the P&M measures for addressing internal and external corrosion in HCAs
and suggested strengthening the proposed provisions further.
    While trade associations and individual operators supported certain
aspects of the proposed provisions covering the P&M measures addressing
external corrosion and internal corrosion in HCAs, these commenters
objected to the specific requirements in Sec.  192.935. Many of these
commenters stated a preference for allowing operators the flexibility
to implement corrosion control based on their own judgment of the
severity of the threat. In general, many industry commenters stated
that individual sections of the proposed provisions were too broad and
prescriptive, and pipeline operators would incur greater costs without
justified benefit. Further, they stated that the monitoring frequency
of twice per year was too frequent. Some commenters recommended that
PHMSA reference ASME standards for implementing P&M measures, and other
commenters stated concern that some of the proposed provisions are not
consistent with NACE standards.
    Many commenters objected to several of the proposed aspects of
internal corrosion control, such as the identification of threats,
monitoring, and filtering, and these commenters stated that operators
should have flexibility in implementing P&M measures. For example,
INGAA opposed the proposed requirement in Sec.  192.935(f) that
requires operators to install continuous gas quality monitoring
equipment at all points in which gas with potentially deleterious
contaminants enters the pipeline. INGAA recommended that Sec.
192.935(f) apply only to pipeline segments with a history of internal
corrosion and stated that this would be consistent with the required
risk analysis that operators perform to determine whether P&M measures
are necessary. Similarly, Atmos Energy recommended that gas sources be
monitored only at those sources suspected, in the judgment of the
operator, of having deleterious gas stream constituents, and that such
monitoring can be performed in real-time or periodically. INGAA stated
that PHMSA should modify proposed Sec.  192.935(g) to require that
operators conduct periodic indirect inspections only where a pipeline
segment has a known history of corrosion.
    During the GPAC meeting on June 6, 2017, committee members
representing the industry reiterated that Sec.  192.935(f) and (g) were
too broad and prescriptive and should not apply to every HCA pipeline
segment indiscriminately. These members, echoing comments made by
INGAA, stated that operators should use their risk assessments to be
used to determine which specific P&M measures are needed in accordance
with the current IM approach.
    The committee also suggested that PHMSA should reference specific
ASME standards for P&M measures and ensure they are consistent with
NACE

standards. Members representing the public suggested PHMSA review the
proposed changes throughout subpart I and ensure that they would be as
enforceable as the proposed P&M measures if the P&M measures were to be
deleted. Members also discussed the fact that distribution operators do
not always have gas monitoring equipment for their lines, as they
depend on the suppliers to monitor the gas quality.
    Following the discussion, the committee voted 9-1 (with a
representative from PST dissenting) that the proposed rule, regarding
the provisions for P&M measures for internal and external corrosion,
were technically feasible, reasonable, cost-effective, and practicable
if PHMSA withdrew the specific provisions discussed in Sec.  192.935(f)
and (g) and appendix E, as the requirements would have been duplicative
with subpart I.
3. PHMSA Response
    PHMSA noted during the GPAC meeting that it was persuaded by
commenters that the changes it is making to the general corrosion
control requirements in subpart I in this final rule are sufficient and
that the additional regulations proposed in Sec.  192.935(f) and (g)
and appendix E were duplicative. The proposed changes to subpart I that
PHMSA is finalizing in this rulemaking apply to pipelines in both HCAs
and non-HCAs, and they were similar to the P&M measures that PHMSA was
proposing regarding corrosion control in HCAs specifically. Therefore,
PHMSA believes that the changes to subpart I in this rule provide the
safety that the proposed changes at Sec.  192.935(f) and (g) intended
to provide. The proposed changes to appendix E incorporated the
proposed definition for ``electrical survey'' and did not contain
further substantive changes. After considering those comments, and as
recommended by the GPAC, PHMSA is withdrawing all the proposed changes
to Sec.  192.935(f) and (g) and appendix E.

D. Inspections Following Extreme Weather Events--Sec.  192.613

1. Summary of PHMSA's Proposal
    Weather events and natural disasters that can cause river scour,
soil subsidence or ground movement may subject pipelines to additional
external loads, which could cause a pipeline to fail. These conditions
can pose a threat to the integrity of pipeline facilities if those
threats are not promptly identified and mitigated. While the existing
regulations provide for design standards that consider the load that
may be imposed by geological forces, weather events and natural
disasters can quickly impact the safe operation of a pipeline and have
severe consequences if not mitigated and remediated as quickly as
possible.
    In the NPRM, PHMSA proposed revising Sec.  192.613 to require that
an operator inspect all potentially affected pipeline facilities after
an extreme weather event to help ensure that no conditions exist that
could adversely affect the safe operation of that pipeline. The
operator would be required to consider the nature of the event and the
physical characteristics, operating conditions, location, and prior
history of the affected pipeline in determining the appropriate method
for performing the inspection required. The NPRM's proposed revisions
to Sec.  192.613 also provided that the initial inspection must occur
within 72 hours after the cessation of the event, defined as the point
in time when the affected area can be safely accessed by available
personnel and equipment required to perform the inspection. If an
operator finds an adverse condition, the NPRM' s proposed revisions to
Sec.  192.613 would require an operator to take appropriate remedial
action to ensure the safe operation of a pipeline based on the
information obtained because of performing the inspection.
2. Summary of Public Comment
    The PST, NAPSR, and EnLink Midstream supported the proposed
amendments to Sec.  192.613, with many other stakeholders supporting
the intent of the proposed provisions but requesting further
clarification on some of the terms used within the proposal.
    Some commenters expressed concern with the broad requirements of an
``inspection'' and requested PHMSA clarify what an inspection following
an extreme weather event would entail. Additionally, these stakeholders
stated that the proposed definition of an extreme weather event was
vague and requested clarification. INGAA stated that operators are
already required to have procedures to ensure a prompt and effective
response to emergency conditions through Sec.  192.615 and suggested
that to avoid duplicative regulation, PHMSA should instead modify Sec.
192.615(a)(3) to incorporate additional specificity on weather events
that may trigger a response.
    Many commenters objected to the proposed timeframe, stating that
the 72-hour requirement listed in the rule could be problematic.
Commenters stated that PHMSA should allow operators to determine when
an impacted area can be safely accessed, and that pipeline operators
are best positioned to evaluate the balance between the safety and the
need for inspections to ensure continued safe operation of their
systems. INGAA stated that the 72-hour requirement should either be
replaced with a more general statement such as ``as soon as
practicable,'' or that PHMSA should create a process to request an
exception to the requirement. Louisiana Mid-Continent Oil and Gas
Associations stated that extreme weather events vary significantly by
region and commented that not all local geography and extreme weather
events are the same. They further stated that the 72-hour deadline for
inspection may be too prescriptive depending on the extreme weather
event. They stated that because Louisiana is subjected to many unusual
extraordinary events, such as spillway openings, high/low river flows,
and rainwater flooding, PHMSA should clarify what ``other events''
means and how the cessation of an event is determined.
    At the GPAC meeting of January 12, 2017, members noted concerns
with the provisions as proposed but voted 12-0 that the provisions were
technically feasible, reasonable, cost-effective, and practicable if
PHMSA modified the proposed rule to clarify that the timing for this
provision is to begin after the operator has made a reasonable
determination that the area is safe, clarify in the preamble that
operators are encouraged to consult with pipeline safety and public
safety officials in order to make such determinations, delete the
phrase ``whichever is sooner'' at the end of Sec.  192.613(c)(2), and
change the word ``infrastructure'' to ``facilities.''
3. PHMSA Response
    PHMSA agrees that an operator's ability to inspect a pipeline
facility following an extreme weather event may vary greatly depending
on the type of extreme weather event that has taken place and the
specific location of the event. The NPRM's proposed revisions to Sec.
192.613 would require operators to inspect its pipeline facilities
after the cessation of an extreme weather event. Cessation of the event
was defined as the point of time when the affected area could be safely
accessed by the personnel and equipment, including availability of
personnel and equipment, required to perform the inspection. However,
in consideration of the comments received, PHMSA is persuaded that
additional clarification is warranted and that 72 hours after the
cessation of the event may not be enough time in all cases for operator
personnel and equipment to assess and inspect a pipeline safely.

    Therefore, as recommended by the GPAC, PHMSA has modified this
final rule to require an operator perform an initial inspection 72
hours after the operator reasonably determines that the affected area
can be safely accessed by personnel and equipment, and the necessary
personnel and equipment required to perform such an inspection are
available. PHMSA encourages operators to consult with pipeline and
public safety officials, including the appropriate PHMSA regional
office, when making these determinations. If an operator is unable to
commence the inspection in the 72-hour timeframe due to the
unavailability of personnel or equipment, the operator must notify the
appropriate PHMSA Region Director as soon as practicable.
    If an operator finds an adverse condition, the operator must take
appropriate remedial action to ensure the safe operation of a pipeline
based on the information obtained from the inspection. Such actions
might include, but are not limited to:
     Reducing the operating pressure or shutting down the
pipeline;
     Isolating pipelines in affected areas and performing
``stand up'' leak tests;
     Modifying, repairing, or replacing any damaged pipeline
facilities;
     Preventing, mitigating, or eliminating any unsafe
conditions in the pipeline rights-of-way;
     Performing additional patrols, depth of cover surveys and
adding cover over the pipeline, ILI or hydrostatic tests, or other
inspections to confirm the condition of the pipeline and identify any
imminent threats to the pipeline;
     Implementing emergency response activities with Federal,
State, or local personnel; and
     Notifying affected communities of the steps that can be
taken to ensure public safety.
    PHMSA would not expect operators to comply with these provisions
for weather or other disruptive events when, considering the physical
characteristics, operating conditions, location, and prior history of
the affected system, the event would not be expected to impact the
integrity of the pipeline. For example, extreme weather events would
not include rain events that do not exceed the high-water banks of the
rivers, streams or beaches in proximity to the pipeline; rain events
that do not result in a landslide in the area of the pipeline; storms
that do not produce winds at tropical storm or hurricane level
velocities; or earthquakes that do not cause soil movement in the area
of the pipeline.
    PHMSA is also modifying Sec.  192.613(c) introductory text and
(c)(1) as the GPAC recommended, by removing the phrase ``whichever is
sooner'' and replacing the term ``infrastructure'' with ``facilities.''
As discussed during the GPAC meeting, ``pipeline facilities'' is a
defined term at Sec.  192.3, and the use of that term will likely
provide additional clarity.

E. Strengthening Requirements for Assessment Methods--Sec. Sec.
192.923(b) & (c), 192.927, 192.929

i. Internal Corrosion Direct Assessment (ICDA)--Sec. Sec.  192.923(b) &
192.927
1. Summary of PHMSA's Proposal
    The current regulations do not specify the quality and
effectiveness of ICDA. NACE International submitted a petition for
rulemaking on February 11, 2009, requesting that PHMSA address this
issue. In the NPRM, PHMSA proposed amendments to Sec. Sec.  192.923(b)
and 192.927 to incorporate by reference NACE SP0206-2006 and further
supplement the NACE standard to address issues observed by PHMSA.
    For indirect inspections, PHMSA proposed to require that operators
use pipeline-specific data, exclusively in performing an indirect
inspection, and that the use of assumed pipeline or operational data
would be prohibited. PHMSA also proposed operators be required to
consider the accuracy, reliability, and uncertainty of data used to
make calculations regarding the critical inclination angle of liquid
holdup and the inclination profile of pipelines. Further, PHMSA
proposed that operators be required to select locations for direct
examination and establish the extent of pipe exposure needed, to
explicitly account for these uncertainties and their cumulative effect
on the precise location of predicted liquid dropout.
    For detailed examinations as defined in NACE SP0206-2006, PHMSA
proposed to require that operators identify a minimum of two locations
for excavation within each covered segment associated with the ICDA
Region and perform a detailed examination for internal corrosion at
each location using ultrasonic thickness measurements, radiography, or
other generally accepted measurement techniques. One required location
would be the low point within the covered segment nearest to the
beginning of the ICDA Region. The second required location would be
near the end of the ICDA Region within the covered segment. If
corrosion was found at any location, the operator would be required to
evaluate the severity of the defect, expand the detailed examination
program to determine all locations that have internal corrosion within
the ICDA region, and expand the detailed examination program to
evaluate the potential for internal corrosion in all pipeline segments
(both covered and non-covered) with similar characteristics to the ICDA
Region in the operator's pipeline system.
    For post-assessment evaluation and monitoring, PHMSA proposed to
require that operators evaluate the effectiveness of ICDA as an
assessment method for addressing internal corrosion and determining
whether a covered segment should be reassessed at more frequent
intervals than those currently specified in the regulations at Sec.
192.939. PHMSA also proposed to require that operators validate their
flow modeling calculations by comparing locations of discovered
internal corrosion with locations predicted by the model. Additionally,
PHMSA proposed to require that operators continually monitor each ICDA
Region that contains a covered segment where internal corrosion was
identified and by periodically drawing off liquids at low points and
chemically analyzing the liquids for the presence of corrosion
products.
    Finally, PHMSA proposed to require that operators include in their
plans the criteria used in making key decisions in implementing each
stage of the ICDA process and provisions that the analysis be carried
out on the entire pipeline in which covered segments are present.
2. Summary of Public Comment
    NAPSR expressed its agreement with, and support for, the proposed
revisions to Sec. Sec.  192.923(b) and 192.927. Multiple pipeline
operators and industry trade associations commented that the proposed
provisions should simply incorporate the NACE standard by reference,
and should not exceed those established industry standards, be rigidly
prescriptive, or otherwise be mandatory. PG&E, commenting on the
incorporation of standards by reference, requested PHMSA replace the
phrase ``as required by'' with ``in accordance with'' so that operators
can meet the substantial requirement but have flexibility in the
implementation of that requirement if the industry publishes new
techniques to perform ICDA. NACE International expressed its belief
that, as described in NACE SP0206-2006, ICDA is an acceptable
standalone methodology for assessing pipeline integrity.
    Atmos Energy commented that the proposed mandated monitoring for
all ICDA regions would be potentially excessive and recommended that
PHMSA delete the proposed language and restore the current language at

