(1) Grandfathered pipe, in direct response to section 23(d) of the
2011 Pipeline Safety Act and NTSB recommendation P-11-14;
    (2) Pipe for which documentation is inadequate to support the MAOP,
in direct response to section 23(c) of the 2011 Pipeline Safety Act;
and
    (3) Pipe that has experienced a reportable in-service incident
since its most recent successful subpart J pressure test due to an
original manufacturing-related defect; a construction-, installation-,
or fabrication-related defect; or a cracking-related defect, including,
but not limited to, seam cracking, girth weld cracking, selective seam
weld corrosion, hard spots, or stress corrosion cracking.
    It is important to note that a given pipeline segment for which the
MAOP reconfirmation process would apply might fit into one, two, or all
three of these proposed categories. For pipeline segments where records
of the pipeline physical properties and attributes to substantiate the
current MAOP are not documented in traceable, verifiable, and complete
records, only those segments located within an HCA or a Class 3 or
Class 4 location would be subject to the MAOP reconfirmation process
under the NPRM.
    This proposal directly correlates to section 23 of the 2011
Pipeline Safety Act and NTSB recommendation P-11-14 regarding the need
for spike hydrostatic testing where in-service incidents have occurred.
The NTSB recommended such testing for all pipe manufactured before
1970.
    For pipeline segments where operators established the MAOP in
accordance with the grandfather clause at Sec.  192.619(c) (i.e.,
pipeline segments where the MAOP is based upon the highest actual
operating pressure records from a 5-year interval between July 1, 1965,
to July 1, 1970, and where operators therefore do not have pressure
test or material property records) or for segments with a history of
in-service incidents caused by cracks or crack-like defects, PHMSA
proposed to restrict the applicability of MAOP reconfirmation to HCAs,
Class 3 or Class 4 locations, or MCAs, if the MCA segment can
accommodate an ILI tool. The proposed inclusion of pipeline segments in
these locations and with these traits slightly expand on the mandate
contained in section 23 of the 2011 Pipeline Safety Act, which applied
only to previously untested pipeline segments operating at a pressure
greater than 30 percent SMYS located in an HCA.
    In recommendation P-11-14, the NTSB recommended that all pipe
manufactured before 1970 be subjected to a hydrostatic pressure test
that would include a spike hydrostatic test, which PHMSA considered in
its process for reconfirming MAOP. PHMSA's preliminary evaluation
concluded that doing so may not be cost-effective, since a large amount
of such pipe could be in remote locations where the likelihood of
personal injury or property damage as a result of an incident would be
low.
    PHMSA's proposal expanded the applicability of MAOP reconfirmation
beyond the minimum required by the congressional mandate to include
pipe operating at less than 30 percent SMYS. In addition, the NPRM
expanded the location criteria to include some non-HCA locations in the
form of MCAs and Class 3 and Class 4 locations. As PHMSA proposed in
the definitions section of the NPRM, MCAs are areas that, while not
meeting the HCA criteria, include 5 or more persons or dwellings
intended for human occupation or are otherwise locations where people
congregate, including the right-of-ways of major roadways. See section
H of this final rule for additional background on the MCA definition.
The NPRM also specified that the MAOP reconfirmation process would
apply only to MCA pipeline segments able to accommodate an ILI tool.
This provision would not preclude an operator from choosing to conduct
a pressure test, but it would avoid forcing operators to conduct a
pressure test because the pipeline segment was not ``piggable.''
2. Summary of Public Comment
    Many stakeholders provided input on the proposed provisions in
Sec.  192.624 that require MAOP reconfirmation for pipeline segments
previously excluded from testing by the grandfather clause, pipeline
segments without adequate documentation to substantiate the current
MAOP, and pipeline segments that have experienced a reportable in-
service incident.
    Regarding the first criterion above, several commenters, including
INGAA, AGA, and NAPSR, generally supported the provision requiring
operators of pipeline segments where the MAOP was established via the
grandfather clause to reconfirm the MAOP of those segments. Several of
the pipeline industry trade associations and industry entities,
however, did not support the proposed application of these criteria to
all grandfathered pipeline segments within HCAs, Class 3 and Class 4
locations, and Class 1 and Class 2 piggable segments within MCAs. Gas
Processors Association's Midstream Association (GPA) and AGA stated
that while they support the congressional mandate to conduct testing to
confirm the material strength of previously untested gas transmission
pipelines in HCAs that operate at a pressure above 30 percent SMYS,
they oppose the proposed provisions which extend to additional pipeline
segments. INGAA and Washington Gas supported the applicability of MAOP
reconfirmation in MCAs for pipelines operating at greater than or equal
to 30 percent SMYS but disagreed with the proposed provisions that
included MCA pipelines operating at less than 30 percent SMYS.
    Some citizen groups, including PST, expressed concern that the
proposed changes regarding the grandfather clause did not go far enough
and suggested that PHMSA should fully implement the recommendations set
forth by the NTSB. They stated that PHMSA should eliminate the
grandfather clause given that the proposed provisions would not include
the following groups of pipelines: (1) Pipelines in non-HCA areas
within Class 1 and Class 2 locations; and (2) pipeline segments for
which there is an inadequate record of a hydrostatic pressure test in
areas newly designated as an MCA that are not capable of being assessed
by an in-line tool. Conversely, Northeast Gas Association (NGA) stated
that PHMSA should retain the grandfather clause as it prevents
existing, historically safe, and maintained pipelines from being
subjected to unwarranted requirements.
    For pipeline segments where operators do not have adequate
documentation to support the current MAOP and that PHMSA proposed would
be subject to the new MAOP reconfirmation requirements, some commenters
stated that they support the

requirement to the extent that it is consistent with the congressional
mandate to reconfirm MAOP for pipeline segments with insufficient
records within Class 3 and Class 4 locations and Class 1 and Class 2
HCAs. These commenters further stated that Sec.  192.624(a)(2) within
the proposed MAOP reconfirmation requirements should be revised to
clarify that it applies only to those gas transmission pipeline
segments in HCAs and Class 3 and Class 4 locations that were
constructed and put into operation since the adoption of the Federal
Pipeline Safety Regulations in 1970, stating that otherwise Sec.
192.624(a)(2) would apply to those pipelines put into service prior to
the implementation of Federal regulations where the requirement to
maintain a pressure test record does not apply. Some commenters also
stated that PHMSA should revise Sec.  192.624(a) within the proposed
MAOP reconfirmation requirements to make clear that operators that have
used one of the proposed allowable methods for establishing MAOP in
Sec.  192.624(b) other than the pressure test method are not required
to have a pressure test record to comply with the record requirements
of the section. Washington Gas asserted that the MAOP reconfirmation
requirements should apply to only pipeline segments in HCAs that
operate at a pressure of greater than or equal to 30 percent SMYS.
Other commenters, including Xcel Energy, stated that the proposed
provisions should allow operator discretion regarding what constitutes
a reliable, traceable, verifiable, and complete record to determine the
necessary documentation to support a pressure test record and the
necessary material properties for MAOP verification. Additionally, AGA
recommended the deletion of the phrase ``reliable, traceable,
verifiable, and complete'' from the proposed MAOP reconfirmation
provisions in Sec.  192.624(a)(2). Similarly, other commenters,
including INGAA, recommended omitting ``reliable'' from the phrase and
provided a suggested definition for ``traceable, verifiable, and
complete.''
    Lastly, with regard to the third category of applicable pipeline
segments to the proposed MAOP reconfirmation requirements, many
commenters either disagreed or requested clarification for the
requirement that MAOP must be reconfirmed in cases where an in-service
incident occurred due to a manufacturing defect listed under Sec.
192.624(a)(1). For example, INGAA stated that an operator can evaluate
such manufacturing defects more effectively through ongoing operations
and maintenance activities rather than through MAOP reconfirmation, and
that the defects PHMSA is concerned with are already addressed through
integrity management. Similarly, Boardwalk Pipeline stated that
pipelines that have experienced an in-service incident because of the
listed defects in Sec.  192.624(a)(1) should be subject to integrity
management measures rather than MAOP reconfirmation. TransCanada and
TPA recommended adding text to the applicability section of the MAOP
reconfirmation requirements that would exclude a pipeline segment from
such requirements if the operator has already acted to address the
cause of the reported incident. Additionally, one commenter suggested
that this requirement should apply only to pipelines in HCAs. Some
commenters, including AGA and Consolidated Edison of New York (Con Ed),
also requested additional time to comply with the proposed MAOP
reconfirmation provisions, asserting that operators would be required
to replace many of their transmission mains to comply with the new
requirements because their current records would not be satisfactory.
Due to the urban density and scale of the service areas of certain
operators, AGA and Con Ed stated that this replacement process would
take longer than the 15-year schedule provided in the rule. One
commenter suggested that if the applicability criteria for pipeline
segments with in-service incidents and manufacturing defects remains in
the rule, it should be limited to a more contemporary time frame, such
as a rolling 15-year window or those in-service incidents that have
occurred since 2003. Pipeline Safety Trust, on the other hand, stated
that the proposed timeframe of 15 years is too long for operators to
reconfirm MAOP in HCAs and complete critical safety work, and they
urged PHMSA to adopt significantly shorter timelines in the final rule.
    Additionally, AGA asserted that the proposed MAOP provisions do not
address how the completion plan and completion dates of the section
would apply to pipelines that might experience a failure in the future
and would then be subject to the proposed MAOP reconfirmation
requirements, or for pipelines that are not currently located in a MCA
but may be in the future. Lastly, INGAA stated that section 23 of the
2011 Pipeline Safety Act requires that PHMSA consult with the Chairman
of the Federal Energy Regulatory Commission (FERC) and State regulators
before establishing timeframes for the testing of previously untested
pipes, and it is not evident that PHMSA has complied with this
requirement.
    As a general comment, several stakeholders, including AGA,
Louisville Gas & Electric, New Mexico Gas Company, National Grid, NW
Natural, PECO Energy, TECO Pipeline Gas, and New York State Electric
and Gas (NYSEG), proposed an alternative method for MAOP reconfirmation
where operators would execute two separate sets of actions that they
stated could be performed simultaneously or separately. First,
operators would either assess high-risk gas transmission pipelines
using a pressure test or an alternative technology that is determined
to be of equal effectiveness. Operators would categorize these
pipelines in three tiers and schedule them for testing depending on the
pipeline's SMYS and class location. Second, operators would use an ILI
tool on all gas transmission pipelines, regardless of class location,
that are capable of accommodating ILI tools. The ILI tool used would be
qualified to find defects that would fail a subpart J pressure test.
These commenters stated that this alternative methodology was necessary
because the proposed provisions would create operational inefficiencies
that would likely result in excessive cost and limited public benefit.
In addition to providing this alternative proposal, many of these
commenters provided other assorted comments on the proposed provisions.
    At the GPAC meeting on March 26, 2018, the GPAC recommended that
PHMSA revise the scope of the proposed MAOP reconfirmation provisions
by excluding lines with previously reported incidents due to crack
defects. To go along with this, the GPAC also recommended PHMSA create
a new section in subpart O of part 192, the natural gas IM regulations,
to address pipeline segments with crack-related incident histories.
Doing these actions would eliminate the need for the proposed
definitions of ``modern pipe,'' ``legacy pipe,'' and ``legacy
construction techniques,'' and the impact of this is discussed later in
this document.
    The GPAC also recommended that the MAOP reconfirmation provisions
be revised to apply to pipeline segments in HCAs or Class 3 or Class 4
locations that do not have traceable, verifiable, and complete records
necessary to establish MAOP under Sec.  192.619. Previously, the
provisions were applicable to those pipeline segments without
traceable, verifiable, and complete subpart J pressure test records.
Similarly, the GPAC recommended that the MAOP

reconfirmation provisions only apply to grandfathered pipelines in
HCAs, Class 3 or Class 4 locations, or MCAs able to accommodate
inspection with ILI tools, and that have MAOPs producing a hoop stress
greater than or equal to 30 percent SMYS. In the NPRM, the provisions
applied to all grandfathered pipelines in those locations regardless of
SMYS. In making this recommendation, the GPAC also suggested PHMSA
review the costs and benefits of applying the MAOP reconfirmation
provisions to non-HCA Class 3 and Class 4 grandfathered pipe with MAOPs
less than 30 percent SMYS.
    During the meeting on March 27, 2018, the GPAC also recommended
revisions to other sections related to the applicability of MAOP
reconfirmation provisions, including withdrawing the proposed revisions
to Sec.  192.503, which tied general requirements of the subpart J
pressure test to alternative MAOP and MAOP reconfirmation provisions,
and withdrawing the proposed revisions to Sec.  192.605(b)(5), which
cross-referenced several sections related to the MAOP reconfirmation
requirements to the requirements regarding an operator's procedural
manuals.
    The GPAC also examined the provisions related to the completion
date of these actions and recommended that PHMSA revise the appropriate
paragraph to account for pipelines that may be subject to these
requirements in the future, such as for pipelines that are not in an
HCA or Class 3 or Class 4 location now, but due to population growth or
development may be in such a location in the future. More specifically,
the GPAC recommended that an operator would have to complete all
actions required by the MAOP reconfirmation provisions on 100 percent
of their pipelines that meet the applicability requirements by 15 years
after the effective date of the rule or as soon as practicable but no
later than 4 years after the pipeline segment first meets the
applicability conditions, whichever is later. The GPAC also recommended
PHMSA consider a waiver or no-objection procedure if operators cannot
meet the requirements within 4 years under this scenario.
3. PHMSA Response
    PHMSA appreciates the information provided by the commenters
regarding the applicability of MAOP reconfirmation. After considering
these comments and as recommended by the GPAC input, PHMSA is modifying
the rule to address many of these comments.
    Regarding the applicability of the new MAOP reconfirmation
requirements at Sec.  192.624, PHMSA notes that a simplistic repeal of
the ``grandfather clause'' at Sec.  192.619(c) is not practical because
it applies to gathering and distribution lines. As the proposed rule
was primarily focused on the safety of gas transmission pipelines, a
broad repeal of the grandfather clause was not contemplated in the
proposed rule. Further, a major expansion of the MAOP reconfirmation
requirements beyond the scope of the congressional mandate in the 2011
Pipeline Safety Act would be costly, and the GPAC noted at the meeting
on March 26, 2018, that there may be cost-benefit concerns to test all
grandfathered pipelines. The GPAC recommended PHMSA analyze requiring
operators to reconfirm the MAOP of all grandfathered lines, and PHMSA
considered this as an alternative in the RIA.\65\
---------------------------------------------------------------------------

