naturally occurring events, including: (1) earthquakes and landslides;
(2) heavy rains and flooding; (3) high winds, tornadoes, or hurricanes;
(4) temperature extremes; and (5) lightning.\64\ Further, PHMSA has
issued advisory bulletins alerting operators to threats related to
natural forces such as land movement (i.e., geological hazards or
``geohazards'' \65\) (ADB-2022-01 and ADB-2019-02), severe flooding
(ADB-2019-01), snow and ice build-up (ADB-2016-03), and extreme
temperatures (ADB-2012-03).\66\
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    \64\ PHMSA, ``Fact Sheet: Natural Force Damage'' (July 23,
2014), https://primis.phmsa.dot.gov/comm/FactSheets/FSNaturalForce.htm.
    \65\ PHMSA also interprets natural hazards to include
geohazards.
    \66\ ``Pipeline Safety: Potential for Damage to Pipeline
Facilities Caused by Earth Movement and Other Geological Hazards,''
ADB-2022-01, 87 FR 33576 (June 2, 2022); ``Pipeline Safety:
Potential for Damage to Pipeline Facilities Caused by Earth Movement
and Other Geological Hazards,'' ADB-2019-02, 84 FR 18919 (May 2,
2019); ``Pipeline Safety: Potential for Damage to Pipeline
Facilities Caused by Flooding, River Scour, and River Channel
Migration,'' ADB-2019-01, 84 FR 14715 (Apr. 11, 2019); ``Pipeline
Safety: Dangers of Abnormal Snow and Ice Build-Up on Gas
Distribution Systems,'' ADB-2016-03, 81 FR 7412 (Feb. 11, 2016);
``Notice to Operators of Driscopipe 8000 High Density Polyethylene
Pipe of the Potential for Material Degradation,''ADB-2012-03, 77 FR
13387 (Mar. 6, 2012). PHMSA notes that many of those advisory
bulletins identify resources maintained by other Federal agencies
that can assist pipeline operators in identifying and evaluating
integrity threats to their pipelines.
---------------------------------------------------------------------------

b. Need for Change--DIMP--Identify Threats--Natural Forces Including
Extreme Weather and Geohazards
    A distribution pipeline system operates in a discrete environment
due to the limited geographic scope of each individual system. The
environment in which a system operates significantly affects the
threats to pipeline integrity that it faces. Factors such as weather
(dry or wet, hot or subject to freezing) can significantly shape the
threats affecting individual distribution operators and the actions
necessary to address those threats. Major climate trends, such as
elevated average surface temperatures, more intense storm events, and
flooding, can, independently and in combination, affect the reliability
and integrity of the United States' gas distribution infrastructure. As
climate change has made extreme weather more common, it is harder to
categorize what types of environmental factors facing distribution
pipelines are ``normal'' based on geography and historical averages
alone.
    While freezing weather once seemed like a problem reserved for
northern regions of the United States, southern regions are also
experiencing unseasonable and extremely cold weather. For example, in
February of 2021, Texas experienced a winter storm that brought some of
the coldest temperatures in its history.\67\ Extremely cold weather can
cause thermal contraction stress or fractures of pipelines due to the
expansion of moisture trapped inside components. In addition, safety
relief devices can malfunction due to icing or freezing.
---------------------------------------------------------------------------

    \67\ On February 16, 2021, Dallas, TX recorded temperatures as
low as -2 [deg]F.
---------------------------------------------------------------------------

    Low temperatures and the accumulation of snow and ice also
increases the potential for physical

damage to meters and regulators and other aboveground pipeline
facilities and components. For example, ice forming on regulators or
pressure relief devices can cause them to malfunction or stop working
completely.\68\ Exposed piping at metering and pressure regulating
stations, at service regulators, and at propane tanks are at the
greatest risk. On February 11, 2016, PHMSA issued advisory bulletin
ADB-2016-03 alerting operators to the dangers of abnormal snow and ice
buildup on gas distribution systems. PHMSA has issued four other
advisory bulletins since 1993 on this same issue.\69\
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    \68\ Regulators must be adequately protected from obstructions
such as dirt, insects, and ice. If the vent on a regulator becomes
completely obstructed, then the regulator can either shut off the
flow of gas to a customer or increase the pressure to the upstream
pressure, causing possible failures.
    \69\ ``Pipeline Safety: Dangers of Abnormal Snow and Ice Build-
Up on Gas Distribution Systems,'' ADB-11-02, 76 FR 7238 (Feb. 9,
2011); ``Pipeline Safety: Dangers of Abnormal Snow and Ice Build-Up
on Gas Distribution Systems,'' ADB-08-03, 73 FR 12796 (Mar. 10,
2008); ``Potential Damage to Pipelines by Impact of Snowfall, and
Actions Taken by Homeowners and Others to Protect Gas Systems from
Abnormal Snow Build-up,'' ADB-97-01 (Jan. 24, 1997); ``Pipeline
Safety Advisory Bulletin; Snow Accumulation on Gas Pipeline
Facilities,'' ADB-93-01, 58 FR 7034 (Feb. 3, 1993).
---------------------------------------------------------------------------

    Natural forces such as severe flooding, river scour, and river
channel migration can also adversely affect the safe operation of a
pipeline. These incidents can damage a pipeline as a result of
additional stresses imposed on the pipe by undermining underlying
support soils, exposing the pipeline to lateral water forces and impact
from waterborne debris. Additionally, the proper function of valves,
regulators, relief sets, pressure sensors, and other facilities
normally above ground or above water can be jeopardized when covered by
water. PHMSA has issued several advisory bulletins alerting operators
to the dangers severe flooding, river scour, and river channel
migration can impose on a pipeline, most recently in 2019 through ADB-
2019-01 and again in 2022 through ADB-2022-01.\70\ Sometimes flooding
is seasonal and predictable; however, the Intergovernmental Panel on
Climate Change (IPCC) predicts increases in the frequency and intensity
of heavy precipitation, which will give rise to increased risk of
flooding.\71\ In some areas, climate change means higher average
precipitation,\72\ resulting in water saturation that inhibits the
ability of soil to absorb extreme precipitation events. Climate change
may, however, result in drought for other parts of the United
States,\73\ as lower average annual precipitation rates result in lower
soil moisture--and therefore, less ability to absorb extreme
precipitation events. Also, rainfall during the four wettest days of
the year has increased about 35 percent, and the amount of water
flowing in most streams during the worst flood of the year has
increased by more than 20 percent.\74\ For parts of the United States,
spring rainfall and average precipitation are likely to increase and
severe rainstorms are likely to intensify during the next century.\75\
Each of these factors will tend to further increase the risk of
flooding--operators must assess how this may impact the integrity of
their pipelines.
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    \70\ See, e.g., ``Pipeline Safety: Potential for Damage to
Pipeline Facilities Caused by Flooding, River Scour, and River
Channel Migration,'' ADB-2016-01, 81 FR 2943 (Jan. 19, 2016);
``Pipeline Safety: Potential for Damage to Pipeline Facilities
Caused by the Passage of Hurricanes,'' ADB-2015-02, 80 FR 36042
(June 23, 2015); ``Pipeline Safety: Potential for Damage to Pipeline
Facilities Caused by Flooding, River Scour, and River Channel
Migration,'' ADB-2015-01, 80 FR 19114 (Apr. 9, 2015); ``Pipeline
Safety: Potential for Damage to Pipeline Facilities Caused by
Flooding,'' ADB-2013-02, 78 FR 41991 (July 12, 2013); ``Pipeline
Safety: Potential for Damage to Pipeline Facilities Caused by
Flooding,'' ADB-11-04, 76 FR 44985 (July 27, 2011).
    \71\ IPCC, Seneviratne, S.I., N. Nicholls et al., ``Managing the
Risks of Extreme Events and Disasters to Advance Climate Change
Adaptation'' at 113 (2012), https://www.ipcc.ch/site/assets/uploads/2018/03/SREX-Chap3_FINAL-1.pdf.
    \72\ U.S. Envtl. Prot. Agency, ``What Climate Change Means for
Missouri'', EPA 430-F-16-027, at 1 (Aug. 2016), https://19january2017snapshot.epa.gov/sites/production/files/2016-09/documents/climate-change-mo.pdf (noting that over the last half
century, average annual precipitation in most of the Midwest has
increased by 5 to 10 percent).
    \73\ See A. Park Williams et al., ``Rapid Intensification of the
Emerging Southwestern North American Megadrought in 2020-2021,'' 12
Nature Climate Change 232-234 (2022).
    \74\ U.S. Envtl. Prot. Agency, ``What Climate Change Means for
Missouri,'' at 1.
    \75\ U.S. Envtl. Prot. Agency, ``Climate Impacts in the
Midwest,'' Climate Change Impacts, https://climatechange.chicago.gov/climate-impacts/climate-impacts-midwest
(last visited Feb. 25, 2023).
---------------------------------------------------------------------------

    Extremely high temperatures can also pose integrity threats to
certain materials. In March 2012, PHMSA issued advisory bulletin ADB-
2012-03 regarding the potential for degradation of Driscopipe8000
pipes, which were produced from 1979 through 1997.\76\ All reported
occurrences of in-service degradation and leaks related to
Driscopipe8000 pipes were installed in the desert region of the
southwestern United States, particularly in the Mojave Desert region in
Arizona, California, and Nevada. The ambient temperatures in the
southwestern United States are very high (typically over 100 degrees
Fahrenheit) and may contribute to issues for plastic piping. Driscopipe
Series 7000 and 8000 HDPE pipe exposed to prolonged elevated
temperatures may degrade as a result of thermal oxidation. One of the
largest producers of polyethylene piping products in North America, has
noted that ``the mechanism for this oxidation appears to be the
depletion of the thermal stabilizer, which has been shown to occur over
time in high ambient temperature conditions.'' \77\ PHMSA has reminded
operators through ADB-2012-03 that they should monitor the performance
of their plastic piping.
---------------------------------------------------------------------------

    \76\ 77 FR at 13388.
    \77\ Performance Pipe, ``Driscopipe[supreg] 8000 Pipe
Degradation in High Temperature Applications'' https://www.cpchem.com/sites/default/files/2020-05/DriscopipeDegradation.pdf
(last visited Mar. 1, 2023).
---------------------------------------------------------------------------

    Following the Merrimack Valley incident, PHMSA reviewed its current
DIMP regulations for areas where additional clarification could improve
the safety of gas distribution pipelines. As climate change increases
the frequency of extreme weather events and natural forces that can
impact the integrity of pipelines, PHMSA proposes to add clarity to the
DIMP regulations to ensure that operators are considering these threats
when evaluating risks. Operators would, therefore, need to consider and
take appropriate action to address the impacts of extreme weather as a
threat, regardless of whether they had experienced such events in their
pipelines' history, while still recognizing regional differences. PHMSA
expects operators to continue evaluating reasonably available
information regarding changing operating environments (i.e., climate)
and the regional impacts of extreme weather on their pipeline.
c. PHMSA's Proposal To Amend Sec.  192.1007(b)--DIMP--Identify
Threats--Natural Forces Including Extreme Weather and Geohazards
    PHMSA proposes to amend Sec.  192.1007(b) to specify that operators
must include the threat of extreme weather and geohazards as
subcategories under the threat category of ``natural forces.'' This
amendment would ensure that operators consider the threat of extreme
weather under the DIMP regulations. Once identified as a threat under
Sec.  192.1007(b), operators would be required to consider how
potential extreme weather events could increase the likelihood of
failure. They would also need to consider the potential consequences of
such a failure, as required in Sec.  192.1007(c), and ensure that they
identify risk-reduction measures and implement them under Sec.
192.1007(d). PHMSA expects that operators would not limit their

