There was no significant public comment on this definition, and the
GPAC recommended PHMSA adopt the definition as it was published in the
NPRM.
3. PHMSA Response
    PHMSA adopts the definition as it was published in the NPRM.

IV. Section-by-Section Analysis

Section 192.3 Definitions

    Section 192.3 provides definitions for various terms used
throughout part 192. In support of other regulations adopted in this
final rule, PHMSA is amending the definition of ``transmission line''
and is adding new definitions for ``close interval survey,''
``distribution center,'' ``dry gas or dry natural gas,'' ``hard spot,''
``in-line inspection,'' ``in-line inspection tool or instrumented
internal inspection device,'' and ``wrinkle bend.'' The definitions,
including ``in-line inspection,'' ``dry gas or dry natural gas,'' and
``hard spot,'' clarify technical terms used in part 192 or in this
rulemaking.

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

    Section 192.7 lists documents that are incorporated by reference in
part 192. PHMSA is making conforming amendments to Sec.  192.7 to
include two NACE standard practice documents regarding SCCDA and ICDA.

Section 192.9 What requirements apply to gathering lines?

    Section 192.9 lists the requirements that are applicable or not
applicable to gathering lines. This final rule addresses several new
requirements for transmission lines that are not intended to apply to
gathering lines; PHMSA is adopting in this final rule revisions to
Sec.  192.9 to except each of offshore and Types A, B, and C \50\ gas
gathering lines from those requirements.
---------------------------------------------------------------------------

    \50\ PHMSA notes that it has introduced in this final rule
revisions to Sec.  192.9(e), which paragraph was adopted in the Gas
Gathering Final Rule, to identify specific provisions of part 192
that would apply to the new Type C category of part 192-regulated
onshore gas gathering pipelines.
---------------------------------------------------------------------------

Section 192.13 What general requirements apply to pipelines regulated
under this part?

    Section 192.13 prescribes general requirements for gas pipelines.
PHMSA has determined that public safety and environmental protection
would be improved by requiring operators of transmission lines to
evaluate and mitigate risks during all phases of the useful life of a
pipeline as an integral part of managing pipeline design, construction,
operation, maintenance, and integrity, including the MOC process.
    As such, PHMSA has added a new paragraph (d) to Sec.  192.13 with a
general clause for transmission pipeline operators that invokes the
requirements for the MOC process as it is outlined in ASME/ANSI B31.8S,
section 11, and explicitly articulates the requirements for a MOC
process applicable to onshore gas transmission pipelines. This final
rule requires each operator to have a MOC process that must include the
reason for change, authority for approving changes, analysis of
implications, acquisition of required work permits, documentation,
communication of change to affected parties, time limitations, and
qualification of staff. While these general attributes of change
management are already required for covered segments by virtue of the
incorporation by reference of ASME/ANSI B31.8S, PHMSA believes it will
improve the visibility and emphasis on these important program elements
to require them for all onshore transmission pipelines directly in the
rule text.

Section 192.18 How To Notify PHMSA

    Section 192.18 in subpart A contains the procedure for an operator
to submit notifications to PHMSA. Paragraph (c) has been modified to
incorporate notification requirements for the use of ``other
technology'' with external corrosion control and ICDA per Sec. Sec.
192.461(g) and 192.927(b).\51\ This is

consistent with the requirements PHMSA issued with the use of other
technology for provisions finalized in the 2019 Gas Transmission Rule.
---------------------------------------------------------------------------

    \51\ PHMSA notes that between publication of this final rule and
its effective date, regulatory amendments to Sec.  191.18 adopted in
rulemaking published in April 2022 will have been codified in the
Code of Federal Regulations. ``Pipeline Safety: Requirement of Valve
Installation and Minimum Rupture Detection Standards,'' 87 FR 20940
(Apr. 8, 2022) (identifying an effective date in October 2022)
(Valve Installation Final Rule). The amendatory text at the end of
this final rule, therefore, reflects the text of Sec.  192.18 as it
will be revised when the Valve Installation Final Rule becomes
effective.
---------------------------------------------------------------------------

Section 192.319 Installation of Pipe in a Ditch

    Section 192.319 prescribes requirements for installing pipe in a
ditch, including requirements to protect pipe coating from damage
during the process. Sometimes pipe coating is damaged during the
construction process while it is being handled, lowered, and
backfilled, which can compromise its ability to protect against
external corrosion. Accordingly, this final rule adds new paragraphs
(d) through (g) to Sec.  192.319, which require that onshore gas
transmission operators perform an above-ground indirect assessment to
identify locations of suspected damage promptly after backfilling is
completed and remediate coating damage. Mechanical damage is also
detectable by these indirect assessment methods, since the forces that
can mechanically damage steel pipe usually result in detectable coating
defects.
    If an operator uses ``other technology'' to perform an assessment
required under this section, paragraph (e) requires the operator to
notify PHMSA in accordance with Sec.  192.18. Paragraph (g) requires
each operator of transmission pipelines to make and retain, for the
life of the pipeline, records documenting the coating assessment
findings and repairs. The additional requirements of this section do
not apply to gas gathering pipelines or distribution mains.

Section 192.461 External Corrosion Control: Protective Coating

    Section 192.461 prescribes requirements for protective coating
systems. Certain types of coating systems that have been used
extensively in the pipeline industry can impede the process of cathodic
protection if the coating disbonds from the pipe. Accordingly, this
final rule amends paragraph (a)(4) to require that pipe coating has
sufficient strength to resist damage during installation and backfill,
and it also adds a new paragraph (f) to require that onshore gas
transmission operators perform an above-ground indirect assessment to
identify locations of suspected damage promptly after backfill is
completed or anytime there is an indication that the coating might be
compromised. To ensure the prompt remediation of any severe coating
damage, new paragraph (h) requires operators create a remedial action
plan and provides the specific timing requirements for repairs. New
paragraph (g) requires an operator to notify PHMSA, in accordance with
Sec.  192.18, if using ``other technology'' for the coating assessment,
and paragraph (i) specifies the documentation requirements for this
section. The additional requirements of this section do not apply to
gas gathering pipelines or distribution mains.

Section 192.465 External Corrosion Control: Monitoring

    Section 192.465 requires that operators monitor CP and take prompt
remedial action to correct deficiencies indicated by the monitoring. To
clarify that regulatory requirement, this final rule amends paragraph
(d) to require that operators of onshore transmission pipelines must
complete remedial action no later than the next monitoring interval
specified in Sec.  192.465, within 1 year, or within 6 months of
obtaining any permits, whichever is less.
    This final rule also adds a new paragraph (f) to require onshore
gas transmission operators to conduct annual test station readings to
determine if CP is below the level of protection required in subpart I.
For non-systemic or location-specific causes of insufficient CP, the
operator must investigate and mitigate the cause. For insufficient CP
due to systemic causes, an operator must complete CIS with the
protective current interrupted, unless it is impractical to do so based
on a geographical, technical, or safety reason. For example, issues
related to cost would not be an adequate reason for not performing the
survey, whereas performing a survey on a pipeline protected by direct
buried sacrificial anodes (anodes directly connected to the pipelines)
might be impractical. The revisions to paragraph (d) and new paragraph
(f) do not apply to gas gathering lines or distribution mains.