Sec.  192.927(c)(4)(ii).\29\ Another commenter recommended that PHMSA
remove the proposed notification requirement prior to an operator
performing an ICDA, noting that operators currently provide this
information as part of other annual reporting.
---------------------------------------------------------------------------

    \29\ PHMSA regulations at Sec.  192.927(c)(2) define an ICDA
region as a continuous length of pipe (including weld joints),
uninterrupted by any significant change in water or flow
characteristics, that includes similar physical characteristics or
operating history. An ICDA region extends from the location where
liquid may first enter the pipeline and encompasses the entire area
along the pipeline where internal corrosion may occur until a new
input introduces the possibility of water entering the pipeline.
---------------------------------------------------------------------------

    At the GPAC meeting on December 15, 2017, the GPAC committee voted,
13-0, to revise Sec. Sec.  192.923(b)(2) and (3) and 192.927 according
to the recommendations by PHMSA staff at the meeting, which included
supplementing the NACE standard with additional requirements to address
specific issues that could adversely affect ICDA results.
3. PHMSA Response
    PHMSA believes that it is appropriate to address ICDA by
incorporating by reference the NACE standard and supplementing it with
additional requirements pertaining to indirect inspections (a step in
the NACE standard's ICDA process to help in determining where direct
assessments need to be made), detailed examinations, and post-
assessments. For indirect inspections, PHMSA has implemented additional
requirements regarding the data an operator must use and accounting for
uncertainties in that data. Where an indirect inspection demonstrates
that detailed examinations are needed, PHMSA is expanding the
examinations that an operator must perform to evaluate for the
potential for internal corrosion in all pipeline segments if corrosion
is found in the ICDA region. Regarding post-assessments, PHMSA is
requiring operators to evaluate the effectiveness of ICDA as an
assessment method and determine whether a covered segment should be
reassessed more frequently than the intervals specified at Sec.
192.939. Additionally, PHMSA is requiring operators validate the flow
modelling calculations they use in the ICDA process as well as
continually monitor each ICDA region that contains a covered segment
where internal corrosion has been identified.
    When the first IM regulations were promulgated in the 2003 IM rule,
there was no consensus industry standard for ICDA that could be adapted
or incorporated into the regulations to promote better pipeline safety
regarding internal corrosion. Incorporating by reference the NACE
standard into the regulations would improve pipeline safety because the
NACE standard (1) typically requires more direct examinations than the
current regulatory requirements; (2) encompasses the entire pipeline
segment and requires that all inputs and outputs be evaluated; and (3)
is considered by many to be an equivalent or superior indirect
inspection model compared to the Gas Technology Institute (GTI) model
currently referenced in Sec.  192.927. Its range of applicability with
respect to operating pressure is greater than the GTI model, thus
allowing the use of ICDA in pipelines with lower operating pressures
and higher flow velocities.
    The existing requirements in Sec.  192.927 have one aspect that has
proven problematic: the definition of regions and requirements for
selection of direct examination locations in the regulations are tied
to the covered segment. A ``covered segment'' is defined in Sec.
192.903 as ``a segment of gas transmission pipeline located in a high
consequence area.'' The terms ``gas'' and ``transmission line'' are
defined in Sec.  192.3. Therefore, covered segment boundaries are
determined by population density and other consequence factors without
regard to the orientation of the pipe and the presence of locations at
which corrosive agents may be introduced or may collect and where
internal corrosion would most likely be detected (e.g., low spots).
Section 192.927 requires that locations selected for excavation and
detailed examination be within covered segments, meaning that the
locations at which internal corrosion would most likely be detected may
not be examined. Thus, the existing requirements do not always
facilitate the discovery of internal corrosion that could affect
covered segments. PHMSA is addressing this problem in this final rule
by incorporating NACE SP0206-2006 and by expanding the detailed
examination program, whenever internal corrosion is discovered, to
determine all locations that have internal corrosion within the ICDA
region.
    PHMSA believes requiring a notification requirement for operators
is important so that PHMSA can review the specific proposal to use a
standard to assess pipe segments that are explicitly excluded from the
scope of the standard. PHMSA has also revised Sec.  192.927(c) to
clarify that an operator must conduct the ICDA process ``in accordance
with'' the NACE standard to avoid the implication that all non-
mandatory recommendations contained in the standard are required.

E. Strengthening Requirements for Assessment Methods--Sec. Sec.
192.923(b) & (c), 192.927, 192.929

ii. Stress Corrosion Cracking Direct Assessment (SCCDA)--Sec. Sec.
192.923 & 192.929
1. Summary of PHMSA's Proposal
    The current regulations do not specify a number of issues that
affect the quality and effectiveness of SCCDA integrity assessments.
Specifically, Appendix A3 of ASME/ANSI B31.8S, which is referenced in
the regulations, provides some guidance for conducting SCCDA, but the
guidance is limited to stress corrosion cracking (SCC) that occurs in
high-pH environments. NACE International submitted a petition for
rulemaking to PHMSA on February 11, 2009, requesting that PHMSA address
this issue by incorporating by reference NACE SP0204-2008, which
addresses near-neutral SCC in addition to high-pH SCC. Accordingly, in
the NPRM, PHMSA proposed changes to Sec. Sec.  192.923 and 192.929 to
incorporate by reference NACE SP0204-2008 and supplement the NACE
standard to address issues observed by PHMSA in the areas of data
gathering and integration, indirect inspection, direct examinations,
remediation and mitigation, and post-assessments.
    PHMSA proposed to require an operator's SCCDA plan to evaluate the
effects of a carbonate-bicarbonate environment; the effects of cyclic
loading conditions on the susceptibility and propagation of SCC in both
high-pH and near-neutral-pH environments; the effects of variations in
applied CP, such as overprotection, CP loss for extended periods, and
high negative potentials; the effects of coatings that shield CP when
disbonded from the pipe; and other factors that affect the mechanistic
properties associated with SCC.
    For indirect inspections, PHMSA proposed to require an operator's
plan include provisions for conducting at least two above-ground
surveys using complementary measurement tools most appropriate for the
pipeline segment based on the data gathered.
    For direct examinations, PHMSA proposed to require an operator's
procedures provide for conducting a minimum of three direct
examinations within the SCC segment at locations determined to be the
most likely for SCC to occur.
    For post-assessments, PHMSA proposed to require that the operator's
procedures include the development of a reassessment plan based on the

susceptibility of the operator's pipe to SCC as well as on the
mechanistic behavior of identified cracking.
2. Summary of Public Comment
    Multiple commenters supported the proposed changes to Sec.  192.929
for SCCDA. NAPSR expressed its agreement with, and support of, these
revisions. Spectra Energy Partners (SEP), which merged with Enbridge in
2017, provided comments in support of the proposed inclusion of
explicit requirements for SCCDA. SEP expressed its belief that SCCDA is
a diligent, practicable approach for assessments for SCC for cases
where the pipeline has not previously experienced an in-service failure
caused by SCC and provided specific edits to make the proposed
requirements for SCCDA clearer and more practicable. A commenter
recommended that the requirements for SCCDA specify that an operator is
required to conduct assessments in areas that are most likely to be
subject to SCC regardless of HCA designation.
    Several other commenters questioned or opposed the proposed changes
to Sec.  192.929. Several commenters, including API, expressed their
support of NACE standards SP0204-2008 for SCCDA but recommended that
PHMSA not exceed those established industry standards and should not
make the recommendations within those standards mandatory. NACE
International stated it was unaware of any conclusive data regarding
overprotection or high-negative potentials as a factor in SCC of
pipelines, which is what the NPRM's proposed revisions to Sec.  192.929
suggested. Additionally, NACE International commented that PHMSA went
beyond the practices stated in NACE Standard SP0204-2008 by proposing
to require a minimum of two above-ground surveys and three direct
examinations.
    INGAA proposed to clarify the way in which SCCDA can be used as an
IM method, asserting that SCCDA is a valid method to assess SCC threats
in gas pipeline segments that are susceptible to, but have no history
of, SCC.
    Other commenters provided specific technical comments regarding
these proposed provisions. TransCanada asserted that applying the NACE
``significant SCC'' definition as the threshold for immediate repair is
both overly conservative and overly complicated, and they suggested
that PHMSA instead adopt the threshold of ``noteworthy'' as defined in
ASME STP-PT-011.
    Enable Midstream Partners (EMP) agreed that operators should
consider the specific factors PHMSA proposed in Sec.  192.929(b)(1) and
(4) as part of the data gathering and integration and post-assessment
remediation and mitigation process for SCCDA. However, EMP asserted
that PHMSA should clarify these sections by including a referenced
standard that provides guidance to operators on how they should
consider these specific factors. Another commenter stated that PHMSA
should include a reference to ASME/ANSI B31.8S, Appendix A3, for
susceptibility criteria.
    Commenters also suggested that PHMSA allow operators to use sound
engineering judgments when calculating the remaining strength of the
pipeline segment if the segment is subject to the pipeline material
properties and attributes verification requirements of Sec.  192.607
and those requirements have not yet been met.
    At the GPAC meeting on December 15, 2017, the committee recommended
PHMSA revise the approach proposed in the NPRM by making the changes to
these provisions that were recommended by PHMSA staff during the
meeting, which were to replace the spike hydrostatic pressure test
requirements with a reference to Sec.  192.506(e) to eliminate
redundancy; address the gap pertaining to failure pressure calculations
when data is not available; codify, as applicable, the expectation that
the recommendations within the NACE standard are not mandatory;
communicate additional guidance as needed during rule implementation;
and consider how to structure the rule to apply results from non-HCAs
to HCAs.
3. PHMSA Response
    When the first IM rule was promulgated in 2003, there was no NACE
standard for SCCDA. Additionally, the requirements pertaining to SCC in
ASME/ANSI B31.8S, Appendix B, only applied to pipe susceptible to high
pH SCC (i.e., pipelines susceptible to near-neutral SCC were not
addressed). Therefore, PHMSA believes that incorporating by reference
the NACE standard and supplementing it with additional requirements to
address issues it has observed related to data gathering and
integration, indirect inspection, direct examinations, remediation and
mitigation, and post-assessments, is an appropriate way to address
SCCDA.
    For data gathering and integration, PHMSA is requiring that
operators gather and evaluate data related to SCC at all sites an
operator excavates while conducting its pipeline operations where the
criteria in NACE SP0204-2008 indicate the potential for SCC. Per this
final rule, operators must additionally analyze the effects of a
carbonate-bicarbonate environment, cyclic loading conditions,
variations in applied CP, the effects of coatings that shield CP when
disbonded from the pipe, and other factors that would affect the
mechanics of SCC. For indirect inspections, PHMSA is requiring
operators conduct at least two above-ground surveys using the
measurement tools most appropriate for the pipeline segment based on an
evaluation of the collected data. An operator's plan for direct
examination must include a minimum of three direct examinations within
the SCC segment at the locations where SCC would be most likely to
occur. If an operator finds any indication of SCC in a segment, an
operator must perform specific mitigation measures. Further, in this
final rule, an operator must develop procedures for post-assessments
based on the susceptibility of the pipeline segment to SCC as well as
the mechanical behavior of identified cracking. Regarding EMP's comment
stating that PHMSA should provide guidance to operators on how they
should consider specific factors as a part of the data gathering and
integration process by referring to a standard incorporated by
reference within PHMSA regulations, as well as the comment recommending
that PHMSA incorporate a reference to ASME/ANSI B31.8S, Appendix A3,
for susceptibility criteria, PHMSA declines to incorporate by reference
such standards because it could limit operators from considering all of
the factors that they should.
    PHMSA also agrees with commenters that referring to Sec.  192.506,
Transmission lines: Spike hydrostatic pressure test, in Sec.  192.929
is preferred instead of repeating the spike hydrostatic test
requirements and has changed this final rule accordingly. PHMSA
addressed the comment about determining predicted failure pressure when
needed data are not available by referencing Sec.  192.712, which
explicitly provides an operator with conservative assumptions and
alternatives for material toughness values, material strength, and pipe
dimensions and other data, in lieu of documented material properties.

