline
Safety Regulations and the preliminary cost and benefit analyses in the
Preliminary RIA, as well as any information that could assist in
quantifying the costs and benefits of this rulemaking. Those comments
are addressed in this final rule, and additional discussion about the
costs and benefits of the final rule are provided within the RIA posted
in the rulemaking docket.
    The table below summarizes the annualized costs for the provisions
in the final rule at a 3 percent and a 7 percent discount rate:

               Table 1--Annualized Costs of the Final Rule
                            [Millions 2019$]
------------------------------------------------------------------------
                                                        7%         3%
                    System type                      Discount   Discount
                                                       rate       rate
------------------------------------------------------------------------
Natural gas.......................................       $2.5       $1.0
Hazardous liquid..................................        3.4        1.5
                                                   ---------------------
  Total...........................................        5.9        2.5
------------------------------------------------------------------------

    The benefits of the final rule consist of improved safety and
avoided unquantified environmental harms (including, but not limited
to, unquantified greenhouse gas emissions) from prompt identification,
isolation, and mitigation actions with respect to unintentional or
uncontrolled, large-volume releases of natural gas or hazardous liquids
during a pipeline rupture. Benefits of the final rule will depend on
the degree to which compliance actions result in additional safety
measures, relative to the baseline, and the effectiveness of these
measures in preventing or mitigating future pipeline releases or other
incidents.

C. Executive Order 13132: Federalism

    PHMSA analyzed this final rule in accordance with Executive Order
13132 (``Federalism'').\51\ Executive Order 13132 requires agencies to
assure meaningful and timely input by State and local officials in the
development of regulatory policies that may have ``substantial direct
effects on the States, on the relationship between the national
government and the States, or on the distribution of power and
responsibilities among the various levels of government.''
---------------------------------------------------------------------------

    \51\ 64 FR 43255 (Aug. 10, 1999).
---------------------------------------------------------------------------

    The final rule does not have a substantial direct effect on the
State and local governments, the relationship between the Federal
government and the States, or the distribution of power and
responsibilities among the various levels of government. This
rulemaking action does not impose substantial direct compliance costs
on State and local governments. Section 60104(c) of Title 49 of the
United States Code prohibits certain State safety regulation of
interstate pipelines. States can augment pipeline safety requirements
for intrastate pipelines regulated by PHMSA, but may not approve safety
requirements less stringent than those required by Federal law. A State
may also regulate an intrastate pipeline facility that PHMSA does not
regulate. The preemptive effect of this final rule is limited to the
minimum level necessary to achieve the objectives of the statutory
authorities under which the final rule is promulgated. Therefore, the
consultation and funding requirements of Executive Order 13132 do not
apply.

D. Regulatory Flexibility Act

    The Regulatory Flexibility Act (5 U.S.C. 601 et seq.) requires
agencies to prepare a Final Regulatory Flexibility Analysis (FRFA) for
any final rule subject to notice-and-comment rulemaking under the
Administrative Procedure Act unless the agency head certifies that the
rule will not have a significant economic impact on a substantial
number of small entities. This final rule was developed in accordance
with Executive Order 13272 (``Proper Consideration of Small Entities in
Agency Rulemaking'') \52\ to promote compliance with the Regulatory
Flexibility Act and to ensure that the potential impacts of the
rulemaking on small entities has been properly considered.
---------------------------------------------------------------------------

    \52\ 67 FR 53461 (Aug. 16, 2002).
---------------------------------------------------------------------------

    PHMSA prepared a FRFA, which is available in the docket for the
rulemaking. In it, PHMSA certifies that the rule will not have a
significant impact on a substantial number of small entities.

E. National Environmental Policy Act

    The National Environmental Policy Act (42 U.S.C. 4321 et seq.;
NEPA) requires Federal agencies to consider the consequences of major
Federal actions and prepare a detailed statement on actions
significantly affecting the quality of the human environment. The
Council on Environmental Quality implementing regulations (40 CFR parts
1500-1508) require Federal agencies to conduct an environmental review
considering (1) the need for the action, (2) alternatives to the
action, (3) probable environmental impacts of the action and
alternatives, and (4) the agencies and persons consulted during the
consideration process. DOT Order 5610.1C (``Procedures for Considering
Environmental Impacts'') establishes departmental procedures for
evaluation of environmental impacts under NEPA and its implementing
regulations.
    PHMSA has completed its NEPA analysis. Based on the final
Environmental Assessment (EA), PHMSA determined that an environmental
impact statement is not required for this rulemaking because it will
not have a significant impact on the human environment. The final EA
and Finding of No Significant Impact have been placed into the docket
and address comments received on an earlier draft EA.

F. Executive Order 13175: Consultation and Coordination With Indian
Tribal Governments

    PHMSA analyzed this final rule per the principles and criteria in
Executive Order 13175 (``Consultation and Coordination With Indian
Tribal Governments'') \53\ and DOT Order 5301.1 (``Department of
Transportation Policies, Programs, and Procedures Affecting American
Indians, Alaska Natives, and Tribes''). Executive Order 13175 requires
agencies to assure meaningful and timely input from Tribal Government
representatives in the development of rules that significantly or
uniquely affect Tribal communities by imposing ``substantial direct
compliance costs'' or ``substantial direct effects'' on such
communities or the relationship and distribution of power between the
Federal Government and Tribes.
---------------------------------------------------------------------------

    \53\ 65 FR 67249 (Nov. 6, 2000).
---------------------------------------------------------------------------

    PHMSA assessed the impact of the rulemaking and determined that it
would not significantly or uniquely affect Tribal communities or Tribal
governments. The rulemaking's regulatory amendments are facially
neutral and would have broad, national scope; PHMSA, therefore, does
not expect this rulemaking to significantly or uniquely affect Tribal
communities, much less impose substantial compliance costs on Native
American Tribal governments or mandate Tribal action. And insofar as
PHMSA expects the rulemaking will improve pipeline safety and reduce
environmental risks, PHMSA does not expect it would entail
disproportionately high adverse risks for Tribal communities. PHMSA
also received no comments alleging ``substantial direct compliance
costs'' or ``substantial direct effects'' on Tribal communities and
Governments. For these reasons, PHMSA has determined the funding and
consultation requirements of Executive Order 13175 and DOT Order 5301.1
do not apply.

G. Executive Order 13211

    Executive Order 13211 (``Actions Concerning Regulations That
Significantly Affect Energy Supply, Distribution, or Use'') \54\
requires Federal agencies to prepare a Statement of Energy Effects for
any ``significant energy action.'' Executive Order 13211 defines a
``significant energy action'' as any action by an agency (normally
published in the Federal Register) that promulgates, or is expected to
lead to the promulgation of, a final rule or regulation that (1) (i) is
a significant regulatory action under Executive Order 12866 or any
successor order and (ii) is likely to have a significant adverse effect
on the supply, distribution, or use of energy (including a shortfall in
supply, price increases, and increased use of foreign supplies); or (2)
is designated by the Administrator of the OIRA as a significant energy
action.
---------------------------------------------------------------------------

    \54\ 66 FR 28355 (May 18, 2001).
---------------------------------------------------------------------------

    This final rule is a significant action under Executive Order
12866; however, it is expected to have an annual effect on the economy
of less than $100 million. Further, this action is not likely to have a
significant adverse effect on the supply, distribution, or use of
energy in the United States. The Administrator of OIRA has not
designated the final rule as a significant energy action. For
additional discussion of the anticipated economic impact of this
rulemaking, please review the RIA posted in the rulemaking docket.

H. Paperwork Reduction Act

    Under the Paperwork Reduction Act of 1995 (44 U.S.C. 3501 et seq.),
no person is required to respond to an information collection unless it
has been approved by OMB and displays a valid OMB control number.
Pursuant to implementing regulations at 5 CFR 1320.8(d), PHMSA is
required to provide interested members of the public and affected
agencies with an opportunity to comment on information collection and
recordkeeping requests.
    PHMSA published an NPRM seeking public comment on its proposed
revisions to the Federal Pipeline Safety Regulations finalized in this
rulemaking. Based on comments received and the updated provisions
contained within this final rule, PHMSA is expanding the notification
and recordkeeping requirements for gas and hazardous liquid pipeline
operators. The provisions in this final rule include the following
Paperwork Reduction Act impacts:
    Operators are required to document certain procedures and to
maintain records pertaining to various aspects of their RMV and
alternative equivalent technology operations. Operators who have
experienced a rupture or RMV shut-off are required to complete a post-
incident or -accident analysis. The summary of this analysis, all
documents used to prepare it, and records of lessons learned must be
kept for the useful life of the pipeline.
    Operators must also develop written rupture identification
procedures to evaluate and identify whether a notification of potential
rupture is an actual rupture event or non-rupture event. These
procedures must, at a minimum, specify the sources of information,
operational factors, and other criteria that operator personnel use to
evaluate a notification of potential rupture.
    The final rule (at 49 CFR 192.179 and 49 CFR 195.258) requires
operators who elect to use alternative equivalent technology to notify
PHMSA's Office of Pipeline Safety at least 90 days in advance of use.
An operator choosing this option must submit a technical and safety
evaluation (including design, construction, and operating procedures)
for the alternative equivalent technology to the Associate
Administrator of Pipeline Safety with the notification. PHMSA would
then have 90 days to object to the alternative equivalent technology
via letter from the Associate Administrator of Pipeline Safety;
otherwise, the alternative equivalent technology would be acceptable
for use. Operators who wish to use a manual valve as an alternative
equivalent technology will also be required to include within their
notification to PHMSA an explanation that installation of an RMV would
be economically, technically, or operationally infeasible.
    An operator may seek PHMSA's approval for an exemption from several
other regulatory installation and