Section 192.473 External Corrosion Control: Interference Currents

    Interference currents can negate the effectiveness of CP systems.
Section 192.473 currently prescribes general requirements to minimize
the detrimental effects of interference currents. However, subpart I
does not presently contain specific requirements to monitor and
mitigate detrimental interference currents. Accordingly, this final
rule adds a new paragraph (c) to require that onshore gas transmission
operator corrosion control programs include interference surveys to
detect the presence of interference currents when potential monitoring
indicates a significant increase in stray current, or when new
potential stray current sources are introduced. Sources of stray
current can include co-located pipelines, structures, HVAC power lines,
new or enlarged power substations, new pipelines, and other structures.
They can also include additional generation, a voltage uprating, and
additional lines. The rule also requires operators perform remedial
actions no later than 15 months after completing the interference
survey, with an allowance for permitting, to protect the pipeline
segment from detrimental interference currents. These additional
requirements do not apply to gas gathering pipelines or distribution
mains.

Section 192.478 Internal Corrosion Control: Monitoring

    Section 192.477 prescribes requirements to monitor internal
corrosion if corrosive gas is being transported. However, the existing
rules do not prescribe operators continually or periodically monitor
the gas stream for the introduction of corrosive constituents through
system modifications, gas supply changes, upset conditions, or other
changes. This could result in operators not identifying internal
corrosion if an initial assessment did not identify the presence of
corrosive gas. Accordingly, PHMSA has determined that additional
requirements are needed to ensure that operators effectively monitor
their gas stream quality to identify if, and when, corrosive gas is
being transported and mitigate deleterious gas stream constituents
(e.g., contaminants or liquids).
    Therefore, this final rule adds a new Sec.  192.478 to require
onshore gas transmission operators monitor for known deleterious gas
stream constituents and evaluate gas monitoring data once every
calendar year, not to exceed a period of 15 months. Additionally, this
final rule adds a requirement for onshore gas transmission operators to
review their internal corrosion monitoring and mitigation program
annually, not to exceed 15 months, and adjust the program as necessary
to mitigate the presence of deleterious gas stream constituents. These
requirements are in addition to the existing requirements to check
coupons or perform other methods to monitor for the actual

presence of internal corrosion in the case of transporting a known
corrosive gas stream. The new Sec.  192.478 does not apply to gas
gathering pipelines or distribution mains.

Section 192.485 Remedial Measures: Transmission Lines

    Section 192.485 prescribes requirements for operators to perform
remedial measures to address general corrosion and localized corrosion
pitting in transmission pipelines. For such conditions, the
requirements specify that an operator may determine the strength of
pipe based on actual remaining wall thickness by using the procedure in
ASME/ANSI B31G or the procedure in AGA Pipeline Research Committee
Project PR 3-805 (RSTRENG). PHMSA has determined that additional
requirements are needed beyond ASME/ANSI B31G and RSTRENG to ensure
such calculations have a sound basis and has revised Sec.  192.485(c)
to specify that an operator must calculate the remaining strength of
the pipe in accordance with Sec.  192.712, which prescribes important
aspects such as pipe and material properties, assumptions allowed when
data is unknown, accounting for uncertainties, and recordkeeping
requirements.

Section 192.613 Continuing Surveillance

    Extreme weather and natural disasters can affect the safe operation
of a pipeline. Accordingly, this final rule revises Sec.  192.613 to
require operators to perform inspections after these events and take
appropriate remedial actions.

Section 192.710 Transmission Lines: Assessments Outside of High
Consequence Areas

    Section 192.710 prescribes requirements for the periodic assessment
of certain pipelines outside of HCAs. In the NPRM, PHMSA proposed for
operators to use the non-HCA repair criteria being finalized in this
rule if they performed an assessment on a non-HCA pipeline and
discovered an anomaly requiring repair. However, in splitting the
rulemaking, PHMSA finalized the assessment requirement in the 2019 Gas
Transmission Final Rule but did not incorporate regulatory text
establishing the corresponding repair criteria. Therefore, in this
final rule, PHMSA has revised the assessment requirement at Sec.
192.710 to require operators to use the repair criteria finalized in
this rulemaking if anomalies are discovered during these assessments.

Section 192.711 Transmission Lines: General Requirements for Repair
Procedures

    Section 192.711 prescribes general requirements for repair
procedures. For non-HCA segments, the existing regulations required
that operators make permanent repairs as soon as feasible. However, no
specific repair criteria were detailed, and no specific timeframe or
pressure reduction requirements were provided. PHMSA has determined
that more specific repair criteria are needed for pipelines not covered
under the integrity management regulations. Such repair criteria will
help to maintain safety in a consistent manner in Class 1 through Class
4 locations that may have significant populations but that are not
HCAs. Accordingly, this final rule amends paragraph (b)(1) of Sec.
192.711 to require operators remediate specific conditions, as defined
in Sec.  192.714, on non-HCA gas transmission pipelines. Paragraph
(b)(1) retains the existing requirement that operators must repair
anomalies on gathering pipelines regulated in accordance with Sec.
192.9 as soon as feasible.

Section 192.712 Analysis of Predicted Failure Pressure and Critical
Strain Levels

    In the 2019 Gas Transmission Rule, PHMSA updated and codified
minimum standards for determining the predicted failure pressure of
pipelines containing anomalies or defects associated with corrosion
metal loss and cracks. In this final rule, PHMSA is revising the repair
criteria for gas transmission pipelines, including for dents. Some of
the revised dent repair criteria allow operators to determine critical
strain levels for dents and defer repairs if critical strain levels are
not exceeded. As such, PHMSA has established minimum standards for
operators to calculate critical strain levels in pipe with dent
anomalies or defects and has included those standards in a new
paragraph (c) of Sec.  192.712. The title of this section has also been
updated to reflect this addition. PHMSA has also provided reassessment
schedules for engineering critical assessments that operators perform
to determine maximum reevaluation intervals to ensure that anomalies do
not grow to critical sizes.

Section 192.714 Transmission Lines: Permanent Field Repair of
Imperfections and Damages

    Section 192.713 prescribes requirements for the permanent repair of
pipeline imperfections or damage that impairs the serviceability of
steel transmission pipelines operating at or above 40 percent of SMYS.
PHMSA has determined that more explicit requirements are needed in
Sec.  192.714 to identify criteria for the severity of imperfections or
damage that must be repaired, and to identify the timeframe within
which repairs must be made for pipelines in all class locations that
are not in HCAs. Pipelines not in HCAs can still have significant
populations that could be harmed by a pipeline leak or rupture. As
such, PHMSA has determined that repair criteria should apply to any
onshore transmission pipeline not covered under the IM regulations in
subpart O. PHMSA believes that establishing these non-HCA segment
repair conditions for Class 1 locations through Class 4 locations are
important because, even though they are not within HCAs, these
locations could be in highly populated areas and are not without
consequence to public safety and the environment.
    Accordingly, this final rule creates a new Sec.  192.714 to
establish repair criteria for immediate, 2-year, and monitored
conditions that the operator must remediate or monitor to ensure
pipeline safety. PHMSA is using the same criteria as it is issuing for
HCAs, except conditions for which a 1-year response is required in HCAs
will require a 2-year response in non-HCA pipeline segments so that
operators can allocate their resources to HCAs on a higher-priority
basis. Additionally, PHMSA is prescribing more explicit requirements
for the in situ evaluation of cracks and crack-like defects using in-
the-ditch tools whenever required, such as when an ILI, SCCDA, pressure
test failure, or other assessment identifies anomalies that suggest the
presence of such defects.