consideration of the threat of extreme weather solely on past normal
weather patterns but would also consider any anticipated increases in
extreme weather conditions and fluctuations. This proposed requirement
would improve safety by ensuring that operators address the impacts of
climate change and protect the reliability and integrity of their
pipeline systems, even if operators have yet to experience these issues
on their systems.
4. DIMP--Identify Threats (Sec.  192.1007(b))--Age of the System, Pipe,
and Components
a. Current Requirements--DIMP--Identify Threats--Age of the System,
Pipe, and Components
    Section 192.1007(b) includes a generic threat category of ``other
issues that could threaten the integrity of [a] pipeline,'' which
operators should use to identify threats that do not fit into the other
threat categories. When performing their risk analysis, Sec.
192.1007(c) states that operators ``may subdivide [their] pipeline into
regions with similar characteristics.'' PHMSA has observed operators
using age as a method of subdividing their pipeline segments when
performing the risk analysis. Further, PHMSA's annual report form,
PHMSA F 7100.1-1, requires operators to identify the miles of pipeline
by decade of installation. Section 192.1007(b) does not, however,
specifically require that operators consider the age of a pipe or
components when identifying threats to pipeline integrity.
b. Need for Change--DIMP--Identify Threats--Age of the System, Pipe,
and Components
    Over time, all pipeline systems are subject to time-dependent
degradation processes threatening pipeline integrity. Pipelines made
from ferrous materials (steel, wrought iron, cast iron, etc.) are all
susceptible to oxidation corrosion over time. Plastic and composite
materials used in pipelines are subject to photodegradation if exposed
to sunlight. Joints, fittings, and welds connecting various pipeline
components can be subject to dissimilar materials corrosion or chemical
degradation of bonding agents and sealants. And the longer the
timeline, the more any gas pipeline components are exposed to a variety
of phenomena--e.g., from internal mechanical stresses, changes in
temperature, changes in external loads (including external force
damage)--that threaten pipeline integrity, exacerbate existing material
weaknesses, or accelerate time-dependent degradation processes.
    Age can impact and potentially modify each of the threats an
operator identifies in Sec.  192.1007(b). The potential threat to
pipeline integrity posed by age depends on the age of the pipeline
components of which it is comprised. PHMSA understands the cumulative
effect of those age-related threats to integrity across an entire
pipeline are not merely the sum of age-related, component-specific
threats; rather, those threats can magnify or exacerbate one another
when integrated within a pipeline system. For example, one component's
failure due to time-dependent degradation processes can strain other
components throughout the system (e.g., by releasing corrosion products
that can damage other, newer components within the system). PHMSA
further notes that trending failure rates by age can be a useful tool
for revealing degraded performance throughout a pipeline system.
    Similarly, the overall age of the pipeline system can provide more
opportunities for safety-critical gaps in material records. Poor
recordkeeping with respect to a pipeline component dating from a
certain time period may threaten not only pipeline integrity on that
segment, but also other components of the same pipeline installed at a
different time period.
    Age can also be expressed in terms of vintage of pipes or
components. Specific manufacturing techniques and materials used during
certain periods of time can result in similar characteristics among
pipes and components of a given vintage. The vintage of pipes or
components can interact with other threats, including materials,
equipment failures, or natural forces. For example, pipe installed
earlier than 1950 has disproportionately high susceptibility to
problems from cold weather and freezing, which could interact with the
threat of natural forces. The greater susceptibility of pre-1950 pipe
is thought to be due to inferior low-temperature ductility of the
steels of the era and the methods used to join pipe at the time (such
as electric arc welds, acetylene welds, couplings, and threaded
collars).\78\ Additionally, as described in section IV.A.1 (materials),
some of the early plastic piping products manufactured from the 1960s
and into the early 1980s are more susceptible to brittle-like cracking
(also known as slow-crack growth) than newer materials.\79\
---------------------------------------------------------------------------

    \78\ M.J. Rosenfeld, ``Cold Weather Can Play Havoc On Natural
Gas Systems'' 242 Pipeline & Gas J. 1 (Jan. 2015), https://pgjonline.com/magazine/2015/january-2015-vol-242-no-1/features/cold-weather-can-play-havoc-on-natural-gas-systems.
    \79\ Brittle-like cracking failures occur under conditions of
stress intensification. Stress intensification is more common in
fittings and joints.
---------------------------------------------------------------------------

    Even though time-dependent degradation processes are widely
understood threats to the integrity of pipeline systems, as discussed
earlier, Sec.  192.1007(b) does not specifically state that operators
must account for the age of the system, pipe, and components in
identifying threats. Increasing failure rates have been observed in
older gas distribution infrastructure that has certain attributes.\80\
The increasing failure rate typically occurs toward the end of life and
accelerates the rate by which the reliability decreases. This behavior
is typically attributed to cumulative degradation that occurs in the
system over its service period. Trending failure rates by system age
can reveal degrading performance.
---------------------------------------------------------------------------

    \80\ PHMSA, ``Pipeline Replacement Background'' (Apr. 26, 2021),
https://www.phmsa.dot.gov/data-and-statistics/pipeline-replacement/pipeline-replacement-background.
---------------------------------------------------------------------------

    Recent incidents have illustrated that operators may be
inadequately identifying and managing threats related to the age of
components on their systems. For example, in its risk analysis, Atmos
used a commercially available software that did not explicitly consider
the age of the pipeline segments, instead grouping them into failure
categories based on similar attributes, such as material and coating.
Although such an approach may have been compliant with current
regulations, this approach to risk analysis disregards how the age
could contribute to failures. Following the 2018 Atmos incidents, the
NTSB recommended that Gas Piping Technology Committee develop guidance
and identify steps operators can take to ensure that their gas
distribution IM programs appropriately consider threats that degrade a
system over time.\81\ By adopting such a practice, operators would
recognize the full threat based on the impact of age and prioritize
remediating or replacing segments of the pipe and components that pose
more acute threats. PHMSA therefore proposes to revise Sec.
192.1007(b) to explicitly identify age as a factor in addressing
threats to integrity.
---------------------------------------------------------------------------

    \81\ NTSB/PAR-21/01 at 82.
---------------------------------------------------------------------------

c. Proposal To Amend Sec.  192.1007(b)--DIMP--Identify Threats--Age of
the System, Pipe, and Components
    PHMSA proposes to amend Sec.  192.1007(b) to clarify that operators

must, when identifying the threats on its distribution system, also
consider the age of the system, piping, and components in identifying
threats.\82\ For example, once an operator identifies a time-dependent
threat exists on their pipeline, such as corrosion, the operator would
then consider how the age of the pipe, or the components, could
influence the severity of the threat. All things equal, an older pipe
or component exposed to the threat of corrosion could carry additional
risk compared to newer pipe. Similarly, for time-independent threats,
such as natural forces, the operator would consider how the age of the
pipeline or components would expose the pipeline to multiple threats
over its lifetime, a threat that may evolve or increase over time.
PHMSA's proposal would ensure that the DIMP regulations explicitly
account for how the age of the system, pipes, and components contribute
to a pipeline's integrity degrading over time.
---------------------------------------------------------------------------

    \82\ See Am. Soc'y of Mech. Eng's, ANSI B31.8S-2004, ``Managing
System Integrity of Gas Pipelines,'' at sec. 2 (Jan. 14, 2005).
---------------------------------------------------------------------------

5. DIMP--Evaluate and Rank Risk (Section 192.1007(c))
a. Current Requirements--DIMP--Evaluate and Rank Risk
    Section 192.1007(c) requires that operators evaluate and rank the
risks associated with their distribution pipeline systems. This
evaluation must consider each applicable current and potential threat,
the likelihood of failure associated with each threat, and the
potential consequences of such a failure. Operators may subdivide their
distribution systems into regions (areas within a distribution system
consisting of mains, services, and other appurtenances) that have
similar characteristics and reasonably consistent risks, and for which
similar actions would be effective in reducing risk.
    Through enforcement guidance, PHMSA recommended that operators
develop weighted factors for each threat specific to their system
depending upon their unique operating environment.\83\ PHMSA has
further stressed that it may be inadequate for operators to conclude
that a pipeline is not subject to any particular threat based solely on
the fact that it has not experienced a pipeline failure attributed to
the threat.\84\ PHMSA has used enforcement guidance to clarify that if
operators conclude that a particular threat is not applicable to
sections of their pipeline, then operators should document the basis
for drawing that conclusion.\85\ This basis should consider the
pipeline's failure history, design, manufacturing, construction,
operation, and maintenance.
---------------------------------------------------------------------------

    \83\ DIMP Guidance at 22.
    \84\ DIMP Guidance at 23.
    \85\ DIMP Guidance at 18, 57.
---------------------------------------------------------------------------

b. Need for Change--DIMP--Evaluate and Rank Risk
    Recent incidents have demonstrated the importance of operators
adequately evaluating and ranking risks on their systems and in their
DIMP plans. For example, as demonstrated by the 2018 Merrimack Valley
and other incidents investigated by the NTSB, some operators have not
been adequately evaluating the risk of overpressurization, and thus not
taking appropriate mitigating measures to account for those risks.\86\
Overpressurization incidents--in particular on low-pressure gas
distribution systems--merit mitigation because they have a high-
consequence. As previously noted, CMA had knowledge of the risks of an
overpressurization, updated their procedures, and still did not take
appropriate action to mitigate the risks. Similarly, the Atmos incident
in Texas demonstrated how operators can underestimate the risks
associated with the presence of leak-prone materials.
---------------------------------------------------------------------------

    \86\ NTSB/PAR-19/02 at 18-21, 39-40, 48.
---------------------------------------------------------------------------

    PHMSA is required by law to ensure that operators' DIMP plans
evaluate the presence and risks associated with cast iron piping and
the threat of overpressurization on low-pressure gas distribution
systems (49 U.S.C. 60109(e)(7)). PHMSA is also required to prohibit
operators, when evaluating risks related to the operation of a low-
pressure gas distribution system, from determining that there are no
potential consequences associated with low-probability events unless
that determination is supported by ``engineering analysis or
operational knowledge.'' PHMSA must also ensure that operators of gas
distribution systems consider factors other than past observed
``abnormal operating conditions''--as that term is defined at Sec.
192.803--when ranking risks and identifying measures to mitigate those
risks.
c. PHMSA's Proposal To Amend Sec.  192.1007(c)--DIMP--Evaluate and Rank
Risk
    PHMSA proposes to redesignate the general requirements of Sec.
192.1007(c) under a new paragraph (c)(1). These general requirements
still require operators to consider the identified threats proposed in
Sec.  192.1007(b) as they evaluate and rank risks.
i. Certain Pipe Materials With Known Issues
    PHMSA proposes to amend Sec.  192.1007(c) by creating a new Sec.
192.1007(c)(2) to specify that operators must evaluate the risks
resulting from pipelines constructed with certain materials (including
cast iron, bare steel, unprotected steel, wrought iron, and historic
plastics with known issues) when such materials are present in their
pipeline systems. Overall, these proposed requirements would improve
safety by codifying in DIMP requirements some of the known, industry-
wide threats if the materials that have exhibited these threats are
present in the operator's systems, even if operators have not yet
experienced any of these issues on their systems.
ii. Evaluate and Rank Risk: Low-Pressure Distribution Systems
    PHMSA also proposes to amend Sec.  192.1007(c) by creating a new
Sec.  192.1007(c)(3) applicable to low-pressure distribution systems.
Consistent with the mandate in 49 U.S.C. 60109(e)(7), PHMSA proposes to
require operators of low-pressure gas distribution systems to evaluate
``the risks that could lead to or result from the operation of a low-
pressure distribution system at a pressure that makes the operation of
any connected and properly adjusted low-pressure gas burning equipment
unsafe.'' For the purposes of this NPRM, PHMSA determines that
``unsafe'' in this context means that gas flowing into the downstream
equipment is at a pressure beyond the rated supply pressure specified
by the manufacturer of that equipment. This amendment would ensure that
operators are addressing the risks on their pipeline that could result
in an overpressurization.
    In evaluating the risks to low-pressure distribution systems, the
mandate in 49 U.S.C. 60109(e)(7)(B) requires PHMSA to ensure that
operators consider ``factors other than past observed abnormal
operating conditions [. . .] in ranking risks.'' This includes any
abnormal operating conditions (AOCs) that operators have experienced
(i.e., observed) on their system and any unobserved AOCs that could
occur on their system (i.e., an overpressurization on a low-pressure
system), including any known industry threats, risks, or hazards, as
identified by an operator from available sources (e.g., PHMSA advisory
bulletins, PHMSA incident and accident reports, PHMSA and NTSB accident
reports, State pipeline safety regulatory actions, and operator
knowledge sharing). PHMSA proposes