    \65\ See section 5.9.1 of the RIA for further details.
---------------------------------------------------------------------------

    In response to the comments received and the recommendations of the
GPAC, PHMSA is modifying the applicability of the MAOP reconfirmation
requirements as follows: (1) The applicability related to pipeline
segments with past in-service incidents is being eliminated. As
commenters mentioned, operational failures are already addressed within
integrity management and other subparts of part 192. Section 192.617,
for example, would require an operator of a gas transmission line that
had an in-service incident caused by an incorrect MAOP to determine the
proper MAOP of the segment before placing it back into service. Causes
of in-service failures are also already incorporated into the risk
analyses required by the current IM regulations. If the cause of an
incident is an incorrect MAOP, for example, then operators would be
required to reconfirm it following the incident within their IM
program. However, PHMSA is adding a new paragraph to strengthen the IM
requirements at Sec.  192.917(e)(6) to specifically include actions
operators must take to address pipeline segments susceptible to cracks
and crack-like defects. (2) PHMSA is also modifying the applicability
of these requirements by specifying the MAOP reconfirmation
requirements are applicable to pipeline segments that do not have the
pipeline physical properties and attributes needed to establish MAOP
documented in traceable, verifiable, and complete records, specifically
those records required to establish and substantiate the MAOP in
accordance with Sec.  192.619(a), including those records required
under Sec.  192.517(a). More specifically, these requirements to verify
MAOP would apply to such pipelines without traceable, verifiable, and
complete records in HCAs and Class 3 and Class 4 locations as specified
in the congressional mandate. Further, PHMSA is dropping the word
``reliable'' from the applicability section of the regulatory text to
be consistent with previous PHMSA advisory bulletins on this topic.\66\
(3) PHMSA is modifying the applicability of the MAOP reconfirmation
provisions for ``grandfathered'' pipeline segments to pipelines with an
MAOP greater than or equal to 30 percent of SMYS, as specified in the
congressional mandate. In addition to these requirements applying to
grandfathered pipelines in HCAs, PHMSA is retaining the MAOP
reconfirmation applicability requirement for grandfathered pipeline
segments in Class 3 and Class 4 locations and in piggable MCAs to
address the NTSB recommendation on this topic. As per the committee's
suggestion, PHMSA analyzed whether it would be feasible to make the
MAOP reconfirmation requirements applicable to non-HCA Class 3 and
Class 4 pipe operating below 30 percent SMYS. This analysis is
presented as an alternative in the RIA for this rulemaking. Ultimately,
PHMSA did not choose to include these categories of pipelines in the
scope for the applicability of the MAOP reconfirmation requirements
because the GPAC recommended it was cost-effective for the provision to
only apply to pipe operating above 30 percent SMYS in Class 3 and 4
locations and because those pipelines present the greatest risk to
safety.
---------------------------------------------------------------------------

    \66\ Pipeline Safety: Verification of Records; 77 FR 26822; May
7, 2012; https://www.govinfo.gov/content/FR-2012-05-07/pdf/2012-10866.pdf.
---------------------------------------------------------------------------

    With respect to the completion date, PHMSA acknowledges the
comments received stating that pipeline segments could meet
applicability criteria at some point in the future such that it would
be difficult or impossible to meet the 15-year deadline for completion.
Therefore, PHMSA agrees with the GPAC recommendation discussed above
and is modifying the requirements in this final rule to include an
alternative completion deadline of 4 years for pipeline segments that
meet the applicability standards at some point in the future, for
example for those pipeline segments that were in non-HCA locations that
later become HCA locations. However, PHMSA emphasizes that this 4-year
timeframe does not supersede, invalidate, or otherwise modify the
existing requirements in Sec.  192.611 for operators to confirm or
revise the MAOP of

segments within 24 months of a change in class location.
    PHMSA also acknowledges that some commenters thought the 15-year
compliance timeframe for MAOP reconfirmation was too long. PHMSA
believes a 15-year timeframe is necessary to be consistent with Sec.
192.939, which allows operators to use a confirmatory direct assessment
to confirm their MAOP in two, 7-year inspection cycles. This timeframe
was discussed by the GPAC and was approved by unanimous vote. PHMSA
will note that operators are required to have 50 percent of the
applicable mileage completed within 8 years of the effective date of
the rule. PHMSA would expect operators to prioritize and reconfirm the
MAOP of the highest-risk segments first.
    PHMSA is also withdrawing miscellaneous revisions to Sec.  192.503,
which tied general requirements of the subpart J pressure test to
alternative MAOP and MAOP reconfirmation provisions, and miscellaneous
revisions from Sec.  192.605(b)(5), which cross-referenced several
sections related to MAOP requirements to the requirements regarding an
operator's procedural manuals. These changes were made to simplify the
regulations.
    Additionally, because PHMSA has eliminated pipeline segments with
past in-service incident history from the scope of the MAOP
reconfirmation requirements, PHMSA is striking the proposed references
within the MAOP reconfirmation requirements to the alternative MAOP
requirements at Sec.  192.620(a)(ii). Operators who used the
alternative requirements to establish the MAOP of their pipelines were
required to have complete documentation \67\ and therefore would not be
subject to the MAOP reconfirmation requirements. If an operator had
previously established the MAOP of a pipeline segment under the
alternative MAOP requirements, but has since lost the records necessary
to validate the alternative, they would have to reconfirm MAOP using
the alternative MAOP requirements, or apply for a special permit to
continue operation.
---------------------------------------------------------------------------

    \67\ ``Pipeline Safety: Standards for Increasing the Maximum
Allowable Operating Pressure for Gas Transmission Pipelines; Final
Rule;'' October 17, 2008; 73 FR 62148. The effective date of the
rule was November 17, 2008.
---------------------------------------------------------------------------

    Per the requirement in section 23 of the 2011 Pipeline Safety Act,
PHMSA consulted with members of FERC and State regulators, including
representatives from NAPSR and the National Association of Regulatory
Utility Commissioners, as appropriate, to establish the timeframes for
completing MAOP reconfirmation. As a part of this consultation, which
occurred as a function of the GPAC meetings from 2017 through 2018,
PHMSA accounted for potential consequences to public safety and the
environment while also accounting for minimal costs and service
disruptions. These representatives provided both input and positive
votes that the provisions surrounding MAOP reconfirmation were
technically feasible, reasonable, cost-effective, and practicable if
certain changes were made. As previously discussed, PHMSA has taken the
GPAC's input into consideration when drafting this final rule and made
the according changes to the provisions.

B. MAOP Reconfirmation--Sec. Sec.  192.624 & 192.632

ii.--Methods

    In developing regulations to reconfirm MAOP where necessary,
Congress mandated that PHMSA consider safety testing methodologies that
include pressure testing and other alternative methods, including in-
line inspections, determined to be of equal or greater effectiveness.
The NTSB recommended an expansive pressure test approach to address the
safety issues identified in their investigation of the PG&E incident
through recommendations P-11-14 and P-11-15. In response to the
congressional mandate, PHMSA evaluated other methodologies and
identified five additional methods that could provide an equivalent or
greater level of safety. Therefore, PHMSA proposed to allow the
following six methods for MAOP reconfirmation, including the
conventional pressure test method.
Summary of PHMSA's Proposal: Method 1--Pressure Test
    A pressure test is the most conventional assessment method by which
an operator may reconfirm a pipeline segment's MAOP. PHMSA proposed
standards for conducting pressure tests for MAOP reconfirmation in part
to meet the intent of NTSB recommendations P-11-14 and P-11-15. First,
PHMSA proposed minimum test pressure standards where a pipeline
segment's MAOP would be equal to the test pressure divided by the
greater of either 1.25 or the applicable class location factor. Second,
if the pipeline segment might be susceptible to cracks or crack-like
defects,\68\ then the operator must incorporate a spike pressure
feature into the pressure test procedure. PHMSA proposed standards for
the spike hydrostatic test in Sec.  192.506. If the operator has reason
to believe any pipeline segment may be susceptible to cracks or crack-
like defects, the operator would be required to also estimate the
remaining life of the pipeline in accordance with the same standards
specified in Method 3, the engineering critical assessment method.
---------------------------------------------------------------------------

    \68\ These pipelines can include pipelines constructed with
``legacy pipe'' or using ``legacy construction techniques;''
pipelines with evidence or risk of stress corrosion cracking or
girth weld cracks; or pipelines that have experienced an incident
due to an original manufacturing-related defects, construction-
related defects, installation-related defects, or fabrication-
related defects.
---------------------------------------------------------------------------

Summary of Public Comment: Method 1--Pressure Test
    Several commenters opposed the proposed provisions requiring a
spike test to be conducted as part of the pressure test for the
purposes of MAOP reconfirmation, and these comments are discussed
further under the ``spike test'' portion of the proposal and comment
summary of this rulemaking.
    API suggested that a pipeline segment's MAOP can be best
established through performing a combination of pressure tests and ILI
examinations, and they discussed how operators could conduct
hydrostatic pressure testing to determine the in-place yield strength
of a segment of pipeline by conducting a ``spike'' test pressure held
for a few minutes followed by a subpart J pressure test approximately
10 percent below the spike level. API further stated that using ILI
tools in conjunction with this method would further substantiate the
results, as geometry ILI tools capable of measuring inside diameter to
detect yielding could further substantiate and quantify the results of
the pressure test.
    AGA stated that while they believe that pressure testing is a
straightforward and well-established method, the proposed Method 1 MAOP
reconfirmation requirements are unnecessarily complex. AGA further
stated that subpart J provides different requirements and
specifications for pressure tests based on the type of pipe being
tested, and that Method 1 should refer to subpart J rather than to
Sec.  192.505(c) specifically, which requires unnecessarily stringent
requirements. PG&E supported the proposed provisions and committed to
pressure testing all pipes.
    INGAA stated that since the basic strength properties of steel pipe
do not change over time, PHMSA should not limit allowable tests to only
those conducted after July 1, 1965, as was proposed in Sec.
192.619(a)(2)(ii). They emphasized that the test parameters, not