Section 192.911 What are the elements of an integrity management
program?

    Paragraph (k) of Sec.  192.911 requires that IM programs include a
MOC process as outlined in ASME/ANSI B31.8S, section 11. PHMSA has
determined that specific attributes and features of the MOC process
that are currently specified in ASME/ANSI B31.8S, section 11, should be
codified directly within the text of subpart O for HCAs to make the
requirements readily available to all operators of onshore gas
transmission pipelines. This change is consistent with the new
paragraph (d) in Sec.  192.13 for all onshore transmission pipelines.

Section 192.917 How does an operator identify potential threats to
pipeline integrity and use the threat identification in its integrity
program?

    Section 192.917 requires that operators with IM programs for
covered pipeline segments identify potential threats to pipeline
integrity and use the threat identification in their integrity program.
This performance-based process includes requirements to identify
threats to which the pipeline is susceptible, collect data for
analysis, and perform a risk assessment. The regulations include
special requirements for operators to address plastic pipe and
particular threats, such as third-party damage and manufacturing and
construction defects.
    As specified in Sec.  192.907(a), PHMSA expected operators to start
with a framework for IM, which would later evolve into a more detailed
and comprehensive program, and expected that an operator would
continually improve its IM program as it learned more about the process
and about the material condition of its pipelines through integrity
assessments. PHMSA elaborated on this philosophy in the 2003 IM
rule.\52\
---------------------------------------------------------------------------

    \52\ ``Pipeline Integrity Management in High Consequence Areas
(Gas Transmission Pipelines)''; 68 FR 69778 (Dec. 15, 2003). See 68
FR 69789.
---------------------------------------------------------------------------

    Even though the IM regulations have been in effect since 2004,
PHMSA still finds certain operators have poorly developed IM programs.
The clarifications and additional specificity adopted in this final
rule, with respect to the processes an operator must use in
implementing the threat identification, risk assessment, and preventive
and mitigative measure program elements, reflect PHMSA's expectation
regarding the degree of progress operators should be making, or should
have made, during the first 10 years of the implementation of the IM
regulations.
    The current IM regulations incorporate by reference ASME/ANSI
B31.8S to require that operators implement specific attributes and
features of the threat identification, data analysis, and risk
assessment process in their IM programs. In this final rule, PHMSA is
amending Sec.  192.917 to insert certain critical features of ASME/ANSI
B31.8S directly into the regulatory text. PHMSA is specifying several
pipeline attributes that must be included in pipeline risk assessments
and is explicitly requiring that operators integrate analyzed
information and ensure that data is verified and validated to the
maximum extent practical. To the degree that subjective data from SMEs
must be used, PHMSA is requiring that an operator's program account and
compensate for uncertainties in the risk model used and the data used
in the operator's risk assessment. PHMSA is also in this final rule
revising the non-exhaustive list of data to be collected for clarity or
to eliminate redundant language.
    PHMSA will note that in its advisory bulletin on the verification
of records that ``verifiable'' records are those in which information
is confirmed by other complementary, but separate, documentation. Such
records might include contract specifications for a pressure test of a
line segment complemented by field logs or purchase orders with pipe
specifications verified by metallurgical tests of coupons pulled from
the same pipe segment.
    Additionally, PHMSA is clarifying the performance-based risk
assessment aspects of the IM regulations in this final rule by
specifying that operators must perform risk assessments that are
adequate for evaluating the effects of interacting threats; determine
additional P&M measures needed; analyze how a potential failure could
affect HCAs, including the consequences of the entire worst-case
incident scenario from initial failure to incident termination;
identify the contribution to risk of each risk factor, or each unique
combination of risk factors that interact or simultaneously contribute
to risk at a common location; account for, and compensate for,
uncertainties in the model and the data used in the risk assessment;
and evaluate risk reduction associated with candidate risk reduction
activities, such as P&M measures.
    In consideration of NTSB recommendation P-11-18, PHMSA is adopting
regulations that require operators to validate their risk models
considering incident, leak, and failure history and other historical
information. These features are currently requirements because they are
incorporated by reference in ASME/ANSI B31.8S. However, PHMSA has found
that provisions incorporated directly into its regulatory text have
higher levels of compliance. The final rule also amends the
requirements for plastic pipe to provide specific examples of integrity
threats for plastic pipe that must be addressed.

Section 192.923 How is direct assessment used and for what threats?

    This final rule incorporates by reference NACE SP0206-2006,
``Internal Corrosion Direct Assessment Methodology for Pipelines
Carrying Normally Dry Natural Gas,'' for addressing ICDA, and NACE
SP0204-2008, ``Stress Corrosion Cracking Direct Assessment,'' for
addressing SCCDA. Accordingly, PHMSA has revised Sec.  192.923(b)(2)
and (3) to require operators comply with these standards.

Section 192.927 What are the requirements for using internal Corrosion
Direct Assessment (ICDA)?

    Section 192.927 specifies requirements for gas transmission
pipeline operators who use ICDA for IM assessments. The requirements in
Sec.  192.927 were promulgated before NACE SP0206-2006 was published
and require that operators follow ASME/ANSI B31.8S provisions related
to ICDA. PHMSA has reviewed NACE SP0206-2006 and finds that it is more
comprehensive and rigorous than either Sec.  192.927 or ASME/ANSI
B31.8S in many respects. Therefore, PHMSA is incorporating NACE SP0206-
2006 into the regulations for the performance of ICDA and is
establishing additional requirements for addressing covered segments
within the technical process defined by the NACE standard.
    This final rule requires that operators perform two direct
examinations within each covered segment the first time ICDA is
performed. These examinations are in addition to those required to
comply with the NACE standard. The additional examinations are
consistent with the current requirement in Sec.  192.927(c)(5)(ii) that
operators apply more restrictive criteria when conducting ICDA for the
first time and are intending to verify, within the HCA, that the
results of applying the process of NACE SP0206-2006 for the ICDA are
acceptable. Applying the process for NACE SP0206-2006 requires more
precise knowledge of the pipeline orientation (particularly slope) than
operators may have in many cases. Conducting examinations within the
HCA during the first application of ICDA will verify that applying the
ICDA process provides an operator with adequate information about the
covered segment. Operators who identify internal corrosion on these
additional examinations, even though excavations at locations
determined using NACE SP0206-2006 did not identify any internal
corrosion, will know that improvements are needed to their knowledge of
pipeline orientation. In addition, operators will know they need other
adjustments to their application of the NACE standard to the covered
segment for using ICDA in the future. Section 192.927(b) and (c) are
revised in this final rule to address these issues.
    PHMSA notes that, for these requirements, operators are prohibited
from using assumed pipeline or operational data. Any data an operator

uses for its ICDA process should be based on known information, such as
the pipeline route, the pipeline diameter, and pipeline flow inputs and
outputs. Operators can choose to base their ICDA process on data that
is more conservative than their known pipeline or operational data.