operational requirements under the final rule by notifying PHMSA in
certain instances. For example, an operator of a gas pipeline may plan
to leave an RMV open for more than 30 minutes following rupture
identification if the operator demonstrates to PHMSA, in accordance
with the notification procedures in Sec.  192.18, that closing an RMV,
or alternative equivalent technology would be detrimental to public
safety. Likewise, for hazardous liquid pipeline segments not in an HCA
and which could not affect an HCA, an operator may request exemption
from specified requirements if it can demonstrate to PHMSA, in
accordance with the notification procedures in Sec.  195.18, that
installing an otherwise-required RMV, or alternative equivalent
technology, would be economically, technically, or operationally
infeasible. Similarly, the maximum valve spacing for HVL pipelines can
be increased by 1.25 times the distance to a maximum of 9 \3/8\ miles
if the operator submits a notification for PHMSA review demonstrating
that the installation of a valve at the otherwise-required spacing is
economically, technically, or operationally infeasible. Lastly, the
final rule also identifies procedures for operators of gas and
hazardous liquid lines to submit for PHMSA review a notification
requesting extension of required timelines (e.g., for RMV or
alternative equivalent technology installation, RMV operability post-
installation) specified in the final rule.
    PHMSA proposes to create an information collection under OMB
Control Number 2137-0637 titled, ``Rupture Mitigation Valve
Recordkeeping Requirements'' to account for the expanded recordkeeping
requirements in this final rule. PHMSA also proposes to create an
information collection under OMB Control Number 2137-0638 titled,
``Rupture Mitigation Valve Notification Requirements'' to account for
the expanded notification requirements in this final rule.
    PHMSA will request approval of these information collections from
the Office of Management and Budget (OMB) based on the requirements
that trigger components of the Paperwork Reduction Act and will notify
the public through a separate notice published in the Federal Register
upon OMB approval of the information collection requirements.
    The following information is provided for each of these information
collections: (1) Title of the information collection; (2) OMB control
number; (3) current expiration date; (4) type of request; (5) abstract
of the information collection activity; (6) description of affected
public; (7) estimate of total annual reporting and recordkeeping
burden; and (8) frequency of collection. The information collection
burdens are estimated as follows:
    1. Title: ``Rupture Mitigation Valve Recordkeeping Requirements.''
    OMB Control Number: 2137-0637.
    Current Expiration Date: To be determined by OMB.
    Abstract: The ``Amendments to parts 192 and 195 to Require Valve
Installation and Minimum Rupture Detection Standards Final Rule''
requires operators of gas and hazardous liquid pipelines to document
certain procedures and to maintain records pertaining to various
aspects of their RMV and alternative equivalent technology operations.
Operators who have experienced a rupture or RMV valve shut-off are
required to complete a post-incident review. The post-incident summary,
all investigation and analysis documents used to prepare it, and
records of lessons learned must be kept for the life of the pipeline.
PHMSA estimates that it will take operators, on average, 40 hours to
comply with this requirement.
    Operators must also develop written rupture identification
procedures to evaluate and identify whether a notification of potential
rupture is an actual rupture event or non-rupture event as soon as
practicable. These procedures must, at a minimum, specify the sources
of information, operational factors, and other criteria that operator
personnel use to evaluate a notification of potential rupture. PHMSA
estimates that it will take operators 40 hours to comply with this
requirement. Operators are also required to maintain certain records if
they experience certain circumstances involving their RMV operations.
On average, PHMSA expects that it will take operators 8 hours to
complete these recordkeeping requirements.
    PHMSA estimates that 1,812 operators (1,304 natural gas and 508
hazardous liquid operators) will be potentially impacted by these
requirements. At minimum, all 1,812 operators will be required to
develop written rupture identification procedures. PHMSA estimates 46
of these operators will experience a rupture that will require the
completion of a post-incident or -accident summary. PHMSA expects that
10 percent of the affected community will be subject to the various
other recordkeeping requirements. As a result, PHMSA expects this
information collection to result in 4,213 responses and 85,724 burden
hours annually.
    Affected Public: Operators of PHMSA-Regulated Pipelines.
    Annual Reporting and Recordkeeping Burden:
    Total Annual Responses: 4,213.
    Total Annual Burden Hours: 85,724.
    Frequency of Collection: On occasion.
    2. Title: ``Rupture Mitigation Valve Notification Requirements.''
    OMB Control Number: 2137-0638.
    Current Expiration Date: To be determined by OMB.
    Abstract: The ``Amendments to Parts 192 and 195 to Require Valve
Installation and Minimum Rupture Detection Standards Final Rule''
requires operators to notify PHMSA in certain instances regarding
installation and operation of RMVs and alternative equivalent
technologies. 49 CFR 192.179 and 195.258 require operators who elect to
use alternative equivalent technology to notify the Office of Pipeline
Safety at least 90 days in advance of use. An operator choosing this
option must include a technical and safety evaluation, including
design, construction, and operating procedures for the alternative
equivalent technology with the notification. Operators who wish to use
a manual valve as an alternative equivalent technology will also be
required to include within their notification to PHMSA an explanation
that installation of an RMV would be economically, technically, or
operationally infeasible. PHMSA expects most operators to use standard
technology and, as such, estimates this notification requirement will
result in approximately four responses annually. PHMSA estimates each
operator will spend 40 hours annually compiling the necessary
components of this notification requirement.
    Operators must notify PHMSA if an RMV cannot be made operational
within 14 days of installation. Operators must also notify PHMSA if a
valve cannot be repaired or replaced within 12 months. PHMSA expects
roughly 10 percent of operators to experience these circumstances
taking 2 hours to complete the notification requirement.
    An operator may seek exemption from certain regulatory requirements
by notifying PHMSA in certain instances. For example, an operator may
plan to leave an RMV open for more than 30 minutes following rupture
identification if the operator demonstrates to PHMSA, that closing an
RMV, or alternative equivalent technology, would be detrimental to
public safety.
    Likewise, for hazardous liquid pipeline segments not in an HCA
which could not affect an HCA, an operator may request exemption from
certain requirements if it can demonstrate to

PHMSA that installing an otherwise-required RMV, or alternative
equivalent technology, would be economically, technically, or
operationally infeasible. PHMSA expects 10 percent of operators to make
each of these and other notifications annually. PHMSA estimates that it
will take operators, on average, 8 hours to make these notifications.
    Affected Public: Operators of PHMSA-Regulated Pipelines.
    Annual Reporting and Recordkeeping Burden:
    Total Annual Responses: 598.
    Total Annual Burden Hours: 2,378.
    Frequency of Collection: On occasion.
    Questions regarding these information collections should be
directed to Angela Hill, Office of Pipeline Safety (PHP-30), Pipeline
and Hazardous Materials Safety Administration, 2nd Floor, 1200 New
Jersey Avenue SE, Washington, DC 20590-0001. Telephone:<PHONE_NUMBER>.

I. Unfunded Mandates Reform Act of 1995

    The Unfunded Mandates Reform Act of 1995 (2 U.S.C. 1501 et seq.)
requires agencies to assess the effects of Federal regulatory actions
on State, local, and Tribal governments, and the private sector. For
any NPRM or final rule that includes a Federal mandate that may result
in the expenditure by State, local, and Tribal governments, in the
aggregate, or by the private sector of $100 million or more (adjusted
annually for inflation) in any given year, the agency must prepare,
among other things, a written statement that qualitatively and
quantitatively assesses the costs and benefits of the Federal mandate.
    As explained in the RIA, PHMSA determined that this final rule does
not impose enforceable duties on State, local, or Tribal governments or
on the private sector of $100 million or more (adjusted annually for
inflation) in any one year. A copy of the RIA is available for review
in the docket. Therefore, the Department has determined that no
assessment is required pursuant to UMRA.

J. Privacy Act Statement

    Anyone may search the electronic form of all comments received for
any of our dockets. You may review DOT's complete Privacy Act Statement
\55\ at http://www.dot.gov/privacy.
---------------------------------------------------------------------------

    \55\ 65 FR 19476 (Apr. 11, 2000).
---------------------------------------------------------------------------

K. Regulation Identifier Number

    A regulation identifier number (RIN) is assigned to each regulatory
action listed in the Unified Agenda of Federal Regulations. The
Regulatory Information Service Center publishes the Unified Agenda in
April and October of each year. The RIN number contained in the heading
of this document can be used to cross-reference this action with the
Unified Agenda.