F. Repair Criteria--Sec. Sec.  192.714, 192.933

    PHMSA identified several improvements to the IM repair criteria
based on its experience gained since the IM rule became effective in
2004; ongoing research and development, including developments in ASME/
ANSI B31.8S; and investigations into recent incidents. In the NPRM,
PHMSA

proposed adjustments to the existing repair criteria for anomalies
discovered in HCAs and proposed new repair criteria for anomalies found
outside of HCAs.\30\
---------------------------------------------------------------------------

    \30\ The GPAC voted on each section of the repair criteria
separately, and each section is discussed in more detail below.
---------------------------------------------------------------------------

F. Repair Criteria--Sec. Sec.  192.714, 192.933

i. Repair Criteria in HCAs--Sec.  192.933
1. Summary of PHMSA's Proposal
    In the NPRM, PHMSA proposed to add more immediate repair conditions
and more 1-year repair conditions for HCA pipeline segments in Sec.
192.933. The specific anomalies and repair schedules for cracks, dents,
and corrosion metal loss are discussed in their respective sections
below. In certain cases, like for SCC and selective seam weld corrosion
anomalies that were new to the repair criteria, PHMSA proposed to
require that operators repair ``any indication of '' such anomalies. In
other cases, such as for dents, PHMSA did not make significant changes
to the existing repair criteria at Sec.  192.933, which require the
repair of ``any indication of '' metal loss, cracking, or a stress
riser.
2. Summary of Public Comment
    Public advocacy groups, including Pipeline Safety Coalition, the
PST, and Clean Water for North Carolina, supported the proposed
provisions that would strengthen the existing repair criteria at
Sec. Sec.  192.713 (non-HCAs) and 192.933 (HCAs). Additionally, NAPSR
and the NTSB supported PHMSA's proposed repair criteria revisions.
    There was common agreement from pipeline operators and the industry
trade associations that the processes for HCA repairs and non-HCA
repairs should be standardized. However, the trade associations and
pipeline operators generally believed that the proposed provisions at
Sec. Sec.  192.713 and 192.933 were too prescriptive and would impede
operators from performing repairs based on risks. They further stated
that the proposed provisions do not take into consideration other
factors that operators currently consider when optimizing plans to
remediate anomalies, such as historical data, geography, and congestion
of the right-of-way.
    Some of the commenters representing the industry recommended PHMSA
eliminate all references to the words ``any indication of '' within the
proposed revisions to Sec. Sec.  192.713 and 192.933 when applied to
anomalies needing repair so that it is the confirmed presence of a
condition that requires a repair instead. These commenters stated that
requiring operators to repair an ``indication of '' certain anomalies
would cause needless repairs and misallocate resources. Spectra Energy
stated that PHMSA's annual report data indicates that only one repair
is required for every three anomaly investigations, which demonstrates
that the existing anomaly response criteria operators have implemented
are appropriately conservative.
3. PHMSA Response
    Based on PHMSA's annual report data, the number of immediate
repairs have remained relatively constant even though the baseline
assessment period has concluded. PHMSA understands that this is likely
the result of operators deferring repair of non-immediate conditions
until the defect progresses into an immediate repair condition, rather
than immediate conditions arising spontaneously. PHMSA understands that
most defects that become immediate repair conditions are observable by
ILI equipment well in advance of progression to an immediate repair
condition. The repair criteria in this final rule are intended to
assure that anomalies are repaired before they become an immediate
condition and are at or near failure. In this final rule, PHMSA has
included reference to ASME/ANSI B31.8S within each of Sec. Sec.
192.714 and 192.933 to take into consideration other factors that
operators currently consider when establishing remediation plans.
    In this final rule, PHMSA has removed the proposed repair criteria
under Sec. Sec.  192.714 (non-HCAs) and 192.933 (HCAs) for SCC and
selective seam weld corrosion, which were new repair criteria that
contained the phrase ``any indication of.'' PHMSA combined SCC and
selective seam weld corrosion repair criteria into a more general
cracking repair criteria because each of these phenomena is, or results
in, cracking. PHMSA included remediation measures for SCC under the
requirements at Sec.  192.929, which are the requirements for using
direct assessment for SCC but did not require the remediation of ``any
indication of '' SCC. PHMSA was not proposing to change any of the
existing repair criteria that referenced ``any indication of,'' such as
that for dents with any indication of metal loss, cracking, or a stress
riser. Those repair criteria remain unchanged in this final rule.

F. Repair Criteria--Sec. Sec.  192.714, 192.933

ii. Repair Criteria in Non-HCAs--Sec.  192.714
1. Summary of PHMSA's Proposal
    In the NPRM, PHMSA proposed at Sec.  192.713 repair criteria for
non-HCA areas to assure that operators promptly repair injurious
defects that are discovered outside of HCAs. These proposed repair
criteria for non-HCAs were based on, and were similar, to, the repair
criteria (regarding structure, anomaly types, and the repair
timeframes) for HCA pipeline segments proposed at Sec.  192.933.
    For those anomalies for which a 1-year response is required on HCA
pipeline segments, PHMSA proposed that a 2-year response would be
required in non-HCA pipeline segments. This proposal would require
operators to remediate anomalous conditions on gas transmission
pipeline segments promptly and commensurate with the risk they present,
while allowing operators to allocate their resources to those anomalies
in HCAs that present a higher risk.
    The specific anomalies and repair schedules for cracks, dents, and
corrosion metal loss are discussed in their respective sections below.
2. Summary of Public Comment
    Citizen groups, including Pipeline Safety Coalition, the PST, and
Clean Water for North Carolina, supported the proposed provisions that
would strengthen the repair criteria for HCAs and non-HCAs.
Additionally, NAPSR and the NTSB supported PHMSA's revisions to the
repair criteria.
    Generally, the industry trade associations and pipeline operators
supported PHMSA's intention of establishing repair criteria outside of
HCAs but disagreed with some of the specific provisions. There was
common agreement, however, that the processes for HCA repairs and non-
HCA repairs should be standardized.
    The trade associations and pipeline operators generally believed
that the proposed provisions were too prescriptive and would impede
operators from performing repairs based on risks. They further stated
that the proposed provisions do not take into consideration other
factors that operators currently consider when optimizing plans to
remediate anomalies, such as historical data, geography, and congestion
of the right-of-way.
    AGA recommended that PHMSA create a new subpart to address
assessment requirements outside of

HCAs and add a section within that subpart to cover repair criteria.
Several other trade associations and pipeline operators echoed AGA's
recommendations.
    Several industry commenters also stated that the rulemaking did not
demonstrate that the safety benefit of strengthened repair criteria
outweighs the costs. Multiple operators stated that the proposed repair
provisions in Sec.  192.713 would increase the number of digs operators
would need to perform and asserted that the increased number of digs
may not improve pipeline safety.
    Certain commenters suggested that it would not be appropriate for
PHMSA to require operators to repair immediate conditions in non-HCAs
before repairing immediate conditions in HCAs, and that PHMSA should
require operators to prioritize those conditions discovered within HCAs
if operators discover multiple immediate conditions in HCAs and non-
HCAs simultaneously. More specifically, AGA requested that the rule
explicitly prioritize immediate conditions within HCAs over immediate
conditions in other locations when conditions are discovered
simultaneously and recommended that PHMSA adopt different terminology
for ``immediate repair conditions'' inside and outside HCAs. Similarly,
other industry trade organizations expressed concern that the proposed
provisions for non-HCAs would complicate the allocation of resources to
HCAs on a higher-priority basis when confronted with the large number
of new, non-HCA pipelines needing assessments.
    Commenters also requested PHMSA make the sections pertaining to
non-HCA repairs and HCA repairs consistent regarding pressure
reductions. Commenters representing the industry noted that, as
proposed, certain notification requirements for long-term pressure
reductions or for those operators unable to respond within the given
timeframe were different depending on whether the pipeline was in an
HCA or a non-HCA. These commenters suggested that those notification
procedures be made consistent, wherever possible, between the HCA and
non-HCA repair criteria. Multiple trade associations and pipeline
industry entities also expressed concerns that the proposed provisions
requiring ``an operator to reduce the operating pressure of its
affected pipeline until it can remediate the immediate repair
conditions'' are unnecessarily conservative. INGAA asserted that the
proposed pressure reduction requirements for non-HCAs are more
stringent than the pressure reductions requirements for HCAs, and
several commenters offered alternative methods for determining
appropriate operating pressure reductions. Specifically, these
commenters requested PHMSA allow operators to take a pressure reduction
other than 80 percent if they documented the analysis performed and
assumptions used. These commenters claimed that, as proposed in the
NPRM, operators were allowed to use a different pressure reduction in
HCAs if an analysis supported it but were not allowed to do so in non-
HCAs.
    During its meeting in late March 2018, the GPAC recommended PHMSA
clarify that pressure reductions would be required for immediate
conditions in non-HCAs and in cases where repair schedules could not be
met. As a part of this recommendation, the GPAC also recommended that
operators notify PHMSA when they could not meet the schedule for
anomaly evaluation and remediation or when a temporary pressure
reduction exceeds 365 days. The GPAC also recommended that PHMSA should
allow operators to calculate pressure reductions (following the
discovery of repairable conditions) by using either class location
factors, or 80 percent of the operating pressure, or 1.1 times the
predicted failure pressure. The GPAC also recommended PHMSA require
that operators document and keep records, for 5 years, of the
calculations and decisions used to determine such pressure reductions
and the implementation of the actual reduced operating pressure.
Further, the GPAC recommended PHMSA avoid duplicating language
regarding the need for repairs and pressure reductions found in other
sections of the regulations.
3. PHMSA Response
    In the 2019 Gas Transmission Rule, PHMSA promulgated new
requirements for operators to conduct integrity assessments in areas
outside of HCAs, including all Class 3 and Class 4 locations and the
newly defined ``moderate consequence areas'' (MCA) that are piggable.
This new requirement was in response to the congressional mandate in
the 2011 Pipeline Safety Act (Pub. L. 112-90) to expand IM or elements
of IM beyond HCAs. The non-HCA repair criteria PHMSA is issuing in this
final rule are the companion requirements to those assessments and are
necessary to extend the assessment and repair program elements of IM
effectively to areas beyond HCAs. Although PHMSA agrees that this
requirement will likely result in additional repairs, PHMSA believes it
is necessary and important to assure that injurious defects are
remediated before they lead to loss of pipeline integrity.
    Commenters requested that the non-HCA repair criteria be split out
from the general non-IM repair provisions that previously existed in
the regulations. PHMSA determined that the non-HCA repair criteria
would be clearer and easier to comply with if they were in a distinct
section, and PHMSA has created a new Sec.  192.714 with all of the non-
HCA repair criteria.
    To the comments that suggested that a different schedule be created
for immediate conditions within HCAs and non-HCAs, PHMSA believes that
the existing approach used in subpart O for HCAs is better because the
identification of anomalies based on ILI results is an actionable
indication that there might be an injurious defect in the pipeline.
Establishing repair criteria based on operators discovering these
actionable anomalies assures that the anomaly is investigated promptly
and repaired, if necessary. PHMSA believes it is prudent for an
operator to perform any necessary repairs once the operator has
excavated the pipe and exposed the anomaly for field investigation,
instead of deferring the repairs. Although PHMSA agrees that defects in
HCAs, if they were to fail, could result in higher consequences, PHMSA
reminds readers that ASME/ANSI B31.8S, section 7.2, defines an
immediate condition as an ``indication show[ing] that [a] defect is at
failure point.'' PHMSA believes that any indication of a pipe that is
at the point of failure needs to be addressed immediately, and as such,
for both HCAs and non-HCAs, operators must reduce pressure and
immediately remediate the anomaly.
    PHMSA agrees with several commenters and the GPAC recommendations
for consistently addressing pressure reductions for repairs for both
HCA and non-HCA pipeline segments. PHMSA believes that pressure
reductions are needed for immediate conditions and when repair
schedules cannot be met and has incorporated pressure reductions for
non-HCA pipelines that are like the existing requirements for HCAs in
subpart O, which include the operator notifying PHMSA. PHMSA also
agrees that the amount of the pressure reduction should be established
to be 80 percent of the operating pressure at the time of discovery of
the defect, or the predicted failure pressure divided by 1.1, or the
predicted failure pressure times the design factor for the class
location in which the affected pipeline is located, and that records
for such pressure reductions must be kept for a minimum of 5 years.
PHMSA

incorporated these provisions, as recommended by the GPAC, in Sec.
192.714(e) for non-HCA pipelines. Further, PHMSA followed the GPAC
recommendation for reducing duplicative language regarding repairs and
pressure reductions and has streamlined this final rule accordingly.
    PHMSA also notes that AGA suggested creating a new subpart for non-
HCA assessments and repairs. Although PHMSA has not created a new
subpart, PHMSA believes it has accomplished the same purpose by putting
the new non-HCA assessment and repair requirements in separate,
distinct sections.