Section 192.929 What are the requirements for using Direct Assessment
for Stress Corrosion Cracking (SCCDA)?

    Section 192.929 specifies requirements for gas transmission
pipeline operators who use SCCDA for IM assessments. The requirements
in Sec.  192.929 were promulgated before NACE Standard Practice SP0204-
2008 was published, and the standard requires that operators follow
Appendix A3 of ASME/ANSI B31.8S. That appendix provides some guidance
for conducting SCCDA but is limited to SCC that occurs in high-pH
environments. Experience has shown that pipelines can also experience
SCC degradation in areas where the surrounding soil has a pH near
neutral (referred to as near-neutral SCC). NACE SP0204-2008 addresses
near-neutral SCC as well as high-pH SCC. NACE SP0204-2008 also provides
technical guidelines and process requirements that are both more
comprehensive and rigorous for conducting SCCDA than Sec.  192.929 or
ASME/ANSI B31.8S.
    Since NACE SP0204-2008 provides comprehensive guidelines on
conducting SCCDA and is more comprehensive in scope than Appendix A3 of
ASME/ANSI B31.8S, PHMSA has concluded the quality and consistency of
SCCDA conducted under IM requirements would be improved by requiring
operators to use NACE SP0204-2008. The final rule accomplishes this.

Section 192.933 What actions must be taken to address integrity issues?

    Section 192.933 specifies injurious anomalies and defects that
operators must remediate and the timeframes within which such
remediation must occur. PHMSA determined that the existing regulations
for repair criteria had gaps, as some injurious anomalies and defects
were not listed as requiring remediation in a timely manner
commensurate with their seriousness. To remedy this, in this final
rule, PHMSA is designating the following types of defects as immediate
conditions: (1) anomalies where the metal loss is greater than 80
percent of nominal wall thickness; (2) metal loss anomalies with a
predicted failure pressure less than or equal to 1.1 times the MAOP;
(3) a topside dent that has metal loss, cracking, or a stress riser;
(4) anomalies where there is an indication of metal loss affecting
certain longitudinal seams; and (5) cracks or crack-like anomalies
meeting specified criteria.
    The final rule also designates the following types of defects as 1-
year conditions: (1) smooth topside dents with a depth greater than 6
percent of the pipeline diameter; (2) dents greater than 2 percent of
the pipeline diameter that are located at a girth weld or spiral seam
weld; (3) a bottom-side dent that has metal loss, cracking, or a stress
riser; (4) metal loss anomalies where a calculation of the remaining
strength of the pipe shows a predicted failure pressure ratio less than
or equal to 1.39 for Class 2 locations, and 1.50 for Class 3 locations
and Class 4 locations; (5) anomalies where there is metal loss that is
at a crossing of another pipeline, is in an area with widespread
circumferential corrosion, or is in an area that could affect a girth
weld, and that has a predicted failure pressure less than 1.39 in Class
1 locations or where Class 2 locations contain Class 1 pipe that has
been uprated in accordance with Sec.  192.611, and less than 1.50 times
the MAOP in all other Class 2 locations and all Class 3 and 4
locations; (6) anomalies where there is metal loss affecting a
longitudinal seam; and (7) any indications of cracks or crack-like
defects other than those listed as an immediate condition.
    In this final rule, PHMSA is also adding requirements for
addressing regulatory gaps related to the methods for calculating
predicted failure pressure if metal loss exceeds 80 percent of wall
thickness; time-sensitive integrity threats including corrosion
affecting a longitudinal seam, especially those associated with seam
types that are known to be susceptible to latent manufacturing defects,
such as the failed pipe at San Bruno,\53\ and selective seam weld
corrosion; and the fact that the current regulations do not list SCC as
an immediate condition even though it is listed in ASME/ANSI B31.8S as
an immediate repair condition.
---------------------------------------------------------------------------

    \53\ These seam types include seams formed by direct current,
low- or high-frequency electric resistance welding, electric flash
welding, or with a longitudinal joint factor less than 1.0, and
where the predicted failure pressure, determined in accordance with
Sec.  192.712(d), is less than 1.25 times the MAOP.
---------------------------------------------------------------------------

    With respect to SCC, PHMSA has incorporated repair criteria to
specify that operators must use engineering assessment techniques
specified in Sec.  192.712 to evaluate if cracks or crack-like
anomalies should be categorized as an ``immediate'' condition, a ``1-
year'' condition, or a ``monitored'' condition. PHMSA believes that
this will help address NTSB recommendation P-12-3, which resulted from
the investigation of the Enbridge accident near Marshall, MI.\54\
Although the NTSB recommendation was specifically made for hazardous
liquid pipelines regulated under part 195, SCC can affect gas
transmission pipelines regulated under part 192 as well.
---------------------------------------------------------------------------

    \54\ See NTSB Recommendation P-12-3, available at https://www.ntsb.gov/_layouts/ntsb.recsearch/Recommendation.aspx?Rec=P-12-003.
---------------------------------------------------------------------------

    The current regulations do not include 1-year conditions for metal
loss anomalies. For non-immediate conditions, the regulations direct
operators to use Figure 4 in ASME/ANSI B31.8S to determine the repair
criteria for metal loss anomalies that do not meet the ``immediate''
threshold. To address this gap, PHMSA is including certain metal loss
anomalies in the list of 1-year conditions. These changes make the gas
transmission repair criteria more consistent with the hazardous liquid
repair criteria at 49 CFR 195.452(h).
    PHMSA is also incorporating safety factors commensurate with the
class location in which the pipeline is located to make 1-year
conditions anomalies where the predicted failure pressure is less than
or equal to 1.39 times MAOP in Class 2 locations, and 1.50 times MAOP
in Class 3 and Class 4 locations in HCAs. Operators must continue to
use ASME/ANSI B31.8S, Figure 4 for corrosion metal loss anomalies in
Class 1 locations.
    Additionally, the NTSB recommended that PHMSA revise the
``discovery of condition'' at 49 CFR 195.452(h)(2) to require, in cases
where a determination about pipeline threats has not been obtained
within 180 days following the date of inspection, that pipeline
operators notify PHMSA and provide an expected date when adequate
information will become available.\55\ PHMSA incorporated this NTSB
recommendation into Sec. Sec.  195.416(f) and 195.452(h)(2) of the
``Safety of Hazardous Liquid Pipelines'' final rule, which was
published on October 1, 2019.\56\
---------------------------------------------------------------------------

    \55\ NTSB Recommendation P-12-4, available at https://www.ntsb.gov/safety/safety-recs/_layouts/ntsb.recsearch/Recommendation.aspx?Rec=P-12-004.
    \56\ See 84 FR 52260.
---------------------------------------------------------------------------

    Although the NTSB made the recommendation for hazardous liquid
pipelines regulated under part 195, the issue applies to gas
transmission pipelines regulated under part 192 as well. Accordingly,
PHMSA has

amended paragraph (b) of Sec.  192.933 to require that operators notify
PHMSA whenever the operator cannot obtain sufficient information to
determine if a condition presents a potential threat to the integrity
of the pipeline within 180 days of completing the assessment.
    PHMSA is also finalizing requirements for the in situ evaluation of
cracks and crack-like defects using in-the-ditch tools whenever an
operator discovers conditions that need to be repaired, such as when an
ILI, an SCCDA, a pressure test failure, or another assessment
identifies such anomalies. This applies to IM pipelines the same
requirement adopted in Sec.  192.714(g) for non-IM pipelines.