L. Executive Order 13609 and International Trade Analysis

    Executive Order 13609 (``Promoting International Regulatory
Cooperation'') \56\ requires agencies consider whether the impacts
associated with significant variations between domestic and
international regulatory approaches are unnecessary or may impair the
ability of American business to export and compete internationally. In
meeting shared challenges involving health, safety, labor, security,
environmental, and other issues, international regulatory cooperation
can identify approaches that are at least as protective as those that
are or would be adopted in the absence of such cooperation.
International regulatory cooperation can also reduce, eliminate, or
prevent unnecessary differences in regulatory requirements.
---------------------------------------------------------------------------

    \56\ 77 FR 26413 (May 4, 2012).
---------------------------------------------------------------------------

    Similarly, the Trade Agreements Act of 1979 (Pub. L. 96-39), as
amended by the Uruguay Round Agreements Act (Pub. L. 103-465),
prohibits Federal agencies from establishing any standards or engaging
in related activities that create unnecessary obstacles to the foreign
commerce of the United States. For purposes of these requirements,
Federal agencies may participate in the establishment of international
standards, so long as the standards have a legitimate domestic
objective, such as providing for safety, and do not operate to exclude
imports that meet this objective. The statute also requires
consideration of international standards and, where appropriate, that
they be the basis for U.S. standards.
    PHMSA participates in the establishment of international standards
to protect the safety of the American public. PHMSA has assessed the
effects of the rulemaking and determined that it will not cause
unnecessary obstacles to foreign trade.

M. Environmental Justice

    DOT Order 5610.2(b) and Executive Orders 12898 (``Federal Actions
to Address Environmental Justice in Minority Populations and Low-Income
Populations''),\57\ 13985 (``Advancing Racial Equity and Support for
Underserved Communities Through the Federal Government''),\58\ 13990,
and 14008 require DOT operational administrations to achieve
environmental justice as part of their mission by identifying and
addressing, as appropriate, disproportionately high and adverse human
health or environmental effects, including interrelated social and
economic effects, of their programs, policies, and activities on
minority populations, low-income populations, and other underserved
disadvantaged communities.
---------------------------------------------------------------------------

    \57\ 59 FR 7629 (Feb. 16, 1994).
    \58\ 86 FR 7009 (Jan. 20, 2021).
---------------------------------------------------------------------------

    PHMSA has evaluated this final rule under DOT Order 5610.2(b) and
the Executive Orders listed above and determined it will not cause
disproportionately high and adverse human health and environmental
effects on minority populations, low-income populations, or other
underserved and disadvantaged communities. The rulemaking is facially
neutral and national in scope; it is neither directed toward a
particular population, region, or community, nor is it expected to
adversely impact any particular population, region, or community. And
insofar as PHMSA expects the rulemaking would reduce the safety and
environmental risks associated with affected natural gas and hazardous
liquid pipelines, many of which are sited in the vicinity of
environmental justice communities,\59\ PHMSA does not expect the
regulatory amendments introduced by this final rule would entail
disproportionately high adverse risks for minority populations, low-
income populations, or other underserved and other disadvantaged
communities in the vicinity of those pipelines. Lastly, as explained in
final EA, PHMSA expects that the regulatory amendments in this final
rule will yield GHG emissions reductions, thereby reducing the risks
posed by anthropogenic climate change to minority, low-income,
underserved, and other disadvantaged populations and communities.
---------------------------------------------------------------------------

    \59\ See Ryan Emmanuel, et al., ``Natural Gas Gathering and
Transmission Pipelines and Social Vulnerability in the United
States,'' 5:6 GeoHealth (June 2021), https://agupubs.onlinelibrary.wiley.com/toc/24711403/2021/5/6 (concluding
that natural gas gathering and transmission infrastructure is
disproportionately sited in socially-vulnerable communities).
---------------------------------------------------------------------------

List of Subjects

49 CFR Part 192

    Gas, Natural gas, Pipeline safety, Reporting and recordkeeping
requirements.

49 CFR Part 195

    Anhydrous ammonia, Carbon dioxide, Petroleum, Pipeline safety,
Reporting and recordkeeping requirements.

    In consideration of the foregoing, PHMSA amends 49 CFR parts 192
and 195 as follows:

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

0
1. The authority citation for part 192 continues to read as follows:

    Authority:  30 U.S.C. 185(w)(3), 49 U.S.C. 5103, 60101 et seq.,
and 49 CFR 1.97.

0
2. In Sec.  192.3, definitions for ``entirely replaced onshore
transmission pipeline segments'', ``notification of potential
rupture'', and ``rupture-mitigation valve'' are added in alphabetical
order to read as follows:

Sec.  192.3   Definitions.

* * * * *
    Entirely replaced onshore transmission pipeline segments means, for
the purposes of Sec. Sec.  192.179 and 192.634, where 2 or more miles,
in the aggregate, of onshore transmission pipeline have been replaced
within any 5 contiguous miles of pipeline within any 24-month period.
* * * * *
    Notification of potential rupture means the notification to, or
observation by, an operator of indicia identified in Sec.  192.635 of a
potential unintentional or uncontrolled release of a large volume of
gas from a pipeline.
* * * * *
    Rupture-mitigation valve (RMV) means an automatic shut-off valve
(ASV) or a remote-control valve (RCV) that a pipeline operator uses to
minimize the volume of gas released from the pipeline and to mitigate
the consequences of a rupture.
* * * * *

0
3. In Sec.  192.9, paragraphs (d)(1) and (e)(1)(i) are revised to read
as follows:

Sec.  192.9   What requirements apply to gathering lines?

* * * * *
    (d) * * *
    (1) If a line is new, replaced, relocated, or otherwise changed,
the design, installation, construction, initial inspection, and initial
testing must be in accordance with requirements of this part applicable
to transmission lines. Compliance with Sec. Sec.  192.67, 192.127,
192.179(e), 192.179(f), 192.205, 192.227(c), 192.285(e), 192.506,
192.634, and 192.636 is not required.
* * * * *
    (e) * * *
    (1) * * *
    (i) Except as provided in paragraph (h) of this section for pipe
and components made with composite materials, the design, installation,
construction, initial inspection, and initial testing of a new,
replaced, relocated, or otherwise changed Type C gathering line, must
be done in accordance with the requirements in subparts B though G and
J of this part applicable to transmission lines. Compliance with
Sec. Sec.  192.67, 192.127, 192.179(e), 192.179(f), 192.205,
192.227(c), 192.285(e), 192.506, 192.634, and 192.636 is not required;
* * * * *

0
4. In Sec.  192.18, paragraph (c) is revised to read as follows:

Sec.  192.18   How to notify PHMSA.

* * * * *
    (c) Unless otherwise specified, if an operator submits, pursuant to
Sec.  192.8, Sec.  192.9, Sec.  192.179, Sec.  192.506, Sec.  192.607,
Sec.  192.619, Sec.  192.624, Sec.  192.632, Sec.  192.634, Sec.
192.636, Sec.  192.710, Sec.  192.712, Sec.  192.745, Sec.  192.921, or
Sec.  192.937, a notification for use of a different integrity
assessment method, analytical method, sampling approach, or technique
(e.g., ``other technology'' or ``alternative equivalent technology'')
than otherwise prescribed in those sections, that notification must be
submitted to PHMSA for review at least 90 days in advance of using the
other method, approach, compliance timeline, or technique. An operator
may proceed to use the other method, approach, compliance timeline, or
technique 91 days after submitting the notification unless it receives
a letter from the Associate Administrator for Pipeline Safety informing
the operator that PHMSA objects to the proposal, or that PHMSA requires
additional time and/or more information to conduct its review.

0
5. In Sec.  192.179, paragraphs (e) through (h) are added to read as
follows:

Sec.  192.179   Transmission line valves.