F. Repair Criteria--Sec. Sec.  192.714, 192.933

iii. Cracking Criteria--Sec. Sec.  192.714(d)(1)(v) & 192.933(d)(1)(v)
1. Summary of PHMSA's Proposal
    In the NPRM, PHMSA proposed to add criteria to address cracking and
crack-like defects, including SCC, because the existing regulations
have no explicit repair criteria for those types of critical defects.
The cracking criteria would apply to both HCAs and non-HCAs, but they
would require repair at different size thresholds and at different
timeframes depending on the anomaly location.
    Following the Enbridge incident near Marshall, MI, the NTSB
recommended that PHMSA revise the hazardous liquid regulations at Sec.
195.452 to state clearly: (1) when an engineering assessment of crack
defects, including environmentally assisted cracks, must be performed;
(2) the acceptable methods for performing these engineering
assessments, including the assessment of cracks coinciding with
corrosion with a safety factor that considers the uncertainties
associated with sizing of crack defects; (3) criteria for determining
when a probable crack defect in a pipeline segment must be excavated
and time limits for completing those excavations; (4) pressure
restriction limits for crack defects that are not excavated by the
required date; and (5) acceptable methods for determining crack growth
for any cracks allowed to remain in the pipe, including growth caused
by fatigue, corrosion fatigue, or SCC as applicable.\31\ Although the
recommendation was limited to hazardous liquid pipelines, the issue
applies equally to gas transmission pipelines, as SCC can occur on
these pipelines as well.
---------------------------------------------------------------------------

    \31\ NTSB Recommendation P-12-3, available at https://www.ntsb.gov/_layouts/ntsb.recsearch/Recommendation.aspx?Rec=P-12-003.
---------------------------------------------------------------------------

    Therefore, in the NPRM, PHMSA proposed to allow operators to use an
engineering critical assessment (ECA) to evaluate indications of SCC.
If the SCC was ``significant,'' it would be categorized as an
``immediate'' repair condition. If the SCC was not ``significant,'' it
would be categorized as a ``1-year'' condition. Further, PHMSA proposed
to adopt the definition of significant SCC from the consensus industry
standard NACE SP0204-2008. PHMSA also proposed that an operator could
not use an ECA to justify not remediating any known indications of SCC.
    The current regulations also do not have repair criteria for seam
cracks or crack-like flaws. Current regulations also fail to address
corrosion affecting a longitudinal seam and selective seam weld
corrosion, which are time-sensitive integrity threats that behave like
cracks and are categorized as crack-like defects. In the NPRM, PHMSA
proposed to address these gaps by including repair criteria for cracks
and crack-like flaws in Sec.  192.933 and proposed similar criteria in
Sec.  192.713.
2. Summary of Public Comment
    INGAA, API, and Piedmont strongly opposed the proposed provisions
in Sec.  192.713(d)(1)(v), that stated ``any indication of significant
SCC'' constitutes an immediate repair condition. Commenters requested
that PHMSA determine the repair condition of cracks and crack-like
defects according to factors that capture the severity of the defect,
such as predicted failure pressures or maximum depth. Many commenters
believed that PHMSA's proposed criteria were too conservative and
suggested the repair criteria be for anomalies with a crack depth of
greater than 70 percent of the pipe wall thickness or with a predicted
failure pressure of less than 1.1 times MAOP. Other commenters
suggested PHMSA delete the definitions of specific significant crack
defects and use the alternative cracking criterion proposed by PHMSA at
the GPAC meeting on March 2, 2018.
    INGAA recommended making the repair criteria for cracking
consistent with the repair criteria for metal loss and suggested that
PHMSA consider anomalies with a crack depth of 80 percent wall
thickness as immediate conditions for this reason. INGAA also
recommended that PHMSA adopt a failure pressure ratio approach for
cracking.
    Certain commenters noted that the classification of all cracks or
crack-like defects as 2-year repair conditions was overly conservative
and suggested PHMSA relax that requirement. For example, some
commenters suggested requiring repairs at 50 percent crack depth or a
predicted failure pressure of less than 1.25 times MAOP.
    At the GPAC meeting, for the proposed repair criteria for cracks,
members representing the industry stated PHMSA's criteria for the
immediate repair of certain crack defects were too conservative and
suggested establishing an immediate repair threshold for cracks up to
70 percent of wall thickness or those with a predicted failure pressure
of less than 1.1 times MAOP rather than those cracks with a predicted
failure pressure of less than 1.25 times MAOP. Members representing the
public noted that public safety would be better served by the threshold
for immediate crack repairs being more conservative but questioned
whether the more stringent threshold would be practical.
    Similarly, members representing the industry suggested that PHMSA's
proposed criteria for 1-year and 2-year scheduled conditions were too
conservative as well and suggested setting the relevant criteria as
those cracks with a depth of 50 percent wall thickness or those cracks
with a predicted failure pressure of less than 1.25 times MAOP. Members
representing the industry also suggested that, in addition to relaxing
the criteria for immediate cracks, PHMSA should also add language
requiring operators to consider tool tolerance and other factors when
examining crack growth rates. Further, members representing the
industry suggested that PHMSA base the repair criteria on design
conditions or design factors rather than class location factors.
Committee members also suggested that PHMSA cross-reference specific
regulatory language rather than repeat the text in full in other
sections of the code.
    Following the discussion, the committee voted 12-0 that, as
published in the Federal Register, the provisions in the proposed rule
and draft regulatory evaluation for cracking repair criteria were
technically feasible, reasonable, cost-effective, and practicable if
PHMSA: (1) struck the proposed definitions of ``significant seam
cracking'' and ``significant stress corrosion cracking,'' (2) deleted
the phrase ``any indication of'' from the repair criteria related to
cracking, (3) combined the criteria for SCC and seam cracking, (4)
required that operators calculate predicted failure pressures for all
time-dependent cracking anomalies by using the fracture mechanics

procedure PHMSA developed, (5) revised the definition of ``hard spot''
as discussed,\32\ and (6) considered specific crack repair criteria as
immediate conditions. Those specific crack repair criteria for
immediate conditions would include (1) crack depth plus corrosion
greater than 50 percent of pipe wall thickness; (2) crack depth plus
any corrosion is greater than the inspection tool's maximum measurable
depth; or (3) the crack anomaly is determined to have a predicted
failure pressure that is less than 1.25 times MAOP.
---------------------------------------------------------------------------

    \32\ This is discussed more under the ``Definitions'' subsection
of this section.
---------------------------------------------------------------------------

3. PHMSA Response
    In this final rule, PHMSA did not adopt the proposed definitions of
``significant seam cracking'' and ``significant stress corrosion
cracking.'' With the revisions to the cracking repair criteria, these
definitions weren't necessary. Similarly, with the deletion of the
proposed repair criteria using those specific definitions, the
recommendation for deleting the phrase ``any indication of'' from those
criteria, became moot. Further, PHMSA's revisions to the cracking
repair criteria also made the recommendation for PHMSA to combine the
proposed SCC criteria and the seam cracking criteria moot.
    PHMSA believes that the repair criteria it proposed in the NPRM for
cracks are consistent with research findings and provides an adequate
safety margin while accounting for the severity of the defects through
the analysis of the predicted failure pressure.\33\ PHMSA believes the
repair criteria for cracks that were suggested by some of the
commenters would not provide an adequate safety margin due to factors
including the accuracy of tool results, varying pipe toughness, and
pressure cycling. This was discussed at length by the GPAC, who
ultimately recommended that anomalies be classified as immediate
conditions where the crack depth plus corrosion is greater than 50
percent of pipe wall thickness, compared to certain commenters who
suggested that cracks with a depth of up to 70 percent pipe wall
thickness be classified as immediate conditions.
---------------------------------------------------------------------------

    \33\ See ASME, ``STP-PT-0011:Integrity Management of Stress
Corrosion Cracking in Gas Pipeline High Consequence Areas'' (2008).
See also Young, B.A., et al., ``Comprehensive Study to Understand
Longitudinal ERW Seam Failures'' (2017), available at https://primis.phmsa.dot.gov/matrix/PrjHome.rdm?prj=390. Both papers call
for anomaly evaluation; the knowledge of certain properties,
including the length and depth of the crack, and pipe properties
like wall thickness, grade, and toughness; and a proposed safety
factor based on the time until the next assessment period. The
papers also require that the depth of a crack not be greater than
the depth of the assessment tool's tolerance. See Sec.  192.712(e).
---------------------------------------------------------------------------

    While the GPAC did not have an explicit recommendation for
scheduled (i.e., non-immediate) crack repair criteria, they recommended
that PHMSA consider a repair schedule for cracks that is less
conservative than what was proposed in the NPRM. Their recommended
schedule is: 1.39 times MAOP for Class 1 and 2 locations and 1.5 times
MAOP for Class 3 and 4 locations. PHMSA considered this recommendation
and determined that the condition should cover Class 1 locations and
Class 2 locations containing Class 1 pipe that has been uprated in
accordance with Sec.  192.611, where the predicted failure pressure is
1.39 times MAOP. For all other Class 2 locations and higher class
locations, the predicted failure pressure would be 1.5 times MAOP.
Section 192.611 allows Class 1 pipe to remain in a Class 2 location if
it has had a subpart J pressure test, for 8 hours, at 1.25 times MAOP.
Also, it allows pipe with a design factor of 0.72, with the reciprocal
of 1 divided by 0.72 being equal to 1.39, which is the predicted
failure pressure. Therefore, PHMSA elected to apply a predicted failure
pressure ratio of 1.39 times MAOP to both Class 1 pipe and uprated
Class 2 pipe.
    For immediate conditions, the GPAC asked PHMSA to consider if a
less conservative repair criterion of 1.1 times MAOP (after tool
tolerance had been applied) would be appropriate. PHMSA considered this
suggestion but notes that, after allowing for pressure excursions above
MAOP due to over pressure protection device settings, the actual safety
margin of such an approach would be between 0 and 6 percent. PHMSA has
determined that this safety margin for immediate crack conditions is
inadequate and, for this final rule, has retained the requirement that
operators must immediately repair crack anomalies with a predicted
failure pressure that is less than 1.25 times MAOP.
    PHMSA took technical guidance information from several sources into
account regarding significant SCC and significant seam weld corrosion
when creating the repair criteria for these anomalies, including ASME
ST-PT-011 (``Integrity Management of Stress Corrosion Cracking in Gas
Pipeline High Consequence Areas'').\34\
---------------------------------------------------------------------------

    \34\ ASME, ``STP-PT-011: Integrity Management of Stress
Corrosion Cracking in Gas Pipeline High Consequence Areas'' (2008).
---------------------------------------------------------------------------

    ASME ST-PT-011 states that stress corrosion cracks are
``Noteworthy'' if the maximum crack depth is greater than 10 percent of
the wall thickness and if the maximum interacting crack length is more
than the critical length of a 50 percent through-wall crack at a stress
level of 110 percent SMYS.\35\ The report provides categories as
follows:
---------------------------------------------------------------------------

    \35\ PHMSA notes that 110 percent SMYS for a Class 1 pipeline is
roughly equivalent to 1.49 times MAOP.
---------------------------------------------------------------------------

    Category 1: Predicted Failure Pressure (PFP) is above 110 percent
SMYS (note that 110 percent SMYS is used to delineate Category 1 cracks
because it corresponds to the pressure most commonly prescribed for
hydrostatic testing).
    Category 2: PFP is above 125 percent MAOP \36\ and below 110
percent SMYS.
---------------------------------------------------------------------------

    \36\ PHMSA notes that 125% times MAOP for a pipeline that
operates at 72% SMYS in a Class 1 location would correspond to
roughly 90% SMYS for a Category 2 crack. PHMSA has defined in Sec.
192.506 that a spike test for cracking should be conducted at a
pressure of 100 percent of SMYS (roughly equivalent to 1.39 times
MAOP for a Class 1 location) or 1.5 times MAOP.
---------------------------------------------------------------------------

    Category 3: PFP is above 110 percent MAOP and below 125 percent
MAOP.
    Category 4: PFP is below 110 percent MAOP.
    Category Zero: A crack below the threshold for Noteworthy cracks.
These typically fall into two groups: (1) Those that are shallow (i.e.,
less than 10 percent through-wall depth), or (2) Those that are so
short that, even if they were 50 percent through-wall depth, they would
not result in a hydrostatic test failure.
    In this final rule, operators can use an engineering analysis on
cracks in Categories 1 through 2 as described above. However, any
Category 3 or 4 cracking defect below 125 percent MAOP would require
immediate remediation. Category 3 cracks would have a 10 percent or
greater safety factor, which is similar to how PHMSA currently treats
corrosion anomalies at Sec.  192.933. PHMSA provides more conservatism
in the cracking criteria because there is more uncertainty with the
accuracy of current ILI technology in its ability to measure crack
length and depth, as well operational factors.
    These severity categories allow operators to estimate the minimum
remaining life at operating pressure for each category. The following
estimates from ASME ST-PT-011 are based on the time it would take for
the crack depth to increase to a failure-causing depth at the operating
pressure. For pipelines operating at 72 percent SMYS, the following
minimum operational lives for each category of cracks are as follows:

    Category Zero: Failure life exceeds 15 years (for short cracks) to
25 years (for shallow cracks).
    Category 1: Failure life exceeds 10 years.
    Category 2: Failure life exceeds 5 years.
    Category 3: Failure life exceeds 2 years.
    Category 4: Failure may be imminent.
    ASME ST-PT-011 further states that mitigating a pipeline segment
with SCC should be commensurate with the severity of the discovered
crack, which would reflect the PFP and the estimated life at the
operating pressure. For example, Category Zero cracks may warrant no
more than ongoing SCC condition monitoring and reassessment after a
period of 7 years. Cracks may be best assessed by direct assessment,
hydrostatic testing, or ILI. The most severe cases would require an
immediate pressure reduction, repair (if the location is known), and
hydrostatic testing or ILI, followed by replacing the pipe or
installing an appropriate sleeve over the crack or known cracking
areas.

