pipe completely unrelated to the segment in which the class location
has changed. Because PHMSA proposed to extend integrity assessments
outside of HCAs in the 2016 Gas Transmission NPRM, these commenters
suggested that special permit inspection areas are no longer
appropriate or necessary to ensure pipeline safety. Similarly, Kinder
Morgan stated that IM measures address segment threats, and the
additional requirements detailed in the 2016 Gas Transmission NPRM will
cover pipeline segments up and downstream of the class-location change.
    An individual citizen commented that prescribing mileage to be
assessed is not appropriate, as it could potentially exempt from the
requirements pipeline segments that do not have 50 miles of pipe
between ILI tool launcher and receivers.
    Another individual citizen recommended that, if PHMSA were to allow
an IM alternative for class location changes, operators should have to
inform PHMSA and affiliated State agencies of their intent to apply IM
measures for managing a pipeline segment changing from a Class 1 to a
Class 3 location.
3. PHMSA Response
    To the PST's comment that class location change special permits
should not be issued if the applicable pipeline segment cannot be
assessed with ILI tools or does not have accurate and verifiable design
records, PHMSA is proposing to require in this NPRM that the segment
must be ``piggable'' to be eligible for the IM alternative to the class
location change requirements. Operators must also have pipe material
property records for the segment to be eligible.
    PHMSA does not believe that assessments and repairs alone are
adequate to demonstrate the eligibility and fitness-for-service of pipe
manufactured to Class 1 location standards to be used in Class 3
locations. In addition, PHMSA has elected to finalize the provisions
proposed in the 2016 Gas Transmission NPRM in three separate final
rules--the 2019 Gas Transmission Final Rule was published October 1,
2019, and the other two are in development. While the 2019 Gas
Transmission Final Rule did include updated assessment requirements for
``moderate consequence areas,'' PHMSA intends to finalize the
corresponding repair criteria in a draft final rule currently titled
``Pipeline Safety: Safety of Gas Transmission Pipelines, Repair
Criteria, Integrity Management Improvements, Cathodic Protection,
Management of Change, and Other Related Amendments.'' PHMSA does not
believe that managing Class 1 to Class 3 location changes using an
updated assessment schedule with the existing repair criteria would
provide an equivalent level of safety when compared to pipe replacement
without additional P&M requirements being applied to the eligible pipe.
ASME B31.8S allows anomalies to grow until only a 10 percent safety
factor remains before they need to be remediated. In this NPRM, PHMSA
is proposing that operators remediate anomalies that have a predicted
failure pressure of less than 1.39 or a depth of less than 40 percent
of the pipe wall thickness. This safety factor of 1.39 would be similar
to the installation of new Class 1 pipe.
    Further, PHMSA agrees with NAPSR and the PST that the study
performed under the requirements at Sec.  192.609, when a pipeline's
class location changes is, in many ways, a type of fitness-for-service
study. PHMSA is hesitant to incorporate a general requirement for
operators to perform a fitness-for-service evaluation because PHMSA is
concerned that such an evaluation would not result in a consistently
applied minimum safety standard across the industry. Therefore, the
specific eligibility conditions PHMSA is proposing in the IM
alternative for threat identification in this NPRM would be akin to
prescribing a fitness-for-service standard that operators would have to
meet to use the IM alternative.
    For the purposes of an operator determining if a segment would be
``fit for service'' to apply IM measures for managing pipeline segments
changing from a Class 1 to a Class 3 location, PHMSA is proposing a set
of pipe attributes that would disqualify a segment from using the IM
alternative based on threats and their higher risks. Those attributes,
and the corresponding threats, are:
    (1) Bare pipe, which cannot maintain proper CP currents;
    (2) Pipe with wrinkle bends, which can be prone to cracking;
    (3) Pipe without records reflecting key attributes, including
diameter, wall thickness, grade, seam type, yield strength, and tensile
strength, which do not allow for proper anomaly evaluation;
    (4) Pipe uprated in accordance with subpart K but without a
pressure test to at least 1.39 times MAOP, unless the segment passes a
subpart J pressure test for a minimum of 8 hours at a minimum pressure
of 1.39 times MAOP within 24 months after the Class 1 to Class 3
location segment change and prior to uprating the MAOP. PHMSA believes
that allowing pipe that has been operated for years at a lower pressure
to be uprated without additional requirements presents undue risk;
    (5) Pipe that has not been pressure tested in accordance with
subpart J for 8 hours at a minimum test pressure of 1.25 times MAOP,
unless the segment passes a subpart J pressure test for a minimum of 8
hours at a minimum pressure of 1.25 times MAOP within 24 months after
the Class 1 to Class 3 segment change. The treatment of this attribute
is consistent with the current regulatory requirements and will not
allow pipeline segments that have been operating in accordance with
Sec.  192.619(c), which may lack material records or be operated above
72 percent SMYS, to be managed under the IM alternative;
    (6) Pipe with DC, LF-ERW, EFW, or lap-welded seams, or with a
longitudinal joint factor below 1.0, which are prone to seam failure
due to cracking and improper jointing that results in lower-strength
joints;
    (7) Pipe, in or within 5 miles of the Class 1 to Class 3 location
segment, with cracking in the pipe body, seam, or girth welds that is
over 20 percent of the pipe wall thickness; \87\ has a predicted
failure pressure less than 100 percent of SMYS; has a predicted failure
pressure less than 1.5 times MAOP; \88\ has experienced a leak or
rupture due to pipe cracking; or for which an analysis indicates the
pipe could fail in brittle mode. Cracking leads to ruptures on pipe
segments with poor toughness properties;
---------------------------------------------------------------------------

    \87\ In PHMSA's experience, current ILI tool detection
effectiveness for cracks is at approximately 10 to 20 percent depth.
    \88\ This threshold is based on a related recommendation from
the Gas Pipeline Advisory Committee on repair criteria. See https://primis.phmsa.dot.gov/meetings/MtgHome.mtg?mtg=132 for more details.

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    (8) Pipe with poor external coating that requires negative cathodic
polarization voltage shifts of 100 millivolts or more,\89\ or linear
anodes to maintain cathodic protection, or pipe with tape wraps or
shrink sleeves. The treatment of this attribute is consistent with
Appendix D to part 192, which is referenced at Sec.  192.463. Such pipe
may have issues with corrosion control or cracking;
---------------------------------------------------------------------------

    \89\ A.W. Peabody, ``Peabody's Control of Pipeline Corrosion,''
second edition, ``Criteria for Cathodic Protection.'' ``The 100 mV
polarization criterion should not be used in areas subject to stray
current because 100 mV of polarization may not be sufficient to
mitigate corrosion in these areas. It is generally not possible to
interrupt the source of the stray currents to accurately measure the
depolarization. To apply this criterion, all DC current sources
affecting the structure, including rectifiers, sacrificial anodes,
and bonds must be interrupted. In many instances, this is not
possible, especially on the older structures for which the criterion
is most likely to be used. The 100 mV polarization criterion should
not be used on structures that contain dissimilar metal couples
because 100 mV of polarization may not be adequate to protect the
active metal in the couple. This criterion also should not be used
in areas where the intergranular form of external SCC, also referred
to as high-pH or classical SCC is suspected. The potential range for
cracking lies between the native potential and -850 mV (CSE) such
that application of the 100 mV polarization criterion may place the
potential of the structure in the range for cracking.''
---------------------------------------------------------------------------

    (9) Pipe transporting gas that is not of a suitable composition
quality for sale to gas distribution customers, such as sour gas, which
can lead to issues with corrosion; and
    (10) Pipe that operates in accordance with Sec.  192.619 (c) or
(d).
    Operators with such higher-risk pipeline segments would still be
able to apply for a special permit for class location change
management. Operators with pipeline segments that do not have any of
the listed disqualifying attributes could use the IM alternative. PHMSA
believes this proposed approach is a way to establish if Class 1 pipe
is suitable (``fit for service'') for operators to use IM methods to
verify MAOP in a Class 3 location, while providing an equivalent level
of safety, over the life of a pipeline, as pipe replacement. As the
majority of these disqualifying attributes have been used to ensure
safety in class location special permits for several years,
incorporating these disqualifying attributes into this rulemaking
should provide an equivalent level of safety compared to the special
permits. PHMSA requests comment as to whether these eligibility
conditions are appropriate, and whether the elimination or modification
of them would impact safety, and how. Is there an alternative approach
PHMSA could take that would modify or eliminate these eligibility
conditions that would maintain safety and increase the net benefits of
this rulemaking?
    PHMSA agrees with commenters that requiring operators to assess an
additional 25 miles upstream and downstream from the class location
change is unnecessary. When the general special permit conditions were
drafted in 2004, PHMSA used the 25-mile inspection area as a sort of
proxy for the length of pipeline between an ILI tool launcher and
receiver. PHMSA is proposing to require instead that operators assess
the length of pipeline between the ILI tool launcher and receiver
containing the Class 1 to Class 3 location segment without prescribing
a specific numeric value for the mileage to be assessed. The ILI tool
launchers and receivers are the natural beginning and endpoints for an
inspection area rather than an arbitrary amount of mileage.
    PHMSA believes that approving each case in which an operator uses
the proposed IM alternative for managing class location changes in lieu
of pipe replacement is unnecessary for public safety and would not be
significantly more efficient than the current approach of operators
applying for special permits. However, PHMSA is proposing a
notification requirement so that PHMSA and applicable State agencies
are aware of each instance in which an operator uses the proposed IM
alternative. This notification requirement will allow PHMSA and State
regulators to know where these pipeline segments are located and can
consider them when conducting inspections.

F. Eligibility for Pipe Operating in Accordance With Sec.  192.619(c)

1. Summary of ANPRM Questions 1c and 4a(i)
    In the ANPRM, PHMSA requested comments on whether pipe operating in
accordance with Sec.  192.619(c) (e.g., pipeline segments with
operating pressures above 72 percent SMYS, pipeline segments without a
pressure test or with an inadequate pressure test, or pipeline segments
with inadequate or missing material properties records), should be
eligible for class location change management using IM principles.
PHMSA also asked if part 192 should continue to require pipe integrity
upgrades for pipeline segments operating in accordance with Sec.
192.619(c).
2. Summary of Comments
    NAPSR and the PST commented that pipeline segments operating in
accordance with Sec.  192.619(c) that lack design, material, or
pressure test records should be required to follow the existing class
location change requirements. They also seemed to suggest that, if
PHMSA moved towards providing an IM alternative to class location
changes, operators could incorporate pipeline segments operating in
accordance with Sec.  192.619(c) that have undergone a class location
change into their IM programs if they performed more robust integrity
assessments and mitigation measures on those segments.
    The California Public Advocates Office requested that PHMSA confirm
pipeline segments operating in accordance with Sec.  192.619(c) will
not be allowed to continue operating in accordance with Sec.
192.619(c) after a class change, consistent with current regulations
and interpretations. Specifically, they noted that PHMSA interpretation
PI-14-0005 states:

    If an operator uses Sec.  192.619(c) to establish the MAOP, the
operator must have documentation of the pipeline segment's condition
and operating and maintenance history, including historical pressure
records for the maximum operating pressure to which the entire
pipeline segment was subjected during the 5 years prior to July 1,
1970. Section 192.619(c) cannot be used to determine the MAOP after
a change in Class Location. Section 192.611 can be used to revise
the MAOP within 24 months after a Class Location change; after that
deadline, the MAOP must be revised according to Sec.  192.619(a).