* * * * *
    (e) For onshore transmission pipeline segments with diameters
greater than or equal to 6 inches that are constructed after April 10,
2023, the operator must install rupture-mitigation valves (RMV) or an
alternative equivalent technology whenever a valve must be installed to
meet the appropriate valve spacing requirements of this section. An
operator seeking to use alternative equivalent technology must notify
PHMSA in accordance with the procedures set forth in paragraph (g) of
this section. All RMVs and alternative equivalent technologies
installed pursuant to this paragraph must meet the requirements of
Sec. Sec.  192.634 and 192.636. Exempted from this paragraph's
installation requirements are pipeline segments in Class 1, or Class 2
locations that have a potential impact radius (PIR), as defined in
Sec.  192.903, of 150 feet or less. An operator may request an
extension of the installation compliance deadline requirements of this
paragraph (e) if it can demonstrate to PHMSA, in accordance with the
notification procedures in Sec.  192.18, that those installation
compliance deadlines would be economically, technically, or
operationally infeasible for a particular new pipeline.
    (f) For entirely replaced onshore transmission pipeline segments,
as defined in Sec.  192.3, with diameters greater than or equal to 6
inches and that are installed after April 10, 2023, the operator must
install RMVs or an alternative equivalent technology whenever a valve
must be installed to meet the appropriate valve spacing requirements of
this section. An operator seeking to use alternative equivalent
technology must notify PHMSA in accordance with the procedures set
forth in paragraph (g) of this section. All RMVs and alternative
equivalent technologies installed pursuant to this paragraph must meet
the requirements of Sec. Sec.  192.634 and 192.636. The requirements of
this paragraph apply when the applicable pipeline replacement project
involves a valve, either through addition, replacement, or removal.
This paragraph's installation requirements do not apply to pipe
segments in Class 1 or Class 2 locations that have a PIR, as defined in
Sec.  192.903, that is less than or equal to 150 feet. An operator may
request an extension of the installation compliance deadline
requirements of this paragraph if it can demonstrate to PHMSA, in
accordance with the notification procedures in Sec.  192.18, that those
installation compliance deadlines would be economically, technically,
or operationally infeasible for a particular pipeline replacement
project.
    (g) If an operator elects to use alternative equivalent technology
in accordance with paragraph (e) or (f) of this section, the operator
must notify PHMSA in accordance with the procedures in Sec.  192.18.
The operator must include a technical and safety evaluation in its
notice to PHMSA. Valves that are installed as alternative equivalent
technology must comply with Sec. Sec.  192.634 and 192.636. An operator
requesting use of manual valves as an alternative equivalent

technology must also include within the notification submitted to PHMSA
a demonstration that installation of an RMV as otherwise required would
be economically, technically, or operationally infeasible. An operator
may use a manual compressor station valve at a continuously manned
station as an alternative equivalent technology, and use of such valve
would not require a notification to PHMSA in accordance with Sec.
192.18, but it must comply with Sec.  192.636.
    (h) The valve spacing requirements of paragraph (a) of this section
do not apply to pipe replacements on a pipeline if the distance between
each point on the pipeline and the nearest valve does not exceed:
    (1) Four (4) miles in Class 4 locations, with a total spacing
between valves no greater than 8 miles;
    (2) Seven-and-a-half (7\1/2\) miles in Class 3 locations, with a
total spacing between valves no greater than 15 miles; or
    (3) Ten (10) miles in Class 1 or 2 locations, with a total spacing
between valves no greater than 20 miles.

0
6. Section 192.610 is added to read as follows:

Sec.  192.610   Change in class location: Change in valve spacing.

    (a) If a class location change on a transmission pipeline occurs
after October 5, 2022, and results in pipe replacement, of 2 or more
miles, in the aggregate, within any 5 contiguous miles within a 24-
month period, to meet the maximum allowable operating pressure (MAOP)
requirements in Sec.  192.611, Sec.  192.619, or Sec.  192.620, then
the requirements in Sec. Sec.  192.179, 192.634, and 192.636, as
applicable, apply to the new class location, and the operator must
install valves, including rupture-mitigation valves (RMV) or
alternative equivalent technologies, as necessary, to comply with those
sections. Such valves must be installed within 24 months of the class
location change in accordance with the timing requirement in Sec.
192.611(d) for compliance after a class location change.
    (b) If a class location change occurs after October 5, 2022, and
results in pipe replacement of less than 2 miles within 5 contiguous
miles during a 24-month period, to meet the MAOP requirements in Sec.
192.611, Sec.  192.619, or Sec.  192.620, then within 24 months of the
class location change, in accordance with Sec.  192.611(d), the
operator must either:
    (1) Comply with the valve spacing requirements of Sec.  192.179(a)
for the replaced pipeline segment; or
    (2) Install or use existing RMVs or alternative equivalent
technologies so that the entirety of the replaced pipeline segments are
between at least two RMVs or alternative equivalent technologies. The
distance between RMVs and alternative equivalent technologies for the
replaced segment must not exceed 20 miles. The RMVs and alternative
equivalent technologies must comply with the applicable requirements of
Sec.  192.636.
    (c) The provisions of paragraph (b) of this section do not apply to
pipeline replacements that amount to less than 1,000 feet within any
one contiguous mile during any 24-month period.

0
7. In Sec.  192.615, paragraphs (a)(2), (6), (8), and (11) are revised,
paragraph (a)(12) is added, and paragraph (c) introductory text is
revised to read as follows:

Sec.  192.615   Emergency plans.

    (a) * * *
    (2) Establishing and maintaining adequate means of communication
with the appropriate public safety answering point (i.e., 9-1-1
emergency call center), where direct access to a 9-1-1 emergency call
center is available from the location of the pipeline, and fire,
police, and other public officials. Operators may establish liaison
with the appropriate local emergency 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. An operator must determine the responsibilities, resources,
jurisdictional area(s), and emergency contact telephone number(s) for
both local and out-of-area calls of each Federal, State, and local
government organization that may respond to a pipeline emergency, and
inform such officials about the operator's ability to respond to a
pipeline emergency and the means of communication during emergencies.
* * * * *
    (6) Taking necessary actions, including but not limited to,
emergency shutdown, valve shut-off, or pressure reduction, in any
section of the operator's pipeline system, to minimize hazards of
released gas to life, property, or the environment.
* * * * *
    (8) Notifying the appropriate public safety answering point (i.e.,
9-1-1 emergency call center) where direct access to a 9-1-1 emergency
call center is available from the location of the pipeline, and fire,
police, and other public officials, of gas pipeline emergencies to
coordinate and share information to determine the location of the
emergency, including both planned responses and actual responses during
an emergency. The operator must immediately and directly notify the
appropriate public safety answering point or other coordinating agency
for the communities and jurisdictions in which the pipeline is located
after receiving a notification of potential rupture, as defined in
Sec.  192.3, to coordinate and share information to determine the
location of any release, regardless of whether the segment is subject
to the requirements of Sec.  192.179, Sec.  192.634, or Sec.  192.636.
* * * * *
    (11) Actions required to be taken by a controller during an
emergency in accordance with the operator's emergency plans and
requirements set forth in Sec. Sec.  192.631, 192.634, and 192.636.
    (12) Each operator must develop written rupture identification
procedures to evaluate and identify whether a notification of potential
rupture, as defined in Sec.  192.3, is an actual rupture event or a
non-rupture event. These procedures must, at a minimum, specify the
sources of information, operational factors, and other criteria that
operator personnel use to evaluate a notification of potential rupture
and identify an actual rupture. For operators installing valves in
accordance with Sec.  192.179(e), Sec.  192.179(f), or that are subject
to the requirements in Sec.  192.634, those procedures must provide for
rupture identification as soon as practicable.
* * * * *
    (c) Each operator must establish and maintain liaison with the
appropriate public safety answering point (i.e., 9-1-1 emergency call
center) where direct access to a 9-1-1 emergency call center is
available from the location of the pipeline, as well as fire, police,
and other public officials, to:
* * * * *

0
8. Section 192.617 is revised to read as follows:

Sec.  192.617   Investigation of failures and incidents.

    (a) Post-failure and incident procedures. Each operator must
establish and follow procedures for investigating and analyzing
failures and incidents as defined in Sec.  191.3, including sending the
failed pipe, component, or equipment for laboratory testing or
examination, where appropriate, for the purpose of determining the
causes and contributing factor(s) of the failure or incident and

minimizing the possibility of a recurrence.
    (b) Post-failure and incident lessons learned. Each operator must
develop, implement, and incorporate lessons learned from a post-failure
or incident review into its written procedures, including personnel
training and qualification programs, and design, construction, testing,
maintenance, operations, and emergency procedure manuals and
specifications.
    (c) Analysis of rupture and valve shut-offs. If an incident on an
onshore gas transmission pipeline or a Type A gathering pipeline
involves the closure of a rupture-mitigation valve (RMV), as defined in
Sec.  192.3, or the closure of alternative equivalent technology, the
operator of the pipeline must also conduct a post-incident analysis of
all of the factors that may have impacted the release volume and the
consequences of the incident and identify and implement operations and
maintenance measures to prevent or minimize the consequences of a
future incident. The requirements of this paragraph (c) are not
applicable to distribution pipelines or Types B and C gas gathering
pipelines. The analysis must include all relevant factors impacting the
release volume and consequences, including, but not limited to, the
following:
    (1) Detection, identification, operational response, system shut-
off, and emergency response communications, based on the type and
volume of the incident;
    (2) Appropriateness and effectiveness of procedures and pipeline
systems, including supervisory control and data acquisition (SCADA),
communications, valve shut-off, and operator personnel;
    (3) Actual response time from identifying a rupture following a
notification of potential rupture, as defined at Sec.  192.3, to
initiation of mitigative actions and isolation of the pipeline segment,
and the appropriateness and effectiveness of the mitigative actions
taken;
    (4) Location and timeliness of actuation of RMVs or alternative
equivalent technologies; and
    (5) All other factors the operator deems appropriate.
    (d) Rupture post-failure and incident summary. If a failure or
incident on an onshore gas transmission pipeline or a Type A gathering
pipeline involves the identification of a rupture following a
notification of potential rupture, or the closure of an RMV (as those
terms are defined in Sec.  192.3), or the closure of an alternative
equivalent technology, the operator of the pipeline must complete a
summary of the post-failure or incident review required by paragraph
(c) of this section within 90 days of the incident, and while the
investigation is pending, conduct quarterly status reviews until the
investigation is complete and a final post-incident summary is
prepared. The final post-failure or incident summary, and all other
reviews and analyses produced under the requirements of this section,
must be reviewed, dated, and signed by the operator's appropriate
senior executive officer. The final post-failure or incident summary,
all investigation and analysis documents used to prepare it, and
records of lessons learned must be kept for the useful life of the
pipeline. The requirements of this paragraph (d) are not applicable to
distribution pipelines or Types B and C gas gathering pipelines.