in Sec.  192.1007(c)(3)(i) to require operators of low-pressure systems
to evaluate risks to their systems in accordance with the mandate. This
amendment would ensure that operators are reviewing their past observed
operational performance to evaluate the risks on their systems. This
amendment would also ensure that operators are considering risks even
if they have yet to experience those risks on their systems. For
example, if an operator has not experienced an overpressurization on
its system, that operator must still consider the risks of an
overpressurization on its system.
    The mandate in 49 U.S.C. 60109(e)(7)(B) also states that operators
may not determine that low probability events have no potential
consequences without a supporting determination. PHMSA proposes
integrating this mandate by adding a new paragraph Sec.
192.1007(c)(3)(ii) that will direct operators to evaluate the potential
consequences associated with low-probability events, unless a
determination--supported and documented by an engineering analysis or
other equivalent analysis incorporating operational knowledge--
demonstrates that the event results in no potential consequences (and
therefore no potential risk).
    An engineering analysis would include documentation of the
engineering principles used to calculate the flows, pressures, and
other parameters of the piping and systems to calculate the actual
downstream pressure. This engineering analysis would also include
documentation of the methods used to determine that the system cannot
fail and cause overpressurization, including any data and assumptions
(including mitigation and control measures) utilized by the operator.
This engineering analysis may necessarily include degrees of measurable
operational knowledge regarding specific pipeline characteristics and
evidence from that analysis combined with documentable known pipeline
characteristics. An operator that determines there are no potential
consequences from a low-probability event must document all these
reasons as part of its ``engineering analysis'' submitted to PHMSA
according to Sec.  192.18 with sufficient detail as listed in Sec.
192.1007(c)(3)(ii)(A)-(F).
    Because the statute requires operators to make an affirmative
determination that there are no potential consequences associated with
low probability events and recognizing that some operators might not
have fully considered the risk of low-probability events based solely
on operational knowledge, PHMSA proposes that any operational knowledge
relied upon must include with it a quantifiable assessment and support
the operator's determination with a level of rigor equal to that of an
engineering analysis. This operational knowledge could be included as
part of the proposed regulatorily required ``engineering analysis, or
an equivalent analysis,'' as used in Sec.  192.1007(c)(3)(ii). For
example, should an operator determine that a release of gas from the
pipeline, such as a leak, has no potential consequences, the operator
should include documentation demonstrating that many scenarios were
considered (such as a leak with ignition or gas migration under nearby
pavement) and that no potential consequences were identified in any of
those potential scenarios. This amendment would ensure that operators
do not dismiss material risks without a meaningful evidentiary basis,
and PHMSA or pertinent State authorities would have the opportunity to
review and consider the validity of the operator's determination when
reviewing DIMP plans.
    State regulatory authorities already review operators' DIMP plans
during regular inspections. Because incorrectly determining that a
potential threat has no consequences would have serious public safety
impacts, however, PHMSA understands there is a compelling policy reason
for an operator's determination that a low-frequency event entails zero
risk be reviewed by those State regulatory authorities as well as
PHMSA. Therefore, if operators choose to apply the proposed exception
in Sec.  192.1007(c)(3)(ii), they must notify PHMSA and the appropriate
State Authority in accordance with Sec.  192.18 within 30 days of
making this determination that there are no potential consequences
associated with the low-probability event. The notification must
include information such as the date the determination was made (to
ensure compliance with the proposed timeline), descriptions of the low-
probability events being considered, and a description of the logic
supporting the determination, including information from an engineering
analysis or an equivalent analysis incorporating operational knowledge.
Further, this notification should contain a description of any
preventive and mitigative measures, including any measures considered
but not taken, as determined through the engineering analysis or an
equivalent analysis incorporating operational knowledge. The
notification should also include a description of the low-pressure
system, including, at a minimum, miles of pipe, number of customers,
number of district regulators supplying the system, and other relevant
information. In addition, operators must provide a written statement
summarizing the documentation it evaluated and how the conclusion that
there would be no potential consequences associated with the low-
probability event was reached. This documentation could include the
inspection and maintenance history of the pipeline segment, incident
reports, any leak repair data, and any failure investigations or
abnormal operations records. Providing this information would be
critical in ensuring that operators robustly evaluated methods of
reducing risk and that the operator did not ignore any material factors
in their engineering analysis or an equivalent analysis incorporating
operational knowledge.
    In a new Sec.  192.1007(c)(3)(iii), PHMSA proposes to require that
in evaluating and ranking risks in their DIMP plans, operators of low-
pressure gas distribution systems must evaluate the configuration of
their primary and any secondary overpressure protection installed at
the district regulator stations, the availability of gas pressure
monitoring at or near overpressure protection equipment, and the
likelihood of any single event that immediately or over time could
result in an overpressurization of the low-pressure system (see amended
Sec.  192.195(c)). Operators' overpressure protection configurations
vary--some include a combination of relief valves, monitoring
regulators, or automatic shutoff valves. Other operators have real-time
monitoring devices located at the district regulator station, while yet
others rely on telemetering devices. Some operators, as demonstrated by
the events of September 13, 2018, may have an overpressure protection
configuration that can be defeated by a single event, such as
excavation damage, natural forces, an equipment failure, or incorrect
operations. This amendment would ensure that operators are evaluating
their existing overpressure protection system for inadequacies or
additional risks that could result in an overpressurization of the
system.

6. DIMP--Identify and Implement Measures To Address Risks (Section
192.1007(d))
a. Current Requirements--DIMP--Identify and Implement Measures To
Address Risks
    Section 192.1007(d) requires operators to determine and implement
measures designed to reduce the risks from failure of their gas
distribution pipeline systems following the identification of threats
(in accordance with Sec.  192.1007(b)) and the evaluation and ranking
of risks (in accordance with Sec.  192.1007(c)). Section 192.1007(d)
also requires that these risk mitigation measures include an effective
leak management program (unless all leaks are repaired when found).
Although the specific process is not defined in Sec.  192.1007(d),
PHMSA has issued guidance material to support the implementation of
these requirements.
    In the guidance material, PHMSA states that operators should have a
documented list of measures to reduce risks identified on their
pipeline system.\87\ The process for identifying risk mitigation
measures must be based on identified threats to each pipeline segment
and the risk analysis. Operators should rank pipeline segments and
group segments that represent the highest risk as the most important
candidates for which measures are taken to reduce risk. The operator
should ensure that the highest priority measures for reducing risk are
for the highest-ranked segments as indicated by the risk analysis.
Because the design and operation of gas distribution systems are so
diverse, no single risk control method is appropriate in all cases.
Therefore, the objective of Sec.  192.1007(d) is to ensure that each
operator has documented and described existing and proposed measures to
address the unique risks to its system and that the operator has
evaluated and prioritized actions to reduce risks to pipeline
integrity.
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    \87\ DIMP Guidance at 28.
---------------------------------------------------------------------------

b. Need for Change--DIMP--Identify and Implement Measures To Address
Risks
    Proper implementation of a DIMP plan should result in aggressive
oversight and replacement of higher-risk infrastructure. For example,
there are many benefits to replacing old, cast-iron, low-pressure
distribution pipes with newer materials, such as modern plastic pipe.
Replacement projects, however, entail their own risks to public safety
and the environment that need to be balanced against the risks
associated with leaving a pipeline segment undisturbed. Poorly managed
construction projects can result in property damage and personal
injury, and replacement activity can include blowdowns to the
atmosphere of methane gas that contribute to climate change. Work on
existing pipeline facilities can also cause a catastrophic
overpressurization, as was the case in CMA's 2018 incident. Operators
must manage those risks while still implementing preventive and
mitigative measures that would reduce the risk of identified threats.
    In 2020, PHMSA issued an advisory bulletin to remind operators of
the possibility of failure due to an overpressurization on low-pressure
distribution systems.\88\ In that advisory bulletin, PHMSA reminded
operators of the existing DIMP regulations and recommended that per
Sec.  192.1007(d), operators take additional actions to reduce risks if
they found their current overpressure protection design to be
insufficient. PHMSA also identified for operators that ``[t]here are
several ways that operators can protect low-pressure distribution
systems from overpressure events,'' such as:
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    \88\ See ``Pipeline Safety: Overpressure Protection on Low-
Pressure Natural Gas Distribution Systems,'' ADB-2020-02, 85 FR
61097 (Sept. 29, 2020).
---------------------------------------------------------------------------

    1. Installing a full-capacity relief valve downstream of the low-
pressure regulator station, including in applications where there is
only worker-monitor pressure control;
    2. Installing a ``slam shut'' device;
    3. Using telemetered pressure recordings at district regulator
stations to signal failures immediately to operators at control
centers; and
    4. Completely and accurately documenting the location for all
control (i.e., sensing) lines on the system.
    As discussed earlier, subsequent to the 2018 Merrimack Valley
incident, PHMSA was required by statute to ensure that operators of
low-pressure gas distribution systems evaluate the risk of
overpressurization in their DIMP plans. (49 U.S.C. 60109(e)(7)(A)(ii)).
For existing low-pressure systems, operators already have a mechanism
in place--their DIMP--to evaluate their systems to ensure they can
identify and implement measures to minimize the risk imposed by any
inadequate overpressure protection.
c. PHMSA's Proposal To Amend Sec.  192.1007(d)--DIMP--Identify and
Implement Measures To Address Risks
    PHMSA proposes to amend Sec.  192.1007(d) to establish additional
criteria for operators to evaluate when identifying and implementing
measures to address risks identified in DIMP plans. PHMSA's proposal
would require operators--when identifying and implementing measures--to
specifically account for risks associated with the age of the pipe, the
age of the system, the presence of pipes with known issues, and
overpressurization of low-pressure distribution systems. PHMSA is
adding these specific risks to Sec.  192.1007(d) because they were the
subject of recent incidents, as discussed earlier. This amendment would
ensure that operators are not only identifying these specific threats
(in Sec.  192.1007(b)), but also implementing measures to address those
risks. In a new Sec.  192.1007(d)(2), PHMSA is proposing to explicitly
require operators of existing low-pressure systems to take certain
actions to prevent and mitigate the risk of an overpressurization that
could be the result of any single event or failure. These actions
include identifying, maintaining, and (if necessary) obtaining
traceable, verifiable, and complete records that document the
characteristics of the pipeline that are critical to ensuring proper
pressure controls for the system. PHMSA discusses the criteria for
these pressure control records in section IV.F of this NPRM.
    In addition to this recordkeeping requirement, in a new Sec.
192.1007(d)(2), PHMSA proposes that operators must confirm and document
that each district regulator station meets the design standards in
Sec.  192.195(c)(1)-(3) or take the following actions: (1) identify
preventative and mitigative measures based on the unique
characteristics of their system to minimize the risk of
overpressurization on low-pressure systems, or (2) upgrade their
systems to meet design standards in Sec.  192.195(c)(1)-(3). PHMSA
discusses the criteria for this proposed upgrade in section IV.H of
this NPRM. Should an operator choose to identify preventative and
mitigative measures based on the unique characteristics of their system
to minimize the risk of overpressurization, PHMSA proposes that the
operator notify PHMSA and State or local pipeline authorities no later
than 90 days in advance of implementing any alternative measures. PHMSA
proposes that an operator must make this notification in accordance
with Sec.  192.18, which would include a description of the operator's
proposed alternative measures, identification, and location of
facilities to which the measures would be applied, and a description of
how the measures would

ensure the safety of the public, affected facilities, and environment.
This notification would ensure that operators are keeping PHMSA and
State authorities informed of alternative measures to address risk.
This amendment would apply to existing low-pressure systems that have
evaluated and identified inadequate overpressure protections in
accordance with Sec.  192.1007(c).
    PHMSA has also proposed to amend Sec.  192.18 to reflect this
proposed change by including a reference to Sec.  192.1007. Should an
operator choose to implement an alternative method of minimizing
overpressurization, PHMSA proposes that the operator notify PHMSA and
State or local pipeline authorities no later than 90 days in advance of
implementing any alternative measures. PHMSA proposes that operators
must make this notification in accordance with Sec.  192.18, which
would include a description of the operators' proposed alternative
measures, identification, and location of facilities to which the
measures would be applied, and a description of how the measures would
ensure the safety of the public, affected facilities, and environment.
This notification would ensure that operators are keeping PHMSA and
State authorities informed of alternative measures to address risk.
    PHMSA proposes these amendments pursuant to 49 U.S.C. 60102(t) and
60109(e)(7). The proposed amendments would reinforce the recommended
actions from PHMSA's 2020 advisory bulletin in which PHMSA identified
for operators of low-pressure distribution systems the risks inherent
to those systems and the preventative or mitigative measures they
should implement to address the risk of overpressurization. PHMSA
expects that operators may already be complying with many of these
practices subsequent to issuance of the advisory bulletin, which set
forth PHMSA's existing policy and interpretation of the current DIMP
requirements. In this NPRM, PHMSA proposes to codify this existing
policy and interpretation in its regulations.
    This amendment is also aligned with the NTSB's clarification to
recommendation P-19-14 that PHMSA would not have to require that
existing low-pressure gas distribution systems be completely
redesigned; rather, PHMSA may satisfy the recommendation by requiring
operators to add additional protections, such as slam-shut or relief
valves, to existing district regulator stations or other appropriate
locations in the system.\89\
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    \89\ NTSB clarified this in an official correspondence to PHMSA
on July 31, 2020. NTSB, ``Safety Recommendation P-19-014'' (July 31,
2020), https://data.ntsb.gov/carol-main-public/sr-details/P-19-014.
---------------------------------------------------------------------------