the test date, should be considered for MAOP reconfirmation. Further,
INGAA stated that recognizing the validity of earlier tests would not
necessarily mean that no further pressure tests would be conducted, as
periodic testing may be required to ensure the continued integrity of
the pipeline segment under the operator's integrity management program.
However, such additional tests are managed under IM, which is separate
from MAOP reconfirmation.
    Certain commenters stated that a spike test is not required to
establish an adequate margin of safety for MAOP reconfirmation and
suggested PHMSA eliminate spike testing from the pressure test method
of MAOP reconfirmation.
    Regarding the proposed definitions of ``legacy pipe'' and ``legacy
construction,'' AGA and Xcel Energy commented that as proposed, the
definitions could be interpreted to apply to distribution pipelines as
well as gas transmission pipelines. Commenters requested that PHMSA
explicitly exclude distribution pipelines from these definitions, which
would be applicable to all part 192.
    On March 26, 2018, the GPAC recommended that PHMSA delete the spike
test requirements from the pressure test method of MAOP reconfirmation.
The GPAC also recommended that PHMSA require operators to perform a
pressure test in accordance with subpart J of part 192 rather than
refer to specific requirements in Sec.  192.505. Further, and as
discussed during the meetings of December 2017 and March 26, 2018, if
the applicable pressure test segment does not have traceable,
verifiable, and complete MAOP records, the operator must use the best
available information upon which the MAOP is currently based to conduct
the pressure test. The GPAC recommended PHMSA create a requirement for
the operator of such a pipeline segment to add the test segment to its
plan for opportunistically verifying material properties in accordance
with the material properties verification provisions. During the
meeting, PHMSA noted that most pressure tests would present at least
two opportunities for material properties verification at the test
manifolds.
PHMSA Response: Method 1--Pressure Test
    PHMSA appreciates the information provided by the commenters
regarding the pressure test method of MAOP reconfirmation (Method 1).
After considering these comments and as recommended by the GPAC, PHMSA
is eliminating the spike testing requirement as part of the pressure
test method of MAOP reconfirmation. As commenters stated, spike testing
is primarily used for the mitigation of cracks and crack-like defects,
and PHMSA has determined it would therefore be more appropriate to be
placed within the context of threat management under IM. Additionally,
PHMSA is removing the definitions for and related references to
``legacy pipe'' and ``legacy construction'' in this final rule because
the applicability to pipe with ``legacy pipe or construction'' leaks or
failures was dropped from the applicability criteria for MAOP
reconfirmation. PHMSA also modified the rule to refer to subpart J
pressure tests rather than paragraph Sec.  192.505(c), specifically,
and to recognize the validity of earlier pressure tests. Lastly, if an
operator does not have traceable, verifiable, and complete records for
the material properties needed to establish MAOP by pressure testing,
PHMSA is requiring that operators test, in accordance with the material
verification requirements, the pipe materials cut out from the test
manifold sites at the time the pressure test is conducted. Further, if
there is a failure during the pressure test, the operator must test any
removed pipe from the pressure test failure in accordance with the
material properties verification requirements to ensure that the
segment of pipe is consistent with operator's sampling program
established under Sec.  192.607. This will avoid issues where operators
may not have the documented and verified physical pipeline material
properties and attributes that would otherwise be necessary to perform
a hydrostatic pressure test to reconfirm MAOP.
Summary of Proposal: Method 2--Pressure Reduction
    In the NPRM, PHMSA proposed that pipeline operators could choose to
reduce the MAOP of the applicable pipeline segment to reconfirm the
segment's MAOP. This approach would use the recent operating pressure
as a de facto pressure test, and then an operator would set the
pipeline segment's MAOP at a slightly lower pressure. PHMSA proposed
that operators using this method set the pipeline's MAOP to no greater
than the highest actual operating pressure sustained by the pipeline
during the 18 months preceding the effective date of the final rule
divided by the greater of either 1.25 or the applicable class location,
which are the same safety factors as used for the pressure testing in
Method 1. PHMSA included standards for establishing the highest actual
sustained pressure for the purposes of reconfirming MAOP under this
method and included standards for addressing class location changes.
Additionally, PHMSA proposed that, if the operator has reason to
believe any pipeline segment contains or may be susceptible to cracks
or crack-like defects, the operator would be required to estimate the
remaining life of the pipeline.
Summary of Public Comment: Method 2--Pressure Reduction
    AGA commented that the 18-month look-back time frame listed in the
pressure reduction MAOP reconfirmation method is a much too narrow time
frame for consideration and that the section should be rewritten to
clarify that the pressure reduction should be taken from either (1) the
immediate past 18 months, or (2) 5 years from the time the last
pressure reduction was taken, stating that tying the baseline pressure
to the effective date of the rule is arbitrary. Enterprise Products
recommended that PHMSA clarify the derating criteria used for pipes
that use this method of reconfirming MAOP. Further, Piedmont expressed
concern that this method does not account for the actual gap that can
occur between MAOP and operating pressure. Some commenters questioned
whether the MAOP from which to take a pressure reduction was based on
the most recent pressure test or the historical highest-pressure test,
and some commenters suggested PHMSA revise this provision to allow
operators to reconfirm the MAOP based on the existing MAOP and not
using an 18-month look-back period unless an incident caused by a
material-related or construction-related defect has occurred on the
pipeline since its last subpart J pressure test.
    TPA stated that using this method unfairly penalizes operators in
situations where the operator has prepared for future needs and has not
operated at MAOP for a period greater than 18 months. Similarly,
another commenter suggested that operators who have already reduced
MAOP on pipeline segments to be proactive should not be penalized by
having to take an additional reduction in MAOP.
    Some commenters recommended limiting the applicability of this
method to those pipelines operating at 30 percent SMYS or greater.
    Regarding the pressure reduction method for MAOP reconfirmation,
the GPAC recommended PHMSA increase the look-back period from 18 months
to 5 years and remove the requirements for operators selecting to take
the pressure reduction to reconfirm MAOP to

perform fracture mechanics analysis on those pipeline segments.
PHMSA Response: Method 2--Pressure Reduction
    PHMSA appreciates the information provided by the commenters
regarding the pressure reduction method of MAOP reconfirmation (Method
2). After considering these comments and as recommended by the GPAC,
PHMSA is increasing the look-back period to 5 years from the
publication date of the rule and is removing the requirements for
operators to perform fracture mechanics analysis on those pipeline
segments where the operator has selected Method 2. PHMSA made this
change because the 5-year look-back period is consistent with IM
requirements regarding MAOP confirmation.
Summary of PHMSA's Proposal: Method 3--Engineering Critical Assessment
    Method 3 directly addresses the congressional mandate for PHMSA to
consider safety testing methodologies that include other alternative
methods, including ILI, determined to be of equal or greater
effectiveness. Demonstrating that knowledge gained from an ILI
assessment provides an equivalent level of safety as a pressure test is
technically challenging. PHMSA used best safety practices gained from
implementation of integrity management since 2003; development of class
location special permits; and technical research on related topics,
such as analysis of crack defects and seam defects. PHMSA applied these
principles and analytical methods to develop an engineering critical
assessment (ECA) methodology, which applies state-of-the-art fracture
mechanics analysis to analyze defects in the pipe and determine if
those defects would or would not survive a hydrostatic pressure test at
the test pressure needed to establish MAOP. In addition, PHMSA proposed
that if the operator has reason to believe any pipeline segment
contains or may be susceptible to cracks or crack-like defects, the
operator would be required to estimate the remaining life of the
pipeline using the fracture mechanics standards PHMSA specified.
Summary of Public Comment: Method 3--Engineering Critical Assessment
    Several trade associations and pipeline industry entities stated
that ILI is the best and most practical method for MAOP reconfirmation
due to its cost-effectiveness and environmentally friendly nature, and
that PHMSA should allow operators to use ILI as a reconfirmation
method. These commenters, however, also stated that the requirements
proposed for the usage of ILI with an ECA are overly complicated and
burdensome, and they specifically recommended that the final rule
should be simplified so that this method will play a greater role in
MAOP reconfirmation in lieu of a pressure test. For example, INGAA
asserted that PHMSA should remove the requirements in the ECA related
to operations, maintenance, and integrity management, arguing that
these requirements do not factor into MAOP reconfirmation and would be
covered elsewhere in part 192. Further, INGAA proposed additional
alternatives for using the ECA method to obtain necessary data for MAOP
reconfirmation, asserting that these alternatives would be less
burdensome and equally effective. More specifically, INGAA suggested
removing duplicate regulatory language, removing the pre-approval
process for ILI, and adding unity plots as a method for operators to
demonstrate that ILI is reliable for identifying and sizing actionable
anomalies. TransCanada and PECO Energy Co. stated that for the ECA
method to be used by industry, the detailed requirements listed under
this method in the proposed rule should be replaced with the use of
standard ECA best practices.
    Some commenters suggested that operators have long relied on sound
engineering judgments and conservative assumptions to account for
record gaps. Commenters stated that, if stripped of the ability to use
sound engineering judgment and conservative assumptions, operators
would need to substantially invest in processes, procedures, tests, and
project engineering and support to develop and implement a
comprehensive material properties verification plan as outlined in the
proposed regulations. Another commenter asked for clarification on
using assumptions of Grade A pipe (30,000 psi) versus the use of 24,000
psi as noted in Sec.  192.107(b)(2) if the SMYS or actual material
yield strength and ultimate tensile strength is unknown or is not
documented in traceable, verifiable, and complete records.
    Another commenter suggested that in cases where a pipeline has been
pressure tested, but not to the level of 1.25 times MAOP, PHMSA should
allow operators to augment the original test with an ECA and other
analysis to reconfirm the pipeline segment's MAOP under method 3.
    The PST stated that there are certain cases in which the ECA method
should not be allowed as an alternative to pressure testing. Citing a
white paper prepared by Accufacts, Inc. on ECA methodology, the PST
recommended that PHMSA prohibit the use of the ECA method for
determining the strength of a pipeline segment in cases where there are
girth weld crack threats, significant stress corrosion cracking
threats, or dents with stress concentrator threats.
    During the GPAC meeting on March 27, 2018, the GPAC recommended
that PHMSA remove the fracture mechanics analysis for failure stress
and crack growth analysis requirements from the ECA method of MAOP
reconfirmation and move them to a stand-alone section in the
regulations. Further, the GPAC recommended that such a section should
not specify when, or for which pipeline segments, fracture mechanics
analysis would be required. The GPAC suggested that this new fracture
mechanics section outline a procedure by which operators perform
fracture mechanics analysis when required or allowed by other sections
of part 192, which was similar to its treatment of the proposed
material properties verification procedures at Sec.  192.607. Under the
GPAC's proposal, the ECA method for MAOP reconfirmation would not
contain any specific technical fracture mechanics requirements or
Charpy V-notch toughness values but would instead refer to the new
fracture mechanics section. Other recommendations related specifically
to the new fracture mechanics section are discussed in that area of the
proposal and comment summary section of this document.
    The GPAC also recommended PHMSA add a requirement to verify
material properties in accordance with the rule's material properties
verification provisions if the information needed to conduct a
successful ECA is not documented in traceable, verifiable, and complete
records.
PHMSA Response: Method 3--Engineering Critical Assessment
    PHMSA appreciates the information provided by the commenters
regarding the ECA method of MAOP reconfirmation (Method 3). As
recommended by the GPAC, PHMSA is removing the fracture mechanics
analysis requirements from the ECA method of MAOP reconfirmation and
moving them to a new stand-alone Sec.  192.712. PHMSA agrees this
change will improve comprehension of the regulations. This new section
does not specify when, or for which pipeline segments, fracture
mechanics analysis would be required but instead outlines a procedure
by which operators perform

fracture mechanics analysis when required by other sections of part
192. Section 192.712 is referenced in the pressure reduction, ECA, and
``other technology'' methods of MAOP reconfirmation under Sec.
192.624, as well as in Sec.  192.917 for cyclic fatigue loading.
Therefore, the ECA method for MAOP reconfirmation does not contain any
specific technical fracture mechanics requirements or Charpy V-notch
toughness values (full-size specimen, based on the lowest operational
temperature) but instead refers to the new Sec.  192.712. Comments
related to the assumptions an operator can use when material properties
are unknown are addressed in the discussion on Sec.  192.712 below.
PHMSA also added a requirement to verify material properties in
accordance with the rule's material properties verification provisions
at Sec.  192.607 if the information needed to conduct a successful ECA
is not documented in traceable, verifiable, and complete records.
    PHMSA disagrees that the additional analytical requirements, beyond
ILI, are overly complicated or burdensome. To conclude that an ECA is
of equal or greater effectiveness as a pressure test for the purposes
of MAOP reconfirmation, as mandated by Congress, more than an ILI and
repair program is required. A pressure test proves that any flaws in
the pipe are small enough to hold the test pressure without leaking.
Such subcritical flaws must be analyzed to prove that they would pass a
pressure test, even if the pressure test is not conducted. A fracture
mechanics analysis is capable of reliably drawing such conclusions but
must be carefully and capably performed. Such an analysis also requires
accurate data. In the absence of reliable data for key parameters, such
as fracture toughness, PHMSA allows the use of appropriately
conservative assumptions. This is discussed in more detail in the
sections below.
    Based on an ASME report and research sponsored by PHMSA,\69\ the
ECA analysis can be reliably used to ascertain if a pipeline segment
would pass a pressure test, even if it has seam weld cracking, and the
final rule includes requirements for conducting ILI using tools capable
of detecting girth weld cracks. The ECA must analyze any cracks or
crack-like defects remaining in the pipe, or that could remain in the
pipe, to determine the predicted failure pressure (PFP) of each defect.
---------------------------------------------------------------------------

    \69\ See: American Society of Mechanical Engineers (ASME)
Standards Technology Report ``Integrity Management of Stress
Corrosion Cracking in Gas Pipeline High Consequence Areas'' (STP-PT-
011), and ``Final Summary Report and Recommendations for the
Comprehensive Study to Understand Longitudinal ERW Seam Failures--
Phase 1'' (Task 4.5); https://primis.phmsa.dot.gov/matrix/PrjHome.rdm?prj=390.
---------------------------------------------------------------------------