0
9. Section 192.634 is added to read as follows:

Sec.  192.634   Transmission lines: Onshore valve shut-off for rupture
mitigation.

    (a) Applicability. For new or entirely replaced onshore
transmission pipeline segments with diameters of 6 inches or greater
that are located in high-consequence areas (HCA) or Class 3 or Class 4
locations and that are installed after April 10, 2023, an operator must
install or use existing rupture-mitigation valves (RMV), or an
alternative equivalent technology, according to the requirements of
this section and Sec. Sec.  192.179 and 192.636. RMVs and alternative
equivalent technologies must be operational within 14 days of placing
the new or replaced pipeline segment into service. An operator may
request an extension of this 14-day operation requirement if it can
demonstrate to PHMSA, in accordance with the notification procedures in
Sec.  192.18, that application of that requirement would be
economically, technically, or operationally infeasible. The
requirements of this section apply to all applicable pipe replacement
projects, even those that do not otherwise involve the addition or
replacement of a valve. This section does not apply to pipe segments in
Class 1 or Class 2 locations that have a potential impact radius (PIR),
as defined in Sec.  192.903, that is less than or equal to 150 feet.
    (b) Maximum spacing between valves. RMVs, or alternative equivalent
technology, must be installed in accordance with the following
requirements:
    (1) Shut-off segment. For purposes of this section, a ``shut-off
segment'' means the segment of pipe located between the upstream valve
closest to the upstream endpoint of the new or replaced Class 3 or
Class 4 or HCA pipeline segment and the downstream valve closest to the
downstream endpoint of the new or replaced Class 3 or Class 4 or HCA
pipeline segment so that the entirety of the segment that is within the
HCA or the Class 3 or Class 4 location is between at least two RMVs or
alternative equivalent technologies. If any crossover or lateral pipe
for gas receipts or deliveries connects to the shut-off segment between
the upstream and downstream valves, the shut-off segment also must
extend to a valve on the crossover connection(s) or lateral(s), such
that, when all valves are closed, there is no flow path for gas to be
transported to the rupture site (except for residual gas already in the
shut-off segment). Multiple Class 3 or Class 4 locations or HCA
segments may be contained within a single shut-off segment. The
operator is not required to select the closest valve to the shut-off
segment as the RMV, as that term is defined in Sec.  192.3, or the
alternative equivalent technology. An operator may use a manual
compressor station valve at a continuously manned station as an
alternative equivalent technology, but it must be able to be closed
within 30 minutes following rupture identification, as that term is
defined at Sec.  192.3. Such a valve used as an alternative equivalent
technology would not require a notification to PHMSA in accordance with
Sec.  192.18.
    (2) Shut-off segment valve spacing. A pipeline subject to paragraph
(a) of this section must have RMVs or alternative equivalent technology
on the upstream and downstream side of the pipeline segment. The
distance between RMVs or alternative equivalent technologies must not
exceed:
    (i) Eight (8) miles for any Class 4 location,
    (ii) Fifteen (15) miles for any Class 3 location, or
    (iii) Twenty (20) miles for all other locations.
    (3) Laterals. Laterals extending from shut-off segments that
contribute less than 5 percent of the total shut-off segment volume may
have RMVs or alternative equivalent technologies that meet the
actuation requirements of this section at locations other than mainline
receipt/delivery points, as long as all of the laterals contributing
gas volumes to the shut-off segment do not contribute more than 5
percent of the total shut-off segment gas volume based upon maximum
flow volume at the operating pressure. For laterals that are 12 inches
in diameter or less, a check valve that allows gas to flow freely in
one direction and contains a mechanism to automatically prevent flow in
the other direction may be used as an alternative equivalent technology
where it is

positioned to stop flow into the shut-off segment. Such check valves
that are used as an alternative equivalent technology in accordance
with this paragraph are not subject to Sec.  192.636, but they must be
inspected, operated, and remediated in accordance with Sec.  192.745,
including for closure and leakage to ensure operational reliability. An
operator using such a check valve as an alternative equivalent
technology must notify PHMSA in accordance with Sec. Sec.  192.18 and
192.179 develop and implement maintenance procedures for such equipment
that meet Sec.  192.745.
    (4) Crossovers. An operator may use a manual valve as an
alternative equivalent technology in lieu of an RMV for a crossover
connection if, during normal operations, the valve is closed to prevent
the flow of gas by the use of a locking device or other means designed
to prevent the opening of the valve by persons other than those
authorized by the operator. The operator must develop and implement
operating procedures and document that the valve has been closed and
locked in accordance with the operator's lock-out and tag-out
procedures to prevent the flow of gas. An operator using such a manual
valve as an alternative equivalent technology must notify PHMSA in
accordance with Sec. Sec.  192.18 and 192.179.
    (c) Manual operation upon identification of a rupture. Operators
using a manual valve as an alternative equivalent technology as
authorized pursuant to Sec. Sec.  192.18 and 192.179 must develop and
implement operating procedures that appropriately designate and locate
nearby personnel to ensure valve shut-off in accordance with this
section and Sec.  192.636. Manual operation of valves must include time
for the assembly of necessary operating personnel, the acquisition of
necessary tools and equipment, driving time under heavy traffic
conditions and at the posted speed limit, walking time to access the
valve, and time to shut off all valves manually, not to exceed the
maximum response time allowed under Sec.  192.636(b).

0
10. Section 192.635 is added to read as follows:

Sec.  192.635   Notification of potential rupture.

    (a) As used in this part, a ``notification of potential rupture''
refers to the notification of, or observation by, an operator (e.g., by
or to its controller(s) in a control room, field personnel, nearby
pipeline or utility personnel, the public, local responders, or public
authorities) of one or more of the below indicia of a potential
unintentional or uncontrolled release of a large volume of gas from a
pipeline:
    (1) An unanticipated or unexplained pressure loss outside of the
pipeline's normal operating pressures, as defined in the operator's
written procedures. The operator must establish in its written
procedures that an unanticipated or unplanned pressure loss is outside
of the pipeline's normal operating pressures when there is a pressure
loss greater than 10 percent occurring within a time interval of 15
minutes or less, unless the operator has documented in its written
procedures the operational need for a greater pressure-change threshold
due to pipeline flow dynamics (including changes in operating pressure,
flow rate, or volume), that are caused by fluctuations in gas demand,
gas receipts, or gas deliveries; or
    (2) An unanticipated or unexplained flow rate change, pressure
change, equipment function, or other pipeline instrumentation
indication at the upstream or downstream station that may be
representative of an event meeting paragraph (a)(1) of this section; or
    (3) Any unanticipated or unexplained rapid release of a large
volume of gas, a fire, or an explosion in the immediate vicinity of the
pipeline.
    (b) A notification of potential rupture occurs when an operator
first receives notice of or observes an event specified in paragraph
(a) of this section.

0
11. Section 192.636 is added to read as follows:

Sec.  192.636   Transmission lines: Response to a rupture; capabilities
of rupture-mitigation valves (RMVs) or alternative equivalent
technologies.