7. DIMP--Small LPG Operators (Section 192.1015)
a. Current Requirements--DIMP and Annual Reporting for Small LPG
Operators
    A ``small LPG operator'' is currently defined at Sec.  192.1001 as
an operator of a liquefied petroleum gas (LPG) distribution pipeline
system that serves fewer than 100 customers from a single source. Small
LPG operators are treated differently in the DIMP regulations than
larger operators and they follow their own set of DIMP requirements in
Sec.  192.1015 that reflect the relative simplicity of these pipeline
systems. The current DIMP requirements for small LPG operators in Sec.
192.1015 are less extensive than for other gas distribution systems,
but still provide operator personnel direction for implementing their
DIMP plans. Currently, under Sec.  191.11, operators of small LPG
systems are not required to submit an annual report to PHMSA.
b. Need for Change--DIMP--Applicability for Small LPG Operators
    In the 2009 DIMP Final Rule, PHMSA imposed requirements for small
LPG operators similar to those for other operators but with more
limited requirements for documentation, consistent with how these
operators are treated throughout the pipeline safety regulations. PHMSA
did not require operators to report performance measures as they do not
file annual reports. Although the DIMP requirements for small LPG
operators are similar to those applicable to other operators, PHMSA
codified them separately under Sec.  192.1015, emphasizing that DIMPs
for small LPG operators should reflect the relative simplicity of their
pipeline systems.
    On January 11, 2021, PHMSA issued a final rule titled ``Pipeline
Safety: Gas Pipeline Regulatory Reform,'' \90\ which among other
things, excepted master meters from the DIMP requirements. During the
development of that rule, PHMSA received several comments in support of
extending that exception to small LPG operators. For example, the
National Association of Pipeline Safety Representatives (NAPSR)
suggested that small gas distribution utilities with 100 or fewer
customers--including small LPG operators--should be excepted from the
DIMP requirements, stating that many master meter systems, small
distribution systems, and small LPG systems typically have no threats
beyond the minimum threats listed in Sec.  192.1015(b)(2). Various
other commenters, including the National Propane Gas Association
(NPGA), AmeriGas, and Superior Plus Propane, voiced support for
excepting small LPG operators from the DIMP requirements. The Pipeline
Safety Trust did not oppose an exception from DIMP requirements for
master meter systems in that rulemaking, only urging PHMSA and its
State partners to ensure that master meter operators are managing the
integrity risks to their systems outside the context of a DIMP plan. In
response, PHMSA in the Gas Regulatory Reform Final Rule stated, ``that
the decision about whether to extend the DIMP exception to [other]
facilities or to all distribution systems with fewer than 100 customers
would benefit from additional safety analysis and notice and comment
procedures prior to further consideration.'' PHMSA went on to say that
it would ``continue to evaluate the issue of DIMP requirements for
small LPG systems and, if appropriate, propose changes in a future
rulemaking[.]'' \91\
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    \90\ 86 FR 2210 (Jan. 11, 2021) (``Gas Regulatory Reform Final
Rule''). The comments submitted by stakeholders in this rulemaking
may be found in Doc. No. PHMSA-2018-0046.
    \91\ 86 FR at 2216.
---------------------------------------------------------------------------

    On December 17, 2021, the NPGA filed a petition for rulemaking in
accordance with 49 CFR 190.331.\92\ NPGA petitioned PHMSA to amend 49
CFR part 192, subpart P to create an exception for small LPG systems in
the DIMP requirements. In support of their petition, they cited that
NPGA, PHMSA, and the National Academies of Sciences (NAS) have
considered the operation and safety of small LPG systems for more than
10 years.\93\ As an alternative, NPGA proposed that PHMSA could enable
a special permit (through Sec.  190.341) for small LPG systems, for
which NPGA would assist small LPG system operators in providing
necessary information to PHMSA in the special permit process.
---------------------------------------------------------------------------

    \92\ NPGA, Petition for Rulemaking: Small Liquefied Petroleum
Distribution Systems, Doc. No. PHMSA-2022-0102-001 (Dec. 17, 2021)
(``NPGA Petition'').
    \93\ NPGA referenced the examples of: (1) PHMSA Gas Regulatory
Reform Final Rule, 86 FR 2210; (2) Nat'l Academies of Sciences,
Eng'g, and Med., ``Safety Regulation for Small LPG Distribution
Systems'' (2018), https://nap.edu/25245 (``NAS Study''); and (3)
NPGA, Comment Re: Pipeline Safety: Integrity Management Program for
Gas Distribution Pipelines, Doc. No. PHMSA-RSPA-2004-19854-0197
(Oct. 23, 2008).

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

    The basis of NPGA's petition is that small LPG system operators are
comparable to master meter systems, a set of operators that PHMSA
recently removed from the DIMP requirements through the 2021 Gas
Regulatory Reform Final Rule. As NPGA explained, master meter systems
tend to be operated by small entities with simple systems compared to
natural gas distribution operators. Master meters also often include
only one type of pipe, and the systems operate at a single operating
pressure. Similarly, as NPGA stated, the vast majority of small LPG
pipeline systems are single property systems that occupy a small,
overall footprint in size and generally operate at a single operating
pressure. Although such systems may be metered or non-metered, the
nature of their simplicity in size and application make them comparable
to master meter systems such that, owing to their ``nearly identical''
function and structure, ``the two systems should be categorized
together for the same treatment under the regulations'' exempting them
from DIMP requirements.\94\
---------------------------------------------------------------------------

    \94\ NPGA Petition at 3.
---------------------------------------------------------------------------

    NPGA reiterated that PHMSA further noted in the 2021 Gas Regulatory
Reform Final Rule that the agency's experience indicated the analysis
and documentation requirements of DIMP had little safety benefit for
this type of operator and that focusing on more fundamental risk
mitigation activities has more safety benefits than implementing a DIMP
for this class of operators. NPGA went on to reiterate PHMSA's position
in the Gas Regulatory Reform Final Rule (as discussed above), where
PHMSA indicated that exempting master meter operators from subpart P
would result in cost savings for master meter operators without
negatively impacting safety. NPGA stated that PHMSA had previously
expressed its intention to address small LPG systems in a future
rulemaking and added that this change would not conflict with the
Administration's aims of reducing methane emissions.\95\
---------------------------------------------------------------------------

    \95\ NPGA Petition at 3-5. PHMSA notes that LPG releases are not
themselves generally considered to be releases of GHGs.
---------------------------------------------------------------------------

    PHMSA has reviewed and considered NPGA's petition and agrees with
its assertion that small LPG systems do not present the same complexity
or incur the same risks as large networks of pipeline systems crossing
hundreds of miles. Therefore, PHMSA addresses NPGA's petition through
this proposed rule and continued oversight through partnership with
State agencies.
    PHMSA has concluded that its existing approach requiring small LPG
operators to comply with limited DIMP requirements offers little public
safety benefit. Small LPG operators by definition have limited systems
serving a small number of customers; in fact, NAPSR data suggests that
there are only between 3,800 and 5,800 multi-user systems nationwide,
with most serving fewer than 50 customers (often well below 50
customers).\96\ Small LPG systems are also more simple systems--less
piping and fewer components that could fail--that are inherently less
susceptible to loss of pipeline integrity than large gas distribution
systems. Further, PHMSA incident data indicate that small LPG systems
entail relatively low public safety risks. PHMSA's incident data
suggest small LPG systems average less than one incident involving a
fatality or serious injury per year. Incidents reported by operators to
PHMSA from 2010 through 2017 include 10 incidents, seven injuries, and
approximately $2 million in property damage.\97\ No fatalities have
been reported since 2006. Incorporating fire events from the National
Fire Incident Reporting System with the PHMSA incident data suggests
that the number of incidents involving LPG distribution systems
averages in the single digits per year. And, because releases of LPG
are not themselves generally considered GHG emissions, continued
regulation of small LPG systems pursuant to PHMSA's DIMP requirements
provides little benefit for mitigating climate change.
---------------------------------------------------------------------------

    \96\ NAS Study at 83.
    \97\ NAS Study at 41, Table 3-4.
---------------------------------------------------------------------------

    PHMSA understands that even limited DIMP requirements can place a
significant compliance burden on small LPG operators and administrative
burdens on PHMSA and State regulatory authorities--which in turn can
detract from other safety efforts. A 2018 study issued by the NAS found
that there is significant regulatory uncertainty among small LPG
operators regarding whether PHMSA's DIMP regulations apply at all--
resulting in many such operators neither understanding they are obliged
to comply with PHMSA regulations nor being regularly inspected by State
regulatory authorities.\98\
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    \98\ The NAS Study identified as a source of much of that
regulatory uncertainty the varied interpretations of ``public
place'' used at Sec.  192.1(b)(5) to determine if certain petroleum
gas systems are subject to PHMSA's 49 CFR part 192 regulations. NAS
Study at 87-88.
---------------------------------------------------------------------------

    Given their small size and the relative simplicity of their
systems, as discussed in the preceding paragraphs, and the significant
compliance burden that DIMP requirements impose on such entities with
limited safety benefit, PHMSA has determined that it is more
appropriate to exempt small LPG operators from DIMP requirements but
impose an annual reporting requirement on these operators.
c. PHMSA's Proposal To Exempt Small LPG Operators From DIMP
Requirements and Extend Annual Reporting Requirements to Small LPG
Systems
    PHMSA proposes to add a new Sec.  192.1003(b)(4) and delete
existing Sec.  192.1015 to remove small LPG operators from DIMP
requirements but extend annual reporting requirements to these
operators. With small LPG operators removed from DIMP requirements at
Sec.  192.1015, the definition of small LPG operators in Sec.  192.1001
becomes redundant and therefore PHMSA would also remove it from DIMP.
In developing this proposal, PHMSA considered the comments made in the
Gas Regulatory Reform Final Rule on the topic of the application of
DIMP requirements to small LPG operators, the NPGA's petition for
rulemaking, the NAS study, and PHMSA's incident data. PHMSA has
preliminarily determined that continuing to impose DIMP requirements
(even in the abbreviated form pursuant to existing Sec.  192.1015) on
small LPG systems that have been proven by PHMSA incident data to
entail inherently limited public safety risks imposes outsized
compliance burdens on operators and administrative burdens on PHMSA and
State regulatory authorities.\99\ At the same time, extending the
annual reporting requirement to these operators is intended to ensure
that PHMSA will maintain the ability to identify and respond to
systemic or emerging issues on those systems.
---------------------------------------------------------------------------

    \99\ Nor does PHMSA expect that small LPG operators would
experience improvements in pipeline safety from the regulatory
amendments that PHMSA is proposing in this NPRM for other (larger)
gas distribution operators. For example, PHMSA's incident data from
2010 through 2021 shows 12 incidents involving propane gas. In
reviewing those incidents, PHMSA found that the age, material type,
and operations of low-pressure distribution systems were not
relevant to small LPG operators serving fewer than 100 customers;
nor did those incidents involved an exceedance of MAOP.
---------------------------------------------------------------------------

    PHMSA does not expect that this proposed exception from DIMP
requirements would adversely impact public safety. As discussed above,
PHMSA understands the public safety benefits attributable to existing,
limited DIMP requirements for small LPG operators are limited. PHMSA
will be able to retain regulatory oversight of small LPG operator
systems through

other requirements within 49 CFR part 192, including the proposed
annual reporting requirement and the incident reporting requirements at
49 CFR part 191.
    To improve the information available to PHMSA and State regulatory
authorities for identifying and addressing systemic public safety
issues from small LPG systems, PHMSA is proposing to revise Sec.
191.11 to require operators of small LPG systems to submit annual
reports using newly designated form PHMSA F 7100.1-2. These annual
reports would require operators of small LPG systems to report the
location and number of customers served by their distribution pipeline
systems, as well as the disposition of any discovered leaks. PHMSA
expects that through an annual reporting requirement, PHMSA would also
be able to provide better data to the public on small LPG systems,
which the agency could assess and may ultimately inform a future
rulemaking. PHMSA also expects that its proposal to require annual
reporting for small LPG operators may help alleviate the confusion
noted by the NAS Study regarding whether those operators are subject to
PHMSA regulations at 49 CFR part 192.
    PHMSA expects the extension of its part 191 annual reporting
requirements to small LPG systems would be reasonable, technically
feasible, cost-effective, and practicable. The information PHMSA
collects on its current annual report form for gas distribution
operators (Form F7100.1-1) does not require significant technical
expertise or particularly expensive equipment to populate; small LPG
operators may also reduce their burdens further by contracting with
vendors to operate and perform maintenance on their systems and
complete annual report forms. PHMSA also expects that the forthcoming
annual report form (PHMSA F 7100.1-2) specific to small LPG operators
will be a further simplified version of the current annual report form.
Additionally, PHMSA notes that the information it expects will be
collected within that simplified annual report form--operator corporate
information, length and composition of the system, leaks on that
system, etc.--is minimal information that a reasonably prudent small
LPG operator would maintain in ordinary course given that their systems
transport pressurized (natural, flammable, toxic, or corrosive) gasses.
Viewed against those considerations and the compliance costs estimated
in section V.D herein and the PRIA, PHMSA expects the new annual
reporting requirement for these operators will be a cost-effective
approach to ensuring PHMSA has adequate information to monitor the
public safety and environmental risks associated with small LPG systems
that would no longer be subject to DIMP requirements. Lastly, PHMSA
expects that the compliance timeline proposed for this new reporting
requirement--which would begin with the first annual reporting cycle
after the effective date of any final rule issued in this proceeding
(which would necessarily be in addition to the time since publication
of this NPRM)--would provide affected operators ample time to compile
requisite information and familiarize themselves with the new annual
report form (and manage any related compliance costs).