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

    Section 192.935 requires an operator to take additional measures
beyond those already required by part 192 to prevent a pipeline failure
and to mitigate the consequences of a pipeline failure in an HCA. An
operator must conduct a risk analysis to identify the additional
measures to protect the HCA and improve public safety. As discussed
earlier, PHMSA is amending Sec.  192.917 to clarify the guidance for
risk analyses operators use to evaluate and select additional P&M
measures. This final rule also adds specific enhanced measures for
operators to use for managing internal and external corrosion in HCAs
and expands the list of P&M measures operators must consider when
providing for public safety.
    Specifically, operators must explicitly consider the following P&M
measures:

    (i) Correcting the root causes of past incidents in order to
prevent recurrence;
    (ii) O&M processes that maintain safety and the pipeline MAOP;
    (iii) Adequate resources for the successful execution of these
activities within the required timeframe;
    (iv) Pressure transmitters that communicate with the pipeline
control center on both sides of automatic shut-off valves and
remote-control valves;
    (v) Additional right-of-way patrols;
    (vi) Hydrostatic tests in areas where pipeline material has
quality issues or records that are not traceable, verifiable, and
complete;
    (vii) Tests to determine unknown material, mechanical, or
chemical properties that are needed to ensure pipeline integrity or
substantiate MAOP, including material property tests from removed
pipe that is representative of the in-service pipeline;
    (viii) The re-coating of damaged, poorly performing, or
disbonded coatings, and
    (ix) Additional depth-of-cover surveys at roads, streams, and
rivers, among other areas.

    These P&M measures do not alter the fundamental requirement for
operators to identify and implement P&M measures; rather, they provide
additional guidance and clarify PHMSA's expectations with this
important aspect of IM.
    Section 29 of the 2011 Pipeline Safety Act requires operators to
consider seismicity when evaluating threats. In the 2019 Gas
Transmission Rule, PHMSA revised Sec.  192.917 to include seismicity as
a potential threat for operators to identify and evaluate. In this
final rule, PHMSA is revising this section to require operators
consider the seismicity of the area when evaluating additional P&M
measures against the threat of outside force damage.

Section 192.941 What is a low stress reassessment?

    Section 192.941 specifies that, to address the threat of external
corrosion on cathodically protected pipe in an HCA segment, an operator
must perform an electrical survey (i.e., with an indirect examination
tool or method) at least every 7 years. In this final rule, PHMSA is
replacing the term ``electrical survey'' with ``indirect assessment''
to accommodate other techniques that are comparably effective.

V. Standards Incorporated by Reference

A. Summary of New and Revised Standards

    Consistent with the amendments in this document, PHMSA is
incorporating by reference into the PSR several standards as described
below. Some of these standards are already incorporated by reference
into the PSR and are being extended to other sections of the
regulations. Other standards provide a technical basis for
corresponding regulatory changes in this final rule.
     NACE Standard Practice 0204-2008, ``Stress Corrosion
Cracking (SCC) Direct Assessment Methodology'' (Sept. 18, 2008).
    This standard addresses the situation in which a portion of a
pipeline has been identified as an area of interest with respect to SCC
based on its history, operations, and risk assessment process, and it
has been decided that direct assessment is an appropriate approach for
integrity assessment. The incorporation of this standard into the PSR
would provide guidance for managing SCC through the selection of
potential pipeline segments, selecting dig sites within those segments,
inspecting the pipe, collecting and analyzing data during the dig,
establishing a mitigation program, defining the re-evaluation interval,
and evaluating the effectiveness of the SCCDA process.
     NACE Standard Practice 0206-2006, ``Internal Corrosion
Direct Assessment Methodology for Pipelines Carrying Normally Dry
Natural Gas'' (DG-ICDA) (Dec. 1, 2006).
    This standard practice formalizes an internal corrosion direct
assessment method (DG-ICDA) that can be used to help ensure pipeline
integrity for pipelines carrying normally dry natural gas. The method
is applicable to natural gas pipelines that normally carry dry gas but
that may suffer from infrequent, short-term upsets of liquid water (or
other electrolyte). This standard is intended for use by pipeline
operators and others who manage pipeline integrity. The basis of DG-
ICDA is a detailed examination of locations along a pipeline where
water would first accumulate and provides information about the
downstream condition of the pipeline. If the locations along a length
of pipe most likely to accumulate water have not corroded, other
downstream locations less likely to accumulate water may be considered
free from corrosion. The presence of extensive corrosion found at many
locations during the evaluation suggests that the transported gas was
not normally dry, and this standard would not be considered applicable.
     ASME/ANSI B31.8S-2004, ``Supplement to B31.8 on Managing
System Integrity of Gas Pipelines'' (Jan. 14, 2005).
    This standard covers onshore gas pipeline systems constructed with
ferrous materials, including pipe, valves, appurtenances attached to
pipe, compressor units, metering stations, regulator stations, delivery
stations, holders, and fabricated assemblies. ASME/ANSI B31.8S is
specifically designed to provide the operator with the information
necessary to develop and implement an effective IM program using proven
industry practices and processes. Effective system management can
decrease repair and replacement costs, prevent malfunctions, and
minimize system downtime.
    The incorporation by reference of ASME/ANSI B31.8S-2004 was
approved for Sec. Sec.  192.921 and 192.937 as of January 14, 2004.
That approval is unaffected by the section revisions in this final
rule.
     ANSI/NACE Standard Practice 0502-2010, ``Pipeline External
Corrosion Direct Assessment Methodology'' (June 24, 2010).
    This standard covers the NACE external corrosion direct assessment
(ECDA) process, which assesses and

reduces the impact of external corrosion on pipeline integrity. ECDA is
a continuous-improvement process providing the advantages of locating
areas where defects can form in the future, not just areas where
defects have already formed, thereby helping to prevent future external
corrosion damage. This standard covers the four components of ECDA:
Pre-Assessment, Indirect Inspections, Direct Examinations, and Post-
Assessment.
    The incorporation by reference of ANSI/NACE Standard Practice 0502-
2010 was approved for Sec. Sec.  192.923, 192.925, 192.931, 192.935,
and 192.939 as of March 6, 2015. That approval is unaffected by the
section revisions in this final rule.
    The incorporation by reference of R-STRENG and ASME/ANSI B31G in
certain sections of this rule was approved July 1, 2020, and remains
unaffected by the revisions in this final rule.