    The Associations and supporting operators recommended an IM
alternative that would include hoop stress limitations as follows: 80
percent of the SMYS in Class 2 locations; 72 percent of SMYS in Class 3
locations; and 60 percent of SMYS in Class 4 locations. These
commenters noted that a hoop stress limitation of 80 percent for Class
2 locations is supported by several existing special permits.
    The Associations and supporting operators also noted that the 2016
Gas Transmission NPRM provides a means for reconfirmation of MAOP for
pipeline segments operating in accordance with Sec.  192.619(c).\90\ So
long as operators complete MAOP reconfirmation within 24 months of the
class change, these commenters believed pipeline segments operating in
accordance with Sec.  192.619(c) should be eligible for the class
location change alternative. However, these commenters also stated that
the MAOP reconfirmation test factor used should correspond with the
class location and installation date at the time of construction,
claiming that if PHMSA enforced the use of current

class location test factors, it would likely result in pipe
replacements or pressure reductions that undermine the application of
IM principles due to the class location change segment not being
designed to meet the Class 3 pressure test factors.
---------------------------------------------------------------------------

    \90\ See 84 FR 52196 and 84 FR 52247.
---------------------------------------------------------------------------

    An individual citizen commented that the hoop stress of a pipeline
segment cannot be determined if it has an unknown outside diameter,
wall thickness, and SMYS. This commenter asked how an operator would be
able to comply with class location change requirements if these values
were unknown. If these variables were known, this commenter stated,
then a multi-tool ILI inspection program in conjunction with chemical
and physical sample tests would provide comparable assurance of
compliance and safety.
3. PHMSA Response
    Commenters are divided on whether pipeline segments operating in
accordance with Sec.  192.619(c) should be eligible for being managed
with an IM alternative when class locations change. Pipeline segments
operating in accordance with Sec.  192.619(c) were installed prior to
adoption of the PSR and that do not meet Sec.  192.619(a)(1), (2), or
(4), or they operate above 72 percent of SMYS. These pipeline segments
may not have pressure test or material properties records.\91\ Section
192.619(c) requires that an operator must still comply with Sec.
192.611 should a class location change occur. This, in effect,
precludes pipeline segments that operate in accordance with Sec.
192.619(c) from continuing to operate without a pressure test or
pressure reduction and records of pipe material properties when the
class location changes. Given that pipeline segments operating in
accordance with Sec.  192.619(c) tend to be higher risk,\92\ PHMSA's
proposal states that pipeline segments operating at greater than 72
percent SMYS and pipeline segments that are missing pipe material
properties records are not candidates for the proposed IM alternative
to class location change management.
---------------------------------------------------------------------------

    \91\ This data is included in PHMSA's annual reports. Pipeline
operators are required to report which pipelines operate at greater
than 72% SMYS, which method of MAOP determination was used for the
pipeline, and whether the pipeline has incomplete records.
    \92\ Operators may know the material properties of pipeline
segments operating in accordance with Sec.  192.619(c). However,
many pipeline segments operating in accordance with Sec.  192.619(c)
lack adequate material records, and may be operating at higher
stress levels (above 72 percent SMYS) than what the pipe design
would allow, if the pipe were to be constructed to today's
standards.
---------------------------------------------------------------------------

    However, in this NPRM, PHMSA proposes that operators of pipelines
that were previously operating in accordance with Sec.  192.619(c) that
operate at or below 72 percent SMYS be eligible for the IM alternative
only if the operator pressure tests any of those pipelines that do not
have a record of a previous pressure test within 24 months after the
class location change and have pipe material records for the segment.
PHMSA proposes such a pressure test must meet current subpart J
requirements for a new segment installed in a Class 2 location (the
test pressure must be at least 1.25 times MAOP for 8 continuous hours).
Operators would need to test such pipeline segments to Class 2
standards rather than Class 3 standards because testing Class 1 pipe to
Class 3 standards would result in a rupture and would require the
operator to replace the pipe. This approach is consistent with the
special permit conditions PHMSA has imposed on pipelines previously
operating in accordance with Sec.  192.619(c).
    PHMSA is also proposing that this pressure-testing approach would
apply to pipeline segments uprated in accordance with subpart K, except
the pressure test for uprating the MAOP on a pipeline segment where the
operator lowered the MAOP for a Class 1 to Class 3 location change
would require a subpart J pressure test of 1.39 times the uprated MAOP
for 8 continuous hours. Under this approach, operators would still be
allowed to apply for a special permit for pipeline segments with the
MAOP established in accordance with Sec.  192.619(c) that would not
meet the proposed requirements. Typically, an operator will downrate
the pressure of a pipeline segment because the segment is not meeting
regulatory standards and the contractual flow volumes have diminished
(i.e., they have lost customers). PHMSA is adding this requirement
because if a pipeline is being uprated, it means that it has been
operating at a lower pressure than to what the operator wants to raise
the MAOP. Therefore, an operator must conduct a pressure test to a
level that will justify the new, higher MAOP.
    To the Associations' point regarding hoop stress limitations, class
location change special permits have been limited to Class 1 to Class 3
location changes only. With the publication of the alternate MAOP rule
in 2008,\93\ PHMSA allowed pipelines to operate up to 80 percent SMYS
in Class 1 locations if those pipelines were built to certain
specifications and are operated with procedures that are additional
(e.g., 49 CFR 192.112, 192.328, and 192.620) to the normal procedures
for pipelines operated at 72 percent SMYS. Pipelines built for Class 1
and Class 2 locations were not designed or constructed to operate at a
hoop stress up to 80 percent SMYS. Should operators conclude that their
design, construction, and operation procedures fulfill the standards of
the Alternate MAOP rule at Sec. Sec.  192.112, 192.328, and 192.620,
then they can apply for a special permit in accordance with Sec.
190.341.
---------------------------------------------------------------------------

    \93\ ``Standards for Increasing the Maximum Allowable Operating
Pressure for Gas Transmission Pipelines,'' 73 FR 62148 (Oct. 17,
2008).
---------------------------------------------------------------------------

G. Eligibility for Pipe With Specific Conditions and Attributes

1. Summary of ANPRM Questions 4a(ii), 4a(iii), 4a(vii), and 4a(viii)
    In question 4 of the ANPRM, PHMSA requested comments on whether
specific pipe conditions should affect a pipeline segment's eligibility
for an IM alternative for class location management.
    Specifically, PHMSA requested comments on whether pipeline segments
that have a failure or leak history, were manufactured with a material
or seam welding process during a time or by a manufacturer that has
been shown over time to experience known integrity issues, or have
lower toughness in the pipe and weld seam (e.g., Charpy impact value
\94\), should be eligible for an IM alternative. PHMSA also asked
whether pipeline segments that contain or are susceptible to cracking,
including in the body, seam, or girth weld, or pipeline segments that
have disbonded coating or CP shielding coatings, should be eligible for
the IM alternative. Further, PHMSA asked whether pipe with seams that
are lap-welded, flash-welded, low-frequency electric resistance welded;
are of ``unknown'' type; have a history of seam failure due to poor
manufacturing properties; or have a derating factor below 1.0, should
be eligible for an IM alternative.
---------------------------------------------------------------------------

    \94\ A Charpy V-notch impact test and its values indicate the
toughness of a given material at a specified temperature and is used
in fracture mechanics analysis.
---------------------------------------------------------------------------

2. Summary of Comments
    The California Public Advocates Office stated that pipeline
segments should not be eligible for the IM alternative for class
location change management if they have experienced an in-service
failure, have manufacturing issues, or have a lower toughness in the
weld seam. It proposed that PHMSA consider holding a

workshop to determine appropriate leak history thresholds and prescribe
the eligibility of pipe with known integrity issues. It also commented
that, if the operator does not know the seam type, the operator must
determine the seam type or be required to use a longitudinal joint
factor of 0.8 in any design calculations, even if the operator asserts
all possible seam types merit a value of 1.0. It also expressed that,
regardless of whether IM measures are deemed appropriate, the derating
factor should be the more conservative of either the derating factor
used at the time of construction or current design factors.
    TransCanada Corporation commented that operators should conduct a
site-specific assessment taking into consideration pipe design,
history, and environmental factors to determine whether particular
pipeline segments should be eligible for an IM alternative when class
locations change. It argued that pipeline segments should be eligible
if operators can use integrity measures to manage any associated
threats effectively. It noted that lap-welded pipe was an exception and
should not be eligible for IM measures, as current inspection
technology is not sufficient in determining lap-weld seam integrity.
    NAPSR and the PST expressed the view that PHMSA should consider all
the factors listed in Question 4 of the ANPRM, including whether a
pipeline is operating in accordance with Sec.  192.619(c), has
experienced an in-service failure, or has significant corrosion or
other damage; the age of the pipe; manufacturing and construction
history; O&M history; and the criteria listed in the 2004 Federal
Register Notice for determining which pipeline segments would be
eligible for operators to apply IM measures when managing class
location changes in lieu of replacing pipe.
    An individual citizen commented that pipe that has experienced an
in-service failure should not be excluded so long as all comparable
remaining defects in the segment have been remediated. This commenter
suggested that pipeline segments with manufacturing defects should not
be excluded from using an IM alternative when class locations change,
so long as the operator has conducted a successful pressure test at
1.25 times the MAOP. Such a pressure test would demonstrate that the
manufacturing defect should be considered stable and will not grow
while the pipeline is in service. This commenter stated that while the
Charpy impact value is shown to be related to crack growth, it is not a
factor in corrosion and pressure stress cycles in gas pipelines are not
a concern. This citizen also noted that, for unknown seam type, an ILI
tool should be able to identify seam type given each seam type's
distinct magnetic signature.
3. PHMSA Response
    Based on the input provided and PHMSA's experience with special
permits and incident investigations, PHMSA is persuaded that some of
the attributes discussed, such as past incident history and toughness
properties, can be effectively managed through an operator's IM program
with mandatory P&M measures. In an operator's IM program, an operator
addresses pipeline segments with an incident history through assessing
and repairing or remediating the threats and causes associated with
those past incidents. In this NPRM, PHMSA is proposing that operators
would identify in their IM programs the specific Class 1 to Class 3
location segments being managed under that program. In doing so,
operators would be required to conduct a data integration and risk
assessment on these segments, including an evaluation of past incident
history, for all threats and establish an integrity assessment program
to find and remediate applicable threats.
    This proposed rule specifies requirements for operators to maintain
a comparable level of safety for the life of the pipeline segment that
changed from a Class 1 to a Class 3 location. In response to the
California Public Advocates Office's comment regarding derating
factors, PHMSA believes that these requirements, including the IM
principles and eligibility criteria prescribed in this NPRM, will
provide the equivalent of conservative derating factors. PHMSA has
issued several special permits over the past 15 years containing
conditions identical to or similar to the conditions being proposed in
this rulemaking for managing class location change waivers. Those
special permits that PHMSA has issued have not resulted in any decrease
in pipeline safety in the areas where they are implemented and in fact
have resulted in no incidents on the applicable pipe. PHMSA, therefore,
has confidence that the IM principles and eligibility criteria being
proposed in this rulemaking will provide an equivalent level of safety
consistent with the regulations.
    PHMSA believes that pipeline segments with known cracking issues
are problematic and is proposing that operators would not be allowed to
use the IM alternative for class location change management for those
pipeline segments with cracks that exceed 20 percent of wall thickness.
PHMSA reached this threshold by considering the current state of ILI
technology and its tolerance for finding crack indications; current ILI
tools can consistently evaluate crack depth and length at this level. A
20 percent through-wall defect of the pipe, whether from cracking or
corrosion, has a minimal effect on a pipeline's failure pressure ratio
based on any of the approved defect analysis methods, such as R-STRENG
or API 579. Operators of pipelines with cracking issues would continue
to be eligible for class location change special permits.
    Material toughness is important when evaluating cracks and crack-
like defects, as cracking can weaken a pipe to the point where it might
rupture.\95\ Since PHMSA is proposing to exclude pipe with known, non-
trivial cracking issues, PHMSA does not propose to include material
toughness as an eligibility criterion for managing class location
changes through IM. However, operators of pipeline segments that change
from a Class 1 to a Class 3 location that identify cracking issues
after implementing the proposed IM alternative for class location
changes must evaluate the significance of those crack anomalies. PHMSA
proposes to require crack evaluation procedures for that purpose. With
respect to pipeline segments with unknown material toughness, the
proposed crack evaluation procedures would require the operator to use
conservative toughness values to evaluate predicted failure pressures
in response to discovered crack anomalies and the threat of cracks.
PHMSA proposes to define a ``predicted failure pressure'' as the
calculated pipeline anomaly failure pressure based on the use of an
appropriate engineering evaluation method for the type of anomaly being
assessed. A predicted failure pressure does not include a safety
factor, and PHMSA believes defining ``predicted failure pressure'' will
help bring clarity to the regulations and improve compliance.
---------------------------------------------------------------------------

    \95\ Material toughness is the ability of a material to absorb
energy and plastically deform without fracturing. Technical
evaluations, including anomaly evaluations, require material
toughness as an input. If material toughness is low, then the safe
pressure of the anomaly will also be low.
---------------------------------------------------------------------------

    PHMSA also believes that operators of pipeline segments with
certain seam attributes should not be allowed to manage class location
changes with an IM alternative. Even the current and most state-of-the-
art ILI technology, with respect to evaluating seams, is not yet
reliable enough to warrant including such pipeline segments in this
NPRM. PHMSA notes that, at this time, ILI tools cannot reliably
identify or differentiate

LF-ERW, HF-ERW, or lap-welded seam pipe. The pipeline would need to be
excavated to observe pipe seam types and use appropriate destructive or
non-destructive methods. Therefore, the proposed rule would not allow
the use of the proposed IM alternative for pipeline segments with DC,
LF-ERW, EFW, or lap-welded seams; or pipe with a longitudinal joint
factor below 1.0.