B. State Pipeline Safety Programs (Sections 198.3 and 198.13)

1. Current Requirements--State Programs and Use of SICT
    PHMSA relies heavily on its State partners for inspecting and
enforcing the pipeline safety regulations. The pipeline safety
regulations provide that States may assume safety authority over
intrastate pipeline facilities, including gas pipeline, hazardous
liquid pipeline, and underground natural gas storage facilities through
certifications and agreements with PHMSA under 49 U.S.C. 60105 and
60106. States may also act as an interstate agent on behalf of DOT to
inspect interstate pipeline facilities for compliance with the pipeline
safety regulations pursuant to agreement with PHMSA.
    To support states' pipeline safety programs, PHMSA provides grants
to reimburse up to 80 percent of the total cost of the personnel,
equipment, and activities reasonably required by the State agency to
conduct its safety programs during a given calendar year. 49 CFR part
198 contains regulations governing grants to aid State pipeline safety
programs. PHMSA also maintains ``Guidelines for States Participating in
the Pipeline Safety Program'' (``Guidelines''), which contains guidance
for how State pipeline safety programs should conduct and execute their
delegated responsibilities.\100\ The Guidelines promote consistency
among the many State agencies that participate under certifications and
agreements and are updated on an annual basis.
---------------------------------------------------------------------------

    \100\ PHMSA, ``Guidelines for States Participating in the
Pipeline Safety Program'' (Jan. 2022), https://www.phmsa.dot.gov/sites/phmsa.dot.gov/files/2020-07/2020-State-Guidelines-Revision-with-Appendices-2020-5-27.pdf.
---------------------------------------------------------------------------

    In 2017, PHMSA adopted within its Guidelines the State Inspection
Calculation Tool (SICT), a tool that helps states conduct an inspection
activity needs analysis for regulatory oversight of every operator
subject to its jurisdiction, for the purpose of establishing a base
level of inspection person-days \101\ needed to maintain an adequate
pipeline safety program.\102\ In the SICT, each State agency considers
the type of inspection it needs to conduct (e.g., standard,
comprehensive, integrity management, operator qualification, damage
prevent activities, drug and alcohol); analyzes each operator's system
for several risk factors (e.g., cast iron pipe, replacement
construction activity, compliance issues); assigns each operator a risk
ranking based on the risk factors (e.g., leak prone pipe would have a
higher score than modern, coated, and cathodically protected pipe); and
lists other unique concerns and considerations (e.g., travel distance
to conduct the inspection) applicable to each operator.\103\ Each State
agency proposes an inspection activity level for each operator, which
is subsequently peer-reviewed before being finalized by PHMSA. PHMSA
expects that each State agency will dedicate a minimum of 85 inspection
person-days for each of its full-time pipeline safety inspectors for
pipeline safety compliance activities each calendar year.\104\ PHMSA
considers a State agency's inspection activity level, among several
other factors, when awarding grants to State pipeline safety programs.
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    \101\ PHMSA proposes below that an inspection person-day means
``all or part of a day, including travel, spent by State agency
personnel in on-site or virtual evaluation of a pipeline system to
determine compliance with Federal or State Pipeline Safety
Regulations.''
    \102\ The SICT is located on PHMSA's access restricted database
portal.
    \103\ Instructions for how to use the SICT and inspection
activity needs analysis examples are in the Guidelines.
    \104\ This 85-day requirement is not tied to each individual
inspector. It is an 85-day average over all inspectors.
---------------------------------------------------------------------------

2. Need for Change--State Programs and Use of the SICT
    A State is authorized to enforce safety standards for intrastate
pipeline facility or intrastate pipeline transportation if the State
submits annually to PHMSA a certification that complies with 49 U.S.C.
60105(b) and (c). As amended in 2020, the certification includes a
requirement that each State agency have the capability to sufficiently
review and evaluate the adequacy of each distribution system operator's
DIMP plan, emergency response plan, and operations, maintenance, and
emergency procedures, as well as ``a

sufficient number of employees'' to help ensure the safe operations of
pipeline facilities, as determined by the SICT. (49 U.S.C. 60105(b)).
PHMSA updates Guidelines and its evaluation process annually to ensure
that State agencies are meeting the certification requirements.\105\
---------------------------------------------------------------------------

    \105\ PHMSA anticipates issuing updated Guidance to reflect the
changes to the Pipeline Safety Grant Program.
---------------------------------------------------------------------------

    In certifying that the State has a ``sufficient number of
employees'', the State must use the SICT to account for:
    1. The number of miles of gas and hazardous liquid pipelines in the
State, including the number of miles of cast iron and bare steel
pipelines;
    2. The number of services in the State;
    3. The age of the gas distribution systems in the State; and
    4. Environmental factors that could impact the integrity of the
pipeline, including relevant geological issues.
    Currently, the SICT accounts for the size (e.g., mileage, service
line count, etc.) of each operator's system; type of operator and
product being transported; risk factors of material composition,
including but not limited to, the presence of cast iron and bare steel;
and environmental factors that could impact the integrity of a
pipeline, including geological issues. Total miles of gas and hazardous
liquid pipelines in a State and the age of gas distribution systems
are, however, only implicitly considered. To comply with the mandate,
PHMSA proposes to codify within its regulations the use of the SICT for
establishing inspection person-days and update the SICT to explicitly
include the total gas or hazardous liquid pipeline mileage in the State
and the age of a gas distribution system as a factor for consideration.
3. PHMSA's Proposal To Codify the Use of the SICT in Pipeline Safety
Regulations
    This NPRM proposes amendments to the pipeline safety regulations at
49 CFR part 198 to codify use of the SICT by all PHMSA's State partners
holding certifications or agreements per 49 U.S.C. 60105 or 60106.
Specifically, PHMSA proposes to revise Sec.  198.3 to add definitions
for ``inspection person-day'' and ``State Inspection Calculation Tool''
and by revising Sec.  198.13 to include the use of the SICT for
determining inspection person-days. PHMSA proposes to define
``inspection person-day'' to mean ``all or part of a day, including
travel, spent by State agency personnel in on-site or virtual
evaluation of a pipeline system to determine compliance with Federal or
State Pipeline Safety Regulations.'' PHMSA will continue to permit
travel to be included for inspection person-days even if travel
requires a full day before or after the inspection because some states
cover a large geographical area that requires substantial travel time
and a State agency's staffing requirement could be impacted if travel
is not considered. PHMSA will also continue to allow inspection person-
days to be counted for those individuals who have not completed
training requirements but who assist in inspections if they are
supervised by a qualified inspector. PHMSA proposes to define the term
``State Inspection Calculation Tool (SICT)'' to mean ``a tool used to
determine the required minimum number of annual inspection person-days
for a State agency.'' These proposed definitions are consistent with
those in the Guidelines.
    PHMSA is required to promulgate regulations to require that a State
authority with a certification under 49 U.S.C. 60105 has a sufficient
number of qualified inspectors to ensure safe operations, as determined
by the SICT and other factors determined appropriate by the Secretary.
(49 U.S.C. 60105 note). Pursuant to this legal requirement, PHMSA
proposes revising Sec.  198.13(c)(6) to state that when allocating
funding and considering various performance factors, PHMSA considers
the number of State inspection person-days, ``as determined by the SICT
and other factors.'' These amendments would codify PHMSA's current
practice of using the SICT in the determination of the minimum number
of inspection person-days each State must dedicate to inspections in a
given calendar year.

C. Emergency Response Plans (Section 192.615)

    The pipeline safety regulations require operators to have written
procedures for responding to emergencies involving their pipeline
systems to ensure a coordinated response to a pipeline emergency. This
response includes communicating with fire, police, and other public
officials promptly. Through a final rule issued on April 8, 2022,
titled ``Requirement of Valve Installation and Minimum Rupture
Detection Standards'', PHMSA extended that emergency communication for
all gas pipeline operators to include a public safety answering point
(PSAP; i.e., 9-1-1 emergency call center).\106\ Among other changes,
the Valve Rule amended Sec.  192.615(a) to ensure proper communication
with PSAPs, requiring operators to immediately and directly notify
PSAPs upon notification of a potential rupture. However, the Valve Rule
requirements were not in effect at the time of the Merrimack Valley
incident.
---------------------------------------------------------------------------

    \106\ 87 FR at 20940, 20973.
---------------------------------------------------------------------------

    Subsequent to the 2018 Merrimack Valley incident, 49 U.S.C. 60102
was amended to improve the emergency response and communications of gas
distribution operators during gas pipeline emergencies in several ways.
Specifically, 49 U.S.C. 60102(r) was added, which requires PHMSA to
promulgate regulations ensuring that gas distribution operators develop
written emergency response procedures for notifying and communicating
with emergency response officials as soon as practicable from the time
of confirmed discovery of certain gas pipeline emergencies; communicate
with the public during and after such a gas pipeline emergency; and
establish an opt-in system for operators to rapidly communicate with
customers. Gas distribution operators must make their updated emergency
response plans available to PHMSA or the relevant State regulatory
agency within 2 years after the final rule is issued, and every 5 years
thereafter (49 U.S.C. 60108(a)(3)).
    PHMSA, in this NPRM, proposes building on the Valve Rule's changes
to emergency response plan requirements through additional changes to
ensure prompt and effective emergency response coordination. For all
gas pipeline operators subject to Sec.  192.615,\107\ PHMSA proposes to
expand the requirements to have procedures for a prompt and effective
response to include emergencies involving notification of potential
ruptures, a release of gas that results in a fatality, and any other
emergencies deemed significant by the operator, with similar
requirements to notify PSAPs in those instances. PHMSA understands
these proposed amendments of existing emergency response plan
requirements as applicable to all part 192-regulated pipelines would be
reasonable, technically feasible, cost-effective, and practicable. The
proposed changes are common-sense, incremental supplementation of
current requirements regarding the content and execution of emergency
response plans for gas pipeline operators.