    PHMSA also notes that the final rule addresses cases where a
pipeline has been pressure tested, but not to the level of 1.25 times
MAOP, by allowing operators to account for those test results and
augment the original test with an ECA, or conduct an ILI tool
assessment program to characterize defects remaining in the pipe along
with using an ECA to establish MAOP, to reconfirm the pipeline
segment's MAOP using Method 3. Detailed ILI requirements are addressed
in new Sec.  192.493, which is discussed in more detail below.
    PHMSA is moving the ECA process requirements in this final rule to
a new stand-alone Sec.  192.632. Section 192.624(c)(3) (ECA method of
MAOP reconfirmation) and the new Sec.  192.632 will cross-reference
each other. PHMSA decided to make this change when finalizing this
rulemaking only to improve the readability of the regulations. No
substantive changes were made to the requirements in connection with
this organizational change.
Summary of PHMSA's Proposal: Method 4--Pipe Replacement
    When reconfirming MAOP on certain pipeline segments, some operators
may face significant technical challenges or costs when performing
either a pressure test or an ILI examination, and it may be more
economically viable to replace the pipeline. Therefore, PHMSA proposed
to allow pipe replacement for operators to reconfirm their MAOP. In
such cases, the replacement pipeline would be designed, constructed,
and pressure tested according to current standards to establish MAOP.
Summary of Public Comment: Method 4--Pipe Replacement
    Commenters, including Mid-American Energy Company and Paiute
Pipeline, stated their support for this method. The GPAC similarly
supported this method and did not recommend any changes for this aspect
of MAOP reconfirmation.
PHMSA Response: Method 4--Pipe Replacement
    PHMSA appreciates the information provided by the commenters
regarding the pipe replacement method of MAOP reconfirmation (Method
4). After considering these comments and as recommended by the GPAC,
PHMSA is retaining the proposed rule text for Method 4 in the final
rule.
Summary of PHMSA's Proposal: Method 5--Pressure Reduction for Small,
Low-Pressure Pipelines
    For low-pressure, smaller-diameter pipeline segments with small
potential impact radii (PIR), PHMSA proposed an MAOP reconfirmation
method similar to the pressure reduction under Method 2. Operators of
pipeline segments for which (1) the MAOP is less than 30 percent SMYS,
(2) the PIR is less than or equal to 150 feet, (3) the nominal diameter
is equal to or less than 8 inches,\70\ and (4) which cannot be assessed
using ILI or a pressure test, may reconfirm the MAOP as the highest
actual operating pressure sustained by the pipeline segment 18 months
preceding the effective date of the final rule, divided by 1.1. In
addition to this pressure reduction, operators of these lines would be
required to perform external corrosion direct assessments in accordance
with the IM provisions, develop and implement procedures to evaluate
and mitigate any cracking defects, conduct a specified number of line
patrols at certain intervals, conduct periodic leak surveys, and
odorize the gas transported in the pipeline segment.
---------------------------------------------------------------------------

    \70\ 8.625 inches actual diameter.
---------------------------------------------------------------------------

Summary of Public Comment: Method 5--Pressure Reduction for Small, Low-
Pressure Pipelines
    AGA stated that PHMSA did not provide enough justification for
imposing the additional pressure reduction requirements listed under
this method, asserting that this method should require either a 10
percent pressure reduction or the implementation of additional
preventative actions that are feasible and practical, but not both. TPA
stated that the 18-month criterion penalizes operators who may have
operated pipelines at lower capacities to anticipate future needs.
Furthermore, TPA urged PHMSA to limit the requirements for MAOP
reconfirmation under Method 5 to the reduction in MAOP and not impose
additional safety requirements, stating that these pipelines are
generally considered low-stress pipelines and that their risk of
rupture is very low. Similarly, API stated that the proposed
requirements for odorization and frequent instrumented leak surveys are
impractical. Some commenters felt that the terms for small potential
impact radius and the applicable diameters should be defined.

    On March 27, 2018, the GPAC recommended PHMSA delete the size and
pressure criteria of this method and base the applicability solely on a
potential impact radius of less than or equal to 150 feet. The GPAC
also recommended increasing the look-back period to 5 years from 18
months. Further, the GPAC recommended PHMSA strike the additional
requirements in this method related to external corrosion direct
assessment, crack analysis, gas odorization, and fracture mechanics
analysis. They also recommended PHMSA change the frequency of patrols
and surveys to 4 times a year for Class 1 and Class 2 locations, and 6
times per year for Class 3 and Class 4 locations.
PHMSA Response: Method 5--Pressure Reduction for Small, Low-Pressure
Pipelines
    PHMSA appreciates the information provided by the commenters
regarding the pressure reduction method of MAOP reconfirmation for
small, low-pressure pipelines (Method 5). After considering these
comments and as recommended by the GPAC, PHMSA is deleting the pipeline
segment size and pressure criteria of this method and basing the
applicability solely on a potential impact radius of less than or equal
to 150 feet. PHMSA believes this change streamlines the regulations
while maintaining pipeline safety. PHMSA is increasing the look-back
period to 5 years, which is consistent with other sections of part 192,
including integrity management. Additionally, PHMSA is deleting the
requirements in this method related to external corrosion direct
assessment, crack analysis, gas odorization, and fracture mechanics
analysis. PHMSA is also changing the frequency of patrols and surveys
to 4 times a year for Class 1 and Class 2 locations, and 6 times per
year for Class 3 and Class 4 locations. PHMSA believes these changes
increase regulatory flexibility while maintaining pipeline safety.
Summary of Proposal: Method 6--Alternative Technology
    PHMSA proposed that operators may use an alternative technical
evaluation process that provides a documented engineering analysis for
the purposes of MAOP reconfirmation. If an operator elects to use an
alternative method for MAOP reconfirmation, it would have to notify
PHMSA and provide a detailed fracture mechanics analysis--including the
safety factors--to justify the establishment of the MAOP using the
proposed alternative method. The notification would have to demonstrate
that the proposed alternative method would provide an equivalent or
greater level of safety than a pressure test. PHMSA included this
option to allow and encourage the continual research and development
needed to improve state-of-the-art fracture mechanics analysis,
integrity assessment methods, advances in metallurgical engineering,
and new techniques.
Summary of Public Comment: Method 6--Alternative Technology
    For the alternative technologies method of MAOP reconfirmation,
several stakeholders opposed the timeframes, case-by-case approval
process, and procedural barriers PHMSA proposed for using this method.
Several commenters, including Cheniere Energy, Delmarva Power & Light,
and INGAA, suggested that the procedural hurdles required by the
proposed provisions would make this option difficult for operators to
use for MAOP reconfirmation as well as for any other provisions PHMSA
allows alternative technology use with notification. More specifically,
these commenters suggested that a process whereby PHMSA could object to
the use of an alternative technology at any time during a project's
lifecycle does not provide the level of certainty necessary for
operators to move forward with using alternative technologies. That
uncertainty would deter the development of what could be better or
safer alternatives.
    Piedmont stated that it does not believe that the role of PHMSA
includes determining the appropriate technologies to be used to
reconfirm MAOP. Piedmont further stated that currently under subpart O,
operators are required to obtain approval from PHMSA to use alternative
technologies for integrity assessment, and that operators have waited
more than 180 days for PHMSA to respond to these requests. Piedmont
stated that this uncertainty cannot be reconciled with the planning and
business considerations that an operator must consider when evaluating
how to invest in technology and which methods to use for establishing
MAOP. The PST stated that the approval process should be similar to the
process used for special permits and that before these methods are
approved by PHMSA, they should be subject to public review and comment
under the National Environmental Policy Act of 1969 (NEPA).
    At the meeting on March 27, 2018, the GPAC recommended PHMSA
incorporate the 90-day notification and objection procedure for the use
of alternative technology. To summarize, operators would have to notify
PHMSA of its intent to use other technology, and PHMSA would have 90
days to respond with an objection if PHMSA had one, or a need for more
review time. Otherwise, the operator would be free to use the proposed
method or technology.
PHMSA Response: Method 6--Alternative Technology
    PHMSA appreciates the information provided by the commenters
regarding the other technology method of MAOP reconfirmation (Method
6). After considering these comments and as recommended by the GPAC,
PHMSA is modifying the rule to incorporate the 90-day notification and
objection procedure the committee recommended. Operators would have to
notify PHMSA of its intent to use other technology to reconfirm MAOP in
accordance with Sec.  192.18, and PHMSA would have 90 days to respond
with an objection if PHMSA had one or a notice that PHMSA required more
time for its review, which would extend the timeframe. Without a notice
of objection or additional review by PHMSA, the operator would be
allowed to use the alternative technology. PHMSA has successfully
applied the notification process to other technology assessments under
subpart O since its inception and does not believe a special permit
process is warranted for every notification for alternative technology.
PHMSA believes the changes made in the final rule will address the
concerns about timeliness of notification reviews by PHMSA.

B. MAOP Reconfirmation--Sec.  192.624

iii.--Spike Test

1. Summary of PHMSA's Proposal
    The ``spike'' hydrostatic pressure test is a special feature of the
pressure testing method of MAOP reconfirmation. PHMSA intends this
aspect of the MAOP reconfirmation process to address the intent of NTSB
recommendations P-11-14 (related to spike testing for grandfathered
pipe) and P-11-15 (related to pressure testing to show that
manufacturing and construction-related defects are stable).
    PHMSA proposed that a spike test would be required for cases where
a pipeline segment might be susceptible to cracks or crack-like
defects. Such pipe may include ``legacy pipe;'' pipe constructed using
``legacy'' construction techniques; pipelines that have experienced an
incident due to an original manufacturing-related defect, a
construction-, installation-, or fabrication-related defect; or pipe
with

stress corrosion cracking or girth weld cracks. Cracks and crack-like
defects in some cases may be susceptible to a phenomenon called
``pressure reversal,'' which is the failure of a defect at a pressure
less than a pressure level that the flaw has previously experienced and
survived. The increased stress from the test pressure may cause latent
cracks that are almost, but not quite, large enough to fail to grow
during the test. If the crack does not fail before the test is
completed, the resultant crack that remains in the pipe may be large
enough to no longer be able to pass another pressure test. The spike
portion of the pressure test is designed to cause such marginal crack
defects to fail during the early, spike phase of the pressure test. The
post-spike, long-duration test pressure validates the operational
strength of the pipe. Using a short-duration, very high spike pressure
followed by a long-duration integrity verification pressure provides
greater assurance that the test is not ``growing cracks'' that could
fail in-service after the test is completed. PHMSA proposed standards
for the spike hydrostatic test in Sec.  192.506. PHMSA used several
technical reports and studies, including PHMSA-sponsored research, to
inform the standards proposed for the spike test. Those materials
include, American Society of Mechanical Engineers Standards Technology
Report ``Integrity Management of Stress Corrosion Cracking in Gas
Pipeline High Consequence Areas'' (STP-PT-011), and ``Final Summary
Report and Recommendations for the Comprehensive Study to Understand
Longitudinal ERW Seam Failures--Phase 1'' (Task 4.5).\71\
---------------------------------------------------------------------------

    \71\ https://primis.phmsa.dot.gov/matrix/PrjHome.rdm?prj=390.
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2. Summary of Public Comment
    Some commenters supported the concept of requiring the use of a
spike hydrostatic pressure test as part of the MAOP reconfirmation
process for establishing MAOP but expressed concern over specific
aspects of the provision. For example, AGA urged PHMSA to allow
pneumatic pressure tests as well as hydrostatic pressure tests. In
addition, AGA disagreed with the allotted test duration provided in the
proposal. Similarly, other operators who commented, such as CenterPoint
Energy and Dominion East Ohio, stated that the proposed spike test
target hold pressure of 30 minutes exceeds the time needed to determine
the mechanical integrity of the pipeline test segment and will cause
pre-existing crack-like defects to grow. Alternatively, Dominion
Transmission, Tallgrass Energy Partners, SoCalGas, and Paiute Pipelines
stated that a test level of 100 percent SMYS, not 105 percent SMYS,
would be sufficient to remediate cracking threats. Enterprise Products
stated that the requirements for the design of a spike test should be
based on integrity science, such as fatigue life and reassessment
intervals, and suggested PHMSA's proposed spike test pressure limits
were set at an arbitrary level. Enterprise further stated that the
utility of stressing a pipe beyond 100 percent of its yield strength is
questionable and potentially damages the pipe. Other commenters,
including MidAmerican Energy Co., requested that pneumatic spike tests
to 1.5 times MAOP be allowed when the resultant pressure complies with
the limitations stated in the table in Sec.  192.503(c).
    Trade associations and pipeline industry entities, including INGAA,
GPA, and TPA, asserted that PHMSA should eliminate the spike test
requirement for establishing MAOP entirely. These commenters stated
that the proposed provisions went beyond what was required to reconfirm
MAOP for an accepted margin of safety. These commenters further
asserted that spike testing is not an appropriate technique for MAOP
reconfirmation, and it could result in unintended negative consequences
without improving pipeline safety. They stated that spike testing is an
aggressive and destructive technique that should be used only in cases
in which time-dependent threats, such as a significant risk of stress
corrosion cracking, exist.
    INGAA and other commenters agreed with PHMSA that the use of spike
hydrostatic testing is appropriate for time-dependent threats, such as
stress corrosion cracking. INGAA, however, suggested changes to the
proposed spike hydrostatic pressure test provisions and the cross-
reference to those provisions in the proposed IM assessment method
revisions to limit the spike testing requirement to time-dependent
threats, to test to a minimum of 100 percent SMYS instead of 105
percent, and to provide an alternative for use of an instrumented leak
survey. INGAA agreed that spike testing is the best means of testing a
pipeline with a history of environmental cracking, such as stress
corrosion cracking that has developed while a pipeline is in service,
and noted that a spike test may be of value for in-service pipelines
where metallurgical fatigue is of concern. INGAA further stated that
pressure cycling should not need to be included in the proposed spike
test provisions and that PHMSA should amend the proposed rule to limit
spike testing only to those pipeline segments with stress corrosion
cracking.
    An additional commenter suggested PHMSA should allow operators to
use the short-duration spike portion of a spike pressure test to
determine the lower bound of the yield strength of the test section,
including all pipe and components that are subjected to the test
pressure. Such a test, if used for this purpose, must also confirm that
yielding beyond that experienced in a standard tensile test to
determine yield strength, typically on the order of 0.5 percent, has
not occurred. This confirmation may be demonstrated by data from a
pressure-volume plot of the test or a post-test geometry tool in-line
inspection.
    Public interest and other groups, including Pipeline Safety
Coalition, Environmental Defense Fund (EDF), and NAPSR, expressed
support for spike testing, stating that it would provide for increased
pipeline safety. NAPSR further stated that the option of applying to
use alternative technology or an alternative technological evaluation
process would allow for some flexibility in cases in which a
hydrostatic test is impractical. EDF also suggested additional measures
to mitigate emissions from methane gas lost during testing.
    At the GPAC meeting on March 2, 2018, the GPAC recommended that
PHMSA revise the spike test requirements to change the minimum spike
pressure to the lesser of 100 percent SMYS or 1.5 times MAOP, reduce
the spike hold time to a minimum of 15 minutes after the spike pressure
stabilizes, revise the applicable language to refer specifically to
``time-dependent'' cracking, incorporate the 90-day notification and
objection procedure discussed for other sections, and adjust the SME
requirements by adding language describing a ``qualified technical
subject matter expert'' where applicable.
3. PHMSA Response
    PHMSA appreciates the information provided by the commenters
regarding the requirements for spike pressure testing. After
considering these comments and as recommended by the GPAC, PHMSA is
modifying the rule to change the minimum spike pressure to the lesser
of 100 percent SMYS or 1.5 times MAOP, as PHMSA believes these
pressures are sufficient to maintain pipeline safety. PHMSA is
specifying a spike hold time of a minimum of 15 minutes after the spike
pressure stabilizes, rather than a 30-minute overall hold time, to be
consistent with pipeline safety. Additionally, PHMSA is