F. Repair Criteria--Sec. Sec.  192.714, 192.933

iv. Dent Criteria--Sec. Sec.  192.714 & 192.933
1. Summary of PHMSA's Proposal
    In the NPRM, PHMSA proposed that dents in non-HCA segments with any
indication of metal loss, cracking, or a stress riser would be
considered ``immediate'' repair conditions. Additionally, PHMSA
proposed that dents meeting the ``1-year'' repair conditions under
Sec.  192.933 would be required to be repaired in non-HCAs within 2
years.
2. Summary of Public Comment
    Multiple commenters, including the industry trade associations and
operators, disagreed that all dents with metal loss should be
considered immediate repair conditions. These commenters requested that
PHMSA's final rule address different kinds of dents separately. Many
pipeline operators stated that dents with metal loss from ``scratches,
gouges, and grooves'' are appropriate as immediate repair conditions,
while dents caused by corrosion are lower risk and should be conditions
scheduled for later repair. Several organizations cited API Publication
1156 \37\ and ASME/ANSI B31.8, ``Gas Transmission and Distribution
Piping Systems,'' to support these claims. Several commenters also
recommended that PHMSA impose different response timelines for dents
depending on the location and the manner of the dents, because dents
with bottom-side metal loss are usually corrosion-related and low-risk,
while dents on the top of the pipeline with metal loss are likely to be
from mechanical damage and are at a higher risk to fail. This
distinction would be consistent with the criteria for smooth dents
(dents with no peaks, buckling, gouging, cracking, or metal loss that
can reduce the operational life of the pipe).
---------------------------------------------------------------------------

    \37\ API, ``Pub. 1156: Effects of Smooth and Rock Dents on
Liquid Petroleum Pipelines'' (1997).
---------------------------------------------------------------------------

    With further regard to the repair criteria for dents, commenters
representing the industry believed PHMSA should allow operators to use
an ECA to evaluate dents as an alternative to following the prescribed
repair criteria. Some of this discussion focused on whether PHMSA
should include a finite element analysis (FEA) \38\ as part of the ECA
and whether PHMSA should define critical strain levels as a criterion
in the ECA. Comments from industry additionally suggested that the
criterion related to gouges or grooves greater than 12.5 percent of
wall thickness was duplicative with other criteria. Industry trade
associations noted that gouges and grooves would be evaluated in
accordance with the dent, metal loss, or cracking criteria, and
therefore, a separate anomaly category for gouges and grooves should be
removed. Further, they asserted that current ILI technology can't
determine the specific cause of metal loss, which would make this
criterion unfeasible.
---------------------------------------------------------------------------

    \38\ FEA is a modeling technique used to find and solve
structural or integrity issues for phenomena such as cracking or
denting. Pipe properties, including the parameters of the damage to
the pipe, planned operating pressure, lifespan until the next
evaluation, and any future operational conditions (max pressure,
pressure cycle, higher temperatures), are needed to perform an FEA.
---------------------------------------------------------------------------

    At the GPAC meeting on March 26, 2018, the committee recommended
changes to several of the specific repair criteria for cracks,
corrosion metal loss, and dents. Specific to dents, the committee
recommended that PHMSA allow use of an ECA to evaluate certain dent-
related anomalies and incorporate the ECA into the repair criteria.\39\
---------------------------------------------------------------------------

    \39\ Many of the recommended changes to the proposed repair
criteria were highly technical in nature. For more information,
including transcripts of the discussion and the voting slides,
please visit: https://primis.phmsa.dot.gov/meetings/MtgHome.mtg?mtg=132.
---------------------------------------------------------------------------

    Following the discussion, the committee voted 12-0 that, as
published in the Federal Register, the provisions in the proposed rule
and draft regulatory evaluation for dent repair criteria were
technically feasible, reasonable, cost-effective, and practicable if
PHMSA: (1) allowed operators to use an ECA for specific dent-related
repair criteria and considered language to accommodate alternative ECA
methods (including an FEA), and (2) distinguished between top-side
dents that exceeded critical strain levels and bottom-side dents that
exceeded critical strain levels by making distinct criteria for those
anomalies.
3. PHMSA Response
    PHMSA believes that the repair criteria it proposed in the NPRM for
dents provide an adequate safety margin and believes the criteria for
dents that were suggested by some of the commenters would not provide
adequate safety margin. PHMSA based this judgment on R&D programs that
have been sponsored by PHMSA and the Pipeline Research Council
International, and on elements of dent repair criteria that are
contained within API RP 1183.\40\
---------------------------------------------------------------------------

    \40\ API, Recommended Practice 1183, ``Assessment and Management
of Dents in Pipelines'' (Nov. 2020).
---------------------------------------------------------------------------

    PHMSA agrees with the GPAC recommendation for allowing an ECA
method to evaluate dent anomalies and has revised the dent repair
criteria for immediate, scheduled, and monitored conditions, as
recommended by GPAC, to do so. PHMSA believes that the development of
high-resolution deformation ILI tools has advanced enough to justify
allowing operators to use an ECA method to evaluate dent anomalies and
believes that it would be consistent with public safety while providing
operators additional flexibility. While this rulemaking was under
development, API published API RP 1183, which provides guidance for
assessing and managing dents that are present in pipeline systems as a
result of contact by rocks, machinery, or other forces. The RP presents
guidance for developing a dent assessment and management program by (1)
providing suitable methods for inspecting and characterizing the
condition of the pipeline with respect to dents; (2) establishing data
screening processes to evaluate dents relative to the extent and degree
of deformation and operational severity; (3) providing response
criteria for dents based on the dent shape and profile as determined by
ILI; (4) applying engineering assessment methods to evaluate the
fitness-for-service of dents, including the reassessment interval; (5)
presenting remediation and repair options to address dents; and (6)
developing preventive and mitigative measures for dents in lieu of, or
in addition to,

periodic dent integrity assessment, including pressure reductions and
pressure cycle management.
    PHMSA agrees with commenters that the criteria based on gouges and
grooves would be duplicative with other criteria being proposed in the
NPRM, namely the criteria related to metal loss anomalies. Accordingly,
PHMSA has removed the criteria related to gouges and grooves from this
final rule.
    In the 2019 Gas Transmission Rule, PHMSA finalized an ECA method
for operators to use as a part of the pipeline material property and
attribute verification under Sec.  192.607 and the MAOP reconfirmation
requirements of Sec.  192.624. A key aspect of that ECA method is the
detailed analysis of the remaining strength of pipe with known or
assumed defects. The 2019 Gas Transmission Rule created a new section,
Sec.  192.712, to address the techniques and procedures an operator
could use to analyze the predicted failure pressures for pipe with
corrosion metal loss and cracks or crack-like defects.\41\ That
analysis requires the conservative analysis of the defect to determine
the remaining life of the pipeline. In this final rule, PHMSA is
building on the provisions it promulgated in the 2019 Gas Transmission
Rule by allowing operators to use such an analysis for determining the
timing of certain anomaly repairs, including dents. Unlike the
previously existing repair criteria, which required the repair of
listed anomalies within a specific timeframe, operators, per this final
rule, can perform this analysis to determine whether the predicted
failure pressure of the anomaly would warrant additional monitoring and
a later repair. PHMSA understands that operators may propose, for PHMSA
review in accordance with Sec.  192.18, procedures for the assessment
and remediation of dent anomalies (such as an ECA for dent anomalies);
operators may develop those procedures using consensus industry
standards (e.g., API RP 1183, ASME B31.8, ASME B31.8S) or current
research findings.
---------------------------------------------------------------------------

    \41\ See 84 FR 52236, 52237.
---------------------------------------------------------------------------

F. Repair Criteria--Sec. Sec.  192.714, 192.933

v. Corrosion Metal Loss Criteria--Sec. Sec.  192.714 & 192.933
1. Summary of PHMSA's Proposal
    The required remediation of several types of corrosion defects that
are incorporated in the hazardous liquid regulations in part 195 are
currently omitted from part 192. The current gas transmission IM
regulations allow operators to use ASME/ANSI B31.8S, Figure 4, for
guiding repair decisions not specified in Sec.  192.933(d), which can
allow operators significant discretion in assessing and remediating
pipe with corrosion or metal loss defects. PHMSA has found a wide
variation in operators' interpretation of how to meet the requirements
of the regulations in assessing, evaluating, and remediating corrosion
and metal loss defects.
    To address these gaps, and to harmonize part 192 with part 195,
PHMSA proposed to amend Sec.  192.933 to designate as immediate repair
conditions those anomalies where metal loss is greater than 80 percent
of nominal wall thickness and for indications of metal loss affecting
certain legacy pipe with longitudinal seams.
    To address gaps related to non-immediate conditions, the NPRM
proposed that operators must repair the following within 1 year: (1)
anomalies where a calculation of the remaining strength of the pipe
shows a predicted failure pressure ratio at the location of the anomaly
less than or equal to 1.25 times the MAOP for Class 1 locations, 1.39
times the MAOP for Class 2 locations, 1.67 times the MAOP for Class 3
locations, and 2.00 times the MAOP for Class 4 locations (comparable to
the alternative design factor specified in Sec.  192.620(a)); (2) areas
of general corrosion with a predicted metal loss greater than 50
percent of nominal wall thickness; (3) anomalies with predicted metal
loss greater than 50 percent of nominal wall thickness that are located
at crossings of another pipeline, are in areas with widespread
circumferential corrosion, or are in areas that could affect a girth
weld; and (4) anomalies with metal loss due to gouges or grooves \42\
that are greater than 12.5 percent of nominal wall thickness.
---------------------------------------------------------------------------

    \42\ Gouges or grooves are stress concentrators that lead to
cracking and fatigue, which in turn may lead to accelerated failure.
---------------------------------------------------------------------------

2. Summary of Public Comment
    A commenter noted that PHMSA should recognize that gouges and
scrapes are metal loss defects that can be smoothed by grinding to
eliminate stress concentrations.
    Multiple commenters also provided input on the proposed provisions
that determine repair criteria for metal loss affecting certain pipe
with longitudinal seams. INGAA, AGA, and a pipeline industry entity
generally supported a classification of ``immediate'' for anomalies
with ``an indication of metal loss affecting a detected longitudinal
seam, if that seam was formed by direct current or low frequency or
high frequency electric resistance welding or by electric flash
welding.'' However, PG&E requested that PHMSA not classify metal loss
affecting a detected longitudinal seam as an immediate repair condition
if that seam was formed by high-frequency electric resistance welding,
as that pipe is considered ductile. National Fuel requested that PHMSA
categorize longitudinal seam metal loss based on a minimum metal-loss
threshold rather than ``an indication.'' Certain commenters requested
PHMSA allow operators to perform a fitness-for-service evaluation or
ECA on selective seam weld corrosion.
    Kern River suggested PHMSA should consider applicable manufacturing
and tool detection tolerances in the establishment of repair criteria
that require response to ``any indication of metal loss.''
    Several commenters, including AGA, Pauite, and DTE, did not support
the proposed inclusion of ``any indication of significant seam weld
corrosion'' in Sec.  192.713(d)(1)(vi). INGAA and AGA asserted that
seam weld corrosion can only be conclusively determined by an in-field
examination even though ILI tools are often employed to identify
possible seam weld corrosion areas.
    INGAA requested that gouge and groove metal loss anomalies be
deleted from the 1-year and 2-year response conditions. Other
commenters noted that current ILI tools do not have the capability of
differentiating 12.5 percent gouge or groove metal loss anomalies from
12.5 percent external corrosion metal loss anomalies and suggested
PHMSA delete this proposed requirement. These commenters argued that,
given current ILI technology and per this proposal, operators would be
required to investigate all metal loss indications greater than 12.5
percent to determine if the metal loss was a gouge or groove. Several
trade associations and pipeline industry entities requested that
operators be allowed to perform excavations to validate ILI results
before classifying a segment as a high-priority repair.
    Several pipeline industry commenters disagreed with the proposed
repair criteria and repair methods that differed from industry standard
ASME/ANSI B31.8S. For example, AGA stated that they opposed the
inclusion of different repair criteria for different class locations
because this contradicts ASME/ANSI B31.8S. API noted that PHMSA's
proposal contradicted the ASME/ANSI standard by including depth-based
criteria and also stated that PHMSA should not include the depth-

based criteria but only reference ASME/ANSI B31.8S, which is considered
the best accepted practice. Similarly, INGAA recommended that PHMSA
allow operators to use the repair methods in ASME/ANSI B31.8S rather
than the proposed criteria.
    Some commenters thought that the new proposed criteria for
corrosion anomalies made the existing corrosion repair requirements at
Sec.  192.485(c) duplicative and requested PHMSA delete the existing
corrosion repair requirements for clarity. Other commenters noted that
PHMSA's proposed requirement for corrosion greater than 50 percent of
wall thickness was redundant to other proposed corrosion metal loss
defects and suggested this specific item should be deleted. Similarly,
commenters suggested that the criteria for predicted metal loss greater
than 50 percent of nominal wall located at the crossing of another
pipeline, areas with widespread circumferential corrosion, or areas
that could affect a girth weld were both too conservative and
duplicative of other corrosion repair criteria.
    At the GPAC meeting on March 26, 2018, regarding the general
provisions and applicability of the corrosion metal loss repair
criteria, commenters representing the industry noted that for 1-year
and 2-year scheduled conditions, the use of class location safety
factors would be burdensome, as it would require more frequent repairs
for pipelines in Class 2, Class 3, or Class 4 locations than
contemplated by consensus industry standard ASME/ANSI B31.8S section 7,
figure 4.
    The committee also discussed specific requirements related to the
repair of corrosion anomalies. Echoing many of the public comments on
the topic, members representing the industry believed that the newly
proposed corrosion repair requirements were either overly conservative
or duplicative compared to existing repair requirements in the
corrosion control subpart. These committee members suggested the new
requirements should be deleted or otherwise changed to be less
conservative. Additionally, these members noted that the proposed
criteria for anomalies where corrosion is greater than 50 percent of
wall thickness would be redundant with other repair criteria for
evaluating corrosion metal loss defects using accepted analysis
techniques, such as ASME B31G and remaining strength of corroded pipe
(RSTRENG).\43\ Further, for corrosion metal loss affecting pipe seams,
members representing the industry suggested the criteria should apply
to corrosion that ``preferentially'' affects the long seam,\44\ and
that PHMSA should allow an ECA to analyze such defects to prevent
unnecessary excavations.
---------------------------------------------------------------------------