H. Eligibility for Pipe With Significant Corrosion

1. Summary of ANPRM Questions 4a(iv) and 4a(v)
    In question 4 of the ANPRM, PHMSA requested comments on whether
operators should be eligible to use IM to manage class location changes
if the pipeline segment has experienced corrosion greater than 40
percent of wall thickness,\96\ or whether operators should replace such
segments. PHMSA also requested comments regarding whether anomalies in
pipeline segments in an IM-managed class location change segment should
use similar repair criteria as subpart O, and whether the current class
location-specific design factor was appropriate or if it should be
increased for a Class 1 to a Class 3 location change.
---------------------------------------------------------------------------

    \96\ Corrosion greater than 40 percent of wall thickness is
considered significant. This threshold is consistent with PHMSA's
typical class location change special permit conditions.
---------------------------------------------------------------------------

2. Summary of Comments
    The California Public Advocates Office commented that pipelines
with significant corrosion should be replaced and should not be
eligible for an IM alternative. It also suggested that PHMSA codify a
definition of ``significant corrosion.''
    The Associations, pipeline operators, and an individual commenter
agreed that the current IM regulatory measures and those proposed in
the 2016 Gas Transmission NPRM would identify ``significant corrosion''
through integrity assessments, and those areas would be remediated
accordingly. In addition, the Associations noted that the GPAC and
PHMSA discussed an appropriate response to wall loss anomalies during
the March 2018 GPAC meeting.
    Further, the Associations and supporting operators commented that
70 percent of corrosion incidents occurred on pipeline segments that
were not previously assessed with ILI, which they suggested is evidence
that the current industry practice to remediate corrosion anomalies
based on ASME B31.8S for those lines that are assessed is an effective
practice.
    TransCanada Corporation proposed that anomalies, including
corrosion anomalies, ``should be repaired to criteria greater than or
equal to MAOP times the reciprocal of the design factor of the
installed pipe.'' \97\
---------------------------------------------------------------------------

    \97\ An example would be a pipeline segment in a Class 1
location with a Sec.  192.111 design safety factor of 0.72. The
reciprocal of 0.72 would be 1.39 (1/0.72), which is a safety factor
of 39 percent over MAOP.
---------------------------------------------------------------------------

3. PHMSA Response
    Based on the input provided and PHMSA's experience with special
permits and incident investigations, PHMSA proposes to allow operators
with pipe with past corrosion to use the IM alternative for Class 1 to
Class 3 location changes. ILI technology for the detection of corrosion
metal loss is very mature, and PHMSA believes it is reliable to manage
the threat of corrosion in pipeline segments that have changed from a
Class 1 to a Class 3 location if operators perform a corrosion
assessment properly and validate the results. However, pipeline
segments would not be eligible if they do not meet the requirements of
Sec.  192.463 and need linear anodes to maintain adequate levels of CP
due to poor coating conditions.
    To help ensure pipeline safety, PHMSA proposes enhanced repair
criteria that would be performed in addition to the repair criteria for
HCAs in subpart O and would be implemented if operators manage a Class
1 to Class 3 location segment through IM. This repair criteria would be
consistent with the repair criteria per the typical class location
change special permit conditions and includes immediate repair
conditions \98\ for certain anomalies that are at or near the point of
failure. The repair criteria would also contain ``scheduled''
conditions that would require an operator to repair them within 1 year.
These scheduled repairs would be for anomalies that are not an
immediate threat to integrity but that would need to be repaired
promptly before they grew further. PHMSA also proposes ``monitored''
conditions that are not severe enough to need prompt repair but that
the operator would have to monitor further. The enhanced repair
criteria would not only apply to the pipeline segment that has changed
from a Class 1 to a Class 3 location, but would also apply to the
surrounding Class 2, Class 3, and Class 4 locations contained within
the in-line inspection segment (i.e., the segment of pipe between the
closest upstream launcher and downstream receiver that contains the
Class 1 to Class 3 location segment). PHMSA believes that these
enhanced repair criteria are necessary for pipe around the Class 1 to
Class 3 segment because it is likely that there would be nearby
populations that could be affected by an incident involving the in-line
inspection segment. Regarding pipe segments with corrosion,
implementing these enhanced repair criteria would manage pipeline
segments with prior significant corrosion appropriately, which is
needed to compensate for operators not installing new pipe to Class 3
design standards in the changed class location.
---------------------------------------------------------------------------

    \98\ Per ASME B31.8S, section 7.2, an ``immediate'' condition is
one where an indication shows a defect is at a failure point. As
such, PHMSA believes that any indication of a pipe that is at the
point of failure needs to be addressed immediately. In addressing
``immediate'' conditions, operators must reduce operating pressure
and immediately remediate the anomaly.
---------------------------------------------------------------------------

    PHMSA is also proposing to exclude those pipeline segments that are
not transporting distribution customer-quality gas from the IM
alternative proposed in this rulemaking due to the impact contaminates
have on corrosion. Such a proposal would prevent Class 1 to Class 3
location segments that transport gas with deleterious contaminates from
being transported in segments near areas with higher populations. This
criterion would also exclude pipeline segments transporting gas with
free-flowing water or hydrocarbons, gas with higher levels of hydrogen
sulfide (sour gas), gas with higher levels of carbon dioxide, or gas
with unacceptable water content, specifically, as these segments would
be at a higher risk of internal corrosion. Further, contaminants like
hydrogen sulfide and carbon dioxide would be asphyxiation risks if a
Class 1 to Class 3 location segment carrying significant percentages or
volumes of these gases leaked or ruptured in a populated area.
    Regarding TransCanada's comment, PHMSA is not proposing to require
operators repair the reciprocal of the design factor of the pipe. PHMSA
is proposing to require operators repair anomalies based on a 1.39
predicted failure pressure, which is the reciprocal of the 0.72 design
factor for class 1 pipe, and a wall loss of 40 percent of the pipe wall
thickness.

I. Eligibility for Damaged Pipe, Dented Pipe, or Pipe That Has Lost
Ground Cover

1. Summary of ANPRM Question 4a(vi)
    In question 4 of the ANPRM, PHMSA requested comments on whether
operators should be eligible to use IM to manage class location changes
if the pipeline segment has been damaged, dented, or has lost ground
cover due to

third-party excavation or environmental factors.
2. Summary of Comments
    Regarding environmental factors, the Associations noted that
operators are already required to conduct patrols with increasing
frequency in Class 3 and Class 4 areas, and that the 2016 Gas
Transmission NPRM, if finalized, will require operators to implement
additional inspections following extreme weather events. Such events
are the most likely cause of a sudden change in the depth of cover. The
commenters suggested these existing and pending requirements are
sufficient to monitor depth of cover changes to ensure pipeline safety,
regardless of whether a class change has occurred.
    An individual citizen commented that damaged pipe should be
addressed as detailed in subpart O.
3. PHMSA Response
    PHMSA does not propose to limit the eligibility of pipeline
segments that have been damaged, dented, or have lost ground cover. ILI
technology for the detection of dents is very mature, and PHMSA
believes it is reliable to manage the threat of dents and mechanical
damage in conjunction with the proposed additional repair criteria and
existing dent repair criteria for HCAs in subpart O for pipeline
segments where the class locations have changed from Class 1 to Class
3. PHMSA also added additional prescriptive P&M actions in the proposed
provisions, including the addition of line markers or an increase in
the depth of cover, to address cases where a pipeline segment that has
changed class location from a Class 1 to a Class 3 location has
experienced a reduction in the depth of cover.

J. Eligibility Factors Based on Diameter, Operating Pressure, or
Potential Impact Radius Size

1. Summary of ANPRM Question 10
    In question 10 of the ANPRM, PHMSA requested comments on whether
operators should be eligible to use IM to manage class location changes
based on the pipeline segment's diameter, operating pressure, or PIR
size.
2. Summary of Comments
    Pipeline industry operators and trade associations contended that
applying diameter, pressure, or PIR limits are not necessary for
determining the eligibility of pipeline segments for using IM
principles in place of the existing class location requirements,
specifically noting that there is currently no technical standard or
regulation that limits an operator's decision-making based on the PIR
size, and that the intent of the PIR concept was not to limit where
integrity assessments could be applied.
    GPA Midstream, in a comment that was echoed by other operators,
stated that a ``one size fits all'' approach is not appropriate and
suggested each operator should be allowed to determine the appropriate
IM measures and actions to ensure safe asset management. It further
suggested PHMSA should focus on ensuring operators appropriately apply
IM measures.
    NAPSR stated that any allowances or exceptions to the current
regulations should be determined on a case-by-case basis. It suggested
PHMSA should continue to encourage operators to operate pipelines at
lower stresses, but operators that install pipe that is rated for a
higher class location than what currently exists should not be
punished.
    The California Public Advocates Office suggested that PHMSA
consider more conservative requirements for any IM-based class location
change management based on the pipeline segment's PIR and that PHMSA
should host a workshop to determine appropriate values or actions. It
also suggested PHMSA consider looped, co-located pipelines as
additional factors for any PIR-based adjustments.
    An individual citizen noted that while diameter and pressure
limitations are not necessary for pipeline segments where operators
would use the IM alternative for managing class location changes, PHMSA
should impose stricter repair criteria on those segments. The commenter
also noted that immediate repair condition requirements are specified
in the current regulations, and remediation requirements, if performed
properly, for all areas, should provide safety beyond the next
assessment.
3. PHMSA Response
    PHMSA acknowledges that the PIR and class location concepts are
both used to identify physical locations at which higher consequences
could result from a pipeline incident by virtue of higher population
density.\99\ PHMSA believes that, for the purposes of managing class
location changes, adding PIR-based exclusion criteria would be
unnecessary. PHMSA believes the requirements it has proposed for
pipeline segments where the class location has changed from a Class 1
to a Class 3 location are appropriate for all Class 3 locations
regardless of the PIR at that location. Therefore, PHMSA is not
proposing to limit eligibility or impose more stringent requirements
based on pipe diameter, operating pressure, or PIR.
---------------------------------------------------------------------------

    \99\ Per Sec.  192.903, a PIR means the radius of a circle
within which the potential failure of a pipeline could have
significant impact on people or property. PIR is used to determine
whether an area is an HCA per the HCA definition at Sec.  192.903.
If, for the purposes of determining an HCA, a PIR in a certain class
location is greater than 660 feet and the area within the potential
impact circle contains 20 or more buildings intended for human
occupancy or contain an identified site, as that term is defined at
Sec.  192.903, then the area is an HCA.
---------------------------------------------------------------------------

    Furthermore, while PHMSA appreciates the feedback regarding
changing the method for determining PIR and class location to include
additional factors such as, looped, co-located pipelines, but this
comment is outside the scope of this NPRM.
    PHMSA considered the suggestion of more stringent repair criteria
and included such criteria, in addition to the repair criteria in
subpart O, for all Class 1 to Class 3 location segments operators would
choose to manage with the IM alternative in this NPRM. The more
stringent repair criteria that PHMSA proposes in this rule are designed
to provide equivalent integrity compared to replacement pipe where a
class location has changed from a Class 1 to a Class 3 location.
Existing pipe in these locations is more likely than not to be pre-
Code, vintage pipe where the steel pipe properties do not have the
toughness properties necessary to mitigate ruptures versus leaks when
the pipe is corroded, dented, or has any cracking in the pipe body or
pipe seam.