B. Availability of Standards Incorporated by Reference

    PHMSA currently incorporates by reference into 49 CFR parts 192,
193, and 195 all or parts of more than 80 standards and specifications
developed and published by standard developing organizations (SDO). In
general, SDOs update and revise their published standards every 2 to 5
years to reflect modern technology and best technical practices.
    The National Technology Transfer and Advancement Act of 1995 (Pub.
L. 104-113; NTTAA) directs Federal agencies to use standards developed
by voluntary consensus standards bodies in lieu of government-written
standards whenever possible. Voluntary consensus standards bodies
develop, establish, or coordinate technical standards using agreed-upon
procedures. In addition, the Office of Management and Budget (OMB)
issued Circular A-119 to implement section 12(d) of the NTTAA relative
to the utilization of consensus technical standards by Federal
agencies.\57\ This circular provides guidance for agencies
participating in voluntary consensus standards bodies and describes
procedures for satisfying the reporting requirements in the NTTAA.
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    \57\ 81 FR 4673 (Jan. 27, 2016).
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    Accordingly, PHMSA has the responsibility for determining, via
petitions or otherwise, which currently referenced standards should be
updated, revised, or removed, and which standards should be added to
the PSR. Revisions to materials incorporated by reference in the PSR
are handled via the rulemaking process, which allows for the public and
regulated entities to provide input. During the rulemaking process,
PHMSA must also obtain approval from the Office of the Federal Register
to incorporate by reference any new materials.
    Pursuant to 49 U.S.C. 60102(p), PHMSA may not issue PSR amendments
that incorporate by reference any documents or portions thereof unless
the documents or portions thereof are made available to the public,
free of charge. Further, the Office of the Federal Register issued a
rulemaking on November 7, 2014, revising 1 CFR 51.5(b) to require that
agencies detail in the preamble of a final rulemaking the ways the
materials it incorporates by reference are reasonably available to
interested parties, and how interested parties can obtain those
materials.\58\
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    \58\ 79 FR 66278.
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    To meet its statutory obligation for this rulemaking, PHMSA
negotiated agreements with SDOs to provide free online access to
standards that are incorporated by reference or proposed to be
incorporated by reference. PHMSA will also provide individual members
of the public temporary access to any standard that is incorporated by
reference. Requests for access can be sent to the following email
address: [email protected]; please include your phone number,
physical address, and an email address and PHMSA will respond within 5
business days and provide access to the standard. PHMSA also notes that
standards incorporated by reference in the PSR can be obtained from the
organization developing each standard. Section 192.7 provides the
contact information for each of those standard-developing
organizations.

VI. Regulatory Analysis and Notices

A. Statutory/Legal Authority for This Rulemaking

    This final rule is published under the existing authorities of the
Secretary of Transportation delegated to the PHMSA Administrator
pursuant to 49 CFR 1.97. Among the statutory authorities delegated to
PHMSA are section 60102 of the Federal Pipeline Safety Statutes (49
U.S.C. 60101 et seq.) (authorizing issuance of regulations governing
design, installation, inspection, emergency plans and procedures,
testing, construction, extension, operation, replacement, and
maintenance of pipeline facilities) and section 28 of the Mineral
Leasing Act, as amended (30 U.S.C. 185(w)(3)). For a complete listing
of authorities, see 49 CFR 1.97.

B. Executive Order 12866 and DOT Regulatory Policies and Procedures

    Executive Order 12866 (``Regulatory Planning and Review'') \59\
requires that agencies ``should assess all costs and benefits of
available regulatory alternatives, including the alternative of not
regulating.'' Agencies should consider quantifiable measures and
qualitative measures of costs and benefits that are difficult to
quantify. Further, Executive Order 12866 requires that agencies
``should maximize net benefits (including potential economic,
environmental, public health and safety, and other advantages;
distributive impacts; and equity), unless a statute requires another
regulatory approach.'' Similarly, DOT Order 2100.6A (``Rulemaking and
Guidance Procedures'') requires that regulations issued by PHMSA and
other DOT Operating Administrations should consider an assessment of
the potential benefits, costs, and other important impacts of the
proposed action and should quantify (to the extent practicable) the
benefits, costs, and any significant distributional impacts, including
any environmental impacts. The Federal Pipeline Safety Statutes at 49
U.S.C. 60102(b)(5) further authorize only those safety requirements
whose benefits (including safety and environmental benefits) have been
determined to justify their costs.
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    \59\ 58 FR 51735 (Oct. 4, 1993).
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    This action has been determined to be significant under Executive
Order 12866. It is also considered significant under DOT Order 2100.6A
because of significant congressional, State, industry, and public
interest in pipeline safety. The final rule has been reviewed by the
Office of Management and Budget in accordance with Executive Order
12866 and is consistent with the requirements of Executive Order 12866,
49 U.S.C. 60102(b)(5), and DOT Order 2100.6. The Office of Information
and Regulatory Affairs (OIRA) has not designated this rule as a ``major
rule'' as defined by the Congressional Review Act (5 U.S.C. 801 et
seq.).
    Executive Order 12866 and DOT Order 2100.6A also require PHMSA to
provide a meaningful opportunity for public participation, which also
reinforces requirements for notice and comment under the Administrative
Procedure Act (5 U.S.C. 551 et seq.). Therefore, in the NPRM, PHMSA
sought public comment on its proposed revisions to the PSR and the
preliminary cost and benefit analyses in the PRIA, as

well as any information that could assist in quantifying the costs and
benefits of this rulemaking. Those comments are addressed in this final
rule, and additional discussion about the costs and benefits of the
final rule are provided within the RIA posted in the rulemaking docket.
    The table below summarizes the annualized costs for the provisions
in the final rule. These estimates reflect the timing of the compliance
actions taken by operators and are annualized, where applicable, over
20 years and discounted using rates of 3 percent and 7 percent. PHMSA
estimates incremental costs for the final requirements in section 5 of
the RIA. The costs of this final rule reflect MOC process improvements,
additional corrosion control requirements, programmatic changes related
to inspections following extreme weather events, and compliance with
the revised repair criteria. PHMSA finds that the other final rule
requirements will not result in an incremental cost. PHMSA estimates
the annualized cost of this rule is $16.7 million at a 7 percent
discount rate.

       Table 1--Annualized Cost of the Final Rule, Year 1-Year 20
                          [$2019 USD thousands]
------------------------------------------------------------------------
                                                   Discount rate
                Provision                -------------------------------
                                                3%              7%
------------------------------------------------------------------------
Integrity Management Process                          $0              $0
 Improvements *.........................
Management of Change Process                       1,194           1,223
 Improvements...........................
Corrosion Control.......................           8,662           8,998
Extreme Weather.........................              55              78
Repair Criteria.........................           2,725           6,357
                                         -------------------------------
    Total...............................          12,637          16,656
------------------------------------------------------------------------
* No incremental costs are estimated for this topic area.

    The benefits of the final rule consist of improved safety and
avoided environmental harms (including greenhouse gas emissions) from
reduction of risk of incidents on natural gas pipelines and will depend
on the degree to which compliance actions result in additional safety
measures, relative to the baseline, and the effectiveness of these
measures in preventing or mitigating future pipeline releases or other
incidents. PHMSA changed its benefit analysis approach for the RIA
relative to the PRIA. The PRIA quantified and monetized the NPRM's
benefits, while the RIA does not monetize this final rule's benefits.
PHMSA chose not to monetize benefits in the RIA based on the public
comments received in response to the PRIA and the uncertainty
associated with quantifying changes in incident rates that can be
explicitly attributed to the final rule's provisions.
    For more information, please see the RIA posted in the rulemaking
docket.