    (a) Scope. The requirements in this section apply to rupture-
mitigation valves (RMVs), as defined in Sec.  192.3, or alternative
equivalent technologies, installed pursuant to Sec. Sec.  192.179(e),
(f), and (g) and 192.634.
    (b) Rupture identification and valve shut-off time. An operator
must, as soon as practicable but within 30 minutes of rupture
identification (see Sec.  192.615(a)(12)), fully close any RMVs or
alternative equivalent technologies necessary to minimize the volume of
gas released from a pipeline and mitigate the consequences of a
rupture.
    (c) Open valves. An operator may leave an RMV or alternative
equivalent technology open for more than 30 minutes, as required by
paragraph (b) of this section, if the operator has previously
established in its operating procedures and demonstrated within a
notice submitted under Sec.  192.18 for PHMSA review, that closing the
RMV or alternative equivalent technology would be detrimental to public
safety. The request must have been coordinated with appropriate local
emergency responders, and the operator and emergency responders must
determine that it is safe to leave the valve open. Operators must have
written procedures for determining whether to leave an RMV or
alternative equivalent technology open, including plans to communicate
with local emergency responders and minimize environmental impacts,
which must be submitted as part of its notification to PHMSA.
    (d) Valve monitoring and operation capabilities. An RMV, as defined
in Sec.  192.3, or alternative equivalent technology, must be capable
of being monitored or controlled either remotely or by on-site
personnel as follows:
    (1) Operated during normal, abnormal, and emergency operating
conditions;
    (2) Monitored for valve status (i.e., open, closed, or partial
closed/open), upstream pressure, and downstream pressure. For automatic
shut-off valves (ASV), an operator does not need to monitor remotely a
valve's status if the operator has the capability to monitor pressures
or gas flow rate within each pipeline segment located between RMVs or
alternative equivalent technologies to identify and locate a rupture.
Pipeline segments that use manual valves or other alternative
equivalent technologies must have the capability to monitor pressures
or gas flow rates on the pipeline to identify and locate a rupture; and
    (3) Have a back-up power source to maintain SCADA systems or other
remote communications for remote-control valve (RCV) or automatic shut-
off valve (ASV) operational status, or be monitored and controlled by
on-site personnel.
    (e) Monitoring of valve shut-off response status. The position and
operational status of an RMV must be appropriately monitored through
electronic communication with remote instrumentation or other
equivalent means. An operator does not need to monitor remotely an
ASV's status if the operator has the capability to monitor pressures or
gas flow rate on the pipeline to identify and locate a rupture.
    (f) Flow modeling for automatic shut-off valves. Prior to using an
ASV as an RMV, an operator must conduct flow modeling for the shut-off
segment and any laterals that feed the shut-off segment, so that the
valve will close within 30 minutes or less following rupture
identification, consistent with the operator's procedures, and in
accordance with Sec.  192.3 and this section. The flow modeling must

include the anticipated maximum, normal, or any other flow volumes,
pressures, or other operating conditions that may be encountered during
the year, not exceeding 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 that could affect the ASV set pressures and the 30-
minute valve closure time after notification of potential rupture, as
defined at Sec.  192.3, 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 time/pressure chart for the segment containing the ASV if a rupture
occurs. An operator must conduct this flow modeling prior to making
flow condition changes in a manner that could render the 30-minute
valve closure time unachievable.
    (g) Manual valves in non-HCA, Class 1 locations. For pipeline
segments in a Class 1 location that do not meet the definition of a
high consequence area (HCA), an operator submitting a notification
pursuant to Sec. Sec.  192.18 and 192.179 for use of manual valves as
an alternative equivalent technology may also request an exemption from
the requirements of Sec.  192.636(b).

0
12. In Sec.  192.745, paragraphs (c) through (f) are added to read as
follows:

Sec.  192.745   Valve maintenance: Transmission lines.

* * * * *
    (c) For each remote-control valve (RCV) installed in accordance
with Sec.  192.179 or Sec.  192.634, an operator must conduct a point-
to-point verification between SCADA system displays and the installed
valves, sensors, and communications equipment, in accordance with Sec.
192.631(c) and (e).
    (d) For each alternative equivalent technology installed on an
onshore pipeline under Sec.  192.179(e) or (f) or Sec.  192.634 that is
manually or locally operated (i.e., not a rupture-mitigation valve
(RMV), as that term is defined in Sec.  192.3):
    (1) Operators must achieve a valve closure time of 30 minutes or
less, pursuant to Sec.  192.636(b), through an initial drill and
through periodic validation as required in paragraph (d)(2) of this
section. An operator must review and document the results of each phase
of the drill response to validate the total response time, including
confirming the rupture, and valve shut-off time as being less than or
equal to 30 minutes after rupture identification.
    (2) Within each pipeline system and within each operating or
maintenance field work unit, operators must randomly select a valve
serving as an alternative equivalent technology in lieu of an RMV for
an annual 30-minute-total response time validation drill that simulates
worst-case conditions for that location to ensure compliance with Sec.
192.636. Operators are not required to close the valve fully during the
drill; a minimum 25 percent valve closure is sufficient to demonstrate
compliance with drill requirements unless the operator has operational
information that requires an additional closure percentage for
maintaining reliability. The response drill must occur at least once
each calendar year, with intervals not to exceed 15 months. Operators
must include in their written procedures the method they use to
randomly select which alternative equivalent technology is tested in
accordance with this paragraph.
    (3) If the 30-minute-maximum response time cannot be achieved
during the drill, the operator must revise response efforts to achieve
compliance with Sec.  192.636 as soon as practicable but no later than
12 months after the drill. Alternative valve shut-off measures must be
in place in accordance with paragraph (e) of this section within 7 days
of a failed drill.
    (4) Based on the results of response-time drills, the operator must
include lessons learned in:
    (i) Training and qualifications programs;
    (ii) Design, construction, testing, maintenance, operating, and
emergency procedures manuals; and
    (iii) Any other areas identified by the operator as needing
improvement.
    (5) The requirements of this paragraph (d) do not apply to manual
valves who, pursuant to Sec.  192.636(g), have been exempted from the
requirements of Sec.  192.636(b).
    (e) Each operator must develop and implement remedial measures to
correct any valve installed on an onshore pipeline under Sec.
192.179(e) or (f) or Sec.  192.634 that is indicated to be inoperable
or unable to maintain effective shut-off as follows:
    (1) Repair or replace the valve as soon as practicable but no later
than 12 months after finding that the valve is inoperable or unable to
maintain effective shut-off. An operator must request an extension from
PHMSA in accordance with Sec.  192.18 if repair or replacement of a
valve within 12 months would be economically, technically, or
operationally infeasible; and
    (2) Designate an alternative valve acting as an RMV within 7
calendar days of the finding while repairs are being made and document
an interim response plan to maintain safety. Such valves are not
required to comply with the valve spacing requirements of this part.
    (f) An operator using an ASV as an RMV, in accordance with
Sec. Sec.  192.3, 192.179, 192.634, and 192.636, must document and
confirm the ASV shut-in pressures, in accordance with Sec.  192.636(f),
on a calendar year basis not to exceed 15 months. ASV shut-in set
pressures must be proven and reset individually at each ASV, as
required, on a calendar year basis not to exceed 15 months.

0
13. In Sec.  192.935, paragraph (c) is revised and paragraph (f) is
added to read as follows:

Sec.  192.935   What additional preventive and mitigative measures must
an operator take?

* * * * *
    (c) Risk analysis for gas releases and protection against ruptures.
If an operator determines, based on a risk analysis, that a rupture-
mitigation valve (RMV) or alternative equivalent technology would be an
efficient means of adding protection to a high-consequence area (HCA)
in the event of a gas release, an operator must install the RMV or
alternative equivalent technology. In making that determination, an
operator must, at least, evaluate the following factors--timing of leak
detection and pipe shutdown capabilities, the type of gas being
transported, operating pressure, the rate of potential release,
pipeline profile, the potential for ignition, and location of nearest
response personnel. An RMV or alternative equivalent technology
installed under this paragraph must meet all of the other applicable
requirements in this part.
* * * * *
    (f) Periodic evaluations. Risk analyses and assessments conducted
under paragraph (c) of this section must be reviewed by the operator
and certified by a senior executive of the company, for operational
matters that could affect rupture-mitigation processes and procedures.
Review and certification must occur once per calendar year, with the
period between reviews not to exceed 15 months, and must also occur
within 3 months of an incident or safety-related condition, as those
terms are defined at Sec. Sec.  191.3 and 191.23, respectively.

PART 195--TRANSPORTATION OF HAZARDOUS LIQUIDS BY PIPELINE

0
14. The authority citation for part 195 continues to read as follows:

    Authority: 30 U.S.C. 185(w)(3), 49 U.S.C. 5103, 60101 et. seq.,
and 49 CFR 1.97.

0
15. In Sec.  195.2, definitions for ``entirely replaced onshore
hazardous liquid or carbon dioxide line segments'', ``notification of
potential rupture'', and ``rupture-mitigation valve'' are added in
alphabetical order to read as follows:

Sec.  195.2   Definitions.

* * * * *
    Entirely replaced onshore hazardous liquid or carbon dioxide
pipeline segments, for the purposes of Sec. Sec.  195.258, 195.260, and
195.418, means where 2 or more miles of pipe, in the aggregate, have
been replaced within any 5 contiguous miles within any 24-month period.
* * * * *
    Notification of Potential Rupture means the notification to, or
observation by, an operator of indicia identified in Sec.  195.417 of a
potential unintentional or uncontrolled release of a large volume of
commodity from a pipeline.
* * * * *
    Rupture-mitigation valve (RMV) means an automatic shut-off valve
(ASV) or a remote-control valve (RCV) that a pipeline operator uses to
minimize the volume of hazardous liquid or carbon dioxide released from
the pipeline and to mitigate the consequences of a rupture.
* * * * *

0
16. In Sec.  195.11, paragraph (b)(2) is revised to read as follows:

Sec.  195.11   What is a regulated rural gathering line and what
requirements apply?