K. Codifying Current Special Permit Conditions

1. Summary of ANPRM Questions 6 and 6a
    In question 6 of the ANPRM, PHMSA requested comments on whether it
should codify any or all the current special permit conditions for
class location changes,\100\ asking whether doing so would satisfy the
need for alternative approaches. PHMSA also asked what special permit
conditions could be codified to provide regulatory certainty and
additional public safety in higher-population areas.
---------------------------------------------------------------------------

    \100\ Examples of typical PHMSA class location special permit
conditions can be found at https://primis.phmsa.dot.gov/classloc/documents.htm.
---------------------------------------------------------------------------

2. Summary of Comments
    NAPSR and the PST commented that, if the current, typical special
permit requirements are codified, they should be the minimum guidelines
and should require multiple tool type assessments, an increased
inspection frequency, more stringent remediation requirements, and
enhanced damage prevention activities. They also recommended that PHMSA

require expedited timeframes and more restrictive remediation criteria
specific to each class location.
    The Associations, GPA Midstream, and operators commented that the
current special permit conditions were not designed for broad
application and should not be codified as written. The Associations
stated that no additional requirements beyond those proposed in the
2016 Gas Transmission NPRM were necessary for operators to use IM to
manage pipeline segments properly where the class location has changed.
TransCanada Corporation added that implementing these ``broad-brush''
conditions would not allow for segment-specific risk considerations,
which is the basis of an IM approach. GPA Midstream asserted that there
are no indications the current special permit conditions would satisfy
statutory considerations in a rulemaking proceeding, or that the cost
of compliance is justified by the level of public safety benefit.
    An individual citizen stated that certain aspects of current
special permits are outdated given technological advancements and
regulatory updates in the 14 years since the initial criteria for
considering waivers was published. This citizen suggested that class
location changes from a Class 1 to a Class 3 location should be treated
as a change in land use, and the pipe in question should be considered
an identified site, thus triggering HCA requirements.\101\
---------------------------------------------------------------------------

    \101\ Under the current IM regulations at Sec.  192.903, an
``identified site'' means ``one of the following 3 sites: (a) An
outside area or open structure that is occupied by 20 or more
persons on at least 50 days in any 12-month period. The days need
not be consecutive. Examples include, but are not limited to,
beaches, playgrounds, recreational facilities, camping grounds,
outdoor theaters, stadiums, recreational areas near a body of water,
or areas outside a rural building such as a religious facility. (b)
A building that is occupied by 20 or more persons on at least 5 days
a week for 10 weeks in any 12-month period. The days and weeks need
not be consecutive. Examples include, but are not limited to,
religious facilities, office buildings, community centers, general
stores, 4-H facilities, or roller skating rinks. (c) A facility
occupied by persons who are confined, are of impaired mobility, or
would be difficult to evacuate. Examples include, but are not
limited to, hospitals, prisons, schools, day-care facilities,
retirement facilities, or assisted-living facilities.''
---------------------------------------------------------------------------

3. PHMSA Response
    PHMSA agrees with certain commenters that including Class 1 to
Class 3 location segments in operator IM programs in accordance with
subpart O is appropriate for allowing operators to use IM to manage
class location changes. However, PHMSA also believes that simply
requiring operators to implement IM on pipeline segments where the
class location has changed from a Class 1 to a Class 3 location,
without undertaking additional safety requirements, does not provide an
equivalent level of safety as the current system of pipe replacement,
pressure testing, or pressure reduction. Thus, to provide public safety
where the pipe has not been upgraded to current Class 3 location
standards when the class location changes, PHMSA proposes to require
that operators implement IM in accordance with subpart O and supplement
that IM with additional standards that have been successfully applied
in previous special permits. These additional activities would include
close interval surveys (CIS),\102\ the installation of CP test
stations, and interference surveys to ensure the maintenance of
coatings and reduce the numbers of immediate and scheduled repairs.
These additional measures address specific threats to pipelines,
including corrosion, and are necessary to account for the lack of
additional pipe wall thickness in lieu of pipe replacement. Without
thicker-walled pipe, these conditions will help to provide for a
consistent level of safety over the lifecycle of the pipeline.
---------------------------------------------------------------------------

    \102\ CIS are a series of closely and properly spaced pipe-to-
electrolyte potential measurements taken over the pipe to assess the
adequacy of cathodic protection or to identify locations where a
current may be leaving the pipeline that may cause corrosion and for
the purpose of quantifying voltage (IR) drops other than those
across the structure electrolyte boundary, such as when performed as
a current interrupted, depolarized or native survey.
---------------------------------------------------------------------------

    PHMSA is also proposing specific repair criteria for the Class 1 to
Class 3 location segment that would be applied in addition to the
existing repair criteria in subpart O. This additional repair criteria
would also be applicable to the Class 2, Class 3, and Class 4 locations
located within the entire in-line inspection segment. With these
proposed changes, operators would categorize more anomalies as
``immediate'' conditions, which would help ensure an expedited repair
schedule. Furthermore, the updated repair requirements of this proposal
essentially provide an approximately 26 percent increase in safety
factor for the pipe strength given that the NPRM would require the
repair of conditions reaching a 1.39 safety ratio whereas the current
IM regulations require the repair of conditions reaching a 1.1 safety
ratio. The proposed repair criteria will also help to ensure safety
where there is thinner-walled pipe in the ground by requiring the
repair of anomalies where there is 40 percent of pipe wall loss, rather
than the 80 percent that currently exists under IM.
    Based on PHMSA's experience with existing Class 1 to Class 3
location change special permits and the feedback from the ANPRM, PHMSA
proposes to incorporate the following special permit conditions into
the regulations for those pipeline segments changing from a Class 1 to
a Class 3 location that operators will manage using the IM alternative.
PHMSA proposes to require the following conditions to help ensure that
the level of safety achieved is equivalent to pipe replacement for the
life of the pipeline:
     Perform an initial integrity assessment within 24 months
of the Class 1 to Class 3 location change, which is consistent with the
requirements at Sec. Sec.  192.609 and 192.611.
     Use high-resolution ILI metal loss and deformation,
electromagnetic acoustic transducer (EMAT), and inertial measurement
unit (IMU) tools where appropriate for the pipeline integrity threat,
which would be consistent with the current IM requirements. To help
ensure that operators address cracking threats and ground movement, if
an operator chooses not to conduct EMAT or IMU inspections on pipeline
segments with a history of cracking or pipe movement, then the operator
would be required to notify PHMSA in accordance with Sec.  192.18.
     Perform periodic reassessments using ILI, which would be
consistent with the current IM requirements.
     Validate ILI tool results, which would be consistent with
the current IM requirements.
     Repair anomalies using more stringent repair criteria than
the existing repair criteria under the current IM requirements, which
will maintain equivalent safety, compared to pipe replacement, over the
life of the pipeline.
     Replace pipeline segments: (1) With discovered cracks that
exceed 20 percent of wall thickness, or (2) with a predicted failure
pressure less than 100 percent of SMYS, or (3) with a predicted failure
pressure less than 1.5 times MAOP, or (4) that could fail in the
brittle failure mode. This requirement is based on PHMSA research and
API's Recommended Practice 1176, ``Assessment and Management of
Pipeline Cracking'' and would go beyond the current IM repair criteria.
     Until the pipeline segment can be replaced per the
requirement above, cracks must be remediated using additional crack
repair criteria. This requirement is consistent with the current IM
requirements.
     Evaluate for pipe cracking, such as SCC, when the pipe is
exposed for IM

or the proposed regulation activities and is found with disbonded or
previously repaired coating. Pipe excavated for damage prevention
program activities under Sec.  192.614 would not require pipe cracking
inspections so as not to delay those activities. This treatment is
consistent with the current IM requirements.
     Conduct close interval surveys (CIS) at intervals at least
once every 7 years and not exceeding 90 months. Operators should be
performing these surveys under the IM regulations, so this condition
would be consistent with that requirement.
     Ensure that at least one CP pipe-to-soil test station is
within the pipeline segment that changed from a Class 1 to a Class 3
location, with a maximum spacing interval of one-half mile. This
condition will meet the current requirements at subpart I for corrosion
control.
     Install line-of-sight markers at defined points, which is
consistent with elements of the current requirement at Sec.  192.707
and PHMSA's current special permit conditions for class location change
management. Line-of-sight markers would be line markers where each
marker is visible from at least one other line-of-sight marker.
     Conduct interference surveys, which would be consistent
with the current requirements at Sec.  192.473. If operators are unable
to receive the necessary permitting authority to complete surveys in
time, they can apply to PHMSA for a special permit regarding that
issue.
     Maintain depth of cover to Class 1 location standards or
remediate areas with reduced cover. This condition keeps the original
design standards for the affected pipe segment so as to avoid imposing
retroactive design standards, which PHMSA cannot do.
     Conduct right-of-way patrols on a monthly basis and
leakage surveys on a quarterly basis. This condition will help to
ensure, on a more consistent basis, that the pipe segment is not
damaged by third-party entities and that hazardous leaks do not occur
where there are substantial populations. These requirements will also
provide safety in that they are more stringent than the current Class 3
requirements.
     Clear shorted casings within 1 year, which operators are
already required to do in accordance with Sec.  192.467.
     Document and maintain records, for the life of the
pipeline, of the actions required by the Class 1 to Class 3 location
requirements. This documentation requirement is consistent with
requirements in the recently published 2019 Gas Transmission Final
Rule.
    PHMSA requests comment as to whether any of these P&M measures
could be modified or otherwise eliminated, and if so, what the impacts
of safety would be and if safety could be maintained, what alternative
approach would maximize net benefits to society.
    Per PHMSA's data over the last decade, there have been 699
``significant'' incidents occurring on gas transmission pipelines,
which are defined as ones involving (1) a fatality or in-patient
hospitalization, (2) $50,000 or more in property damage, or (3)
incidents where over 3 million cubic feet of gas are lost. Of these
incidents, 269 were caused by material, equipment, or weld failures (38
percent); 165 by corrosion (24 percent); 93 by excavation damage (13
percent); 61 by natural force damage (9 percent); 42 by other outside
force damage (6 percent); 40 by incorrect operation (6 percent); and 29
by other causes (4 percent).
    In many ways, the conditions that are consistent with IM outlined
above are meant to mitigate many of these incident causes, including
material failure and corrosion. Performing recurring integrity
assessments helps operators understand the current condition of their
pipe and reveals anomalies that, if left unchecked, could result in a
serious rupture and incident.
    Some of the additional surveys PHMSA is proposing to require are
additional safeguards against corrosion threats. In the absence of new,
thicker-walled pipe in a Class 3 location, performing CIS and
interference surveys, as well as ensuring the proper placement of CP
test stations, will help to provide assurance that a pipeline segment
will not rapidly corrode prior to being discovered before the next
integrity assessment.
    PHMSA is proposing conditions for line-of-sight markers and depth
of cover because these serve as mitigation measures for potential
accidents involving excavation damage. Excavation damage is more likely
to happen in more populated areas, as there are typically more
utilities near pipelines and more people digging around those
utilities. A strike from excavation equipment can cause a rupture,
severely dent the pipe, or damage the pipe's protective coating. Even
though PHMSA is not proposing to require more stringent depth-of-cover
conditions beyond those designed for Class 1 locations, PHMSA believes
the additional line-of-sight markers combined with additional
patrolling and leak survey requirements will provide a commensurate
level of safety compared to the Class 3 depth of cover requirements.
    PHMSA proposed including a condition for operators to clear shorted
casings because shorted casings were major contributors in two major
pipeline incidents. On December 14, 2007, a 30-inch gas transmission
pipeline owned by Columbia Gulf Transmission Company ruptured near
Delhi, LA, killing a man and injuring another man who were driving
nearby on Interstate 20. On December 11, 2012, a 20-inch gas
transmission pipeline operated by Columbia Gas Transmission Company
ruptured about 100 feet west of Interstate 77 near Sissonville, WV.
Three houses were destroyed by the fire, and several other houses were
damaged. Interstate 77 was closed in both directions because of the
fire and resulting damage to the road surface, causing delays to
travelers and commercial freight. Both accidents were attributable to
shorted casings that had not been properly addressed.
    In addition to the above special permit conditions, PHMSA is also
proposing to require operators use SCADA systems and install and use
remote-control or automatic shutoff block valves upstream and
downstream of the Class 1 to Class 3 segment. PHMSA believes that the
additional P&M measures proposed in this NPRM, along with the higher
standards for repairs and remediation, make an increased inspection
frequency suggested by certain commenters unnecessary.