C. Regulatory Flexibility Act

    The Regulatory Flexibility Act (5 U.S.C. 601 et seq.) requires
agencies to prepare a Final Regulatory Flexibility Analysis (FRFA) for
any final rule subject to notice-and-comment rulemaking under the APA
unless the agency head certifies that the rule will not have a
significant economic impact on a substantial number of small entities.
This final rule was developed in accordance with Executive Order 13272
(``Proper Consideration of Small Entities in Agency Rulemaking'') \60\
to promote compliance with the Regulatory Flexibility Act and to ensure
that the potential impacts of the rulemaking on small entities has been
properly considered.
---------------------------------------------------------------------------

    \60\ 68 FR 7990 (Feb. 19, 2003).
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    PHMSA prepared a FRFA, which is available in the docket for the
rulemaking. In it, PHMSA certifies that the rule will not have a
significant impact on a substantial number of small entities.

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

    PHMSA analyzed this final rule per the principles and criteria in
Executive Order 13175 (``Consultation and Coordination with Indian
Tribal Governments'') \61\ and DOT Order 5301.1 (``Department of
Transportation Policies, Programs, and Procedures Affecting American
Indians, Alaska Natives, and Tribes''). Executive Order 13175 requires
agencies to assure meaningful and timely input from Tribal Government
representatives in the development of rules that significantly or
uniquely affect Tribal communities by imposing ``substantial direct
compliance costs'' or ``substantial direct effects'' on such
communities or the relationship and distribution of power between the
Federal Government and Tribes.
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    \61\ 65 FR 67249 (Nov. 6, 2000).
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    PHMSA assessed the impact of the rulemaking and determined that it
would not significantly or uniquely affect Tribal communities or Tribal
governments. The rulemaking's regulatory amendments are facially
neutral and would have broad, national scope; PHMSA, therefore, does
not expect this rulemaking to significantly or uniquely affect Tribal
communities, much less impose substantial compliance costs on Native
American Tribal governments or mandate Tribal action. And insofar as
PHMSA expects the rulemaking will improve transmission pipeline safety
and environmental risks, PHMSA does not expect it would entail
disproportionately high adverse risks for Tribal communities. PHMSA
also received no comments alleging ``substantial direct compliance
costs'' or ``substantial direct effects'' on Tribal communities and
Governments. For these reasons, PHMSA has determined the funding and
consultation requirements of Executive Order 13175 and DOT Order 5301.1
do not apply.

E. Paperwork Reduction Act

    Under the Paperwork Reduction Act of 1995 (44 U.S.C. 3501 et seq.),
no person is required to respond to an information collection unless it
has been approved by OMB and displays a valid OMB control number.
Pursuant to implementing regulations at 5 CFR 1320.8(d), PHMSA is
required to provide interested members of the public and affected
agencies with an opportunity to comment on information collection and
recordkeeping requests.
    On April 8, 2016, PHMSA published an NPRM seeking public comments
on proposed revisions of the PSR

applicable to the safety of gas transmission pipelines and gas
gathering pipelines. Based on the provisions in the NPRM, PHMSA
proposed corresponding changes to information collections. PHMSA
determined it would be more effective to first advance a rulemaking
that focused on the mandates from the 2011 Pipeline Safety Act and
subsequently split out the other provisions contained in the NPRM into
three separate rules. As such, in this rulemaking, PHMSA has removed
all references to the changes in the information collections covered in
those other rulemakings. PHMSA will submit information collection
revision requests to OMB based on the requirements contained within
this final rule.
    PHMSA estimates that the proposals in this final rule will involve
new and amended information collections as described below. The
following information is provided for each information collection: (1)
title of the information collection; (2) OMB control number; (3)
current expiration date; (4) type of request; (5) abstract of the
information collection activity; (6) description of affected public;
(7) estimate of total annual reporting and recordkeeping burden; and
(8) frequency of collection. Relevant information collections consist
of the following:
    1. Title: Record Keeping Requirements for Gas Pipeline Operators.
    OMB Control Number: 2137-0049.
    Current Expiration Date: 3/31/2025.
    Abstract: A person owning or operating a natural gas pipeline
facility is required to maintain records, make reports, and provide
information to the Secretary of Transportation upon request. Based on
the proposed revisions in this final rule, 16 new recordkeeping
requirements are being added to the pipeline safety regulations for
owners and operators of gas transmission pipelines. PHMSA expects these
new mandatory recordkeeping requirements to result in 1,902 responses
and 9,530 burden hours.
    Affected Public: Gas Transmission Pipeline Operators.
    Annual Reporting and Recordkeeping Burden:
    Total Annual Responses: 3,863,374.
    Total Annual Burden Hours: 1,686,560.
    Frequency of Collection: On occasion.
    2. Title: Notification Requirements for Gas Transmission Pipelines.
    OMB Control Number: 2137-0636.
    Current Expiration Date: 01/31/2023.
    Abstract: A person owning or operating a natural gas pipeline
facility is required to provide information to the Secretary of
Transportation at the Secretary's request in accordance with 49 U.S.C.
60117. The regulations in 49 CFR part 192 require operators to make
various notifications upon the occurrence of certain events. Based on
the proposed revisions in this final rule, 6 new notification
requirements are being added to the PSR for owners and operators of gas
transmission pipelines. PHMSA expects these revisions to result in 268
additional responses and 290 additional burden hours for this
information collection. These mandatory notification requirements are
necessary to ensure safe operation of transmission pipelines, ascertain
compliance with gas pipeline safety regulations, and to provide a
background for incident investigations.
    Affected Public: Gas Transmission Pipeline Operators.
    Annual Reporting and Recordkeeping Burden:
    Total Annual Responses: 990.
    Total Annual Burden Hours: 1,360.
    Frequency of Collection: On occasion.
    3. Title: Annual Reports for Gas Pipeline Operators
    OMB Control Number: 2137-0522.
    Current Expiration Date: 3/31/2025.
    Abstract: This information collection covers the collection of
annual report data from natural gas pipeline operators. PHMSA is
revising the Gas Transmission and Gas Gathering Annual Report (form
PHMSA F7 100.2-1) to collect more granular data on conditions being
repaired outside of HCA segments. Operators currently provide the
number of anomalies outside of HCAs based on assessment methods,
however, PHMSA requires operators to further categorize the data in
accordance with 49 CFR 192.713. Based on the proposed revisions, PHMSA
estimates that it will take an additional 30 minutes per report to
include the newly required data--increasing the burden for completing
each annual report to 47.5 hours. This change results in an overall
burden increase of 905 hours for this information collection.
    Affected Public: Natural Gas Pipeline Operators.
    Annual Reporting and Recordkeeping Burden:
    Total Annual Responses: 3,053.
    Total Annual Burden Hours: 95,521.
    Frequency of Collection: On occasion.
    Requests for copies of these information collections should be
directed to Angela Hill or Cameron Satterthwaite, Office of Pipeline
Safety (PHP-30), Pipeline Hazardous Materials Safety Administration
(PHMSA), 2nd Floor, 1200 New Jersey Avenue, SE, Washington, DC 20590-
0001, Telephone<PHONE_NUMBER>.