* * * * *
    (b) * * *
    (2) For steel pipelines contracted, replaced, relocated, or
otherwise changed after July 3, 2009:
    (i) Design, install, construct, initially inspect, and initially
test the pipeline in compliance with this part, unless the pipeline is
converted under Sec.  195.5.
    (ii) Except for pipelines subject to Sec.  195.260(e), such
pipelines are not subject to the rupture-mitigation valve (RMV) and
alternative equivalent technology requirements in Sec. Sec.  195.258(c)
and (d), 195.418, and 195.419.
* * * * *

0
17. Section 195.18 is added to read as follows:

Sec.  195.18   How to notify PHMSA.

    (a) An operator must provide any notification required by this part
by:
    (1) Sending the notification by electronic mail to
[email protected]; or
    (2) Sending the notification by mail to ATTN: Information Resources
Manager, DOT/PHMSA/OPS, East Building, 2nd Floor, E22-321, 1200 New
Jersey Ave. SE, Washington, DC 20590.
    (b) An operator must also notify the appropriate State or local
pipeline safety authority when an applicable pipeline segment is
located in a State where OPS has an interstate agent agreement, or an
intrastate pipeline segment is regulated by that State.
    (c) Unless otherwise specified, if an operator submits, pursuant to
Sec.  195.258, Sec.  195.260, Sec.  195.418, Sec.  195.419, Sec.
195.420 or Sec.  195.452 a notification requesting use of a different
integrity assessment method, analytical method, sampling approach,
compliance timeline, or technique (e.g., ``other technology'' or
``alternative equivalent technology'') than otherwise prescribed in
those sections, that notification must be submitted to PHMSA for review
at least 90 days in advance of using that other method, approach,
compliance timeline, or technique. An operator may proceed to use the
other method, approach, compliance timeline, or technique 91 days after
submittal of the notification unless it receives a letter from the
Associate Administrator of Pipeline Safety informing the operator that
PHMSA objects to the proposal, or that PHMSA requires additional time
and/or information to conduct its review.

0
18. In Sec.  195.258, paragraphs (c) through (e) are added to read as
follows:

Sec.  195.258   Valves: General.

* * * * *
    (c) For all onshore hazardous liquid or carbon dioxide pipeline
segments with diameters greater than or equal to 6 inches that are
constructed after April 10, 2023, the operator must install rupture-
mitigation valves (RMV) or an alternative equivalent technology
whenever a valve must be installed to meet the appropriate valve
spacing requirements of this section and Sec.  195.260. An operator
using alternative equivalent technology must notify PHMSA in accordance
with the procedure in paragraph (e) of this section. All RMVs and
alternative equivalent technology installed as required by this section
must meet the requirements of Sec.  195.419. An operator may request an
extension of the installation compliance deadline requirements of this
paragraph if it can demonstrate to PHMSA, in accordance with the
notification procedures in Sec.  195.18, that those installation
deadline requirements would be economically, technically, or
operationally infeasible for a particular new pipeline.
    (d) For all entirely replaced onshore hazardous liquid or carbon
dioxide pipeline segments with diameters greater than or equal to 6
inches that have been replaced after April 10, 2023, the operator must
install RMVs or an alternative equivalent technology whenever a valve
must be installed to meet the appropriate valve spacing requirements of
this section. An operator using alternative equivalent technology must
notify PHMSA in accordance with the procedure in paragraph (e) of this
section. All valves installed as required by this section must meet the
requirements of Sec.  195.419. The requirements of this paragraph (d)
apply when the applicable pipeline replacement project involves a
valve, either through addition, replacement, or removal. An operator
may request an extension of the installation compliance deadline
requirements of this paragraph if it can demonstrate to PHMSA, in
accordance with the notification procedures in Sec.  195.18, that those
installation deadline requirements would be economically, technically,
or operationally infeasible for a particular pipeline replacement
project.
    (e) If an operator elects to use alternative equivalent technology
in accordance with paragraph (c) or (d) of this section, the operator
must notify PHMSA in accordance with Sec.  195.18. The operator must
include a technical and safety evaluation in its notice to PHMSA.
Valves that are installed as alternative equivalent technology must
comply with Sec. Sec.  195.418, 195.419, and 195.420. An operator
requesting use of manual valves as an alternative equivalent technology
must also include within the notification submitted to PHMSA a
demonstration that installation of an RMV as otherwise required would
be economically, technically, or operationally infeasible. An operator
may use a manual compressor station valve at a continuously manned
station as an alternative equivalent technology. Such a valve used as
an alternative equivalent technology would not require a notification
to PHMSA in accordance with Sec.  195.18, but it must comply with
Sec. Sec.  195.419 and 195.420.

0
19. Section 195.260 is revised to read as follows:

Sec.  195.260   Valves: Location.

    A valve must be installed at each of the following locations:
    (a) On the suction end and the discharge end of a pump station in a
manner that permits isolation of the pump station equipment in the
event of an emergency.
    (b) On each pipeline entering or leaving a breakout storage tank
area in a manner that permits isolation of the tank from other
facilities.
    (c) On each pipeline at locations along the pipeline system that
will minimize or prevent safety risks, property damage, or
environmental harm from accidental hazardous liquid or carbon dioxide
discharges, as appropriate for onshore areas, offshore areas, and high-
consequence areas (HCA). For newly constructed or entirely replaced
onshore hazardous liquid or carbon dioxide pipeline segments, as that
term is defined at Sec.  195.2, that are installed after April 10,
2023, valve spacing must not exceed 15 miles for pipeline segments that
could affect or are in HCAs, as defined in Sec.  195.450, and 20 miles
for pipeline segments that could not affect HCAs. Valves on pipeline
segments that are located in HCAs or which could affect HCAs must be
installed at locations as determined by the operator's process for
identifying preventive and mitigative measures established pursuant to
Sec.  195.452(i) and by using the selection process in section I.B of
appendix C of part 195, but with a maximum distance that does not
exceed 7\1/2\ miles from the endpoints of the HCA segment or the
segment that could affect an HCA. An operator may request an exemption
from the compliance deadline requirements of this section for valve
installation at the specified valve spacing if it can demonstrate to
PHMSA, in accordance with the notification procedures in Sec.  195.18,
that those compliance deadline requirements would be economically,
technically, or operationally infeasible.
    (d) On each lateral takeoff from a pipeline in a manner that
permits shutting off the lateral without interrupting flow in the
pipeline.
    (e) On each side of one or more adjacent water crossings that are
more than 100 feet (30 meters) wide from high water mark to high water
mark, as follows:
    (1) Valves must be installed at locations outside of the 100-year
flood plain or be equipped with actuators or other control equipment
that is installed so as not to be impacted by flood conditions; and
    (2) The maximum spacing interval between valves that protect
multiple adjacent water crossings cannot exceed 1 mile in length.
    (f) On each side of a reservoir holding water for human
consumption.
    (g) On each highly volatile liquid (HVL) pipeline that is located
in a high-population area or other populated area, as defined in Sec.
195.450, and that is constructed, or where 2 or more miles of pipe have
been replaced within any 5 contiguous miles within any 24-month period,
after April 10, 2023, with a maximum valve spacing of 7\1/2\ miles. The
maximum valve spacing intervals may be increased by 1.25 times the
distance up to a 9 \3/8\-mile spacing, provided the operator:
    (1) Submits for PHMSA review a notification pursuant to Sec.
195.18 requesting alternative spacing because installation of a valve
at a particular location between a 7-mile to a 7\1/2\-mile spacing
would be economically, technically, or operationally infeasible, and
that an alternative spacing would not adversely impact safety; and
    (2) Keeps the records necessary to support that determination for
the useful life of the pipeline.
    (h) An operator may submit for PHMSA review, in accordance with
Sec.  195.18, a notification requesting site-specific exemption from
the valve installation requirements or valve spacing requirements of
paragraph (c), (e), or (f) of this section and demonstrating such
exemption would not adversely affect safety. An operator may also
submit for PHMSA review, in accordance with Sec.  195.18, a
notification requesting an extension of the compliance deadline
requirements for valve installation and spacing of this section because
those compliance deadline requirements would be economically,
technically, or operationally infeasible for a particular new
construction or pipeline replacement project.

0
20. In Sec.  195.402, paragraphs (c)(4), (5), and (12) and (e)(1), (4),
(7), and (10) are revised to read as follows:

Sec.  195.402   Procedural manual for operations, maintenance, and
emergencies.