L. Additional Preventive and Mitigative Measures Needed for an
Integrity Management Option for Class Location Change Management

1. Summary of ANPRM Questions 9, 9a, and 9b
    In question 9 of the ANPRM, PHMSA requested comments on whether
operators would need to install additional pipeline safety equipment,
P&M measures, or more conservative prescribed standard pipeline
predicted failure pressures if using IM principles to manage pipeline
segments where the class location has changed from a Class 1 to a Class
3. More specifically, PHMSA requested comments on whether the
regulations should require rupture-mitigation valves or SCADA systems
on IM-managed class location change pipeline segments.
2. Summary of Comments
    TransCanada Corporation proposed operators should perform site-
specific assessments to determine the

appropriate safety equipment or mitigative measures to implement. GPA
Midstream supported this concept in its comments.
    NAPSR stated that if PHMSA does not require pipe replacement, PHMSA
should specify additional safety and P&M measures. They suggested that
rupture-mitigation valves or equivalent technology should be required
if an operator does not replace pipe to manage a class location change,
and SCADA systems should be required for large and complex pipeline
systems. Further, NAPSR stated that IM should be a system-wide program,
``not a substitute'' for the additional safety provided by class-
location requirements. Similarly, NAPSR also stated that pipe
replacements are preventive measures while valves are mitigative
measures, arguing the level of safety between the two is not equal.
    Broadly speaking, the Associations and multiple operators stated
that the requirements proposed in the 2016 Gas Transmission NPRM are
more than sufficient in ensuring safety, and it is unnecessary for
PHMSA to require additional P&M measures for pipeline segments changing
class locations. Class location change requirements, they asserted, are
just a few of many regulations that are applicable to any given
pipeline segment. MidAmerican Energy Company, for instance, stated that
the requirements proposed in the 2016 Gas Transmission NPRM are
adequate for covering class location changes, and no additional safety
equipment or P&M measures should be required beyond those regulations.
    Further, the Associations and GPA Midstream commented that the
installation of rupture-mitigation values has not been addressed
historically in special permits nor any previous class location
regulatory discussions. GPA Midstream did not feel that this would
achieve the intended purpose of class location change requirements, and
PHMSA has not provided evidence or discussion in support of this
requirement.
    Similarly, the Associations commented that SCADA systems have not
been required compliance items in special permits historically, and
most gas transmission pipelines already have SCADA systems in place.
They argued that this requirement seems unnecessary given that PHMSA
has not provided evidence or discussion in support of this requirement.
    GPA Midstream noted that, as currently allowed in the IM
regulations, the operator should be able to determine the necessity of
a SCADA system. It noted that for short pipelines or simple systems, it
may be impractical. Other operators echoed this comment, noting that if
a site-specific assessment determined that a SCADA system would be
beneficial, the operator should have the option to add it.
    Other operators provided a range of comments regarding SCADA
systems, from supporting the viewpoint that impacted segments should be
monitored with SCADA systems to general data indicating that large
portions of their individual pipeline systems were managed with SCADA
systems.
    An individual citizen commented that the regulations currently do
not require newly installed or previously installed pipe to have
additional safety equipment or P&M measures. The commenter suggested
that allowing operators to use ILI or similar technologies in a
rigorous IM program would allow operators to know the pipeline
segment's condition and remediate it appropriately, which would
preclude the need for prescriptive P&M measures. In addition, this
citizen commented that rupture-mitigation valves have limited efficacy
and are not proven to be reliable technology. The commenter also noted
that ``systems designed to react to ruptures will not be useful in
detecting leaks.'' Further, the commenter noted that SCADA systems
should not be required, as they only mitigate the consequences of an
incident and will not prevent a rupture.
3. PHMSA Response
    PHMSA has observed that certain operators have not adopted
additional P&M measures when implementing the IM regulations under
subpart O.\103\ As a result, PHMSA has determined that proposing
additional prescriptive mitigative measures are appropriate, including
to install remote-control or automatic shutoff valves upstream and
downstream of the segment changing from a Class 1 to a Class 3
location. While the installation of rupture-mitigation valves has not
previously been required when operators replace pipe, using IM to
manage class locations that change from Class 1 to Class 3 would be
fundamentally different in that operators would not be putting stronger
pipe in the ground, thereby making additional safety measures
necessary.
---------------------------------------------------------------------------

    \103\ For instance, following the PG&E incident at San Bruno,
CA, PG&E rapidly installed automatic shutoff valves where possible
and stated there was sufficient basis to deploy such valves.
However, company documents from 2006 stated that the company had
concluded that most of the damage from a rupture would take place in
the first 30 seconds before shut-off valves could stop the flow of
gas and declined to install the valves in the area.
---------------------------------------------------------------------------

    As proposed, the rupture-mitigation valve spacing would be
consistent with existing Class 1 location mainline valve spacing
requirements, with the explicit intent that this approach would not
require the addition of any mainline valves, and assuming operators
currently comply with the existing valve spacing requirements. However,
if the valves in place are manual valves, PHMSA proposes that operators
upgrade those valves to be operated by remote control or automatic
shutoff as an additional mitigative measure. This approach would be
consistent with NTSB recommendation P-11-11 to require automatic or
remote control valves in HCAs and Class 3 and Class 4 locations,\104\
which was issued after the 2010 PG&E incident in San Bruno, CA.
---------------------------------------------------------------------------

    \104\ https://www.ntsb.gov/investigations/AccidentReports/Reports/PAR1101.pdf. ``Pacific Gas and Electric Company, Natural Gas
Transmission Pipeline Rupture and Fire, San Bruno, CA, September 9,
2010.''
---------------------------------------------------------------------------

    PHMSA is proposing that any remote-control or automatic shutoff
valves installed in accordance with the additional P&M measures must be
set so that, based on operating conditions, they will fully close
within a maximum of 30 minutes following rupture identification.
PHMSA's proposed 30-minute valve closure time would be consistent with
conditions it has required operators to meet in special permits for
class location changes. In addition, PHMSA requests comment on whether
additional requirements and standards are needed for the installation
of automatic shutoff valves in place of remote-control valves for the
purposes of this rulemaking. If installing automatic shutoff valves in
accordance with this proposed requirement, operators would be required
to review their procedures and results for determining valve shutoff
times on a calendar year basis, not to exceed 15 months. This approach
is consistent with current requirements in Sec.  192.745 where
operators must inspect and partially operate each transmission line
valve that might be required during any emergency, and take prompt
remedial action to correct any valve found inoperable.
    As noted by industry, most operators already have a SCADA system in
place. Therefore, PHMSA is proposing that operators must have a SCADA
system to implement IM measures for managing Class 1 to Class 3
location changes. A SCADA system will help operators detect leaks and
other pressure loss situations more rapidly. In addition, PHMSA is
proposing that remote-control valves and automatic shutoff

valves installed per this NPRM must be controlled and monitored by a
SCADA system and promptly closed to isolate the pipeline segment should
a rupture occur. As such, and similar to how pipelines with
exclusionary conditions would be handled, operators without a SCADA
system could apply for a special permit to implement IM in lieu of pipe
replacement when class locations change.

M. Traceable, Verifiable, and Complete Records for Supporting Class-
Location-Change Integrity Management Measures

1. Summary of ANPRM Questions 5, 5a, and 5b
    In question 5 of the ANPRM, PHMSA requested comments on introducing
requirements for TVC records, including what records would be required,
and how and when they could be obtained, to support any IM measures
that would be performed to manage class location changes. More
specifically, PHMSA asked whether necessary TVC record should include
pipe properties, including yield strength, seam type, and wall
thickness; coating type; O&M history; leak and failure history;
pressure test records; MAOP; class location; depth of cover; and
ability to be in-line inspected.
2. Summary of Comments
    NAPSR, the PST, and the California Public Advocates Office
supported requiring TVC records for segments where operators would like
to manage class location changes by using IM measures. NAPSR also
asserted, and PST agreed, that historically poor recordkeeping
practices should be considered a potential indicator of risk, as
mapping issues have often been found to be latent conditions or
indicators of higher risk in pipeline accidents.
    More specifically, the California Public Advocates Office supported
the idea that PHMSA require in the regulation TVC records for yield
strength, seam type, and wall thickness, and it suggested adding
outside diameter as an additional pipe property to consider. It stated
that records, if available, should be obtained by the operator within 2
years of the class location change. If these records were unavailable,
the California Public Advocates Office supported allowing an operator
to request a special permit from PHMSA.
    NAPSR and the PST stated that, given that records can be acquired
or created if necessary (i.e., through a pressure test, pipe
specification verification, and lab tests), if an operator does not
have the appropriate records, PHMSA should not allow an operator to use
IM measures to manage class location changes. Both NAPSR and the PST
noted that operators should be leveraging ILI technology to create
records needed for regulatory compliance by, at a minimum, employing
tools that can effectively identify corrosion, dents, gouges, cracks,
and interactive defects.
    The Associations, GPA Midstream, and multiple operators requested
that TVC records only apply to MAOP verification, and that a lack of
records should not make a pipeline segment ineligible for using IM to
manage class location changes. They also noted that, should TVC records
not be available for pipeline segments undergoing a class location
change, the 2016 Gas Transmission NPRM provides a way for operators to
obtain those records and take appropriate safety options within 24
months of the class location change. Further, they stated that
additional records may be required for ILI-identified anomaly analysis
and will be collected.
    Kinder Morgan added that the TVC standard is not intended for many
records used in IM processes. TransCanada Corporation stated that while
TVC records are helpful and would improve site-specific assessments,
they are not critical for an operator to perform IM measures given that
adequate testing or conservative assumptions may be employed.
    An individual citizen commented that for IM measures specifically,
ILI technology implementation, design records, and pressure test
records are necessary for anomaly assessment. As stated by this
citizen, pressure test information is only required for assessing
longitudinal seam anomalies and is only valuable if the test was
conducted to at least 1.25 times MAOP. The commenter also asserted that
record ``completeness'' should be determined based on the required use
of the information. Given that design pressure is calculated with
outside diameter, wall thickness, and SMYS, records that supply these
values should be considered ``complete'' if the data is used to
calculate design pressure, according to this individual. Finally, the
commenter noted that coating type is not nearly as important as coating
condition, and depth of cover is a practical concern, especially in
agricultural areas, yet is not required in Sec.  192.611 and was not
required prior to the promulgation of the natural gas regulations in
1970.
3. PHMSA Response
    PHMSA agrees with certain commenters that documentation and
recordkeeping are very important and has included a proposed
requirement that operators keep records of the pipeline assessments,
surveys, remediations, maintenance, analyses, and any other action
implemented to comply with the requirements proposed under this
rulemaking for managing Class 1 to Class 3 location changes using the
IM for the life of the pipeline.
    Per this rulemaking, operators would need to have, or otherwise
obtain, TVC material-properties records (e.g., diameter, wall
thickness, yield strength, seam type, and coating type) to implement
the proposed IM alternative for managing a pipeline segment that has
changed from a Class 1 to a Class 3. These types of material properties
records are necessary for a PSR-compliant IM program \105\ and MAOP
determination.\106\
---------------------------------------------------------------------------

    \105\ Operators need TVC records to repair anomalies and for IM
measures that depend on design properties.
    \106\ TVC records are required for MAOP determination. To be
TVC, a record must be clearly linked to the original information
about a pipeline segment or facility; confirmed by other
complementary, but separate, documents; and finalized by a
signature, date, or other appropriate marking.
---------------------------------------------------------------------------

    As commenters noted, the 2019 Gas Transmission Final Rule provides
a mechanism for operators to obtain TVC material property records if
they are missing, and the 24-month compliance window of this NPRM
provides operators with adequate time to obtain those records, if
needed. As specified in the 2019 Gas Transmission Final Rule, if
operators are missing any material property records needed when
performing anomaly evaluations and repairs, operators must confirm
those material properties under Sec. Sec.  192.607 and 192.712(e)
through (g). Records created in accordance with Sec.  192.607 must be
maintained for the life of the pipeline and must be TVC; therefore, if
an operator would need to create material records prospectively to be
eligible for the IM alternative, those records would be TVC.

N. Data on Class Location Pipe Replacement and Route Planning

1. Summary of ANPRM Questions 7 and 8
    In the ANPRM, PHMSA requested data regarding operators' compliance
with current class change pipe replacement requirements, including the
amount of pipe being replaced, the number of distinct locations where
pipe

was being replaced, and the associated costs.
    PHMSA also requested comments on whether and to what extent
operators consult growth and development plans during route planning.
2. Summary of Comments
    PHMSA received various technical data provided by individual
operators and trade associations regarding the amount of pipe being
replaced, the number of locations at which pipe was replaced, and the
associated costs.
    Pertaining to route planning, the responses PHMSA received from
industry, individuals, and groups alike stated that operators consider
future building plans along a proposed pipeline route when considering
both the route and pipe materials. NAPSR asserted that most operators
are currently defaulting to Class 3 requirements for all newly
installed pipe. NAPSR also stated concern with allowing operators to
use IM principles for managing class location changes in that it could
discourage operators from continuing this conservative practice.
3. PHMSA Response
    PHMSA considered the data it received on class location change pipe
replacement when developing the PRIA; see that document for further
discussion on the data received and the subsequent assumptions and
analysis PHMSA made and performed.
    Regarding operators considering growth and development plans when
route planning, PHMSA will note that operators must monitor and
implement class location changes based on the required study
requirements of Sec.  192.609 and confirm or revise MAOP based on the
requirements in Sec.  192.611. Pipeline segments that experienced a
class change before the date of the rule would not be eligible to apply
the IM approach to managing the class location change, but operators
could still apply for a special permit to manage these pipeline
segments with IM.