Implementation of the proposed requirements should not require special
expertise or investment in expensive new equipment; PHMSA expects that
some operators may already comply with these proposed requirements
either voluntarily or due to similar requirements imposed by State
pipeline safety regulators. And insofar as these incremental proposed
additions to emergency planning requirements are consistent with
historical PHMSA guidance, industry operational experience, and the
lessons learned from incidents such as the Merrimack Valley incident,
they are precisely the sort of actions a reasonably prudent operator of
any gas pipeline facility would maintain in ordinary course given that
their systems transport commercially valuable, pressurized (natural
flammable, toxic, or corrosive) gasses. Viewed against those
considerations and the compliance costs estimated in the PRIA, PHMSA
expects its proposed amendments are a cost-effective approach to
achieving the commercial, public safety, and environmental benefits
discussed in this NPRM and its supporting documents. Lastly, PHMSA
understands that its proposed compliance timeline--one year after
publication of a final rule (which would necessarily be in addition to
the time since publication of this NPRM)--would provide operators ample
time to implement requisite changes to their procedures (and manage any
related compliance costs).
---------------------------------------------------------------------------

    \107\ PHMSA notes that Sec.  192.9(d) does not currently require
compliance with Sec.  192.615 for Type B gathering lines, however
PHMSA has proposed, in another rulemaking, to amend Sec.  192.9(d)
to require Type B gas gathering operators to comply with Sec.
192.615. See 88 FR at 31952-53, 31955-56.
---------------------------------------------------------------------------

    PHMSA proposes additional requirements for gas distribution
operators. First, those operators would be subject to an expanded list
of emergencies that includes unintentional releases of gas with
significant associated shutdown of customer services. Second, gas
distribution operators must establish written procedures for
communications with the general public during an emergency, and
continue communications through service restoration and recovery
efforts, to inform the public of the emergency and service restoration
and recovery efforts. Third, gas distribution operators would be
required to develop and implement for their customers an opt-in or opt-
out notification system to provide them with direct communications
during a gas pipeline emergency. PHMSA understands its proposed
amendments enhancing existing emergency response plan requirements
would be reasonable, technically feasible, cost-effective, and
practicable for affected gas distribution operators. PHMSA expects that
some gas distribution operators may already comply with these
requirements either voluntarily or due to similar requirements imposed
by State pipeline safety regulators. PHMSA also expects that operators
will already have (due to the need to bill their customers) the
requisite contact information needed to implement voluntary opt-in or
opt-out notification systems; as explained below, some operators may
also be able to leverage existing emergency notification systems
maintained by local and State government officials in satisfying this
proposed requirement. PHMSA further notes that its proposed
enhancements for emergency communications are precisely the sort of
minimal actions a reasonably prudent operator of gas distribution
pipeline facility would undertake in ordinary course to protect each of
(1) the public safety, given that their systems transport pressurized
(natural, flammable, toxic, or corrosive) gasses; and (2) their
customers, given the economic cost to those customers from interruption
of supply. Viewed against those considerations and the compliance costs
estimated in the PRIA, PHMSA expects its proposed amendments will be a
cost-effective approach to achieving the public safety and
environmental benefits discussed in this NPRM and its supporting
documents. Lastly, PHMSA understands that its proposed compliance
timeline--between 12 to 18 months after publication of a final rule
(which would necessarily be in addition to the time since publication
of this NPRM)--would provide operators ample time to implement
requisite changes to their procedures and procure necessary personnel
and vendor services (and manage any related compliance costs).
    Finally, PHMSA is requesting comments on whether it should require
gas distribution operators to follow incident command systems (ICS)
during an emergency response. PHMSA may consider whether to include
this requirement in any final rule in this proceeding. The sections
below discuss each of these proposals in more detail.
1. Emergency Response Plans--First Responders
a. Current Requirements--Emergency Response Plans--Notifying PSAPs,
First Responders, and Public Officials
    Section 192.615(a) requires that each gas pipeline operator have
written procedures for responding to gas pipeline emergencies,
including for how operators are expected to communicate with fire,
police, and other appropriate public officials before and during an
emergency. The Valve Rule revised Sec.  192.615(a)(2) to add direct
communication with PSAPs in response to gas pipeline emergencies and
required operators to establish and maintain an adequate means of
communication with PSAPs.\108\ Further, the Valve Rule revised Sec.
192.615(a)(8) to require operators to notify these entities and
coordinate with them during an emergency. This communication to the
appropriate PSAPs must occur immediately and directly upon receiving a
notification of potential rupture to coordinate and share information
to determine the location of any release.\109\ The Valve Rule also
revised Sec.  192.615(c) to require each operator establish and
maintain liaison with the appropriate PSAPs ``where direct access to a
9-1-1 emergency call center is available from the location of the
pipeline, as well as fire, police, and other public officials'' to
coordinate responses and preparedness planning.
---------------------------------------------------------------------------

    \108\ PHMSA expects that ``maintaining adequate means of
communication'' should include, but not be limited to, considering
the frequency of communication, changes to the nature of the
emergency, changes to previously liaised information, and updates to
other emergency response information, as determined by the operator.
    \109\ 87 FR at 20983.
---------------------------------------------------------------------------

    Further, PHMSA issued an advisory bulletin in 2012 (ADB-2012-09)
regarding communications between pipeline operators and PSAPs.\110\ In
the advisory bulletin, PHMSA reminded operators that they should notify
PSAPs of indications of a pipeline facility emergency, including an
unexpected drop in pressure, an unanticipated loss of SCADA
communications, or reports from field personnel. In the advisory
bulletin, PHMSA recommended that pipeline operators immediately contact
the PSAPs of the communities in which such indications occur.
Furthermore, the advisory bulletin noted that operators should have the
ability to immediately contact PSAPs along their pipeline routes if
there is an indication of a pipeline emergency to determine if the PSAP
has information that may help the operator confirm whether a pipeline
emergency is occurring or to provide assistance and information to
public safety personnel who may be responding to the event. The
revisions to Sec.  192.615 in the Valve Rule essentially codified this
advisory.

PHMSA notes that indications of a gas pipeline emergency, including
unexpected pressure drops or reports from field personnel, might be a
notification of potential rupture under amended Sec.  192.615, which
would require the direct and immediate notification of the appropriate
PSAP.
---------------------------------------------------------------------------

    \110\ ``Pipeline Safety: Communication During Emergency
Situations,'' ADB-2012-09, 77 FR 61826 (Oct. 11, 2012). PHMSA also
issued draft FAQs on 9-1-1 notification on July 8, 2021.
``Frequently Asked Questions on 911 Notifications Following Possible
Pipeline Ruptures,'' 86 FR 36179 (July 8, 2021). If PHMSA were to
finalize the proposed revisions for these emergency plan provisions
in a subsequent final rule, PHMSA would withdraw the draft 9-1-1
notification FAQs as redundant.
---------------------------------------------------------------------------

b. Need for Change--Emergency Response Plans--Notifying PSAPs, First
Responders, and Public Officials
    During the initial response to the 2018 Merrimack Valley incident,
the three fire departments in the affected municipalities were
inundated with emergency calls from residents and businesses reporting
fires and explosions and requesting assistance shortly after 4 p.m. on
September 13, 2018. Around that same time, the CMA technician reported
smoke and explosions. However, it was not until nearly 4 hours later at
7:43 p.m. that the president of CMA declared a ``Level 1'' emergency
under CMA's emergency response plan. Lawrence's deputy fire chief told
NTSB investigators that, during the incident response, he attempted to
contact CMA through the station dispatch to get a status update to see
if CMA had the gas incident under control but did not receive updates
from the company until hours later. About 2 hours after the initial
fires, Lawrence's deputy fire chief assumed the gas company had
resolved the incident.\111\ The Andover fire chief recognized the
events occurring were gas-related and contacted CMA through a regular
dispatch number to provide status updates so the fire department could
relay information to the public. He told NTSB investigators that CMA
did call him back more than 4 hours later, while also acknowledging the
delay was likely caused by the number of emergency calls CMA received.
---------------------------------------------------------------------------

    \111\ NTSB, PLD18MR003, ``Interview of: Kevin Loughlin, Deputy
Chief Lawrence Fire Department,'' (Sept. 15, 2018), https://data.ntsb.gov/Docket/Document/docBLOB?ID=40476257&FileExtension=.PDF&FileName=Emergency%20Response%20-%20Interview%20of%20Lawrence%20Deputy%20Fire%20Chief-Master.PDF.
---------------------------------------------------------------------------

    The NTSB report noted that CMA had emergency response plans but did
not implement their plans in a manner that would allow them to
effectively respond to such a large incident, explaining that
ambiguities within the operator's emergency response plans could have
contributed to the poor emergency response in that incident.
Specifically, the NTSB pointed out that the operator's emergency
response plans suggested that notification could be discretionary, as
those procedures stated that when an overpressurization of the system
occurs, there ``may be a need'' to communicate with local government
officials and emergency management agencies, as well as with fire and
police departments.\112\ According to the NTSB report, the NiSource
emergency plan also stated that it is ``imperative for all entities
involved to remain informed of each other's activities,'' and that
CMA's Incident Commander (IC), (in this case, the field operations
leader (FOL)) was required to establish appropriate contacts for
communication purposes throughout the incident. However, during the
initial hours of the event, the IC did not establish these requisite
communication contacts because the IC was involved with shutting down
the natural gas system. And although CMA representatives went to
emergency responder staging areas and emergency operations centers, the
NTSB report noted that CMA representatives could not address many of
the questions from emergency responders because the representatives
were not prepared with thorough and actionable information. As a result
of the lack of timely, thorough, and actionable information on the
circumstances of the overpressurization event, emergency responders
unnecessarily evacuated areas, straining limited emergency response
resources, and creating confusion among the public. The NTSB concluded
that CMA was not adequately prepared with the resources necessary to
assist emergency management services with the emergency response.
---------------------------------------------------------------------------

    \112\ NTSB/PAR-19/02 at 46.
---------------------------------------------------------------------------

    Subsequent to the 2018 Merrimack Valley incident, PHMSA was
required by law to promulgate regulations to ensure that gas
distribution system operators include in their emergency response plans
written procedures for notifying ``first responders and other relevant
public officials as soon as practicable, beginning from the time of
confirmed discovery, as determined by [PHMSA], by the operator of a gas
pipeline emergency,'' and including gas distribution-specific
indications of what constitutes a gas pipeline emergency. (49 U.S.C.
60102(r)).
c. Proposal To Amend Sec.  192.615--Emergency Response Plans--Notifying
PSAPs, First Responders, and Public Officials
    As discussed earlier, the Valve Rule revised the existing emergency
response regulations to require operators notify PSAPs in the event of
gas pipeline emergencies, and immediately and directly notify PSAPs
when receiving a notification of potential rupture. In this NPRM, PHMSA
proposes to revise the non-exclusive list at Sec.  192.615(a)(3) of gas
pipeline emergencies requiring all part 192-regulated gas pipeline
operators to undertake prompt, effective response on notification of
potential ruptures; a release of gas that results in one or more
fatalities; and any other emergency deemed significant by the operator.
PHMSA is also proposing that gas distribution pipeline operators would
need to undertake prompt, effective response on notification of the
unintentional release of gas and shutdown of gas service to either 50
or more customers or, if the operator has fewer than 100 customers, 50
percent of total customers. Additionally, PHMSA proposes to amend
existing requirements at Sec.  192.615(a)(8) to apply its requirement
for operators of all gas pipelines to establish written procedures for
immediately and directly notifying PSAPs, or other coordinating
agencies for the communities and jurisdictions in which the pipeline is
located, to include after a notification of these gas pipeline
emergencies. Gas distribution operators, moreover, would also have to
immediately and directly notify PSAPs on notification of an
unintentional release and shutdown of gas services where either 50 or
more customers lose service, or for operators with fewer than 100
customers, if 50 percent of all the operator's customers lose service.
i. What is a ``Gas Pipeline Emergency?''
    PHMSA is revising the list of gas pipeline emergencies in Sec.
192.615(a)(3) to add: (1) for all part 192-regulated gas pipeline
operators, events involving 1 or more fatalities or any other emergency
deemed significant by the operator; and (2) for gas distribution
pipeline operators only, an unintentional release of gas resulting in a
shutdown of gas services affecting at least 50 customers, or for
operators with fewer than 100 customers, 50 percent of customers.\113\
---------------------------------------------------------------------------

    \113\ PHMSA also is adding, applicable to all part 192-regulated
gas pipeline operators, ``potential rupture'', consistent with the
amendment in the Valve Rule to Sec.  192.615(a)(8).
---------------------------------------------------------------------------

    The statutory language does not elaborate on the meaning of
``significant'' within its usage in the phrase ``the unscheduled
release of gas and shutdown of gas service to a significant number of
customers.'' Therefore, PHMSA proposes to establish the threshold for a
``significant number of customers'' to be 50 customers or, for
operators with fewer than 100 customers, 50 percent of all the
operator's customers. In determining this threshold, PHMSA reviewed the

data for all reportable gas distribution incidents from 2010 to 2021
and averaged the number of residential, commercial, and industrial
customers affected by those incidents.\114\
---------------------------------------------------------------------------

    \114\ See PHMSA, ``Distribution, Transmission & Gathering, LNG,
and Liquid Accident and Incident Data'' (Aug. 31, 2022), https://www.phmsa.dot.gov/data-and-statistics/pipeline/distribution-transmission-gathering-lng-and-liquid-accident-and-incident-data.
---------------------------------------------------------------------------