modifying the rule to revise the applicable language to refer
specifically to ``time-dependent'' cracking, incorporate the same
notification procedure under Sec.  192.18 with the 90-day timeframe for
objections or requests for more review time, and adjust the SME
requirements by using broader language describing a ``qualified
technical subject matter expert'' where applicable instead of
specifying technical fields of expertise such as metallurgy or fracture
mechanics. PHMSA believes these changes increase regulatory flexibility
while maintaining pipeline safety.
    In addition, as stated above, the spike test is being removed from
the MAOP reconfirmation requirements. The spike test procedure in the
new Sec.  192.506 would be used whenever required by other requirements
in part 192 to address crack remediation and the integrity threat of
cracks and crack-like defects.
    PHMSA disagrees with allowing pneumatic spike tests to 1.5 times
MAOP based on safety concerns. Pneumatic pressure tests are allowed in
Sec.  192.503(c), with certain limitations, for new, relocated, or
replaced pipe. For new, relocated, or replaced pipe, there is knowledge
that the pipe is likely sound and is usually manufactured with recent
mill pressure tests to confirm the pipe meets applicable standards. A
spike test to perform an integrity assessment on in-situ pipe with
known or suspected cracks or crack-like defects presents a much higher
likelihood of the pipeline segment experiencing a leak or rupture
during the test with resultant consequences, including the possibility
of fire or explosion. PHMSA notes that conducting a pneumatic test
using a compressible gas, such as air, nitrogen, or methane, would be a
safety concern for the public and operating personnel. Gas that is
highly compressed has stored energy that would be suddenly released
should there be a flaw in the pipe. Liquids, such as water, do not have
the stored energy release that a compressible gas has should the pipe
have a flaw that either leaks or ruptures. Therefore, the safety risk
of performing a hydrostatic pressure test (with water) is much lower
due to the less-compressible nature of liquids. Compressed gas would be
a fire or explosion hazard to the public. However, as specified in the
proposed and final rules, operators that desire to use a pneumatic
spike test may propose using such a test, with justification, by
submitting a notification to PHMSA.

B. MAOP Reconfirmation--Sec.  192.624

iv.--Fracture Mechanics

1. Summary of PHMSA's Proposal
    In the proposal, PHMSA determined that fracture mechanics analysis
is a key aspect of meeting the congressional mandate to consider safety
testing methodologies for MAOP reconfirmation of equal or greater
effectiveness as a pressure test, including other alternative methods
such as ILI. Demonstrating that knowledge gained from an ILI assessment
provides an equivalent level of safety as a pressure test is
technically challenging. An ILI assessment might reveal the presence of
crack flaws and crack-like defects and characterize them within the
accuracy of tool performance capabilities, but determining whether
those cracks would survive a pressure test to reconfirm MAOP requires
very in-depth and highly technical analysis. Such an analysis not only
requires an accurate characterization of cracks, it also requires
accurate and known metallurgical properties of the pipe. To address
these aspects, PHMSA proposed more detailed requirements in Sec.
192.921 for evaluating defects discovered during ILI to account for
tool accuracy and other factors to accurately characterize flaw
dimensions and support accurate fracture mechanics analysis. In
addition, the material properties verification and documentation
requirements PHMSA proposed are critical to performing fracture
mechanics analysis of ILI-discovered defects that would be accurate
enough to establish MAOP in a way that is demonstrably equivalent in
safety to a pressure test. In the MAOP reconfirmation provisions, PHMSA
proposed new requirements for fracture mechanics analysis for failure
stress and cracks, listing specific requirements, standards, and data
operators must use when performing a fracture mechanics analysis.
2. Summary of Public Comment
    Most industry stakeholders were opposed to the proposed fracture
mechanics requirements. AGA, New Mexico Gas Co., and TPA suggested that
fracture mechanics have a limited place in preventing pipeline failures
or predicting them accurately and should not be a component of MAOP
reconfirmation. AGA stated that the rule should not prescriptively
require fracture mechanics calculations to be performed for a broad
range of applications but should be narrowed to include only
transmission pipelines operating at a hoop stress greater than 30
percent SMYS, given that pipelines that operate below 30 percent SMYS
have a strong tendency to leak rather than rupture.
    Commenters also stated that requiring fracture mechanics as any
part of the MAOP reconfirmation process was overly burdensome and
unclear. Specifically, API stated that some of the requirements listed
under the MAOP reconfirmation requirements were overly conservative and
burdensome for most situations where this technique would be used. For
instance, a commenter noted that there is no non-destructive evaluation
(NDE) methodology for obtaining Charpy V-notch toughness values.
Therefore, PHMSA's requirement to obtain Charpy V-notch toughness
values eliminates the availability of non-destructive testing. Further,
a commenter noted that the proposed ECA analysis prescribed a body
toughness of 5-ft.-lbs. and a seam toughness of 1-ft.-lbs., which are
arbitrary and very conservative. Vintage pipelines will not have Charpy
V-notch toughness data, and requiring an overly conservative assumption
of toughness is not reasonable. Toughness can vary depending on the
manufacturer, the manufacturing method, and the pipe vintage, and it
should not be prescribed in the regulations. The commenter further
noted that using the conservative defaults, especially the overly
conservative defaults PHMSA proposed, may result in an unacceptably
short remaining life of the pipeline.
    Similarly, commenters recommended PHMSA allow alternative methods
of assessing strength properties that provide a suitable lower bound to
the actual strengths. Allowing alternative methods will provide
flexibility to consider conservative, but realistic, estimates of
material properties. Commenters also stated that SMEs in both
metallurgy and fracture mechanics are not needed to validate non-
destructive test (NDT) methods. Engineers with knowledge in test
validation methods but not necessarily metallurgy and fracture
mechanics are capable of validating NDT methods.
    More broadly, Energy Transfer Partners suggested that the proposed
language for fracture mechanics is misplaced in MAOP reconfirmation and
should be moved to the proposed requirements for non-HCA assessments,
or elsewhere, since this text more closely resembles an ``assessment.''
Other commenters agreed with that concept, suggesting fracture
mechanics is more appropriate under the IM measures for threat
mitigation rather than for MAOP reconfirmation.
    As previously discussed in this document, the GPAC recommended

PHMSA move the fracture mechanics analysis requirements out of the ECA
method of MAOP reconfirmation and into a new stand-alone section in the
regulations, making it a process for performing fracture mechanics
analysis whenever required or allowed by part 192. The committee
therefore recommended that PHMSA delete any cross-references to the
MAOP reconfirmation and the spike pressure test provisions. The GPAC
also recommended that operators make and retain specific records to
document fracture mechanics analyses performed.
    Along with moving the fracture mechanics analysis requirements to a
stand-alone section, the GPAC had several specific recommendations
related to how the requirements would function. The GPAC recommended
PHMSA remove ILI tool performance specifications and replace them with
a requirement for operators to verify tool performance using unity
plots or equivalent technologies, and also recommended revisions to the
fracture mechanics requirements by striking the sensitivity analysis
requirements and replacing them with a requirement for operators to
account for model inaccuracies and tolerances.
    As it pertains to the Charpy V-notch toughness values (full-size
specimen, based on the lowest operational temperatures) used in
fracture mechanics analysis, the GPAC recommended that operators could
use a conservative Charpy V-notch toughness value based on the sampling
requirements of the material properties verification provisions or use
Charpy V-notch toughness values from similar-vintage pipe until the
actual properties are obtained through the operator's opportunistic
testing program. The GPAC recommended that PHMSA clarify that default
Charpy V-notch toughness values of 13-ft.-lbs. for pipe body and 4-ft.-
lbs. for pipe seam only apply to pipe with suspected low-toughness
properties or unknown toughness properties. Further, if a pipeline
segment has a history of leaks or failures due to cracks, the GPAC
recommended PHMSA require the operator to work diligently to obtain any
unknown toughness data. In the interim, operators of such pipeline
segments must use Charpy V-notch toughness values of 5-ft.-lbs. for
pipe body and 1-ft.-lbs. for pipe seam. The GPAC also recommended PHMSA
include a 90-day notification procedure similar to the previously
agreed-upon procedure if operators wanted to request the use of
differing Charpy V-notch toughness values.
3. PHMSA Response
    PHMSA appreciates the information provided by the commenters
regarding the proposed fracture mechanics requirements. After
considering these comments and as recommended by the GPAC, PHMSA is
moving the fracture mechanics analysis requirements out of the ECA
method of MAOP reconfirmation and into a new stand-alone Sec.  192.712
in the regulations, making it a process by which operators must perform
fracture mechanics analysis whenever required by part 192. This change
was made to increase the readability of the regulations. As a part of
making these provisions into a stand-alone section in the regulations,
PHMSA is also deleting the references within Sec.  192.712 to the MAOP
reconfirmation and the spike pressure test provisions. PHMSA is adding
a requirement for operators to make and retain specific records
documenting any fracture mechanics analyses performed. PHMSA is also
removing ILI tool performance specifications and sensitivity analysis
requirements and replacing them with a requirement for operators to
verify tool performance using unity plots or equivalent technologies
and to account for model inaccuracies and tolerances. This change will
increase regulatory flexibility while maintaining pipeline safety.
    Regarding the default Charpy V-notch toughness values (full-size
specimen, based on the lowest operational temperatures) used in
fracture mechanics analysis when actual values are not known, industry
and the GPAC had significant comments. PHMSA is aware of pipe
manufactured per API Specification 5L in this decade (2010-2019) with
Charpy V-notch toughness values for the weld seam as low as 1-ft. lbs.
that has been used in gas transmission pipelines. Furthermore, API 5L
does not contain required minimum Charpy V-notch toughness values for
the weld seam.
    A single default assumed toughness value might be inappropriate or
overly conservative under some circumstances, or it might be a proper
choice under other circumstances. To address this issue in this final
rule, PHMSA is allowing the use of: (1) Charpy V-notch toughness values
(full-size specimen, based on the lowest operational temperatures) from
the same vintage and the same steel pipe manufacturers with known
properties; (2) a conservative Charpy V-notch toughness value to
determine the toughness based upon the ongoing material properties
verification process specified in Sec.  192.607; (3) maximum Charpy V-
notch toughness values of 13.0 ft.-lbs. for body cracks and 4.0 ft.-
lbs. for cold weld, lack of fusion, and selective seam weld corrosion
defects if the pipeline segment does not have a history of reportable
incidents caused by cracking or crack-like defects; (4) maximum Charpy
V-notch toughness values of 5.0 ft.-lbs. for body cracks and 1.0 ft.-
lbs. for cold weld, lack of fusion, and selective seam weld corrosion
if the pipeline segment has a history of reportable incidents caused by
cracking or crack-like defects; or (5) other appropriate Charpy V-notch
toughness values that an operator demonstrates can provide conservative
Charpy V-notch toughness values for the analysis of the crack-related
conditions of the line pipe upon submittal of a notification to PHMSA.
These modifications will provide flexibility to operators for
considering conservative but realistic estimates of material
properties.
    PHMSA is also clarifying that operators do not need to use distinct
metallurgy and fracture mechanics subject matter experts to review
fracture mechanics analyses. In this final rule, PHMSA is replacing
that requirement with a general requirement stating that fracture
mechanics analyses must be reviewed and confirmed by a qualified
subject matter expert. PHMSA expects a qualified subject matter expert
to be an individual with formal or on-the-job technical training in the
technical or operational area being analyzed, evaluated, or assessed.
The operator must be able to document that the individual is
appropriately knowledgeable and experienced in the subject being
assessed.