    \43\ Both are incorporated by reference at Sec.  192.7; see
(c)(4): ASME/ANSI B31G-1991 (Reaffirmed 2004), ``Manual for
Determining the Remaining Strength of Corroded Pipelines,'' 2004,
and (j)(1): AGA, Pipeline Research Committee Project, PR-3-805, ``A
Modified Criterion for Evaluating the Remaining Strength of Corroded
Pipe,'' (December 22, 1989).
    \44\ Corrosion that ``preferentially'' affects the long seam is
corrosion that is of and along the weld seam that is classified as
selective seam weld corrosion. It normally effects low frequency
electric resistance weld seams (LF-ERW) and electric flash welded
seams (EFW).
---------------------------------------------------------------------------

    The committee also suggested that PHMSA evaluate predicted failure
pressure ratings and thresholds for remediation schedules of anomalies
at pipeline crossings with widespread circumferential corrosion or with
corrosion that can affect a girth weld.
    Following the discussion, the committee voted 11-0 that, as
published in the Federal Register, the provisions in the proposed rule
and draft regulatory evaluation for corrosion metal loss repair
criteria (excluding the repair timing) were technically feasible,
reasonable, cost-effective, and practicable if PHMSA: (1) clarified
that the criteria do not apply to corrosion pits near a long seam but
does apply to corrosion along seams that could lead to slotting-type
crack-like defects, (2) deleted duplicative criteria, (3) cross-
referenced the proposed new fracture mechanics section with the general
corrosion remediation requirements, and (4) revised the repair criteria
for scheduled conditions regarding the predicted failure pressure as
discussed by the committee.
    The committee then voted 8-3 (with each of two members representing
State regulators and one member representing the public dissenting)
that, as published in the Federal Register, the provisions in the
proposed rule and draft regulatory evaluation for scheduled conditions
regarding the predicted failure pressure repair criteria for corrosion
metal loss anomalies were technically feasible, reasonable, cost-
effective, and practicable if PHMSA: (1) incorporated ASME/ANSI B31.8S,
section 7, figure 4, into the repair criteria; (2) required operators
to consider ILI tool tolerance on all runs; (3) removed and revised the
predicted failure pressure standards for metal loss anomalies per the
discussion of the committee; and (4) provided guidance to improve the
understanding and use of ASME/ANSI B31.8S, section 7, figure 4.
    For corrosion metal loss anomalies that meet the ``scheduled''
criteria (i.e., 1-year conditions for HCAs and 2-year conditions for
non-HCAs), the GPAC voted 8-3 that PHMSA should remove the predicted
failure pressure standards for Class 1 and Class 2 segments from the
NPRM and require operators to use section 7, figure 4 from ASME/ANSI
B31.8S instead (i.e., retain the current requirement in place for HCAs
under subpart O).
3. PHMSA Response
    When developing the repair criteria in the NPRM, PHMSA evaluated
grounding the predicted failure pressure for those criteria in one or
more of the following three factors: (1) the test pressure of a
pipeline, (2) the design factor of a pipeline, and (3) the HCA repair
criteria. Because PHMSA sought to improve upon existing HCA repair
criteria, PHMSA decided against using that factor as the basis for
calculating predicted failure pressures and proposed using test
pressure or design factor of a pipeline instead. PHMSA based its
proposed threshold for Class 1 pipelines (less than or equal to 1.25
times MAOP predicted failure pressure) on the maximum test pressure in
Sec.  192.619 for Class 1 pipelines (1.25 times MAOP). For the repair
thresholds for Class 2, Class 3, and Class 4 pipelines, PHMSA
calculated predicted failure pressures using the reciprocals of the
design factors listed at Sec.  192.111 for the immediately preceding
class location rating. This approach ensured an adequate margin to
failure even if the pipeline were to experience a one-class bump
(pursuant to Sec.  192.611) from changes in population density of the
surrounding area. The resulting predicted failure pressure thresholds
were less than or equal to 1.39 times MAOP (reciprocal of the 0.72
Class 1 design factor) for pipelines in a Class 2 location, less than
or equal to 1.67 times MAOP for pipelines in Class 3 locations, and
less than or equal to 2.00 times MAOP for pipelines in Class 4
locations.
    PHMSA believes the repair criteria for corrosion metal loss that
were suggested by some of the commenters would not provide adequate
safety margin compared to what PHMSA proposed in the NPRM. This was
discussed at length by the GPAC, who recommended repair criteria that,
in some cases, were less conservative than what PHMSA proposed in the
NPRM.
    In this final rule, PHMSA adopted the GPAC's recommendation to
incorporate ASME/ANSI B31.8S section 7, figure 4, into the repair
criteria by requiring operators to use it in Class 1 locations for
metal loss anomalies with a

predicted failure pressure greater than 1.1 times MAOP, which is
consistent with the previous IM repair regulations. The committee also
recommended PHMSA provide additional guidance on the use of ASME/ANSI
B31.8S section 7, figure 4. ASME/ANSI B31.8S, section 7, figure 4 has
three scales for repair that are based on the MAOP of the pipeline and
the MAOP's percentage of the pipeline's SMYS.\45\ Operators can use one
of the 3 sliding scales of figure 4, as appropriate, to address
anomalies when the anomaly has a failure pressure ratio above 1.1. As
discussed previously, operators are currently required to follow ASME/
ANSI B31.8S section 7, figure 4 under elements of the previous IM
repair regulations. PHMSA understands that the 10 percent nominal
safety margin provided by compliance with ASME/ANSI B31.8S section 7,
figure 4 is appropriate for the relatively low risk to public safety
posed to pipelines in low-population-density, Class 1 locations.
---------------------------------------------------------------------------

    \45\ Those three scales pertain to (1) not exceeding 30 percent
SMYS, (2) above 30 percent SMYS but not exceeding 50 percent SMYS,
and (3) above 50 percent SMYS.
---------------------------------------------------------------------------

    However, PHMSA did not accept the GPAC's recommendation for Class 2
locations. The number of immediate repair conditions being discovered
during reassessments in Class 2 locations continues at approximately
the same rate as they were discovered during the baseline assessment
phase of the IM rule promulgated in 2004, according to PHMSA annual
report data. PHMSA attributes this to defects that are not repaired and
allowed to grow to a size that are at or near failure (i.e., an
immediate condition). Existing immediate repair criteria for pipelines
in Class 2 locations (predicated on ASME/ANSI B31.8S section 7, figure
4) allow up to a maximum 10 percent safety margin over the MAOP.
However, after allowing for pressure excursions above MAOP due to
overpressure protection device settings, the actual safety margin is
between 0 and 6 percent. PHMSA has determined that the continued
reliance on those ASME/ANSI B31.8S section 7, figure 4-derived safety
margins in more densely populated Class 2 locations does not ensure
adequate identification and elimination of sub-critical defects before
they grow to a size that would raise immediate safety concerns.
Therefore, in this final rule, PHMSA chooses to retain the NPRM's
predicted failure pressure threshold for metal loss anomalies in Class
2 locations of less than 1.39 times MAOP.
    For Class 3 and Class 4 locations, PHMSA considered predicted
failure pressure thresholds between 1.39 times and 1.50 times MAOP as
requested by the committee. However, PHMSA has determined that, in
order to provide adequate margin for public safety in higher-
population-density Class 3 and 4 locations, PHMSA could not establish a
predicted failure pressure threshold as low as 1.39 times MAOP.
Therefore, in this final rule, PHMSA has provided a repair threshold
for anomalies meeting a predicted failure pressure of less than 1.50
times MAOP for pipelines in Class 3 and Class 4 locations. PHMSA notes
this approach would align repair criteria with the approach in Sec.
192.619 for determining maximum allowable pressures for the same
locations, and reflects that transmission pipelines in Class 3 and
Class 4 locations are more robust (as a result of thicker walls and
other design requirements) than those used in Class 1 and Class 2
locations.
    PHMSA has provided similar repair criteria in this final rule for
corrosion metal loss anomalies that are at a crossing of another
pipeline; are in an area with widespread circumferential corrosion;
could affect a girth weld; or that preferentially affects detected
longitudinal seams that are formed by direct current, low-frequency or
high-frequency electric resistance welding, electric flash welding, or
with a longitudinal joint factor less than 1.0. Specifically, PHMSA is
requiring the repair of conditions that reach less than 1.39 times the
MAOP for anomalies in Class 1 locations or where Class 2 locations
contain Class 1 pipe that has been uprated in accordance with Sec.
192.611. For those corrosion metal loss anomalies at all other Class 2
locations, as well as those anomalies in Class 3 and Class 4 locations,
operators will have to repair them once they reach a predicted failure
pressure of less than 1.50 times MAOP.
    PHMSA is requiring the additional stringency in Class 1 locations
and Class 2 locations compared to the general corrosion metal loss
repair standard discussed above because, should corrosion at the
crossing of other pipelines induce failure, multiple pipelines could be
damaged or fail. Pipelines with anomalies located at areas of
widespread circumferential corrosion could additionally lose pipe
strength due to outside longitudinal (pulling force) loading on the
pipeline. And, historically, longitudinal seams that are formed by
direct-current welding, low-frequency or high-frequency electric
resistance welding, electric flash welding, or that have a longitudinal
joint factor of less than 1.0, are more likely to fail. Therefore,
PHMSA has determined that more stringent repair criteria are necessary
for corrosion metal loss anomalies that preferentially affect these
longitudinal seams. In contrast, because pipelines in Class 3 and Class
4 locations are (as noted above) more robust than those in Class 1 and
Class 2 locations, PHMSA has determined that it is unnecessary to
impose different thresholds for pipelines in Class 3 and Class 4
locations based on whether they are located at the crossing of another
pipeline.
    As explained in the discussion for dent anomalies above, PHMSA
agreed with commenters that the specific criteria for gouges and
grooves was duplicative with other metal loss conditions and has chosen
not to finalize gouge and groove criteria in this final rule.
Therefore, the comments related to whether ILI tools can properly or
reliably identify gouges and grooves specifically are moot.