O. Other Topics--General Comments

    The following relevant comments received were of a general nature
or did not pertain to questions considered in the ANPRM.
    The PST and multiple individuals from the public requested that
PHMSA host public meetings and webinars early in the rulemaking process
to educate the public on the current and proposed class location change
regulations. The Pipeline Safety Coalition stated that PHMSA doing so
would facilitate a safety culture based on holistic participation from
informed parties.
    State representatives from the State of New Jersey's 14th, 15th,
16th, and 18th legislative districts commented that New Jersey requires
that intrastate pipelines be constructed to Class 4 location design
requirements, regardless of population density. They encouraged PHMSA
to consider adopting New Jersey's stricter intrastate requirements for
interstate assets.
    The California Public Advocates Office supported PHMSA's effort to
streamline the current class location regulations as it believed it
would be advantageous to both operators and regulators. It also
requested that PHMSA re-evaluate the definition of a Class 4 location
to include stadiums or concert venues, which would not qualify
currently but present significant public safety consequences.
    Based on certain aspects of the ANPRM, GPA Midstream expressed
concern about PHMSA's commitment to making meaningful improvements to
the class location regulations, stating that PHMSA is suggesting
``unrelated issues identified in previous advisory bulletins or during
routine inspections are relevant to the decision of whether to update
the class location regulations'' and that the agency suggests ``topics
that are already being addressed in a separate rulemaking proceeding
should limit an operator's ability to obtain class location relief.''
They did, however, support adding more options for an operator to
address class location changes.
    The Associations and TransCanada Corporation suggested that
currently issued special permits could be retired when an operator
demonstrates that all conditions have been satisfied and that the class
location change is managed to an acceptable level of safety.
    As an additional consideration to the class location change
regulations, the Associations suggested other regulations that would be
affected, such as those at Sec.  192.625 for odorization, should be
adjusted. They specifically requested that PHMSA allow alternative P&M
measures in lieu of odorization. Further, they also commented that an
operator using integrity assessments for class location change
management should also be allowed to uprate their MAOP in accordance
with subpart K.
    The Associations also requested that PHMSA implement an expedited
interim process for class location changes, which would allow operators
to manage class location changes through integrity assessments prior to
implementation of the final rule. They contend that this regulatory
update has been in the works for 15 years, and cost efficiencies
realized by this change would enhance operator ability to fund
integrity assessment technology development.
    The Associations expressed support for PHMSA including additional
fields in the annual report to collect information on class location
designation, integrity assessments, or data on other class change
management operators use. Furthermore, they requested that PHMSA
implement annual report changes to replace what they identified as
excessive reporting and notifications required for special permits.
    Finally, the Associations commented that PHMSA's singular focus on
pipe stress is misplaced and outdated given that modern integrity
assessment technology can provide equivalent safety factors to stress-
reducing measures.
1. Response to General Comments
    Regarding the New Jersey State legislators' comment, PHMSA
recognizes that New Jersey may have more conservative design
requirements for new intrastate gas transmission pipelines than what is
being proposed in this NPRM; however, implementing these requirements
would not support the NPRM focus of managing class location changes
safely in existing pipelines.
    PHMSA is proposing that segments uprated in accordance with subpart
K may be allowed to use this proposed rule for class location change
management, but only if the segment has had a subpart J pressure test
to at least 1.39 times MAOP \107\ and meets all the requirements of the
proposed rule, including those regarding records. Segments uprated
without a subpart J pressure test would be excluded under this proposed
rule.
---------------------------------------------------------------------------

    \107\ PHMSA acknowledges that Sec.  192.555 allows uprating
based upon the highest pressure allowed in Sec.  192.619, which
would require a 1.50 times MAOP for a Class 3 location. Since Class
1 location pipe would only be tested to either 1.1 or 1.25 times
MAOP based upon Sec.  192.619, the proposed rule change would
require a 1.39 times MAOP for uprating the MAOP where operating
pressures of a segment have been lowered for other existing Class 1
to Class 3 location changes.
---------------------------------------------------------------------------

    Regarding the comments from TransCanada and the Associations on the
class location definitions, odorization requirements, and special
permit ``retirement'' provisions, PHMSA has determined to propose
alternative requirements to those currently imposed on pipeline
segments experiencing a change in class location in this NPRM.
    PHMSA is not proposing an expedited interim process for class
location changes as a part of this NPRM. In the absence of these
proposed regulatory

changes, operators can currently apply for a special permit to manage
class location changes in a similar manner. Part of the intent of this
NPRM is to codify much of the current special permit process into the
regulations, thereby providing greater regulatory certainty and a
streamlined process for class location change management for eligible
pipe segments.
    PHMSA respectfully disagrees that a singular focus has been placed
on pipe stress. PHMSA is concerned with every threat to pipeline
integrity and how they can be remediated to maintain safety. PHMSA also
disagrees that the reporting requirements for the current special
permit process are excessive. The special permit process is an optional
process that operators can opt into. If the requirements are excessive,
operators can comply with the regulations as they are written. With
that said, PHMSA may consider revising the annual report as needed when
finalizing this rulemaking.

IV. Section-by-Section Analysis

Sec.  191.22 National Registry of Pipeline and LNG Operators

    Section 191.22 details events that require a notification to PHMSA.
PHMSA has proposed the addition of requiring operators to notify PHMSA
if they use IM to manage pipeline segments that have changed from a
Class 1 to a Class 3 location. This prompt notification would provide
PHMSA an opportunity to oversee the operator's implementation of the
proposed Class 1 to Class 3 location segment regulations.

Sec.  192.3 Definitions

    Section 192.3 provides definitions for various terms used
throughout part 192. In support of the regulations proposed in this
NPRM, PHMSA is proposing new definitions for the terms ``Class 1 to
Class 3 location segment'' and ``in-line inspection segment.'' These
two terms define the segments to which the requirements of the proposed
Sec.  192.618 would apply.
    A ``Class 1 to Class 3 location segment'' would be defined as the
segment of pipe where the class location has changed from a Class 1 to
a Class 3 location and where the operator intends to confirm or revise
the MAOP by using the IM alternative in this proposed rulemaking. The
Class 1 to Class 3 location segment will consist of the pipe that was
designed to Class 1 specifications, per subpart C, that is in a newly
identified Class 3 location.
    An ``in-line inspection segment'' would be defined as including all
pipe upstream and downstream of the Class 1 to Class 3 location segment
that is between the nearest upstream ILI launcher and the nearest
downstream ILI receiver and the Class 1 to Class 3 location segment.
    PHMSA is also proposing a definition for ``predicted failure
pressure'' to provide additional clarification to the regulations. A
``predicted failure pressure'' would be defined as the calculated
pipeline anomaly failure pressure based on the use of an appropriate
engineering evaluation method for the type of anomaly being assessed
and without any safety factors.

Sec.  192.7 What documents are incorporated by reference partly or
wholly in this part?

    Section 192.7 lists documents that are incorporated by reference in
part 192. PHMSA is making conforming amendments to Sec.  192.7 to
reflect other changes adopted in this final rule.
    API Standard 1163, which is already incorporated by reference into
the regulations for natural gas transmission pipelines at Sec.  192.493
and for hazardous liquid pipelines at Sec.  195.591, covers the use of
ILI systems for onshore and offshore gas and hazardous liquid
pipelines. This standard includes, but is not limited to, tethered,
self-propelled, or free-flowing systems for detecting metal loss,
cracks, mechanical damage, pipeline geometries, and pipeline location
or mapping. The standard applies to both existing and developing
technologies, and it is an umbrella document that provides performance-
based requirements for ILI systems, including procedures, personnel,
equipment, and associated software.
    In this NPRM, PHMSA is proposing to incorporate this standard by
reference into the proposed IM alternative at Sec.  192.618(b)(4) to
require operators validate ILI results to Level 3 in accordance with
API Standard 1163. Per API Standard 1163, a Level 3 validation is one
where ``extensive validation measurements are available that allow
stating the as-run tool performance. Validating to such a level allows
an operator to establish a direct link between the ILI tool performance
and the impact it has on IM decisions.'' PHMSA requests comment as to
whether it should allow operators to validate ILI results to Level 2 or
Level 3 per API Standard 1163. Per API Standard 1163, a Level 2
validation is ``where no definitive statement is made about the actual
tool performance. Although it is possible to state with a high degree
of confidence whether the tool performance is worse than the
specification, the approach does not allow one to state with confidence
that the tool performance is within specification.''
    Further, PHMSA is proposing to incorporate by reference ASME/ANSI
B31.8S-2004 for proposed Sec.  192.618. B31.8S is specifically designed
to provide the operator with the information necessary to develop and
implement an effective IM program utilizing proven industry practices
and processes. Effective system management can decrease repair and
replacement costs, prevent malfunctions, and minimize system downtime.

Sec.  192.611 Change in Class Location: Confirmation or Revision of
Maximum Allowable Operating Pressure

    Section 192.611 prescribes requirements for operators when a change
in class location has occurred. With the development of the IM
alternative in proposed Sec.  192.618, conforming changes would be
needed to this section to specify that an operator may confirm or
revise the MAOP of a Class 1 to Class 3 segment in accordance with
proposed Sec.  192.618. A pressure reduction taken in accordance with
this section and after the effective date of this rule would not
preclude an operator from implementing an integrity assessment program
per paragraph (a)(4) of this section at a later date. Further, an
operator would need to implement such a program prior to any future
increases of MAOP. For the purposes of this section, operators will not
be allowed to use pressure reductions taken prior to the effective date
of the rule for Class 1 to Class 3 locations. Operators who wish to do
so would be required to apply to PHMSA for a special permit.

Sec.  192.618 Class 1 to Class 3 Location Segment Requirements

    Section 192.618 establishes the proposed conditions an operator
would implement in its O&M procedures if it chooses to manage pipeline
segments where the class location has changed from a Class 1 to a Class
3 through the IM alternative. PHMSA notes that the approach outlined in
this NPRM would apply only to those pipeline segments that have changed
class location following the effective date of the rulemaking;
operators would not be able to use the IM alternative retroactively for
pipeline segments that have experienced a class location change prior
to this rulemaking.
    The proposed requirements in this NPRM are based on PHMSA's
extensive experience with evaluating special permit applications and
granting special permits that effectively apply specific