B. MAOP Reconfirmation--Sec.  192.624

v.--Legacy Construction Techniques/Legacy Pipe

1. Summary of PHMSA's Proposal
    PHMSA proposed to add a definition to part 192 for ``legacy
construction techniques,'' which defined historical practices used to
construct or repair transmission pipeline segments that are no longer
recognized as acceptable. In addition, PHMSA proposed a definition for
``legacy pipe'' that is defined by the presence of specific legacy
manufacturing, welding, and joining techniques.
2. Summary of Public Comment
    AGA expressed significant concerns with the proposed definitions of
legacy pipe and legacy construction techniques for the purposes of part
192, commenting that PHMSA should eliminate the use of the terms
entirely or otherwise revise these definitions to

exclude currently acceptable manufacturing and construction techniques.
AGA stated if PHMSA were to codify the definitions of legacy pipe and
legacy construction techniques, then PHMSA should limit its catch-all
provisions within the language of the definitions to pipes with a
longitudinal joint factor of less than 1.0. Doing so would ultimately
include pipes with unknown joint factors, as Sec.  192.113 requires a
default longitudinal joint factor of 0.80 for any pipe with an unknown
longitudinal joint factor. Similarly, AGL Resources, Alliant Energy,
Atmos Energy, and TECO Peoples Gas supported AGA's suggested revisions
to the definitions of legacy construction techniques and legacy pipe.
API commented that PHMSA's proposed definition of legacy construction
technique inappropriately includes the repair technique of puddle welds
and recommended PHMSA clarify the definitions of wrought iron and pipe
made from Bessemer steel. Dominion Transmission commented there may be
instances where the longitudinal seam for modern day pipe is unknown,
yet the pipe is not a high-risk seam type. They stated that such pipe
does not present an integrity threat and should be excluded from the
``legacy pipe'' definition.
    Gas Piping Technology Committee commented that the proposed
definition of legacy construction techniques seems to contain some
erroneous information. They asserted that the proposed definition went
too far by implying that all the listed methods are no longer used to
construct or repair pipelines, stating that while wrinkle bends may no
longer be a common construction technique, they are still allowed under
Sec.  192.315 for steel pipe operating at a pressure producing a hoop
stress of less than 30 percent of SMYS. Similarly, Oleksa and
Associates commented that some operators are still installing Dresser
couplings.
    The Michigan Public Service Commission staff suggested that PHMSA
add to the definition of ``legacy construction techniques'' a
subsection that addresses other legacy construction techniques that are
not in the current list and include within this subsection language
referencing ``all other'' techniques. Northern Natural Gas proposed
PHMSA eliminate the phrase ``including any of the following
techniques'' from the definition of legacy construction techniques as
it implies the list is not complete. They suggested that the definition
of legacy pipe should differentiate between ductile and brittle pipe by
toughness values in both the seam and the pipe body. Lastly, SoCalGas
thought it would be more appropriate to reference these definitions
under the IM regulations in subpart O instead of defining the terms in
the context of the entire part.
    These definitions were taken up by the GPAC in the context of the
scope of MAOP reconfirmation, and they recommended in the meeting on
March 26, 2018, that the definitions be withdrawn. Because the GPAC
recommended to revise the scope of MAOP confirmation to not include
pipelines with previous reportable incidents due to crack defects,
these definitions would no longer be needed in the rule.
3. PHMSA Response
    PHMSA appreciates the information provided by the commenters
regarding the proposed definitions for ``legacy pipe'' and ``legacy
construction techniques.'' After considering these comments and as
recommended by the GPAC, PHMSA is withdrawing these definitions from
the final rule. Because the revised scope of MAOP confirmation
requirements, discussed in the previous sections, no longer includes
pipelines with previous reportable incidents due to crack defects,
these definitions are no longer necessary.

C. Seismicity and Other Integrity Management Clarifications--Sec.
192.917

1. Summary of PHMSA's Proposal
    Subpart O of 49 CFR part 192 prescribes requirements for managing
pipeline integrity in HCAs. It requires operators of covered segments
to identify potential threats to pipeline integrity and use that threat
identification in their integrity programs. Included within this
process are requirements to identify threats to which the pipeline is
susceptible, collect data for analysis, and perform a risk assessment.
Special requirements are included to address particular threats such as
third-party damage and manufacturing and construction defects.
    Following the PG&E incident, the NTSB recommended that PG&E
evaluate every aspect of its IM program, paying particular attention to
the areas identified in the incident investigation, and implement a
revised IM program. PHMSA held a workshop on July 21, 2011, to address
perceived shortcomings in the implementation of IM risk assessment
processes and the information and data analysis (including records)
upon which such risk assessments are based. PHMSA also sought input
from stakeholders on these issues in the ANPRM.
    Section 29 of the 2011 Pipeline Safety Act requires that operators
consider the seismicity of the geographic area in identifying and
evaluating all potential threats to each pipeline segment, pursuant to
49 CFR part 192. Pipeline threat analysis is addressed as one program
element in the IM regulations in subpart O. Addressing seismicity is
already implicitly required by Sec.  192.917 as part of addressing
outside force threat through the incorporation by reference of ASME
B31.8S. Based on the direction of the mandate, PHMSA proposed to
explicitly require that operators analyze seismicity and related
geotechnical hazards, such as geology and soil stability, as part of
the threat identification IM program element and mitigate those threats
of outside force damage. PHMSA determined this would clarify
expectations for this requirement and explicitly implement section 29
of the 2011 Pipeline Safety Act.
    PHMSA also proposed revisions to Sec.  192.917(e) to clarify that
certain pipe designs must be pressure tested to assume that seam flaws
are stable and that failures or changes to operating pressures that
could affect seam stability are evaluated using fracture mechanics
analysis.
2. Summary of Public Comment
    There was broad support for explicitly requiring the consideration
of the seismicity of a geographic area when identifying and evaluating
all potential threats to a pipeline segment, and several stakeholders
suggested minor revisions to the proposal. California Public Utilities
Commission (CPUC) supported the proposed provisions and recommended
adding text that would require consideration of any significant
localized threat that could affect the integrity of the pipeline. CPUC
further commented that operating conditions on the pipeline must also
be a factor when operators identify local threats.
    Some commenters, including PG&E and NGA, requested further
clarification regarding what would constitute a seismic event for the
purposes of identifying threats under the IM program for compliance
purposes. AGA requested clarification on the requirements regarding
whether operators are expected to conduct a one-time investigation on
the risk of seismicity and geology, or if there is an expectation of a
periodic requirement for re-investigation.
    Multiple commenters disagreed with the proposed requirement in
Sec.  192.917(e) for operators to perform annual cyclic fatigue
analyses if an operator identifies cyclic fatigue as a threat. INGAA
and National Fuel

suggested that cyclic fatigue is an uncommon risk for natural gas
pipelines and asserted that PHMSA did not provided significant
technical justification for this analysis requirement. Some commenters
suggested that the proposal to address cyclic fatigue and require
pressure tests on seam threats is an overcompensation for the level of
risk the threats present. Trade associations and pipeline industries
proposed several alternative requirements for the conditions under
which cyclic fatigue analyses should be required. API stated that they
did not object to the measures listed, but the proposed provisions in
Sec.  192.935(b)(2) imply that an operator must take all the actions
listed. API asserted that PHMSA should modify this proposed provision
to state that operators must consider taking the actions listed but
would not be specifically required to take all of them. Other
commenters expressed concern that these proposed requirements conflict
with the proposed requirements for pipeline segments needing to
undertake MAOP reconfirmation because they experienced an incident due
to manufacturing and construction (M&C) defects. Specifically, the
requirements under Sec.  192.917(e)(3) only allow operators to consider
M&C defects stable if they have been subjected to a hydrostatic
pressure test of 1.25 times MAOP, which would seemingly disallow or
otherwise make fruitless the other methods of MAOP reconfirmation for
these types of pipeline segments.
    At the GPAC meeting on January 12, 2017, the GPAC recommended that
no changes should be made to the proposed provisions on seismicity.
    Regarding Sec.  192.917(e)(2), which was discussed during the
meeting on June 6-7, 2017, the GPAC noted that, under this provision,
operators should be monitoring for condition changes that would cause
the threat to potentially activate, and those condition changes should
be what triggers a reassessment. The GPAC also noted problems with a
suggested revision of performing a cyclic fatigue analysis within a 7-
calendar-year period to match certain IM requirements because it would
then impose a hard deadline on the continuous monitoring process and
would prompt operators to act and again study cyclic fatigue even if
the monitoring showed no evidence of cyclic fatigue being a threat. At
the meeting, PHMSA suggested that operators could ensure the data
involved in a cyclic fatigue analysis is periodically verified within a
period not exceeding 7 years to align with IM requirements, but
operators would only be required to perform a full evaluation if the
data has changed. Following that discussion, the GPAC recommended
revising the proposed requirements for cyclic fatigue at Sec.  192.917
based on the discussion of GPAC members and considering PHMSA's
proposed language that was presented at the meeting.
    At the GPAC meeting on March 26-28, 2018, a public commenter
suggested PHMSA remove the word ``hydrostatic'' from the requirements
for considering M&C-related defects stable because any strength test
that is approved in subpart J should qualify. Further, that public
commenter suggested adding language where a pressure reduction or an
ILI assessment with an ECA could be allowed for M&C defects as well.
Another public commenter suggested removing references to cracks in
these sections if PHMSA was intending to create a new section dedicated
to addressing crack defects.
    Ultimately, the GPAC recommended PHMSA revise the proposed
requirements for M&C defects by deleting a cross-reference with the
MAOP reconfirmation requirements, updating an applicability reference,
and considering removing the term ``hydrostatic'' while allowing other
authorized testing procedures. For the requirements related to electric
resistance welded (ERW) pipe, the GPAC recommended PHMSA delete the
phrase related to pipe body cracking and have those requirements be
addressed in a new section within the IM regulations related to crack
defects.
3. PHMSA Response
    PHMSA appreciates the information provided by the commenters
regarding the consideration of seismicity and manufacturing- and
construction-related defects under the IM regulations. After
considering these comments as well as recommendations by the GPAC,
PHMSA is revising Sec.  192.917(e)(2) to require operators monitor
operating pressure cycles and periodically determine if the cyclic
fatigue analysis is valid at least once every 7 calendar years, not to
exceed 90 months, as necessary. PHMSA is also deleting a reference to
the MAOP reconfirmation requirements in Sec.  192.624 and is
referencing the new Sec.  192.712 for fracture mechanics analysis.
PHMSA believes these changes are consistent with current IM
requirements and will increase regulatory flexibility while maintaining
pipeline safety.
    In Sec.  192.917(e)(3), PHMSA deleted a cross-reference to the MAOP
reconfirmation requirements in Sec.  192.624 and replaced it with a
requirement to prioritize the pipeline segment if it has experienced an
in-service reportable incident since its most recent successful subpart
J pressure test due to an original manufacturing-related defect; or a
construction-, installation-, or fabrication-related defect. This
clarifies that the IM requirement in Sec.  192.917(e)(3) is not part of
the MAOP reconfirmation standards. Although the GPAC asked PHMSA to
consider removing the term ``hydrostatic'' and allow other testing
procedures, PHMSA is retaining the term ``hydrostatic'' in Sec.
192.917(e)(3), as the proposed revision, as written, addresses NTSB
recommendation P-11-15. The NTSB specifically recommended that PHMSA
amend part 192 so that manufacturing- and construction-related defects
can only be considered stable following a postconstruction hydrostatic
pressure test of at least 1.25 times the MAOP. Therefore, deleting the
word ``hydrostatic'' would be contrary to the letter and intent of this
NTSB recommendation.
    For the requirements related to ERW pipe in Sec.  192.917(e)(4),
PHMSA has deleted the phrase related to pipe body cracking and deleted
a cross-reference to the MAOP reconfirmation requirements in Sec.
192.624, referencing the new Sec.  192.712 for fracture mechanics
analysis instead for cracking and crack-related issues. PHMSA made
these changes to streamline the regulations and increase readability.