    PHMSA also proposes to add ``other emergency deemed significant by
the operator'' to the list of examples of a gas pipeline emergency to
allow operators to use their best professional judgment when
coordinating with first responders and other relevant public officials
and account for other system-specific circumstances, such as an outage
to a single customer that happens to be a hospital or other critical-
use facility, when complying with Sec.  192.615. This amendment would
specify a non-exclusive list of gas pipeline emergencies.
ii. When must operators communicate with PSAPs, first responders, and
other relevant public officials?
    PHMSA proposes to adopt the aforementioned more-inclusive list of
gas pipeline emergencies into the Sec.  192.615(a)(8) notification
requirements established in the Valve Rule that required the immediate
and direct notification of PSAPs and other relevant emergency
responders and public officials after receiving notice of such an
emergency. Pursuant to 49 U.S.C. 60102(r), operator communications with
first responders and other relevant public officials must occur ``as
soon as practicable, beginning from the time of confirmed discovery, as
determined by the Secretary, by the operator of a gas pipeline
emergency.'' PHMSA, in Sec. Sec.  191.5 and 195.52, already uses the
term ``confirmed discovery'' \115\ to require operators to report
certain events to the National Response Center at the earliest
practicable moment following ``confirmed discovery;'' however, these
notifications may occur up to 1 hour after confirmation. Further, those
Sec. Sec.  191.5 and 195.52 reportable events may not always constitute
a gas pipeline emergency as proposed in Sec.  192.615. Because the 49
U.S.C. 60102(r) mandate directs PHMSA to improve and expand emergency
response efforts--distinct from operator notification of incidents/
accidents for reporting purposes--PHMSA determines that the timing of
local emergency communication must come immediately and directly upon
indication of such a gas pipeline emergency. PHMSA, therefore, does not
propose to interpret ``confirmed discovery'' in 49 U.S.C. 60102(r) to
apply in Sec.  192.615(a) in the same manner as the term is used in 49
CFR parts 191 and 195.\116\ Instead, PHMSA proposes ``confirmed
discovery'' in 49 U.S.C. 60102(r), for purposes of Sec.  192.615, to
mean immediately after receiving notice of a gas pipeline
emergency.\117\ This will bring local emergency services to bear as
near as possible to a gas pipeline emergency based on early
indications, rather than considering whether the gas pipeline emergency
is also a reportable event under Sec.  191.5 before initiating an
emergency response.
---------------------------------------------------------------------------

    \115\ The term ``confirmed discovery,'' defined at Sec. Sec.
191.3 and 195.3, ``means when it can be reasonably determined, based
on information available to the operator at the time a reportable
event has occurred, even if only based on a preliminary
evaluation.''
    \116\ Relying on the same operative phrase (``confirmed
discovery'') that is already used to notify the National Response
Center of reportable incidents risks introducing confusion and
uncertainty with respect to what regulations to follow and how to
incorporate these regulations into response plans for when operators
must contact local emergency responders. In an emergency, clarity is
critical and PHMSA believes that utilizing distinct regulatory
phrases for these different duties will help distinguish and clarify
responsibilities in an emergency response.
    \117\ PHMSA's proposal anticipates that an operator will alert
local emergency response officials upon earliest indications of gas
pipeline emergencies.
---------------------------------------------------------------------------

    PHMSA proposes that gas pipeline emergencies be immediately and
directly communicated to local emergency responders because any delays
in emergency response may make the emergency significantly more
difficult to contain. PHMSA expects that in no case should that
``immediate'' communication to PSAPs begin any later than 15 minutes
following initial notification to the operator of that emergency. This
expectation is consistent with certain criteria for ``notification of a
potential rupture'' adopted in the Valve Rule,\118\ and would ensure
the timely and effective implementation of the pipeline operator's
emergency response plan and coordinated response with local public
safety officials. PHMSA also expects that if a gas pipeline emergency
also meets the criteria of an incident in Sec.  191.3, operators would
report the incident to the National Response Center in accordance with
Sec.  191.5, as already required.
---------------------------------------------------------------------------

    \118\ See Sec.  192.635(a)(1) (specifying a 15-minute time
interval for evaluating significant pressure losses on gas pipelines
as an indicium of a rupture).
---------------------------------------------------------------------------

iii. What information should operators provide to first responders and
public officials?
    As the emergency response to the Merrimack Valley incident
continued, public safety officials asked CMA for detailed information
on the locations of the overpressurized gas lines to aid in assessing
the scope and scale of the incident. Officials requested maps and lists
of impacted customers and impacted streets, but CMA did not provide
them in a timely manner. This significantly hampered the response to
the event and caused first responders to take unnecessary actions
during the immediate response efforts. For example, instead of
targeting specific residents based on the location of the affected
services, first responders needed to go door to door to evaluate safety
impacts and determine where the gas lines were overpressurized. To
prevent such delays from occurring in the future, PHMSA recommends
operators provide first responders and public officials with pertinent
information, as it becomes available, to support emergency
communications during a gas pipeline emergency, including: (1) the
operator's response efforts; (2) information on the gas service sites
impacted by the release; (3) the magnitude of the incident and its
expected impact; (4) the location(s) of the emergency and of affected
customers; (5) the specific hazard and the potential risks; and (6) the
operator point of contact responsible for addressing first responder
and public official questions and concerns. Procedures to provide such
information must be included in their emergency response plans and
should also comport with guidance by the Federal Emergency Management
Agency (FEMA) for State and local governments in developing effective
hazard mitigation planning and would help ensure that appropriate
instructions, directions, and information is provided to the right
people at the appropriate time.\119\
---------------------------------------------------------------------------

    \119\ FEMA, ``Lesson 3: Communicating in an Emergency'' (Feb.
2014), https://training.fema.gov/emiweb/is/is242b/instructor%20guide/ig_03.pdf.
---------------------------------------------------------------------------

2. Emergency Response Plans--General Public
a. Current Requirements--Emergency Response Plans--General Public
    Currently, there are no Federal regulations requiring gas
distribution operators to establish communications with the general
public during or following a gas pipeline emergency. Section 192.615
requires operator

coordination and communication with only fire, law enforcement,
emergency management, and other public safety officials. Section
192.616 contains requirements for public awareness but does not contain
provisions specific to communications with the public during or after
an emergency.\120\
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    \120\ Section 192.616 requires operators to develop and
implement a written continuing public-education program that follows
the guidance provided in American Petroleum Institute's (API)
Recommended Practice (RP) 1162 (incorporated by reference, see Sec.
192.7). API RP 1162 is a consensus standard that establishes a
baseline public-awareness program for pipeline operators. It states
that operators should provide notice of, and information regarding,
their emergency response plans to appropriate local emergency
officials.
---------------------------------------------------------------------------

b. Need for Change--Emergency Response Plans--General Public
    In any gas pipeline emergency, communicating basic information and
a consistent message can be difficult. While communication with
emergency responders is important, so too is contemporaneously updating
affected members of the public, as both serve to reduce public safety
harms. CMA's failure to communicate promptly with its affected
customers throughout the 2018 Merrimack Valley incident showed
deficiencies in CMA's incident response planning. CMA first provided
the public with information regarding the incident at approximately
9:00 p.m. on September 13, 2018--nearly 5 hours after the onset of the
emergency at approximately 4:00 p.m. when the first 9-1-1 calls on the
incident were made. Although CMA was still gathering relevant
information during the first several hours following the incident and
did not have a complete understanding of the situation, it nevertheless
should have conveyed information to the public on the nature of the
incident and affected areas more quickly.
    Subsequent to the 2018 Merrimack Valley incident, PHMSA was
directed in 49 U.S.C. 60102(r) to revise its regulations to ensure that
each gas distribution operator includes written procedures in its
emergency plan for ``establishing general public communication through
an appropriate channel'' as soon as practicable after a gas pipeline
emergency. In particular, operators should communicate to the public
information regarding the gas pipeline emergency and ``the status of
public safety.''
c. PHMSA's Proposal To Amend Sec.  192.615--Emergency Response Plans--
General Public
    Gas distribution pipeline operators are not currently required to
communicate public safety or service interruption and restoration
information to the public during and following a gas pipeline
emergency. Therefore, PHMSA proposes that gas distribution operators
include procedures for establishing and maintaining communication with
the general public as soon as practicable during a gas pipeline
emergency on a gas distribution pipeline. Operators would need to
continue communications through service restoration and recovery
efforts. Operators would need to establish communication through one or
more channels appropriate for their communities, which could include
in-person events (e.g., press conferences or town hall-style events),
print media, broadcast media, the internet or social media, text
messages, phone apps, or any combination of these channels. Further,
PHMSA proposes that such communications must include the following
components:
    1. Information regarding the gas pipeline emergency (which could
include the specific hazard and potential risks to the community, the
location of the incident and boundaries of the impacted area, the
magnitude of the event and the expected impact, protective actions the
public should take, and how long the public may be impacted),
    2. The status of the emergency (e.g., have the condition causing
the emergency or the resulting public safety risks been resolved),
    3. The status of pipeline operations affected by the gas pipeline
emergency and when possible, a timeline for expected service
restoration, and
    4. Directions for the public to receive assistance (e.g., provide a
phone number for customers to call if they are without power for 24
hours, or directions to safe local shelters should temperatures drop
below freezing).
    PHMSA believes that providing in its regulations a list of
information for operators to include in their procedures will help
streamline communications to the public during a gas pipeline emergency
and post-emergency efforts and ensure that members of the public have
information needed to understand the risks to public safety posed by a
gas pipeline emergency. In addition, by providing a list of minimum
requirements for public communications, operators can train personnel
on the type of information they should collect and share with the
public. Operators can require the communication of additional
information in their procedures, but should, at a minimum, inform the
public of the information listed above. During an emergency response,
an operator's resources may be strained such that not all the
information pertaining to the incident may be available at a given
time. Therefore, during a gas pipeline emergency on a distribution
line, operators should provide updates to the public on a reasonable
basis as this information becomes available or changes. This provision
allows for a common-sense approach to when an operator must provide
general public updates to an emergency. However, it would require
operators to provide these updates based on the circumstances of the
emergency such that the general public timely receives information that
could influence the public's response to the emergency or benefit
affected communities' understanding of recovery effort progress.
    Further, PHMSA also proposes that when communicating this minimum
information with the general public, operators must ensure these
messages are issued in English and in other languages commonly
understood by a significant number and concentration of the non-English
speaking population in the operator's service area and are delivered in
a manner accessible to diverse populations in their service operators.
Operators should use clear and simple language in their communications.
The Merrimack Valley incident underscores the value of such broadly
accessible communications. The city of Lawrence, MA, is comprised of a
higher percentage of Spanish-speaking residents than other areas
affected by the Merrimack Valley incident. In the Massachusetts
Emergency Management Agency (MEMA) After Action Report, MEMA reported
that CMA did not fully account for the demographics of the impacted
communities when attempting to communicate with the public during and
following the incident, which in some cases delayed delivery of
appropriate information and services to impacted customers.\121\
---------------------------------------------------------------------------

    \121\ Mass. Emergency Mgmt. Agency & Mass. Nat'l Guard,
``Merrimack Valley Natural Gas Explosions After Action Report,'' at
49-50 (Jan. 2020), https://www.mass.gov/doc/merrimack-valley-natural-gas-explosions-after-action-report/download (``Merrimack
Valley After Action Report'').
---------------------------------------------------------------------------

    Operators must prepare their public communication plans before a
gas pipeline emergency develops to ensure that the proper tools and
resources are available to assist limited English proficiency (LEP)
individuals in the communities they serve when an emergency arises.
PHMSA notes that, as required under Sec.  192.616(g), operators must
conduct their public awareness program in other languages commonly
understood by a significant number and