safety requirements on a case-by-case basis.
    Per this proposal, operators would designate the Class 1 to Class 3
location segment as an HCA, as that term is defined in Sec.  192.903,
and include the segment in its IM program in accordance with subpart O.
Operators would also inspect all pipe between the nearest upstream ILI
launcher and nearest downstream ILI receiver that contains the pipeline
segment changing from a Class 1 to a Class 3 location when performing
an ILI assessment of the Class 1 to Class 3 location segment.
    PHMSA has proposed certain conditions, similar to its practice for
special permits, that would preclude the use of this IM alternative for
managing class location change segments for pipeline segments with
certain higher-risk attributes. More specifically, the proposed minimum
pipe eligibility criteria are based on the previously published
guidance in the 2004 Federal Register Notice. As outlined in that
criteria and this NPRM, certain pipeline segments would not be eligible
for the IM alternative because they are higher risk and warrant a case-
by-case review per the special permit process.
    PHMSA proposes a pipeline segment would be ineligible to use the IM
alternative if any of the following conditions exist on that segment:
     Pipeline segments that operate above 72 percent SMYS.
     Pipeline segments with bare pipe (i.e., uncoated pipe).
     Pipeline segments with wrinkle bends.
     Pipeline segments that are missing records for diameter,
wall thickness, grade, seam type, yield strength, and tensile strength.
     Pipeline segments without a hydrostatic test conducted
with a test pressure of at least 1.25 times MAOP.
     Pipe with DC, LF-ERW, EFW, or lap-welded seams, or pipe
with a longitudinal joint factor below 1.0.
     Pipe with cracking in the pipe body, seam, or girth welds
in the segment, or within 5 miles of the segment, that is over 20
percent of the pipe wall thickness, has a predicted failure pressure
less than either 100 percent of SMYS or 1.5 times MAOP, or has
experienced a leak or a rupture due to brittle failure mode. Should a
pipeline segment changing from a Class 1 to a Class 3 location at any
time fail the requirements regarding cracking, that segment would no
longer be eligible for the IM alternative for class location change
management, and the operator would be required to replace the segment
within 2 years of the ineligibility determination. Prior to the
replacement, the enhanced crack repair conditions as detailed below
would apply.
     Pipeline segments with tape coatings or shrink sleeves, or
with poor external coating that requires the use of a 100 millivolt
shift or linear anodes to maintain required levels of CP.
     Pipeline segments that transport gas whose composition
quality is not suitable for sale to gas distribution customers.
     Pipeline segments that operate under Sec.  192.619 (c) or
(d).
     Pipeline segments, or portions of pipeline segments, that
have been denied a class location change special permit in the past.
    This section also contains proposed requirements for operators to
conduct their initial integrity assessment within 24 months of the
Class 1 to Class 3 location segment change, which would be consistent
with existing requirements for the deadline to reconfirm or revise a
pipeline segment's MAOP when its class location changes; the specific
ILI integrity assessment methodology, including ILI results validation,
that operators must use; and additional repair criteria for these
segments that supplements the existing repair criteria in subpart O.
    For the purposes of ILI tool calibration and validating ILI
results, an operator may use previously excavated anomalies or recent
anomaly excavations with known dimensions that were field measured for
length, depth, and width; externally re-coated; CP maintained; and
documented for ILI calibrations prior to the ILI tool run. ILI tool
calibrations must use ILI tool run results and anomaly calibrations
from either the Class 1 to Class 3 location segment or from the
complete ILI tool run in the in-line inspection area. A minimum of four
calibration excavations should be used for unity plots.
    Regarding the additional repair criteria, subpart O allows metal
loss anomalies to grow until the predicted failure pressure is 1.1
times MAOP (i.e., a 10 percent safety factor). PHMSA believes the more
stringent repair criteria proposed in this NPRM is needed to compensate
for the lack of newly replaced pipe in locations changing from a Class
1 to a Class 3. The existing pipe in these locations could include
pipelines that were built before design and construction standards were
promulgated in 49 CFR part 192. Such existing pipe may not have the
steel toughness to mitigate ruptures when the pipe is corroded, dented,
or has any cracking in the pipe body or pipe seam.
    As such, PHMSA is proposing additional anomaly inspection and
repair criteria as follows:
     Operators must use high-resolution ILI methods for
performing integrity assessments.
     Integrity assessments for pipeline segments where the
class location has changed from Class 1 to Class 3 must also include
all pipe upstream and downstream of the segment between the nearest
upstream ILI launcher and the nearest downstream ILI receiver. This
segment would be defined as the ``in-line inspection segment.''
     Operators would conduct non-destructive SCC inspections
any time pipe in the in-line inspection segment is exposed (except for
times a pipe segment is exposed by a third party through a ``one-call''
excavation under Sec.  192.614) and where the operator finds disbonded
or repaired coating (except for pipe that is coated with fusion-bonded
or liquid-applied epoxy coatings).
    For ILI anomalies identified in the in-line inspection segment,
PHMSA proposes the following repair criteria that is consistent with
granted special permit conditions: Immediate repair conditions for pipe
threats such as metal loss, denting, cracking, and other anomalies that
are at or near the point of failure. These include metal loss with a
predicted failure pressure less than or equal to 1.1 times the MAOP,
crack-type defects with a predicted failure pressure less than 1.25
times the MAOP, and additional specified criteria dependent on anomaly
type and size.
    To ensure anomalies in the in-line inspection segment are repaired
in a timely manner, PHMSA is proposing for operators to repair
scheduled anomalies in 1 year regardless of whether the applicable
pipeline segment is in an HCA. One-year scheduled conditions are for
pipe threats such as metal loss, denting, cracking, and other anomalies
that are not an immediate threat to integrity but that operators would
need to repair promptly. PHMSA is also proposing to incorporate a
tiered approach for the predicted failure pressure criteria for metal
loss and crack anomalies based on the class location at the anomaly to
make the criteria more stringent as the class location increases. In
addition to repair criteria based on predicted failure pressure, PHMSA
is basing the proposed dent repair criteria on anomaly size and
location. For Class 1 to Class 3 location segments, PHMSA has also
established monitored conditions for pipe threats such as metal loss
denting, cracking, and other anomalies that are not severe enough to

need prompt repair but that the operator must monitor.
    PHMSA is also proposing additional repair criteria for anomalies
identified in the Class 1 to Class 3 location segment beyond the
criteria proposed for the in-line inspection segment. These criteria
include more conservative criteria for crack anomalies and a
requirement for operators to repair discovered pipe wall thickness loss
greater than 40 percent within 1 year. These criteria are based on
PHMSA research and development projects and were developed in
conjunction with the repair criteria that the GPAC discussed and voted
to adopt in 2019.
    In addition, PHMSA is proposing the following maintenance surveys
to address threats not assessed by ILI and the findings remediated, as
well as other P&M actions:
     CIS,
     CP test site survey,
     Line-of-sight markers,
     Interference survey,
     Depth-of-cover survey,
     Right-of-way patrols,
     Leakage survey, and
     Shorted casings survey.
    PHMSA also proposes requiring operators install remote-control or
automatic shutoff valves, or otherwise equip existing valves with
remote-control or automatic shutoff capability for the mainline block
valves both upstream and downstream of the class location upgrade
segment. In this proposed rule, PHMSA is defining the timing for
remote-control and automatic shutoff valve closure should there be a
pipeline rupture and is requiring operators use a SCADA system if
managing class location changes through IM. More specifically, PHMSA is
proposing a 30-minute valve closure standard to be consistent with
conditions it has required operators to meet in certain class location
change special permits. This 30-minute standard would help protect
populations where Class 1 pipe is not being upgraded and will remain in
the ground. If operators determine they would not be able to meet this
30-minute valve closure standard as a part of the IM alternative in
this NPRM, an operator could apply to PHMSA for a special permit for
managing their class location change.
    PHMSA is also requiring documentation for pipe properties, pressure
tests, ILI assessments, surveys, and any other required action
operators take to comply with this proposed rulemaking.
    Finally, if an operator intends to use the IM alternative to manage
a pipeline segment that has changed from a Class 1 to a Class 3
location, the operator must submit a notification to PHMSA within 60
days of the class location change, in accordance with Sec.
191.22(c)(2). Such a notification must include details of each pipeline
segment that experienced a class location change that the operator will
manage using IM.
    PHMSA requests comments on whether it should consider modifying or
eliminating any of the O&M procedural requirements of this section,
including:
    (a) Program requirements, including the eligibility conditions, for
a Class 1 to Class 3 location segment.
    (b) Pipeline integrity assessments.
    (c) Remediation schedule (In-line inspection segment).
    (d) Special requirements for crack anomalies.
    (e) Pipe and weld cracking inspections.
    (f) Additional preventive and mitigative measures.
    (g) Remote-control or automatic shutoff valves.
    (h) Documentation.
    (i) Notifications to PHMSA of integrity assessment program for
class 1 to class 3 location segment changes.
    If a commenter determines that any of the above requirements should
be modified or eliminated, please explain how such a modification or
elimination would maintain, increase, or decrease the current level of
pipeline safety and environmental protection. Based on comments
received, PHMSA may consider modifying or eliminating the above
requirements if they are not necessary for maintaining pipeline safety
or protecting the environment and another approach would maximize net
benefits to society.

Sec.  192.712 Analysis of Predicted Failure Pressure and Critical
Strain Levels

    In the ``Safety of Gas Transmission Pipelines: MAOP Reconfirmation,
Expansion of Assessment Requirements, and Other Related Amendments''
final rule published on October 1, 2019, PHMSA updated and codified
minimum standards for determining the predicted failure pressure of
pipelines containing anomalies or defects associated with corrosion
metal loss and cracks. In this NPRM, PHMSA is proposing repair criteria
for the in-line inspection segment and the Class 1 to Class 3 location
segment, which include repair criteria for dents. Some of the proposed
dent repair criteria allows operators to determine critical strain
levels for dents and defer repairs if critical strain levels are not
exceeded. In this section, PHMSA has established minimum standards for
calculating critical strain levels in pipe with dent anomalies or
defects and has included those standards in a new paragraph (c). These
standards are based off of the dent ECA method discussed and voted on
as part of the repair criteria discussion at the Gas Pipeline Advisory
Committee meetings during March 26-28, 2018. The title of this section
has also been updated to reflect this addition.

Sec.  192.903 What definitions apply to this subpart?

    Section 192.903 provides definitions for various terms used
throughout part 192 subpart O. In support of the regulations proposed
in this NPRM, PHMSA is proposing to amend the definition of ``high
consequence area.'' The revised definition would require operators to
incorporate any Class 1 to Class 3 location segment, as defined in
proposed Sec.  192.3, into their IM programs as an HCA.

V. Regulatory Analysis and Notices

A. Statutory/Legal Authority for This Rulemaking

    This proposed rule is published under the authority of the Federal
Pipeline Safety Law (49 U.S.C. 60101 et seq.). Section 60102 authorizes
the Secretary of Transportation to issue regulations governing the
design, installation, inspection, emergency plans and procedures,
testing, construction, extension, operation, replacement, and
maintenance of pipeline facilities. Further, section 60102(l) requires
the Secretary, to the extent appropriate and practicable, to update
incorporated industry standards that have been adopted as a part of the
pipeline safety regulations. The Secretary has delegated the authority
vested in the Secretary by the Pipeline Safety Law to the PHMSA
Administrator under 49 CFR 1.97.

B. Executive Order 12866 and DOT Regulatory Policies and Procedures

    Executive Order 12866, Regulatory Planning and Review, (58 FR
51735; Oct. 4, 1993), requires agencies to regulate in the ``most cost-
effective manner,'' to make a ``reasoned determination that the
benefits of the intended regulation justify its costs,'' and to develop
regulations that ``impose the least burden on society.'' The Executive
Order and DOT regulations governing rulemaking procedures (49 CFR part
5) require that PHMSA submit ``significant regulatory actions'' to OMB
for review. The proposed rulemaking is a ``significant regulatory
action'' under section 3(f) of Executive Order 12866 and DOT rulemaking
regulations. The proposed rulemaking has been reviewed by the Office of
Management and

Budget in accordance with Executive Order 12866 and is consistent with
the Executive Order 12866 requirements and 49 U.S.C. 60102(b)(5)-(6).
    The tables below summarize the annualized cost savings for the
provisions in the proposed rule. PHMSA anticipates that, if
promulgated, the proposals in this NPRM would have economic benefits to
the public and the regulated community by reducing cost burdens without
increasing risks to public safety or the environment. These estimates
reflect the assumption that the IM alternative for managing class
location changes proposed in this rule will be a less-costly
alternative to the current regulatory requirements.
    PHMSA estimates that the proposed rule will result in annualized
cost savings of approximately $55 to $86 million per year, based on its
analysis of two different scenarios and at a 7 percent discount
rate.\108\ The tables below present the annualized costs for the
baseline and this proposed rule, for both scenarios examined, at a 3
percent and a 7 percent discount rate:
---------------------------------------------------------------------------

    \108\ Scenario 1 averaged PHMSA's estimates, annually and from a
low- and high-end concept, of the number of miles that would change
from a Class 1 to a Class 3 location and where operators would use
the IM alternative. This estimate was 77.6 miles per year. Scenario
2 took the median of PHMSA's estimates, annually and from a low- and
high-end concept, and this estimate was 117.6 miles per year. See
Section 3 of the Preliminary Regulatory Impact Analysis for more
details.

            Annualized Proposed Rule Cost Savings, Scenario 1
                          [2020-2039, millions]
------------------------------------------------------------------------
                                                   Discount rate
                                         -------------------------------
                                                3%              7%
------------------------------------------------------------------------
                               Baseline *
------------------------------------------------------------------------
Pipe Replacement........................          $206.7          $206.7
Special Permits.........................             9.0             8.0
                                         -------------------------------
    Total Cost..........................           215.7           214.7
------------------------------------------------------------------------
                              Proposed Rule
------------------------------------------------------------------------
Pipe Replacement........................           135.8           135.8
Special Permits.........................             2.5             2.2
New Compliance Method...................            23.8            21.8
                                         -------------------------------
    Total Cost..........................           162.1           159.8
                                         -------------------------------
        Net Annualized Cost.............           -53.6           -54.9
------------------------------------------------------------------------
* Operators also have the option to use a pressure test or pressure
  reduction to manage the class location change. To the extent operators
  find the new class location MAOP acceptable, the decision by operators
  to use these options is not affected by the addition of the proposed
  rule compliance method. Therefore, the rule has no incremental effect
  on these compliance options.

            Annualized Proposed Rule Cost Savings, Scenario 2
                          [2020-2039, millions]
------------------------------------------------------------------------
                                                   Discount rate
                                         -------------------------------
                                                3%              7%
------------------------------------------------------------------------
                               Baseline *
------------------------------------------------------------------------
Pipe Replacement........................          $326.7          $326.7
Special Permits.........................             9.0             8.0
                                         -------------------------------
    Total Cost..........................           335.7           334.7
------------------------------------------------------------------------
                              Proposed Rule
------------------------------------------------------------------------
Pipe Replacement........................           214.6           214.6
Special Permits.........................             2.5             2.2
New Compliance Method...................            34.8            31.8
                                         -------------------------------
    Total Cost..........................           251.9           248.7
                                         -------------------------------
        Net Annualized Cost.............           -83.8             -86
------------------------------------------------------------------------
* Operators also have the option to use a pressure test or pressure
  reduction to manage the class location change. To the extent operators
  find the new class location MAOP acceptable, the decision by operators
  to use these options is not affected by the addition of the proposed
  rule compliance method. Therefore, the rule has no incremental effect
  on these compliance options.