D. 6-Month Grace Period for 7-Calendar-Year Reassessment Intervals--
Sec.  192.939

1. Summary of PHMSA's Proposal
    Section 5 of the 2011 Pipeline Safety Act identifies a technical
correction amending 49 U.S.C. 60109(c)(3)(B) to allow the Secretary of
Transportation to extend the 7-calendar-year IM reassessment interval
for an additional 6 months if the operator submits written notice to
the Secretary with sufficient justification of the need for the
extension. The NPRM proposed to codify this technical correction as
required by the statute.
2. Summary of Public Comment
    PHMSA received a comment regarding the 6-month grace period for the
7-calendar-year reassessment interval from a trade organization
expressing general support of the proposed provisions and requesting
that PHMSA clarify that the 6-month extension begins after the close of
the 7-calendar-year reassessment interval period, which would be
consistent with

the 2011 Pipeline Safety Act revision to the Federal Pipeline Safety
Statutes.
    At the GPAC meeting on January 12, 2017, the GPAC voted that the
proposed changes on the 6-month grace period for the reassessment
intervals are technically feasible, reasonable, cost-effective, and
practicable, and did not recommend that PHMSA modify these proposed
provisions.
3. PHMSA Response
    PHMSA appreciates the information provided by the commenters
regarding the grace period for IM reassessment intervals. After
considering the comment and as recommended by the GPAC, PHMSA is
retaining the proposed revisions to Sec.  192.939 in this final rule.
The proposed rule clearly stated that the 6-month extension begins
after the close of the 7-calendar-year reassessment interval period.
This is mirrored in PHMSA's frequently asked questions (FAQ) for the IM
program,\72\ which clarifies that the maximum interval for reassessment
may be set using the specified number of calendar years in accordance
with the 2011 Pipeline Safety Act. The use of calendar years is
specific to gas pipeline reassessment interval years under IM and does
not alter the interval requirements that appear elsewhere in the code
for various inspection and maintenance requirements.
---------------------------------------------------------------------------

    \72\ FAQ-41 at https://primis.phmsa.dot.gov/gasimp/faqs.htm.
---------------------------------------------------------------------------

E. ILI Launcher and Receiver Safety--Sec.  192.750

1. Summary of PHMSA's Proposal
    PHMSA determined that more explicit safety requirements are needed
when performing maintenance activities that use launchers and receivers
for inserting and removing ILI maintenance tools and devices. The
current regulations for hazardous liquid pipelines under part 195 have,
since 1981, contained safety requirements for scraper and sphere
facilities. However, the current regulations for natural gas
transmission pipelines do not similarly require controls or
instrumentation to protect against an inadvertent breach of system
integrity due to the incorrect operation of launchers and receivers for
ILI tools, or scraper and sphere facilities. As a result, PHMSA
proposed to add a new section to the Federal Pipeline Safety
Regulations to require ILI launchers and receivers include a suitable
means to relieve pressure in the barrel and either a means to indicate
the pressure in the barrel or a means to prevent opening if pressure
has not been relieved. While most launchers and receivers are already
equipped with such devices, some older facilities may not be so
equipped. Under the proposed provisions, operators would be required to
have this safety equipment installed consistent with current industry
practice.
2. Summary of Public Comment
    Stakeholders, including TPA, provided input on PHMSA's changes to
the requirements for safety when performing maintenance activities that
utilize launchers and receivers for inserting and removing inspection
and maintenance tools and devices. TPA supported the proposed safety
additions to the regulations but stated that Sec.  192.750 should be
included within the regulations for pipeline components rather than the
subpart for pipeline maintenance. In addition, TPA suggested PHMSA
revise the language to allow 18 months after the effective date of the
rule to comply with the provisions. This change would allow for more
time to plan, budget, and complete the work safely. Another commenter
recommended these provisions be effective prior to the next time an
operator would use an applicable launcher or receiver. Public interest
groups and others, such as PST and NAPSR, had broad support for the
proposed provisions regarding ILI launcher and receiver safety.
    At the GPAC meeting on January 12, 2017, a public commenter
suggested clarification on PHMSA's use of the term ``relief device'' or
``relief valve'' within the proposed provisions. During discussion, the
committee noted that there are requirements for ``relief valves''
elsewhere in the code, and calling a needed safety device for ILI
launchers and receivers a ``relief valve'' would then make it subject
to those additional requirements. Based on that discussion, the
committee recommended that PHMSA modify the proposed rule to clarify
that the rule does not require ``relief valves'' or use ``relief
valve'' as an officially defined term within the provision, as those
terms have distinct meanings within the broader context of the Federal
Pipeline Safety Regulations.
3. PHMSA Response
    PHMSA appreciates the information provided by the commenters
regarding launcher and receiver safety. After considering these
comments and the GPAC input, PHMSA is finalizing the provisions as they
were proposed in the NPRM, with the exception of a compliance date 1
year after the effective date of the rule. This approach avoids
disruption of work planned within a year of the effective date of the
rule, and it allows operators that are not planning work until beyond
the 1-year grace period to implement the upgrade before the next
planned use. Therefore, special modification work would not be required
before the launcher or receiver is needed. Operators would not be
required to perform the upgrades until the launcher or receiver is to
be used.
    Consistent with the originally proposed language, this final rule
does not use the term ``relief valve'' and instead uses the generic
phrase ``device capable of safely relieving pressure.'' The proposed
rule effectively avoided any potential for confusion with respect to
the defined term ``relief valve'' and the requirements associated with
those components, therefore no change to this wording was necessary for
this final rule.
    PHMSA believes that this requirement is appropriately located in
subpart M, ``Maintenance,'' of part 192, and notes that the comparable
requirement in part 195 for hazardous liquid pipelines is located in
subpart F, ``Operations and Maintenance.''

F. MAOP Exceedance Reporting--Sec. Sec.  191.23, 191.25

1. Summary of PHMSA's Proposal
    Section 23 of the 2011 Pipeline Safety Act requires that operators
report each exceedance of a pipeline's MAOP beyond the build-up allowed
for the operation of pressure-limiting or control devices. On December
21, 2012 (77 FR 75699), PHMSA published Advisory Bulletin ADB-2012-11
to advise operators of their responsibility under section 23 of the
2011 Pipeline Safety Act to report such exceedances. The advisory
bulletin further stated that the reporting requirement is applicable to
all gas transmission pipeline facility owners and operators. PHMSA
advised pipeline owners and operators to submit this information in the
same manner as safety-related condition reports. The information
pipeline owners and operators submit should comport with the
information listed at Sec.  191.25(b), and pipeline owners and
operators submitting such information should use the reporting methods
listed at Sec.  191.25(a).
    Although this provision of the 2011 Pipeline Safety Act is self-
executing, PHMSA proposed to revise the safety-related condition
reporting requirements under part 191 to codify this requirement and
harmonize part 191 with the statutory requirement by eliminating the
reporting exemption and to provide a consistent procedure,

format, and structure for operators to submit such reports.
2. Summary of Public Comment
    Trade associations, citizen groups, and pipeline industries
generally supported PHMSA's codification of the statutory reporting
requirements for MAOP exceedances for transmission lines.
    API and GPA objected to MAOP exceedance reporting requirements for
unregulated gathering pipelines. GPA stated that PHMSA did not
sufficiently weigh the benefits of reporting MAOP exceedance against
the hurdles to compliance for unregulated gathering pipelines. GPA also
questioned whether PHMSA has the authority to require unregulated
gathering pipelines report MAOP exceedance, since complying with this
reporting requirement would necessitate that unregulated gathering
pipelines establish MAOP, which they are currently not required to do.
Citizen and other safety groups, including Earthworks, NAPSR, the
Pipeline Safety Coalition, and PST, supported the inclusion of
unregulated gathering pipelines in this section, stating that it would
improve pipeline safety.
    Several commenters suggested editorial revisions to streamline and
improve these provisions. NGA expressed concern that the proposed
provisions could apply to distribution systems and suggested that PHMSA
clarify that reporting requirements for MAOP exceedance only apply to
transmission pipelines. Additionally, Spectra Energy Partners requested
that PHMSA require reporting of MAOP exceedances only when the operator
is unable to respond to MAOP exceedances within the timeframe required
elsewhere in part 192.
    One operator expressed concern that the proposed change would
require operators to submit additional safety-related condition reports
anytime the operator had to implement a pressure reduction upon
discovering an immediate condition.
    At the GPAC meeting on June 7, 2017, there was brief discussion on
whether the 5-day reporting requirement was too prescriptive, but the
committee agreed that PHMSA was properly implementing the statutory
requirement as written and intended by Congress. Following that
discussion, the committee recommended that PHMSA modify the proposed
rule to clarify that the MAOP exceedance reporting provisions do not
apply to gathering lines.
3. PHMSA Response
    PHMSA appreciates the information provided by the commenters
regarding MAOP exceedance reporting. The 2011 Pipeline Safety Act
mandates that an operator report MAOP exceedances on gas transmission
lines, regardless of whether the operator corrects the safety-related
condition through repair or replacement. After considering the comments
PHMSA received on the NPRM and as recommended by the GPAC, PHMSA is
inserting the word ``only'' in the additional MAOP exceedance reporting
provision in Sec.  191.23(a)(10) to make it clearer that the amended
requirement applies only to gas transmission lines and not to gathering
or distribution lines. Conforming changes were made to Sec.
191.23(a)(6). PHMSA notes that the prior safety-related condition
reporting requirements and exceptions related to pressure exceedances
for gathering and distribution lines have not been altered.

G. Strengthening Assessment Requirements--Sec. Sec.  192.150, 192.493,
192.921, 192.937, Appendix F

i. Industry Standards for ILI--Sec. Sec.  192.150, 192.493

1. Summary of PHMSA's Proposal
    In the NPRM, PHMSA proposed to revise Sec.  192.150 to incorporate
by reference a NACE Standard Practice, NACE SP0102-2010, ``In-line
Inspection of Pipelines,'' to promote a higher level of safety by
establishing consistent standards for the design and construction of
pipelines to accommodate ILI devices.
    In Sec.  192.493, PHMSA proposed requirements for operators to
comply with the requirements and recommendations of API STD 1163, In-
line Inspection Systems Qualification Standard; ANSI/ASNT ILI-PQ-2005,
In-line Inspection Personnel Qualification and Certification; and NACE
SP0102-2010, In-line Inspection of Pipelines. PHMSA also proposed to
allow operators to conduct assessments using tethered or remotely
controlled tools.
2. Summary of Public Comment
    NAPSR supported the proposed provisions in Sec.  192.493,
commenting that the incorporation by reference of the three consensus
standards provides enhanced guidance for the determination of adequate
procedures and qualifications related to in-line inspections of
transmission pipelines.
    Some industry representatives commented that it is unnecessary to
incorporate American Society for Nondestructive Testing (ASNT) ILI-PQ
by reference since API 1163 requires that providers of ILI services
ensure that their employees are qualified. Others commented that PHMSA
should exclude requirements contained in section 11 of API 1163, which
pertains to quality management systems. Lastly, industry
representatives asserted that ILI vendors may not be able to meet the
90 percent tool tolerance specified in the referenced standards, and
PHMSA should relocate these proposed requirements to a different
subpart.
    Several commenters noted that if PHMSA required compliance with
``the requirements and recommendations of'' the recommended practices
and standards, it would create enforceable requirements out of actions
that the standards themselves did not necessarily mandate.
    During the GPAC meeting of March 2, 2018, the committee recommended
PHMSA revise this provision by striking the phrase ``the requirements
and the recommendations of,'' so that recommendations within the
incorporated standard would not be made mandatory requirements.
3. PHMSA Response
    PHMSA appreciates the information provided by the commenters
regarding the incorporation by reference of industry standards for ILI.
After considering these comments and as recommended by the GPAC, PHMSA
is deleting the phrase ``the requirements and the recommendations of''
from Sec. Sec.  192.150 and 192.493 so that the recommendations within
the incorporated standard would not be made mandatory requirements.
    PHMSA believes that the inclusion of the NACE standard at Sec.
192.150 will help to address the NTSB recommendation P-15-20, which
asked PHMSA to identify all operational complications that limit the
use of ILI tools in piggable pipelines, develop methods to eliminate
those complications, and require operators use such methods to increase
the use of ILI tools. PHMSA also believes that more pipelines will
become piggable in the future as the nation's pipeline infrastructure
ages and is eventually replaced. A current provision in the regulations
requires that all new and replaced pipeline be piggable, and as
operators address higher-risk infrastructure through this rulemaking,
there is a likelihood that some previously unpiggable pipe will be
replaced.
    PHMSA disagrees that ASNT ILI-PQ is unnecessary. The foreword of
API 1163 states ``This standard serves as an umbrella document to be
used with and complement companion standards.

NACE SP0102, In-line Inspection of Pipelines and ASNT ILI-PQ, In-line
Inspection Personnel Qualification and Certification.'' These three
standards are complimentary and are intended to be used together. PHMSA
also disagrees that quality requirements should be excluded from the
rule. One of the fundamental objectives of this rule is to establish a
minimum standard for quality in conducting ILI. Also, the consensus
industry standard API 1163 only uses 90 percent tool tolerance as an
example to illustrate key points but does not specify or establish a
minimum standard tool tolerance of 90 percent.