F. Repair Criteria--Sec. Sec.  192.714, 192.933

vi. General Discussion
Process for Analyzing Defects Discovered--Sec.  192.933
1. Summary of PHMSA's Proposal
    Following the Enbridge hazardous liquid incident in 2010 that
spilled nearly 1 million barrels of oil near Marshall, MI, in 2010, the
NTSB recommended that PHMSA revise requirements in the hazardous liquid
pipeline safety regulations at Sec.  195.452(h)(2) related to the
``discovery of condition'' to require, in cases where a determination
about pipeline threats has not been obtained within 180 days following
the date of inspection, that pipeline operators notify PHMSA and
provide an expected date when adequate information will become
available.\46\ The NTSB also recommended that PHMSA revise part 195 to
state the acceptable methods for performing engineering assessments of
ILI results, including the assessment of cracks coinciding with
corrosion, with a safety factor that considers the uncertainties
associated with sizing of crack defects (P-12-3). Although these
recommendations were for the hazardous liquid pipeline safety
regulations in part 195, the issues apply equally to gas pipelines
regulated under part 192.
---------------------------------------------------------------------------

    \46\ NTSB Recommendation P-12-4, available at https://www.ntsb.gov/safety/safety-recs/_layouts/ntsb.recsearch/Recommendation.aspx?Rec=P-12-004.
---------------------------------------------------------------------------

    Accordingly, PHMSA proposed to amend paragraph (b) of Sec.  192.933
to

require that operators notify PHMSA within 180 days following an
assessment where the operator cannot obtain sufficient information to
determine if a condition presents a potential threat to the integrity
of the pipeline; and expand the requirements in Sec.  192.933 to
clarify that operators must assure that persons qualified by knowledge,
training, and experience must analyze the data obtained from an ILI to
determine if a condition could adversely affect the safe operation of
the pipeline. PHMSA also proposed to require that operators explicitly
consider uncertainties in reported results in identifying and
characterizing anomalies, which includes uncertainties in tool
tolerance, detection threshold, the probability of detection, the
probability of identification, sizing accuracy, conservative anomaly
interaction criteria, location accuracy, anomaly findings, and unity
chart plots.
    PHMSA also proposed to amend paragraphs (a) and (d) of Sec.
192.933 to require that operators document a pipeline's physical
material properties and attributes that are used in remaining strength
calculations in reliable, traceable, verifiable, and complete records.
If such records were not available, operators would be required to base
the pipe and material properties used in the remaining strength
calculations on properties determined and documented in accordance with
Sec.  192.607.
2. Summary of Public Comment
    Commenters noted that there were potential issues with how the
revised repair criteria and the proposed material verification
requirements at Sec.  192.607 would interact regarding remaining
strength calculations. These commenters requested that, absent reliable
data, PHMSA allow operators to use supportable, sound engineering
judgments when calculating remaining strength. This would allow
operators to establish the remaining strength of affected segments
while material verification was completed. Similarly, commenters
suggested if the value for specified minimum yield strength is unknown,
operators should be able to use a conservative default value, such as
30,000 pounds per square inch (psi). For predicted failure pressure
calculations, operators suggested they should be able to use the
records they have on hand and operator knowledge for calculations until
any necessary material properties are verified through Sec.  192.607.
Similarly, at the GPAC meeting on March 26, 2018, commenters
representing the industry suggested PHMSA should allow, in the absence
of traceable, verifiable, and complete material records,\47\ for
operators to use sound engineering judgment or otherwise conservative
assumptions in repair-related decision making, and recommended PHMSA
modify the regulations as such.
---------------------------------------------------------------------------

    \47\ In an advisory bulletin dated May 7, 2012 (77 FR 26822),
PHMSA provided guidelines for what records would meet a traceable,
verifiable, and complete standard. The phrase ``traceable,
verifiable, and complete'' matched a phrase from NTSB recommendation
P-10-5, which recommended to the California Public Utilities
Commission to ensure that PG&E ``aggressively and diligently
searched documents and records relating to [ . . . ] natural gas
transmission lines in class 3 and class 4 locations and class 1 and
class 2 high consequence areas [ . . . ]. These records should be
traceable, verifiable, and complete [ . . . ].'' See NTSB
Recommendation P-10-5, available at https://www.ntsb.gov/safety/safety-recs/_layouts/ntsb.recsearch/Recommendation.aspx?Rec=P-10-005. While PHMSA proposed that records meet a reliable, traceable,
verifiable, and complete standard, PHMSA believes that being
consistent with the guidance it provided in the May 2012 advisory
bulletin and the NTSB recommendation will provide further clarity.
---------------------------------------------------------------------------

    The EDF and PST supported PHMSA's proposals related to considering
uncertainties in ILI results for identifying and characterizing
anomalies. Several pipeline operators and industry trade associations
on the other hand, including INGAA, expressed concern that the NPRM
would require pipeline operators to repair anomalies that do not
threaten pipeline integrity, stating that many anomalies that are
identified by indirect measurements as requiring repair are later
determined not to require repair upon examination in the field. These
commenters requested that PHMSA change the proposed requirements to
distinguish between ILI results and in-field examinations and start the
repair timeline with the time an anomaly is examined in the field and
not when it is identified by ILI.
    INGAA suggested that PHMSA change the proposed requirements to
differentiate between response, remediation, and repair, and that PHMSA
replace ``repair'' with ``response'' in the terms ``2-year repair
criteria'' and ``1-year repair criteria'' as those terms pertain to the
non-HCA repair criteria. INGAA also requested that PHMSA further divide
``2-year response conditions'' into ``2-year response conditions and
scheduled responses'' and similarly divide ``1-year response
conditions'' into ``1-year response conditions and scheduled
responses.'' INGAA suggested such a revision would be necessary because
the proposed requirements for the response to, and repair of, potential
pipeline anomalies do not recognize the differences between actions
that operators take when evaluating the result of integrity assessments
versus those actions operators take following in-field examinations of
potential anomalies.
    Several commenters requested that PHMSA change the proposed
regulatory language to distinguish between ILI results and in-field
examinations (response) and the actual remediation activity (repair)
with a view to start the repair timeline after an anomaly is examined
in the field and not when it is identified by ILI. Commenters suggested
separate timelines to distinguish between the ``response'' and
``repair'' phases of pipeline remediation.
3. PHMSA Response
    PHMSA addressed comments pertaining to the use of sound engineering
judgment and assumed values to evaluate anomalies when data required
for the evaluation is unknown or not available in traceable,
verifiable, and complete records in the 2019 Gas Transmission Rule at
Sec.  192.712.\48\ If an operator does not have one or more of the
material properties necessary to perform an ECA analysis (diameter,
wall thickness, seam type, grade, and Charpy v-notch toughness values,
if applicable), the operator must use the conservative assumptions
PHMSA provided and include the pipeline segment in its program to
verify the undocumented information in accordance with the material
properties verification requirements at Sec.  192.607.
---------------------------------------------------------------------------

    \48\ See 84 FR 52236, 52251.
---------------------------------------------------------------------------

    In the Response to Petitions for Reconsideration on the 2019 Gas
Transmission Rule,\49\ PHMSA stated that if operators are missing any
material properties during anomaly evaluations and repairs, operators
must confirm those material properties under Sec. Sec.  192.607 and
192.712(e) through (g). For consistency in this final rule, and to make
this requirement more explicit, PHMSA has linked those material
property confirmation requirements to the anomaly repair requirements
by cross-referencing Sec.  192.607 at both Sec. Sec.  192.714 and
192.933. PHMSA will also note that, in accordance with the section 23
mandate in the 2011 Pipeline Safety Act, operators reported that
approximately 13 percent of pipeline segment mileage in HCAs and Class
3 and Class 4 locations lack adequate documentation of the physical and
operational characteristics of the pipelines necessary to confirm the
proper MAOP. Such documentation is

also critical for performing predicted failure pressure calculations.
---------------------------------------------------------------------------

    \49\ 85 FR 40132 (July 6, 2020).
---------------------------------------------------------------------------

    In an earlier section of the repair criteria discussion, PHMSA
noted that the identification of anomalies based on ILI results is an
actionable indication that there might be an injurious defect in the
pipeline. Establishing repair criteria based on operators discovering
these actionable anomalies assures that these anomalies are
investigated promptly and repaired. Therefore, PHMSA disagrees with
commenters who suggested that there should be separate timelines for
anomaly responses and repairs, as it would be prudent for operators to
perform any necessary repairs once the operator has excavated the pipe
and exposed the anomaly for investigation rather than deferring such
repairs.

F. Repair Criteria--Sec. Sec.  192.714, 192.933

vii. Miscellaneous Comments
1. Summary of Public Comments
    Commenters were concerned that the requirements in this rulemaking
would apply to gas gathering pipelines and requested that PHMSA clarify
this is not the case. Similarly, the GPAC, in its late March 2018
meeting, recommended PHMSA clarify that the non-HCA repair criteria
applied to those pipeline segments not currently covered under the IM
regulations at subpart O.
    Additionally, pipeline operators and their trade associations
requested that PHMSA clarify the effective date of the repair
provisions, as the requirements were proposed in an allegedly
retroactive section of the regulations. These commenters claimed, as
written, the proposed provisions would force operators to apply the
revised repair criteria to prior ILI assessments that, at the time, met
all the standards of the regulations. Some of these commenters
recommended PHMSA establish reasonable, risk-based timeframes for
operators to implement repairs of anomalies that were historically
identified and were repaired in accordance with the code requirements
of the time. The GPAC, during their meeting in late March of 2018,
similarly recommended that PHMSA add an effective date to these general
repair provisions to clarify that they were not retroactive.
    Some commenters also discussed the application of the proposed
repair criteria to pipelines outside of HCAs that have established
their MAOP under the alternative requirements at Sec.  192.620. The
GPAC recommended PHMSA apply appropriate predicted failure pressure
factors to alternative MAOP pipelines based on class location and
design factors for scheduled conditions under the repair criteria.
2. PHMSA Response
    PHMSA did not intend for the new repair criteria for non-HCA pipe
segments to be applicable to gas gathering pipelines, HCA segments, or
offshore transmission lines. However, PHMSA will consider expanding the
application of these provisions in the future. In this final rule, to
clarify that the new non-HCA repair criteria apply only to onshore
transmission lines, PHMSA placed the new non-HCA repair criteria in a
new Sec.  192.714, which applies only to onshore transmission lines.
Subsequently, PHMSA withdrew all proposed changes to Sec.  192.713.
PHMSA has also revised Sec.  192.9 in this final rule to exempt
regulated gas gathering lines from the requirements of Sec.  192.714.
Additionally, PHMSA has modified Sec.  192.711 in this final rule to
clarify that the new repair criteria in Sec.  192.714 do not apply to
gathering lines or HCA segments subject to subpart O. The current and
unchanged Sec.  192.713 would continue to apply to regulated gas
gathering lines. Although the creation of a new Sec.  192.714 was not
discussed at the GPAC, PHMSA determined that this approach was a
clearer means to specify that the new non-HCA repair criteria only
apply to onshore transmission pipelines and meet the intent of the GPAC
recommendation to clarify that the non-HCA repair criteria do not apply
to gathering lines, HCA segments, or offshore transmission lines.
Furthermore, PHMSA determined that this approach avoids duplication of
repair language in other code sections.
    PHMSA did not intend to imply that the new repair criteria were to
be applied retroactively and has clarified this intent in this final
rule by revising Sec.  192.711(b) to include an effective date as
recommended by the GPAC.
    Regarding alternative MAOP pipelines, the NPRM did not propose, and
therefore did not give opportunity for comment on, changes to repair
criteria for alternative MAOP pipe segments. However, PHMSA agrees with
commenters that the language proposed in the NPRM could create
ambiguity with respect to the applicability of the non-HCA repair
criteria to pipe with MAOP established in accordance with Sec.
192.620. Therefore, in this final rule, PHMSA more broadly exempted
alternative MAOP lines from compliance with non-HCA repair criteria and
reiterated the applicability of the repair criteria provided at the
alternative MAOP provisions under Sec.  192.620(d)(11) as they provide
a comparable level of safety based upon the operating factors. PHMSA
did not make a corresponding change to Sec.  192.933, as alternative
MAOP pipelines in HCAs must meet both the HCA and the alternative MAOP
repair criteria. This approach is preferable to repeating the alternate
MAOP repair criteria in two locations of part 192.

G. Definitions--Sec.  192.3

i. Close Interval Survey
1. Summary of PHMSA's Proposal
    In the NPRM, PHMSA proposed a new definition for ``close interval
survey'' as a series of closely spaced pipe-to-electrolyte potential
measurements taken to assess the adequacy of cathodic protection or to
identify locations where a current may be leaving the pipeline and may
cause corrosion, and for the purpose of quantifying voltage drops other
than those across the structure electrolyte boundary.
2. Summary of Public Comment
    Comments from the trade associations and GPAC members representing
the industry questioned whether PHMSA should tie the definition of
``close interval survey'' to a corresponding NACE standard for
consistency. PHMSA presented some minor changes to the definition at
the meeting on March 28, 2018, and the committee voted 13-0 that PHMSA
should adopt those changes into the final rule.
3. PHMSA Response
    After considering the comments and GPAC recommendations, PHMSA is
adopting the definition of ``close interval survey'' as recommended by
GPAC. As such, PHMSA has specified that the pipe-to-electrolyte
potential measurements are taken ``over the pipe,'' and added the
phrase ``such as when performed as a current interrupted, depolarized,
or native survey'' to qualify what is ``other than those across the
structure electrolyte boundary.''