* * * * *
    (c) * * *
    (4) Determining which pipeline facilities are in areas that would
require an immediate response by the operator to prevent hazards to the
public, property, or the environment if the facilities failed or
malfunctioned, including segments that could affect high-consequence
areas (HCA) or are in HCAs, and valves specified in Sec.  195.418 or
Sec.  195.452(i)(4).
    (5) Investigating and analyzing pipeline accidents and failures,
including sending the failed pipe, component, or equipment for
laboratory testing or examination where appropriate, to determine the
cause(s) and contributing factors of the failure and to minimize the
possibility of a recurrence.
    (i) Post-failure and -accident lessons learned. Each operator must
develop, implement, and incorporate lessons learned from a post-failure
and accident review into its written procedures, including in pertinent
operator personnel training and qualifications programs, and in design,
construction, testing, maintenance, operations, and emergency procedure
manuals and specifications.
    (ii) Analysis of rupture and valve shut-offs; preventive and
mitigative measures. If a failure or accident on an onshore hazardous
liquid or carbon dioxide pipeline involves the closure of a rupture-
mitigation valve (RMV), as defined in Sec.  195.2, or the closure of an
alternative equivalent technology, the operator of the pipeline must
also conduct a post-failure or -accident analysis of all of the factors
that may have impacted the release volume and the consequences of the
release and identify and implement operations and maintenance measures
to minimize the consequences of a future failure or incident. The
analysis must include all relevant factors impacting the release volume
and consequences, including, but not limited to, the following:
    (A) Detection, identification, operational response, system shut-
off, and emergency-response communications, based on the type and
volume of the release or failure event;
    (B) Appropriateness and effectiveness of procedures and pipeline
systems, including supervisory control and data acquisition (SCADA),
communications, valve shut-off, and operator personnel;
    (C) Actual response time from identifying a rupture following a
notification of potential rupture, as defined at Sec.  195.2, to
initiation of mitigative actions and isolation of the segment, and the
appropriateness and effectiveness of the mitigative actions taken;
    (D) Location and timeliness of actuation of all RMVs or alternative
equivalent technologies; and
    (E) All other factors the operator deems appropriate.
    (iii) Rupture post-failure and accident summary. If a failure or
accident on an onshore hazardous liquid or carbon dioxide pipeline
involves the identification of a rupture following a notification of
potential rupture; the closure of an RMV, as those terms are defined in
Sec.  195.2; or the closure of an

alternative equivalent technology, the operator must complete a summary
of the post-failure or -accident review required by paragraph
(c)(5)(ii) of this section within 90 days of the failure or accident.
While the investigation is pending, the operator must conduct quarterly
status reviews until the investigation is completed and a final post-
failure or -accident review is prepared. The final post-failure or -
accident summary and all other reviews and analyses produced under the
requirements of this section must be reviewed, dated, and signed by the
operator's appropriate senior executive officer. An operator must keep,
for the useful life of the pipeline, the final post-failure or -
accident summary, all investigation and analysis documents used to
prepare it, and records of lessons learned.
* * * * *
    (12) Establishing and maintaining adequate means of communication
with the appropriate public safety answering point (i.e., 9-1-1
emergency call center), where direct access to a 9-1-1 emergency call
center is available from the location of the pipeline, and fire,
police, and other public officials. Operators must determine the
responsibilities, resources, jurisdictional area(s), and emergency
contact telephone numbers for both local and out-of-area calls of each
Federal, State, and local government organization that may respond to a
pipeline emergency, and inform the officials about the operator's
ability to respond to the pipeline emergency and means of communication
during emergencies. Operators may establish liaison with the
appropriate local emergency 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.
* * * * *
    (e) * * *
    (1) Receiving, identifying, and classifying notices of events that
need immediate response by the operator or notice to the appropriate
public safety answering point (i.e., 9-1-1 emergency call center),
where direct access to a 9-1-1 emergency call center is available from
the location of the pipeline, and fire, police, and other appropriate
public officials, and communicating this information to appropriate
operator personnel for prompt corrective action. Operators may
establish liaison with the appropriate local emergency 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.
* * * * *
    (4) Taking necessary actions, including but not limited to,
emergency shutdown, valve shut-off, or pressure reduction, in any
section of the operator's pipeline system, to minimize hazards of
released hazardous liquid or carbon dioxide to life, property, or the
environment. Each operator must also develop written rupture
identification procedures to evaluate and identify whether a
notification of potential rupture, as defined in Sec.  195.2, is an
actual rupture event or non-rupture event. These procedures must, at a
minimum, specify the sources of information, operational factors, and
other criteria that operator personnel use to evaluate a notification
of potential rupture, as defined at Sec.  195.2. For operators
installing valves in accordance with Sec.  195.258(c), Sec.
195.258(d), or that are subject to the requirements in Sec.  195.418,
those procedures should provide for rupture identification as soon as
practicable.
* * * * *
    (7) Notifying the appropriate public safety answering point (i.e.,
9-1-1 emergency call center), where direct access to a 9-1-1 emergency
call center is available from the location of the pipeline, and fire,
police, and other public officials, of hazardous liquid or carbon
dioxide pipeline emergencies to coordinate and share information to
determine the location of the release, including both planned responses
and actual responses during an emergency, and any additional
precautions necessary for an emergency involving a pipeline
transporting a highly volatile liquid (HVL). The operator must
immediately and directly notify the appropriate public safety answering
point or other coordinating agency for the communities and
jurisdiction(s) in which the pipeline is located after notification of
potential rupture, as defined at Sec.  195.2, has occurred to
coordinate and share information to determine the location of the
release, regardless of whether the segment is subject to the
requirements of Sec.  195.258 (c) or (d), Sec.  195.418, or Sec.
195.419.
* * * * *
    (10) Actions required to be taken by a controller during an
emergency, in accordance with the operator's emergency plans and
Sec. Sec.  195.418 and 195.446.
* * * * *

0
21. Section 195.417 is added to read as follows:

Sec.  195.417   Notification of potential rupture.

    (a) As used in this part, a notification of potential rupture means
refers to the notification to, or observation by, an operator (e.g., by
or to its controller(s) in a control room, field personnel, nearby
pipeline or utility personnel, the public, local responders, or public
authorities) of one or more of the below indicia of a potential
unintentional or uncontrolled release of a large volume of hazardous
liquids from a pipeline:
    (1) An unanticipated or unexplained pressure loss outside of the
pipeline's normal operating pressures, as defined in the operator's
written procedures. The operator must establish in its written
procedures that an unanticipated or unplanned pressure loss is outside
of the pipeline's normal operating pressures when there is a pressure
loss greater than 10 percent occurring within a time interval of 15
minutes or less, unless the operator has documented in its written
procedures the operational need for a greater pressure-change threshold
due to pipeline flow dynamics (including changes in operating pressure,
flow rate, or volume), that are caused by fluctuations in product
demand, receipts, or deliveries;
    (2) An unanticipated or unexplained flow rate change, pressure
change, equipment function, or other pipeline instrumentation
indication at the upstream or downstream station that may be
representative of an event meeting paragraph (a)(1) of this section; or
    (3) Any unanticipated or unexplained rapid release of a large
volume of hazardous liquid, a fire, or an explosion, in the immediate
vicinity of the pipeline.
    (b) A notification of potential rupture occurs when an operator
first receives notice of or observes an event specified in paragraph
(a) of this section.

0
22. Section 195.418 is added to read as follows:

Sec.  195.418   Valves: Onshore valve shut-off for rupture mitigation.

    (a) Applicability. For newly constructed and entirely replaced
onshore hazardous liquid or carbon dioxide pipeline segments, as
defined at Sec.  195.2, with diameters of 6 inches or greater that
could affect high-consequence areas or are located in high consequence
areas (HCA), and that have been installed after April 10, 2023, an
operator must install or use existing rupture-mitigation valves (RMV),
as defined at Sec.  195.2, or alternative equivalent technologies
according to the requirements of this section and Sec.  195.419. RMVs
and alternative

equivalent technologies must be operational within 14 days of placing
the new or replaced pipeline segment in service. An operator may
request an extension of this 14-day operation requirement if it can
demonstrate to PHMSA, in accordance with the notification procedures in
Sec.  195.18, that application of that requirement would be
economically, technically, or operationally infeasible. The
requirements of this section apply to all applicable pipe replacements,
even those that do not otherwise directly involve the addition or
replacement of a valve.
    (b) Maximum spacing between valves. RMVs and alternative equivalent
technology must be installed in accordance with the following
requirements:
    (1) Shut-off Segment. For purposes of this section, a ``shut-off
segment'' means the segment of pipeline located between the upstream
valve closest to the upstream endpoint of the replaced pipeline segment
in the HCA or the pipeline segment that could affect an HCA and the
downstream valve closest to the downstream endpoint of the replaced
pipeline segment of the HCA or the pipeline segment that could affect
an HCA so that the entirety of the segment that could affect the HCA or