G. Strengthening Assessment Requirements--Sec. Sec.  192.150, 192.493,
192.921, 192.937, Appendix F

ii. Expand Assessment Methods Allowed for IM--Sec. Sec.  192.921(a) and
192.937(c)

1. Summary of PHMSA's Proposal
    In the current Federal Pipeline Safety Regulations, Sec.  192.921
requires that operators with pipelines subject to the IM rules must
perform integrity assessments. Currently, operators can assess their
pipelines using ILI, pressure test, direct assessment, and other
technology that the operator demonstrates provides an equivalent level
of understanding of the condition of the pipeline.
    In the NPRM, PHMSA proposed to require that direct assessment only
be allowed when the pipeline cannot be assessed using ILI. As a
practical matter, direct assessment is typically not chosen as the
assessment method if the pipeline can be assessed using ILI. Further,
PHMSA proposed to add three additional assessment methods to the
regulations:
    1. A spike hydrostatic pressure test, which is particularly well-
suited to address stress corrosion cracking and other cracking or
crack-like defects;
    2. Guided Wave Ultrasonic Testing (GWUT), which is particularly
appropriate in cases where short segments such as road or railroad
crossings are difficult to assess; and
    3. Excavation with direct in situ examination.
2. Summary of Public Comment
    NAPSR expressed its support for the proposed provisions. Many
comments expressed concerns with the proposed provisions for the
assessment methods regarding uncertainties in reported results.
Multiple commenters stated that operators should be able to run the
appropriate assessment or ILI tools for the threats that are known or
likely to exist on the pipeline based on its condition. Atmos Energy
commented that ASME/ANSI B318.S requirements should be the standard to
which operators are required to follow. Enable Midstream Partners
proposed that PHMSA add ``significant'' to make a distinction between
significant and insignificant threats and offered specific language to
address its concerns. PG&E commented on the proposed provisions for ILI
assessments, requesting that PHMSA provide guidance as to how to
explicitly consider the numerous uncertainties associated with ILI
regarding anomaly location accuracy, detection thresholds, and sizing
accuracy, and suggested that PHMSA allow industry guidance and best
practices to be used where practical. Some commenters expressed concern
that PHMSA proposed to add requirements surrounding the detection of
anomalies that many ILI tools could not meet. These commenters stated
that there are no tools designed to find girth weld cracks and that
most incidents caused by girth weld cracks have third-party excavation
damage as a contributing factor. Commenters further stated that this is
a threat that is best handled by procedures that require caution around
girth welds during excavation and backfilling procedures.
    Several entities commented on the proposed qualification
requirements under the ILI assessment method provisions, expressing
concern that they are redundant with existing operator qualification
regulations under the IM regulations at Sec.  192.915 and the proposed
revisions to Sec.  192.493 incorporating the industry ANSI standard on
ILI personnel qualification. Multiple entities proposed changes to
remove such redundancies and improve clarity.
    Commenters requested clarification that the proposed text in the IM
assessment provisions ``apply one or more of the following methods for
each threat to which the covered segment is susceptible'' does not mean
that at least one assessment is required for each threat. Additionally,
commenters disagreed with adding an explicit requirement for a ``no
objection'' letter as notification of using ``other technology'' and
suggested that if this notification is required, operators should be
allowed to proceed with the technology if they do not receive a ``no
objection'' letter from PHMSA within a certain period.
    The NTSB commented that PHMSA's proposal to revise the pipeline
inspection requirements to allow the direct assessment method to be
used only if a line is not capable of inspection by internal inspection
tools directly conflicts with the recommendations of their pipeline
safety study, Integrity Management of Gas Transmission Lines in High
Consequence Areas, which recommended that PHMSA develop and implement a
plan for eliminating the use of direct assessment as the sole integrity
assessment method for gas transmission pipelines. The CPUC asserted
that direct assessment must always be supplemented with other methods,
such as ILI or a pressure test.
    Many industry entities argued that PHMSA's proposed changes to the
IM assessment provisions limiting direct assessment to unpiggable lines
are not technically justified. Several entities, including AGA and API,
believed it was unreasonable to limit operators' ability to use direct
assessment for pipeline assessments unless all other assessment methods
have been determined unfeasible or impractical. PG&E requested that
PHMSA recognize that although a pipeline may be considered piggable, it
does not mean that ILI technology is available, and they provided
specific suggestions for revision. Similarly, AGA stated that free-
swimming flow-driven ILI tools are often not compatible with intrastate
transmission lines for several reasons, stating that certain conditions
must exist to assess a pipeline by ILI and obtain valid data, including
adequate flow rate, lack of bends or valves that would impede diameter,
and ability to insert and remove the tool from the system. Therefore,
AGA provided a suggested definition for ``able to accommodate
inspection by means of an instrumented in-line inspection tool.''
    Trade associations asserted that direct assessment is a proven
assessment technique that works in addressing the threat of corrosion.
INGAA stated that the criteria for when direct assessment can be used
should depend on whether direct assessment can provide the necessary
information about the pipe condition rather than whether other
assessment methods can be used. AGA commented that it is not aware of
any industry study that would suggest that direct assessment does not
work effectively to identify corrosion defects in certain
circumstances, which it describes in its comments. In addition, AGA
stated that direct assessment is a predictive tool that identifies
areas where corrosion could occur, including time-dependent threats,
while other methods can only detect where corrosion has resulted in a
measurable metal loss. Atmos Energy commented that limiting the use of
direct assessment only to those pipeline segments that are not capable
of

inspection by internal inspection tools is not consistent with other
requirements of subpart O.
    At the GPAC meeting on December 15, 2017, the committee voted to
revise the ``no objection'' process to incorporate language stating
that, if an operator does not receive an objection letter from PHMSA
within 90 days of notifying PHMSA of an alternative sampling approach,
the operator can proceed with their method. Additionally, the GPAC,
during the meeting on March 2, 2018, recommended that PHMSA change
these provisions to clarify that operators should select the
appropriate assessment based on the threats to which the pipeline is
susceptible and remove certain language that is duplicative to another
existing section of the regulations. The GPAC also recommended that
PHMSA clarify that direct assessment is allowed where appropriate but
may not be used to assess threats for which the method is not suitable.
Further, the GPAC wanted PHMSA to incorporate the notification and
objection procedure and 90-day timeframe that the GPAC approved under
the material properties verification requirements.
3. PHMSA Response
    PHMSA appreciates the information provided by the commenters
regarding the inclusion of additional assessment methods for integrity
assessments. After considering these comments and as recommended by the
GPAC, PHMSA is clarifying in this final rule that operators should
select the appropriate assessment method based on the threats to which
the pipeline is susceptible and is removing language regarding the
qualification of persons reviewing ILI results that is duplicative with
existing Sec.  192.915. PHMSA is also clarifying in Sec.  192.921 that
direct assessment is allowed where appropriate but may not be used to
assess threats for which the method is not suitable, such as assessing
pipe seam threats. In addition, PHMSA incorporated the notification
procedure under Sec.  192.18 with the 90-day timeframe and objection
process.
    PHMSA notes that other comments regarding the determination of
suitable assessment methods for applicable threats and ILI tool
capabilities relate to long-standing IM regulations that were not
proposed for revision. PHMSA did provide substantial additional
guidance and standards for implementing the integrity assessment
requirements for ILI by incorporating the industry standards in Sec.
192.493, as discussed in the previous sections.

G. Strengthening Assessment Requirements--Sec. Sec.  192.150, 192.493,
192.921, 192.937, Appendix F

iii. Guided Wave Ultrasonic Testing--Appendix F

1. Summary of PHMSA's Proposal
    When expanding assessment methods for both HCA and non-HCA areas,
PHMSA proposed to add three additional assessment methods, one being
GWUT. Under the existing regulations, GWUT is considered ``other
technology,'' and operators must notify PHMSA prior to its use. PHMSA
developed guidelines for the use of GWUT, which have proven successful,
and proposed to add them under a new Appendix F to part 192--Criteria
for Conducting Integrity Assessments Using Guided Wave Ultrasonic
Testing. As such, future notifications to PHMSA would not be required,
representing a cost savings for operators.
2. Summary of Public Comment
    Multiple entities commented in support of using GWUT and the
inclusion of proposed Appendix F. NAPSR expressed its agreement with
and support for the proposed Appendix. American Public Gas Association
(APGA) applauded PHMSA for including guidelines for GWUT; however, it
cautioned that the guidance only specifies Guided Ultrasonics LTD (GUL)
Wavemaker G3 and G4, which use piezoelectric transducer technology, as
acceptable technology. APGA recommended that Magnetostrictive Sensor
technology also be included as an acceptable guided wave technology,
stating that at least one of its members reported good results using
this technology for guided wave assessment of an unpiggable segment of
a transmission pipeline.
    A commenter noted that the requirement of both torsional and
longitudinal wave modes in all situations introduces unnecessary
complexity into the GWUT data interpretation process. The commenter
further noted that PHMSA should specify that torsional wave mode is the
primary wave mode when utilizing GWUT, and that longitudinal wave mode
may be used as an optional, secondary mode. Other commenters
recommended additional changes to Appendix F, such as stating that
qualified GWUT equipment operators are trained to understand the
strengths, weaknesses, and proper applications of each wave mode and
should have the freedom to select the appropriate and most effective
wave mode(s) for the given situation. PG&E requested that PHMSA
recognize that this technology is used at locations other than casings
as implied in the introductory paragraph and commented that double-
ended inspections are not always required to meet the specification.
    During the GPAC meeting on December 15, 2017, the GPAC agreed with
the provisions related to Appendix F and GWUT but recommended PHMSA
revise the ``no objection'' letter process.
3. PHMSA Response
    PHMSA appreciates the information provided by the commenters
regarding GWUT. After considering these comments and as recommended by
the GPAC, PHMSA is removing the reference to GUL equipment for clarity.
PHMSA is modifying the notification process to allow operators to
proceed with an alternative process for using GWUT if the operator does
not receive an objection letter from PHMSA within 90 days of notifying
PHMSA in accordance with Sec.  192.18. PHMSA believes this change
increases regulatory flexibility while maintaining pipeline safety.
    In this final rule, PHMSA is retaining the requirement to use both
torsional and longitudinal wave modes since that is a long-standing
requirement in PHMSA's guidance for accepting GWUT as an allowed
technology under an ``other technology'' notification. Also, PHMSA
recognizes that GWUT is used at locations other than casings, although
it is most often deployed for the integrity assessment of cased
crossings. However, double-ended inspections would not always be
required to meet Appendix F, and Appendix F does not require double-
ended inspections. Double-ended inspections are not necessary as long
as the guided wave ultrasonic test covers the entire length of the
assessment as well as the ``dead zone'' where the equipment is set up.
    The proposed rule already addresses validation of operator
training, but in this final rule, PHMSA is deleting the sentence
``[t]here is no industry standard for qualifying GWUT service
providers'' to provide clarity.

H. Assessing Areas Outside of HCAs--Sec. Sec.  192.3, 192.710

i. MCA Definition--Sec.  192.3

1. Summary of PHMSA's Proposal
    In the NPRM, PHMSA introduced a new definition for a Moderate
Consequence Area (MCA). The proposed rule defined an MCA as an onshore
area, not meeting the definition of an HCA, that is within a potential
impact circle, as defined in Sec.  192.903, containing 5 or more
buildings intended

for human occupancy; an occupied site; or a right-of-way for a
designated interstate, freeway, expressway, or other principal four-
lane arterial roadway as defined in the Federal Highway
Administration's ``Highway Functional Classification Concepts, Criteria
and Procedures.'' PHMSA proposed that requirements for data analysis,
assessment methods, and immediate repair conditions within these MCAs
would be similar to requirements for HCA pipeline segments but with
longer timeframes so that operators could properly allocate resources
to higher-consequence areas. PHMSA proposed that the 1-year repair
conditions that currently exist for HCA pipeline segments would be 2-
year repair conditions when found on MCA pipeline segments. These
changes would ensure the prompt remediation of anomalous conditions
that could potentially affect people, property, or the environment,
commensurate with the severity of the defects, while still allowing
operators to allocate their resources to HCAs on a higher-priority
basis.
2. Summary of Public Comment
    The NTSB stated that the proposed provisions to create an MCA
category and include a highway size threshold in the definition of an
MCA accomplishes part of what the NTSB intended in Safety
Recommendation P-14-1. However, the NTSB objected to the proposed
highway coverage as being limited to four lanes and stated its support
of expanding the highway size threshold as they had specifically
recommended in P-14-1. The NTSB asserted that the proposed language
would exclude the category of other principal arterial roadways wider
than four lanes when, in fact, the wider roadways should be included.
    INGAA supported the addition of an MCA category to the Federal
Pipeline Safety Regulations but recommended several modifications to
the proposed definition. INGAA suggested PHMSA should limit the
definition of an MCA to only those pipeline segments that could be
assessed through an ILI inspection, amend the MCA definition to avoid
ambiguity regarding residential structures, remove ``outside areas and
open structures'' from the portion of the definition of MCA related to
``identified sites,'' include timeframes for incorporating changes to
existing MCAs, and permit operators to use the edge of the pavement
rather than the highway right-of-way to determine if a roadway