G. Definitions--Sec.  192.3

ii. Distribution Center
1. Summary of PHMSA's Proposal
    PHMSA proposed to define a ``distribution center'' as a location
where gas volumes are either metered or have a pressure or volume
reduction prior to delivery to customers through a distribution line.
2. Summary of Public Comment
    AGL Resources, Pipeline Safety Coalition, Southern California Gas

Company, Spire STL Pipeline LLC, and Xcel Energy supported PHMSA's
intention to define the term ``distribution center.'' In particular,
AGL Resources stated that the proposed definition would remove
confusion and the potential for conflict between operators and
regulators throughout the Nation. Like its comments on the proposed
definition for ``transmission line,'' Xcel Energy suggested that PHMSA
add an implementation period for operators to handle the regulatory
impacts of the new definition.
    AGA supported PHMSA's effort to define a ``distribution center'' to
ensure consistency and certainty in the identification of transmission
lines. However, AGA also stated that PHMSA failed to provide any
justification or explanation for its proposed definition, and AGA
proposed an alternative definition of ``distribution center'' where
piping downstream of a distribution center that operates above 20
percent SMYS would be classified as a transmission line. Other
organizations, such as Alliant Energy, Dominion Energy, PECO Energy,
Paiute Pipeline Company, and Southwest Gas Corporation, supported AGA's
alternative definition.
    TPA recommended PHMSA revise the proposed definition of
``distribution center'' to provide a clear endpoint for transmission
lines and the start of distribution lines. Atmos Energy stated that the
proposed definition did not recognize the many possible configurations
of pipes in which transmission pipelines deliver to distribution
systems. For example, Oleksa and Associates stated that some
distribution systems may have no meters prior to delivery to customers
and also may have no pressure or volume reductions (e.g., a
distribution system supplied by a landfill). Lastly, Cascade Natural
Gas requested the term ``distribution center'' clearly refer to
distribution pipelines and that such a definition should not be
included in a rulemaking for transmission and gathering pipelines.
    At the GPAC meeting, PHMSA offered for the committee's
consideration the option of recommending withdrawal of the proposed
definition for ``distribution center.'' Committee members opposed this
suggestion, stating that finalizing a definition for ``distribution
center'' would provide the industry and regulators with regulatory
certainty and clarity. During the meeting, committee members came to a
consensus on the definition of a ``distribution center'' based on
comments the industry provided. However, certain committee members
representing the public were not inclined to adopt a definition of a
``distribution center'' that was based on the comments provided by
industry and wished to defer to PHMSA regarding the wordsmithing of the
definition.
    Following the discussion, the committee voted 10-0 that the
definition for ``distribution center'' was technically feasible,
reasonable, cost-effective, and practicable if PHMSA incorporated a
definition for ``distribution center'' in the final rule and considered
revising the definition to mean the initial point where gas enters
piping used to deliver gas to customers for end use as opposed to
customers who purchase it for resale. Examples of a distribution center
would include a metering location; a pressure reduction location; or
where there is a reduction in the volume of gas, such as a lateral off
a transmission pipeline.
3. PHMSA Response
    After considering the comments received and the GPAC's
recommendations, PHMSA is adopting the definition recommended by GPAC
so that a ``distribution center'' means the initial point where gas
enters piping used to deliver gas to customers for end use as opposed
to customers who purchase it for resale.
    PHMSA disagrees that an implementation period for the definition is
appropriate, given that this term has been in use for a long period of
time. PHMSA agrees with commenters for the need to clarify the end
point of transmission and the start of distribution. PHMSA agrees with
those commenters who suggested that piping downstream of a distribution
center operating at above 20 percent SMYS should be considered a
transmission line and is modifying the definition of ``transmission
line'' accordingly in this final rule.

G. Definitions--Sec.  192.3

iii. Dry Gas or Dry Natural Gas
1. Summary of PHMSA's Proposal
    In the NPRM, PHMSA proposed a new definition for the term ``dry gas
or dry natural gas'' to mean gas with less than 7 pounds of water per
million cubic feet that is not subject to excessive upsets allowing
electrolytes into the gas system.
2. Summary of Public Comment
    GPAC members representing the industry asked whether PHMSA should
tie the definition for dry gas to the corresponding NACE standard for
continuity. Committee members representing the public were concerned
about incorporating by reference the definition into the regulations
but were amenable to lifting the language directly from the standard to
ensure consistency. PHMSA representatives noted that the agency could
consider the NACE definition and make the definition for dry gas less
prescriptive than proposed.
    After discussion, the committee voted 13-0 that the definition for
``dry gas or dry natural gas'' was technically feasible, reasonable,
cost-effective, and practicable if PHMSA revised the definition to be
consistent with the NACE definition as discussed at the meeting.
3. PHMSA Response
    PHMSA has taken into consideration the comments as well as the GPAC
recommendations and is modifying the definition for ``dry gas or dry
natural gas'' to be consistent with the NACE standard. More
specifically, the definition specifies that ``dry gas or dry natural
gas'' is gas ``above its dew point and without condensed liquids.''

G. Definitions--Sec.  192.3

iv. Electrical Survey
1. Summary of PHMSA's Proposal
    In the NPRM, PHMSA proposed revising the term ``electrical survey''
so that it means a series of closely spaced measurements of the
potential difference between two reference electrodes to determine
where the current is leaving the pipe on ineffectively coated or bare
pipelines.
2. Summary of Public Comment
    PHMSA received a variety of comments on the definition for
``electrical survey.'' Some commenters expressed support for the
definition and its inclusion in the regulations. Other commenters
supported the concept of the definition but provided PHMSA with varying
edits to improve on the clarity and functionality of the definition.
    Several commenters noted that the proposed definition for
electrical survey was duplicative with the proposed definition for
``close interval survey'' and recommended that PHMSA retain the
definition for close interval survey instead. Some of these commenters
noted that the proposed definition for electrical survey was more
restrictive than the definition of electrical survey in NACE standards
and excluded certain types of surveys. Other commenters suggested that
the proposed definition for electrical survey should match the
definition in various NACE standards.
    NACE itself believed that the definition used in the NPRM for

``electrical survey'' was ambiguous and inaccurate, stating the
proposed definition does not align with current terminology and
accepted pipeline integrity practices. NACE recommended that PHMSA use
the definition for ``indirect inspection'' in NACE SP0502, which is
widely accepted as standard practice and should meet PHMSA's intent.
    The GPAC recommended that PHMSA withdraw the proposed changes to
appendix D as a part of the recommended revisions to the proposed
corrosion control regulations. There was no further discussion on the
definition for the term, and the committee voted, 13-0, to delete the
definition from the rule.
3. PHMSA Response
    PHMSA notes that, when the committee voted to withdraw the proposed
changes to appendix D as a part of the corrosion control discussion, a
revised definition for electrical survey was unnecessary as all
references to ``electrical surveys'' were removed. Therefore, PHMSA
agrees with the GPAC recommendation and has struck the proposed
revision to the definition of ``electrical survey'' from this final
rule.

G. Definitions--Sec.  192.3

v. Hard Spot
1. Summary of PHMSA's Proposal
    In the NPRM, PHMSA proposed to define a ``hard spot'' as steel pipe
material with a minimum dimension greater than 2 inches (50.8 mm) in
any direction with hardness greater than or equal to Rockwell 35 HRC,
Brinnel 327 HB, or Vickers 345 HV10.
2. Summary of Public Comment
    During the GPAC meeting, committee members noted there was a small
editorial correction that needed to be made--changing ``Brinnel'' to
``Brinell'' --and also recommended that the definition be prefaced with
the phrase ``an area on'' so that the definition reads ``an area on
steel pipe material [. . .].''
3. PHMSA Response
    PHMSA has modified the proposed definition of hard spot as the GPAC
recommended for this final rule.

G. Definitions--Sec.  192.3

vi. In-Line Inspection (ILI) and In-Line Inspection Tool or
Instrumented Internal Inspection Device
1. Summary of PHMSA's Proposal
    In the NPRM, PHMSA proposed to add definitions for ``in-line
inspection (ILI)'' and ``in-line inspection tool or instrumental
internal inspection device'' to Sec.  192.3. Specifically, the term
``in-line inspection'' would mean the inspection of a pipeline from the
interior of the pipe using an ILI tool, which may also be known as
intelligent or smart pigging. The term ``in-line inspection tool or
instrumented internal inspection device'' would mean a device or
vehicle that inspects a pipeline from the inside using a non-
destructive technique. Such a device might also be called an
intelligent or smart pig.
2. Summary of Public Comment
    NACE International commented that the proposed definitions of ``in-
line inspection'' and ``in-line inspection tool or instrumented
internal inspection device'' do not align with the definition provided
in NACE International Standard SP01024 or SP0102, respectively. NACE
International suggested that PHMSA use the definition in NACE Standard
SP0102, as PHMSA had proposed to incorporate by reference the standard
in the regulations.
    The GPAC reviewed the proposed definitions and, following their
discussion, voted 13-0 that the definitions for ``in-line inspection''
and ``in-line inspection tool or instrumented internal inspection
device'' were technically feasible, reasonable, cost-effective, and
practicable if PHMSA considered clarifying in the preamble that the
phrase ``a line that can accommodate inspection by means of an
instrumented in-line inspection tool'' referred to pipeline segments
that can be inspected with free-swimming ILI tools without any
permanent physical modification of the pipeline segment.
3. PHMSA Response
    After considering these comments, PHMSA is modifying the
definitions of both ``in-line inspection'' and ``in-line inspection
tool or instrumented internal inspection device'' based on the
definitions in NACE SP0102-2010. In accordance with the GPAC
recommendation, PHMSA is also noting that an ILI can include both
tethered and self-propelled (i.e., ``free-swimming'') tools.

G. Definitions--Sec.  192.3

vii. Transmission Line
1. Summary of PHMSA's Proposal
    In the NPRM, PHMSA proposed to modify the second criterion of the
``transmission line'' definition to base the percentage of SMYS on the
MAOP of the pipeline, whereas currently it is based on the pressure at
which the pipeline is operating. PHMSA also proposed editorial changes
to the ``Note'' section of the definition and make it clearer that
``factories, power plants, and institutional users of gas'' were
examples of a large-volume customer.
2. Summary of Public Comment
    AGA asserted that modifying the second criterion in the
``transmission line'' definition in conjunction with other definition
changes PHMSA proposed would result in the reclassification of some
transmission pipelines to distribution lines and some distribution
pipelines to transmission lines. Several pipeline operators and
industry representatives, including AGL Resources, Alliant Energy,
Black Hills Energy, Cascade Natural Gas, Centerpoint Energy, Spire,
Delmarva Power, National Grid, National Fuel Gas Supply Corporation,
North Dakota Petroleum Council, Paiute Pipelines, TECO Peoples Gas,
TPA, and PECO Energy, supported AGA's comments or provided similar
recommendations. Additionally, Dominion East Ohio and Southwest Gas
objected to PHMSA's proposed modifications to the definition, stating
that the proposed definition would burden operators with ongoing IM
programs with no additional benefit to public safety.
    APGA commented that PHMSA's slight rewording of the note in the
transmission definition regarding types of large-volume customers could
be interpreted to mean that only factories, power plants, and
institutional users of gas can be large-volume customers. APGA
suggested PHMSA change the proposed language in the final rule to
clarify that those listed items are examples of large-volume customers
rather than a comprehensive list.
    ONE Gas proposed an alternative simplified approach to the
definition of ``transmission line'' that focuses on a line's MAOP as it
relates to the percentage of yield strength.
    There were various comments from other pipeline operators,
including the suggestion that PHMSA remove the term ``distribution
center'' from the definition of ``transmission line,'' allow operators
to use MAOP to determine a transmission pipeline, and provide an
implementation period for operators to incorporate regulatory
requirements of the newly defined transmission lines.
    During the GPAC meeting, committee members representing the
industry expressed support for allowing operators to designate
pipelines voluntarily as transmission lines, especially if their risk
profile was high,

so that operators could operate and maintain those lines to a higher
standard.
    Following the discussion, the committee voted 10-0 that the
definition for ``transmission line'' was technically feasible,
reasonable, cost-effective, and practicable if PHMSA included the
phrase ``an interconnected series of pipelines'' within the text of the
definition and allowed operators to designate pipelines voluntarily as
transmission lines.
3. PHMSA Response
    PHMSA has considered the comments received regarding the proposed
definition of a ``transmission line.'' PHMSA agrees with the
recommendation from the GPAC to allow operators to designate pipelines
voluntarily as transmission lines, as well as the recommendation from
the GPAC to include the phrase ``an interconnected series of
pipelines.'' Accordingly, PHMSA has revised the definition of
``transmission line'' in this final rule to include these
recommendations.
    PHMSA agrees with commenters that the language to clarify the
examples of large-volume customers may imply a specific list and has
withdrawn the changes to the note in the definition. In response to the
comment on providing an implementation period for compliance with the
new definition, PHMSA notes that it does not apply separate
implementation periods to definitions outside of the effective date of
the rule. If PHMSA determines that corresponding regulations would be
affected by a change in a definition, it incorporates appropriate
implementation time to those regulations as necessary.
    PHMSA also notes that, per the comments received on the definition
for ``distribution center,'' it agreed with commenters who suggested
that piping downstream of a distribution center operating at above 20
percent of SMYS should be considered a transmission line and is
modifying the definition of ``transmission line'' accordingly in this
final rule.
    PHMSA sees no functional difference in changing the definition of a
transmission line from a pipeline that operators at a hoop stress of 20
percent or more of SMYS and a pipeline that has a MAOP of 20 percent or
more of SMYS. For a pipeline to operate above 20 percent or more of
SMYS, it will have an MAOP of 20 percent or more of SMYS. If an
operator has a pipeline where the theoretical MAOP is higher than the
pipeline's actual operating pressure, and therefore the line would need
to be reclassified, the operator could reduce the MAOP of the line to
keep the line's classification the same without affecting its operating
pressure.

G. Definitions--Sec.  192.3

viii. Wrinkle Bend
1. Summary of PHMSA's Proposal
    In the NPRM, PHMSA proposed to define ``wrinkle bend'' as a bend in
the pipe that was formed in the field during construction such that the
inside radius of the bend has one or more ripples of various sizes or
where the ratio of peaks to peaks or peaks to valleys are of a certain
size, or where a mathematical equation could be substituted when a
wrinkle bend's length cannot reliably be determined.
2. Summary of Public Comment