concentration of the non-English speaking population in the operator's
area. Therefore, operators should already be aware of the languages
used in their service areas and have this information readily
available. If operators do not already have this information, data from
the U.S. Census Bureau American Community Survey at the tract level--
including summarized information on English proficiency along with
mapping of critical infrastructure and locations of hospitals, long-
term care facilities, police, and fire stations--can help provide more
targeted and community-specific services.\122\ Operators can use this
information to understand the demographics of their communities and
build lists of common media sources for each language population in
their service area. More information on how to reach LEP communities in
emergency preparedness, response, and recovery is available through the
Department of Justice.\123\ Where appropriate, operators'
communications during pipeline emergencies should account for
disabilities that might make communication difficult by, for example,
having American Sign Language interpreters present during press
conferences to ensure that hearing-impaired residents can receive
communications during a pipeline emergency.
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    \122\ Ltd. English Proficiency, ``Data and Language Maps,'' U.S.
DOJ, https://www.lep.gov/maps (last visited Feb. 27, 2023).
    \123\ U.S. DOJ, ``Tips and Tools for Reaching Limited English
Proficiency in Emergency Preparedness, Response, and Recovery,''
(2016), https://www.justice.gov/crt/file/885391/download.
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3. Emergency Response Plans--Opt-in System for Customers
a. Current Requirements--Emergency Response Plans--Customers
    As previously discussed, there are currently no Federal regulations
in place that would require gas distribution operators to establish
communications with customers throughout a gas pipeline emergency.
There are also no current Federal requirements in place requiring these
operators establish procedures for developing and implementing an opt-
in communication system whereby customers in their service area can
receive updates of pipeline emergencies on their cell phones or other
media.
b. Need for Change--Emergency Response Plans--Customers
    As the incident unfolded and local leaders made decisions to ensure
the safety of citizens, each community sent their own evacuation
notifications targeting their residents by using 9-1-1 call location
data to estimate the locations of the affected services. Local
officials used this data to reach a consensus about which areas to
evacuate because they were unable to use more accurate data from CMA
regarding the number and location of impacted customers.\124\
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    \124\ Merrimack Valley After Action Report at 46.
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    Andover and North Andover used their existing emergency
notification systems to notify residents to evacuate. Authorities in
North Andover issued a voluntary evacuation for all occupied structures
with natural gas utility service, using local cable channels, the town
website, and a citizen alert telephone system that sends public service
messages. The alert system automatically called every landline.
However, cell phones and private numbers had to be registered to
receive a call. The Andover fire chief called for an evacuation using a
citizen alert telephone system and social media. The wireless emergency
alerts to evacuate South Lawrence, and later to return home, were sent
out in both English and Spanish. The South Lawrence mayor's evacuation
order was issued as an alert over cell phones and media broadcasts to
residents in the area. In total, more than 50,000 residents were asked
to evacuate through a variety of methods.
    While many municipalities have communication systems to rapidly
communicate with their constituents during an emergency, not all gas
distribution operators are using these tools to rapidly communicate
with their customers during a gas pipeline emergency. PHMSA believes
that operators could use these tools to provide customers with real-
time information during an emergency to protect public safety. The
Merrimack Valley incident underscored the need for operators to improve
their communication with customers when responding to an emergency on a
gas distribution pipeline. Subsequently, 49 U.S.C. 60102 was amended to
include a new mandate to expand the use of voluntary, opt-in customer
notifications during an emergency. Specifically, PHMSA was directed to
update its regulations to ensure that each emergency response plan
developed by an operator of a gas distribution system includes written
procedures for ``the development and implementation of a voluntary,
opt-in system that would allow operators of distribution systems to
rapidly communicate with customers in the event of an emergency.'' (49
U.S.C. 60102(r)(3)). PHMSA understands that a ``system'' to ``rapidly
communicate with customers'' could take many forms; however, in
practice, it is typically a ``reverse 9-1-1'' system that calls or
texts individual customers to notify them of significant, time-
sensitive events. Many cities and utilities already use such systems to
allow emergency officials to notify residents and businesses of
emergencies or outages by telephone, cell phone, text message, or
email.
c. Proposal To Amend Sec.  192.615--Emergency Response Plans--Customers
    Pursuant to 49 U.S.C. 60102(r)(3), PHMSA proposes to add to Sec.
192.615 a new paragraph (d) that would require operators of gas
distribution pipelines to establish procedures for developing and
implementing a voluntary, opt-in customer notification system to
communicate with customers in the event of a gas pipeline emergency.
PHMSA understands the statutory mandate for a ``voluntary, opt-in
system'' to mean that the gas pipeline operators give the customers
they serve the opportunity to opt-in (or opt-out) to receiving
notifications from the operator's communication system, therefore
making the system voluntary for customers. Gas distribution operators
must notify all customers of the existence of such a communications
tool and their ability to elect to receive such emergency
notifications.
    PHMSA does not expect that a voluntary, opt-in emergency
notification system would impose a significant burden on operators.
PHMSA notes that operators will often already have from their billing
activities much of the information (customer phone numbers, email and
postal addresses, and preferred language) needed to implement such a
system. And because an iteration of a voluntary, opt-in or opt-out
emergency notification systems may already be in place in some local
communities,\125\ PHMSA concludes that operators could comply with this
proposed requirement by coordinating with cities and townships to
utilize those existing systems. Where coordination with an existing
communication system is not possible, operators may choose to utilize a
third-party vendor or build such a service in-house. Regardless of who
administers the notification system proposed in Sec.  192.615(d),
operators would need to provide a basic description of the system and
describe the operation of the system in their procedures. Operators

must also include in their procedures a description of the protocols
for activating the system and notifying customers (i.e., who initiates
the notification and when). PHMSA notes that such a voluntary opt-in or
opt-out system could have additional benefits outside of gas pipeline
emergencies, as operators could use such a system to communicate with
their customers during non-emergencies (such as service outages or
planned maintenance) or for billing purposes.
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    \125\ PHMSA further understands that some utilities (e.g.,
electric utilities) may have similar notification systems for their
customers and the public within their service areas.
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    Because periodic testing is essential for ensuring proper operation
of such an emergency customer notification system, PHMSA includes
within its proposed Sec.  192.615(d) that operators' procedures must
describe system testing protocols and (at least) annual testing.
Operators would need to maintain the results of their testing and
operations history for at least 5 years. If an operator does not
control the testing protocol (e.g., because they rely on an emergency
notification system administered by a local government), they should
describe in their procedures the frequency of testing performed by
partnered municipality and arrange to receive confirmation of those
tests after they occur.
    Similar to the requirements discussed earlier for public
communications during and following gas pipeline emergencies, PHMSA is
also proposing that an operator's written procedures for this opt-in
notification system include a description of how the system's messages
will be accessible to English-speaking and LEP customers alike.
Operators should describe the process for identifying any LEP or other
pertinent demographic information for the areas they serve. These
procedures should include a description of any non-English languages
required in standardized emergency communications that would be
provided in an operator's system. Because there may be LEP individuals
who need to receive these messages, operators should be prepared to
translate messages about public safety into the required non-English
language(s).
    PHMSA also proposes to require operators' procedures include
cybersecurity measures to protect the notification system and customer
information. As with any system that interfaces with operators'
information technology assets or customers private information,
operators should protect against cybersecurity vulnerabilities and
insider threats. Operators should, for example, include protocols aimed
at protecting their infrastructure from malicious attacks, false
notifications being sent to customers, and theft of customers'
information. If the communication system is operated by a third party,
operators should document the cybersecurity measures managed by the
vendor.\126\
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    \126\ As discussed in Section I.A. of the preamble, the BIL
provides funding for the Natural Gas Distribution Infrastructure
Safety and Modernization Grant Program. Each applicant selected for
grant funding under this notice must demonstrate, prior to the
signing of the grant agreement, effort to consider and address
physical and cyber security risks relevant to their natural gas
distribution system and the type and scale of the project. Projects
that have not appropriately considered and addressed physical and
cyber security and resilience in their planning, design, and project
oversight, as determined by the Department of Transportation and the
Department of Homeland Security, will be required to do so before
receiving funds for construction, consistent with Presidential
Policy Directive 21--Critical Infrastructure Security and Resilience
and the National Security Presidential Memorandum on Improving
Cybersecurity for Critical Infrastructure Control Systems.
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    PHMSA proposes that operators of gas distribution systems must
implement such a voluntary, opt-in notification system in accordance
with their procedures (i.e., ensure that the system is ready for use
during a gas pipeline emergency) no later than 18 months after the
publication of the final rule.\127\ PHMSA proposes that 18 months after
the publication of the final rule in this proceeding is a reasonable
timeframe to implement these new procedures and seeks comment on this
conclusion.
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    \127\ While 49 U.S.C. 60109(e)(7)(C)(i)(II) directs gas
distribution operators to make their updated emergency response
procedures available to PHMSA or the relevant State regulatory
agency no later than 2 years after issuing a final rule, it does not
specify a deadline for operators to have implemented their customer
notification systems.
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4. Emergency Response--Incident Command Systems
a. Background
    Communication during a pipeline emergency is complex and includes
communication between the pipeline operator, other pipeline companies,
non-pipeline utilities, emergency responders, elected officials, PSAPs,
and the public. Effective communication between and within each of
these entities is crucial to the successful response to a gas pipeline
emergency. For this reason, some gas distribution pipeline operators
and other utilities use an Incident Command System (ICS) to coordinate
emergency response actions.
    An ICS is a standardized approach to the command, control, and
coordination of on-scene management of emergencies and other incidents,
providing a common hierarchy within which personnel from multiple
organizations can be effective.\128\ An ICS is the combination of
procedures, personnel, facilities, equipment, and communications
operating within a common organizational structure, designed to aid in
the management of on-scene resources. It can be applied to incidents
(including emergencies and planned events alike) of any size.
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    \128\ FEMA, ``Glossary of Related Terms, E/L/G 0300 Intermediate
Incident Command System for Expanding Incidents, ICS 300'' at 6
(Mar. 2018), https://training.fema.gov/emiweb/is/icsresource/assets/glossary%20of%20related%20terms.pdf.
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    The National Incident Management System (NIMS), a system commonly
used in the public and private sectors of incident management, uses ICS
principles. As stated in the American Gas Association's (AGA) Emergency
Preparedness Handbook, ``[u]tilities across our nation are increasingly
integrating [NIMS] into their planning and incident management
structure.'' \129\ Additionally, API in API RP 1174 recommends the use
of NIMS for responding to accidents on hazardous liquid pipelines.\130\
FEMA has also indirectly recommended the use of NIMS through its
recommendation of National Fire Protection Association (NFPA) Standard
1600 for emergency preparedness, a standard which recommends the use of
NIMS.\131\
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    \129\ AGA, ``Emergency Preparedness Handbook for Natural Gas
Utilities'' at 10, https://www.aga.org/wp-content/uploads/2022/12/aga-emergency-preparedness-handbook-2018.pdf.
    \130\ API Recommended Practice 1174, ``Recommended Practice for
Onshore Hazardous Liquid Pipeline Emergency Preparedness and
Response'' at 26 (1st ed. Dec. 2015).
    \131\ NFPA, ``NFPA 1600: Standard on Continuity, Emergency, and
Crisis Management'' (2019); FEMA, ``Fact Sheet: NIMS Recommended
Standards'' (Jan. 4, 2007), https://www.fema.gov/pdf/emergency/nims/fs_standards_010407.pdf.
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    Typically, local authorities handle most incidents using the
communications systems, dispatch centers, and incident personnel within
their jurisdiction. For larger and more complex incidents, however,
response efforts may rapidly expand to multi-jurisdictional or multi-
disciplinary efforts requiring outside resources and support.
Widespread use of ICSs could allow the efficient integration of outside
resources and enable personnel from anywhere in the Nation to
participate in the incident-management structure. Regardless of the
size, complexity, or scope of the incident, the use of an ICS could
benefit pipeline operators.
    PHMSA is considering an ICS-based system in this rulemaking to
provide safety benefits. However, PHMSA has preliminarily determined
further input from the public would be beneficial in assessing the
feasibility of doing so, as well as the best practices that would

inform such a regulatory standard. Specifically, PHMSA is considering
requirements under Sec.  192.615 for operators of gas distribution
pipelines to follow ICS procedures in response to gas pipeline
emergencies. For example, PHMSA could require that operators of gas
distribution pipelines develop written procedures in accordance with
ICS tools and practices. An example of an ICS practice would be to
identify the roles and responsibilities of emergency responders and
communicate those responsibilities to designated personnel, which would
be similar to the current requirements in Sec.  192.615(c). PHMSA
recognizes the benefit of pipeline operators using ICS for gas pipeline
emergencies, as such an approach can help hone and maintain skills
needed to coordinate response efforts effectively, even as poor
implementation of an ICS may hinder effectiveness. For example, in the
Merrimack Valley incident, both the operator and emergency responders
had an ICS in their respective emergency response manuals; however, the
ICS procedures were implemented with mixed results. While State and
local emergency responders were able to effectively manage, organize,
and coordinate the activities of multiple agencies serving in the
emergency response by following the ICS, the NTSB concluded that CMA's
Incident Commander (IC) struggled to manage the multiple competing
priorities, such as communicating with affected municipalities,
updating emergency responders, and shutting down the natural gas
distribution system, which adversely affected the IC's ability to
complete tasks in a timely manner.\132\ The Merrimack Valley incident
underscores that effective execution of an ICS is still dependent upon
each operator's ability to implement the practices during a crisis.
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    \132\ NTSB/PAR-19/02 at 45-47, 48-49.
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    PHMSA is also considering, if it determines to adopt requirements
for operators of gas distribution pipelines to follow ICS procedures in
response to gas pipeline emergencies, requiring operators to train
personnel on ICS tools and practices. PHMSA expects that to develop an
ICS for a response to gas pipeline emergencies, operator personnel
would need to undergo extensive training and coordination exercises
with first responders, and local and State public safety officials.
FEMA provides free resources for implementing and training on ICS on
their website.\133\ Because this training is free, PHMSA expects there
should be no upfront costs to provide training, however, there would be
a burden in terms of time for operators to (1) take these trainings and
(2) incorporate ICS tools and practices into their training and
emergency response procedures. Further, the ICS tools and guidance are
designed to be integrated into an organization's existing
infrastructure, so PHMSA would not expect operators to have to hire
additional personnel to meet a new requirement in its regulations for
an ICS. PHMSA seeks comment on these assumptions.