    For more information, please see the PRIA in the docket for this
rulemaking.

C. Executive Order 13771

    This proposed rule is expected to be a deregulatory action under
Executive Order 13771. Details on the estimated costs of this proposed
rule can be found in the PRIA in the rulemaking docket.

D. Regulatory Flexibility Act

    The Regulatory Flexibility Act (RFA) (5 U.S.C. 601 et seq.)
requires federal agencies to review each rulemaking action to consider
whether it would have a ``significant economic impact on a substantial
number of small entities'' to include small businesses, not-for-profit
organizations that are independently owned and operated and are not
dominant in their fields, and governmental jurisdictions with
populations under 50,000. This NPRM was developed in accordance with
Executive Order 13272, ``Proper Consideration of Small Entities in
Agency Rulemaking'' (68 FR 7990, Feb. 19, 2003) and DOT's procedures
and policies to promote compliance with the RFA and to ensure that the
potential impacts of a regulatory action on small entities were
properly considered.
    Based on the analysis within the PRIA in the rulemaking document,
which PHMSA has summarized below, PHMSA expects that this rulemaking
will not have a significant economic impact on a substantial number of
small entities. However, PHMSA seeks public comment on its analysis.
(1) Statement of the Need for, and Objectives of, the Rulemaking
    In this rulemaking PHMSA proposes to add an alternative set of
requirements within the PSR that operators could use, based on
implementing integrity management principles and pipe eligibility
criteria, to manage certain pipeline segments where the class location
has changed from a Class 1 location to a Class 3 location. Through
required periodic assessments, repair criteria, and other extra
preventive and mitigative measures, PHMSA expects this alternative
approach would providing cost savings for pipeline operators without
adversely affecting safety. The need for and objectives of this
rulemaking are discussed further above in Section I.A (``Purpose of
Regulatory Action'').
(2) Description of the Small Entities That Could Be Affected by the
Rulemaking and Their Estimated Compliance Costs
    The RFA obliges PHMSA to assess whether the rulemaking would have
``a significant impact on a substantial number of small entities. This
assessment involves (1) identifying the domestic parent entities for
affected operators, (2) determining which are small entities based on
Small Business Administration size criteria, and (3) assessing the
potential impact of the rule on those small entities based on estimated
entity-level annualized compliance cost savings and annual revenues.
Although PHMSA's analysis on each of these issues is provided in
greater detail within the PRIA in the rulemaking docket, that analysis
is summarized below.
    There are currently 1,099 operators of onshore natural gas
transmission pipelines, and approximately 85 percent, or 939 operators
operate Class 1 pipelines. PHMSA estimates that operators of Class 1
pipelines are owned by 324 parent entities, and of these, 254 are small
entities. Small entities operate approximately 5,200 miles of Class 1
pipeline, which is only about 2.2 percent of all Class 1 pipeline.
    The NPRM does not eliminate any of the currently available options
for management of changes from Class 1 to Class 3, but would rather
provide flexibility to operators by enabling the use of another
compliance option. Since PHMSA expects that the approach introduced in
this NPRM would cost less than the other predominately used options--
pipeline replacement and special permit--such that small entities would
have the opportunity to achieve cost savings should they need to manage
class location changes in the future for pipeline segments that meet
the eligibility criteria set forth in this NPRM.
    The quantity, character, and location of future class changes is
highly uncertain, particularly on a year-to-year basis. In any given
year, only a subset of pipelines will experience a change from Class 1
to Class 3. PHMSA is not able to develop an annual forecast describing
specific pipeline segments changing classes or to what extent those
changes will be managed by small versus large operators. Over the 20-
year period of analysis, PHMSA assumes that each pipeline operator will
manage a share of the future changes from Class 1 to Class 3 that is
proportional to the total miles of Class 1 pipeline it operates.
    PHMSA estimates that small entities will manage an aggregate 1.7 to
2.6 miles of pipeline changing from Class 1 to Class 3 annually, in
Scenarios 1 and 2, respectively. Aggregate annualized cost savings for
small entities is estimated to be $1.17-$1.19 million in Scenario 1,
using 3 and 7 percent discount rates, respectively; annualized small
entity savings is $1.8-$1.9 million in Scenario 2. Under Scenario 1,
the average annual cost savings per small entity is $4,700, with a
median savings of $1,500 per year. Under Scenario 2, the average per-
entity annual savings is $7,400, with a median of $2,300.
    PHMSA estimates only about 1 percent of Class 1 pipeline miles will
be affected by a change to Class 3 in total over the next 20 years.
Based on PHMSA's high-end Scenario 2 estimate of 117.6 miles per year,
only 2,352 miles will make this change over the next 20 years.
Annually, the proposed rule affects 0.05 percent of Class 1 miles. The
characteristics of this small subset of affected pipeline miles (or
segments) will ultimately determine the extent to which large and small
entities ultimately avail themselves of the proposed rule option. Given
that small entities operate only about 2 percent of Class 1 miles,
large entities in the aggregate are more likely to experience a
pipeline segment requiring a change from Class 1 to Class 3.
    It is also important to note that although the savings are
presented here on an annualized basis, the vast majority of small
entities will likely not have to manage a change from Class 1 to Class
3 for any pipeline miles in a given year. For instance, PHMSA's
estimate of 1.7 to 2.6 miles per year of Class 1 to Class 3 changes
managed by small entities (Scenarios 1 and 2), and PHMSA's estimated
average segment length of 0.26 miles, suggests an average of 7 to 10
segments per year experiencing a change from Class 1 to Class 3 across
the entire pipeline industry. If each operator only manages one segment
changing from Class 1 to Class 3 each year, then only 7 to 10 small
entities (or fewer if operators manage multiple segments in one year)
may manage a Class 1 to Class 3 change per year, out of 254 total
affected small entities.
(3) Significant Alternatives Considered
    PHMSA does not expect this proposed rulemaking to have a
significant economic impact on small businesses. Further, the changes
to the PSR proposed in this NPRM are generally intended to provide
regulatory flexibility and cost savings to industry members without
adversely affecting safety. PHMSA solicits public comment on the
economic impact on small entities, and potential alternatives that
reduce any economic impact on small entities.

(4) Duplicative, Overlapping, and Conflicting Federal Rules
    PHMSA is unaware of any Federal regulations that are substantially
similar to the proposals in this NPRM and which would duplicate,
overlap, or conflict with the PSR revisions proposed.

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

    PHMSA analyzed this proposed rule per the principles and criteria
in Executive Order 13175, ``Consultation and Coordination with Indian
Tribal Governments'' (65 FR 67249; Nov. 6, 2000) and under DOT Order
5301.1. Because PHMSA does not anticipate that this proposed rule will
have tribal implications, the funding and consultation requirements of
Executive Order 13175 would not apply. PHMSA seeks comment on the
applicability of the Executive Order to this proposed rule.

F. Paperwork Reduction Act

    The Paperwork Reduction Act of 1995 (44 U.S.C. 3501 et seq.)
establishes policies and procedures for controlling paperwork burdens
imposed by Federal agencies on the public. Pursuant to 44 U.S.C.
3506(c)(2)(B) and 5 CFR 1320.8(d), PHMSA is required to provide
interested members of the public and affected agencies with an
opportunity to comment on information collection and recordkeeping
requests. The proposals in this NPRM will trigger new notification
requirements for pipeline operators who experience a change in their
class location.
    PHMSA proposes to create a new information collection to help
operators comply with the proposed revision to the PSR. Operators will
be required to notify PHMSA if they choose to use an alternative to an
inline-inspection device when conducting pressure tests on their
pipelines. Operators will also be required to notify PHMSA if they use
integrity management protocols to manage pipeline segments that have
changed from a Class 1 to a Class 3 location. PHMSA will request a new
Control Number from OMB for this new information collection.
    PHMSA will submit an information collection request to OMB for
approval based on the proposed requirements in this NPRM. The
information collection is contained in the PSR, 49 CFR parts 190-199.
The following information is provided for this information collection:
(1) Title of the information collection; (2) OMB control number; (3)
Current expiration date; (4) Type of request; (5) Abstract of the
information collection activity; (6) Description of affected public;
(7) Estimate of total annual reporting and recordkeeping burden; and
(8) Frequency of collection. The information collection burden is
estimated as follows:
    1. Title: Class Location Change Notification Requirements.
    OMB Control Number: Will request from OMB.
    Current Expiration Date: TBD.
    Abstract: This information collection covers the collection of data
from owners and operators of pipelines. Pipeline operators are required
to notify PHMSA in the event of certain instances that pertain to a
change in their class location.
    Affected Public: Owners and operators of pipelines.
    Annual Reporting Burden:
    Total Annual Responses: 100.
    Total Annual Burden Hours: 25.
    Frequency of Collection: On occasion.
    Requests for a copy of this information collection should be
directed to Angela Hill or Cameron Satterthwaite, Office of Pipeline
Safety (PHP-30), Pipeline Hazardous Materials Safety Administration
(PHMSA), 2nd Floor, 1200 New Jersey Avenue SE, Washington, DC 20590-
0001, Telephone<PHONE_NUMBER>.
    Comments are invited on:
    (a) The need for the proposed collection of information for the
proper performance of the functions of the agency, including whether
the information will have practical utility;
    (b) The accuracy of the agency's estimate of the burden of the
revised collection of information, including the validity of the
methodology and assumptions used;
    (c) Ways to enhance the quality, utility, and clarity of the
information to be collected; and
    (d) Ways to minimize the burden of the collection of information on
those who are to respond, including the use of appropriate automated,
electronic, mechanical, or other technological collection techniques.
    Those desiring to comment on these information collections should
send comments directly to the Office of Management and Budget, Office
of Information and Regulatory Affairs, Attn: Desk Officer for the
Department of Transportation, 725 17th Street NW, Washington, DC 20503.
Comments should be submitted on or prior to December 14, 2020. Comments
may also be sent via email to the Office of Management and Budget at
the following address<EMAIL_ADDRESS>
G. Unfunded Mandates Reform Act of 1995

    The Unfunded Mandates Reform Act of 1995 (2 U.S.C. 1501 et seq.)
requires Federal agencies to prepare and consider estimates of the
budgetary impact of regulations containing Federal mandates upon State,
local, and Tribal governments before adopting such regulations. This
NPRM imposes no unfunded mandates. If promulgated, this rule would not
result in costs of $100 million, adjusted for inflation, or more in any
one year to either State, local, or Tribal governments, in the
aggregate, or to the private sector. A copy of the PRIA is available
for review in the docket.

H. National Environmental Policy Act

    The National Environmental Policy Act (NEPA) (42 U.S.C. 4321 et.
seq.) requires Federal agencies to prepare a detailed statement on
major Federal actions significantly affecting the quality of the human
environment. PHMSA analyzed this NPRM in accordance with NEPA, Council
on Environmental Quality regulations (40 CFR parts 1500-1508), and DOT
Order 5610.1C. PHMSA has prepared a draft Environmental Assessment (EA)
and has preliminarily determined this action will not significantly
affect the quality of the human environment. A copy of the EA for this
action is available in the docket. PHMSA invites comment on the
environmental impacts of this proposed rulemaking.

I. Executive Order 13132: Federalism

    Executive Order 13132, ``Federalism'' (64 FR 43255; Aug. 10, 1999)
imposes certain requirements on Federal agencies formulating or
implementing policies or regulations that preempt State law or that
have federalism implications. This NPRM does not impose a substantial,
direct effect on the States, the relationship between the national
government and the States, or the distribution of power and
responsibilities among the various levels of government. This NPRM also
does not impose substantial direct compliance costs on State and local
governments.
    The proposed rule could have preemptive effect because the pipeline
safety laws, specifically 49 U.S.C. 60104(c), prohibit State safety
regulation of interstate pipelines. Under the pipeline safety law,
States can augment pipeline safety requirements for intrastate
pipelines but may not approve safety requirements less stringent than
those required by Federal law. A State may also regulate an intrastate
pipeline

facility not otherwise covered by PHMSA regulations. In this instance,
the preemptive effect of the proposed rule is limited to the minimum
level necessary to achieve the objectives of the pipeline safety laws
under which the proposed rule is promulgated. Therefore, the