F. Unfunded Mandates Reform Act of 1995

    The Unfunded Mandates Reform Act (2 U.S.C. 1501 et seq.) requires
agencies to assess the effects of Federal regulatory actions on State,
local, and Tribal governments, and the private sector. For any NPRM or
final rule that includes a Federal mandate that may result in the
expenditure by State, local, and Tribal governments, in the aggregate,
or by the private sector of $100 million or more in 1996 dollars in any
given year, the agency must prepare, amongst other things, a written
statement that qualitatively and quantitatively assesses the costs and
benefits of the Federal mandate.
    As explained in the RIA, PHMSA determined that this final rule does
not impose enforceable duties on State, local, or Tribal governments or
on the private sector of $100 million or more (in 1996 dollars) in any
one year. A copy of the RIA is available for review in the docket.

G. National Environmental Policy Act

    The National Environmental Policy Act of 1969 (42 U.S.C. 4321 et
seq., NEPA), requires Federal agencies to consider the consequences of
major Federal actions and prepare a detailed statement on actions
significantly affecting the quality of the human environment. The
Council on Environmental Quality implementing regulations (40 CFR parts
1500-1508) require Federal agencies to conduct an environmental review
considering (1) the need for the action, (2) alternatives to the
action, (3) probable environmental impacts of the action and
alternatives, and (4) the agencies and persons consulted during the
consideration process. DOT Order 5610.1C (``Procedures for Considering
Environmental Impacts'') establishes departmental procedures for
evaluation of environmental impacts under NEPA and its implementing
regulations.
    PHMSA has completed its NEPA analysis. Based on the environmental
assessment, PHMSA determined that an environmental impact statement is
not required for this rulemaking because it will not have a significant
impact on the human environment. The final EA and Finding of No
Significant Impact have been placed into the docket addressing the
comments received.

H. Executive Order 13132

    PHMSA analyzed this final rule in accordance with Executive Order
13132 (``Federalism'').\62\ Executive Order

13132 requires agencies to assure meaningful and timely input by State
and local officials in the development of regulatory policies that may
have ``substantial direct effects on the States, on the relationship
between the national government and the States, or on the distribution
of power and responsibilities among the various levels of government.''
---------------------------------------------------------------------------

    \62\ 64 FR 43255 (Aug.10, 1999).
---------------------------------------------------------------------------

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

I. Executive Order 13211

    Executive Order 13211 (``Actions Concerning Regulations That
Significantly Affect Energy Supply, Distribution, or Use'') \63\
requires Federal agencies to prepare a Statement of Energy Effects for
any ``significant energy action.'' Executive Order 13211 defines a
``significant energy action'' as any action by an agency (normally
published in the Federal Register) that promulgates, or is expected to
lead to the promulgation of, a final rule or regulation that (1)(i) is
a significant regulatory action under Executive Order 12866 or any
successor order and (ii) is likely to have a significant adverse effect
on the supply, distribution, or use of energy (including a shortfall in
supply, price increases, and increased use of foreign supplies); or (2)
is designated by the Administrator of the OIRA as a significant energy
action.
---------------------------------------------------------------------------

    \63\ 66 FR 28355 (May 18, 2001).
---------------------------------------------------------------------------

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

J. Privacy Act Statement

    Anyone may search the electronic form of all comments received for
any of our dockets. You may review DOT's complete Privacy Act Statement
\64\ at: https://www.govinfo.gov/content/pkg/FR-2000-04-11/pdf/00-8505.pdf.
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    \64\ 65 FR 19476 (Apr. 11, 2000).
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K. Executive Order 13609 and International Trade Analysis

    Executive Order 13609 (``Promoting International Regulatory
Cooperation'') \65\ requires agencies consider whether the impacts
associated with significant variations between domestic and
international regulatory approaches are unnecessary or may impair the
ability of American business to export and compete internationally. In
meeting shared challenges involving health, safety, labor, security,
environmental, and other issues, international regulatory cooperation
can identify approaches that are at least as protective as those that
are or would be adopted in the absence of such cooperation.
International regulatory cooperation can also reduce, eliminate, or
prevent unnecessary differences in regulatory requirements.
---------------------------------------------------------------------------

    \65\ 77 FR 26413 (May 4, 2012).
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    Similarly, the Trade Agreements Act of 1979 (Pub. L. 96-39), as
amended by the Uruguay Round Agreements Act (Pub. L. 103-465),
prohibits Federal agencies from establishing any standards or engaging
in related activities that create unnecessary obstacles to the foreign
commerce of the United States. For purposes of these requirements,
Federal agencies may participate in the establishment of international
standards, so long as the standards have a legitimate domestic
objective, such as providing for safety, and do not operate to exclude
imports that meet this objective. The statute also requires
consideration of international standards and, where appropriate, that
they be the basis for U.S. standards.
    PHMSA participates in the establishment of international standards
to protect the safety of the American public. PHMSA has assessed the
effects of the rulemaking and determined that it will not cause
unnecessary obstacles to foreign trade.

L. Environmental Justice

    DOT Order 5610.2(b) and Executive Orders 12898 (``Federal Actions
to Address Environmental Justice in Minority Populations and Low-Income
Populations''),\66\ 13985 (``Advancing Racial Equity and Support for
Underserved Communities Through the Federal Government''),\67\ 13990
(``Protecting Public Health and the Environment and Restoring Science
To Tackle the Climate Crisis''),\68\ and 14008 (``Tackling the Climate
Crisis at Home and Abroad'') \69\ require DOT operational
administrations to achieve environmental justice as part of their
mission by identifying and addressing, as appropriate,
disproportionately high and adverse human health or environmental
effects, including interrelated social and economic effects, of their
programs, policies, and activities on minority populations, low-income
populations, and other underserved disadvantaged communities.
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    \66\ 59 FR 7629 (Feb. 16, 1994).
    \67\ 86 FR 7009 (Jan. 20, 2021).
    \68\ 86 FR 7037 (Jan. 20, 2021).
    \69\ 86 FR 7619 (Feb. 1, 2021).
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    PHMSA has evaluated this final rule under DOT Order 5610.2(b) and
the Executive Orders listed above and determined it would not cause
disproportionately high and adverse human health and environmental
effects on minority populations, low-income populations, and other
underserved and disadvantaged communities. The rulemaking is facially
neutral and national in scope; it is neither directed toward a
particular population, region, or community, nor is it expected to
adversely impact any particular population, region, or community. And
insofar as PHMSA expects the rulemaking would reduce the safety and
environmental risks associated with natural gas transmission pipelines,
many of which are located in the vicinity of environmental justice
communities,\70\ PHMSA expects the regulatory amendments introduced by
this final rule would reduce adverse human health and environmental
risks for minority populations, low-income populations, and other
underserved and other disadvantaged communities in the vicinity of
those pipelines. Lastly, as

explained in the final EA, PHMSA expects that the regulatory amendments
in this final rule will yield GHG emissions reductions, thereby
reducing the risks posed by anthropogenic climate change to minority,
low-income, underserved, and other disadvantaged populations and
communities.
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    \70\ See Ryan Emmanuel, et al., ``Natural Gas Gathering and
Transmission Pipelines and Social Vulnerability in the United
States,'' 5:6 GeoHealth (June 2021), https://agupubs.onlinelibrary.wiley.com/toc/24711403/2021/5/6 (concluding
that natural gas gathering and transmission infrastructure is
disproportionately sited in socially-vulnerable communities).
---------------------------------------------------------------------------

List of Subjects in 49 CFR Part 192

    Corrosion control, Incorporation by reference, Installation of pipe
in a ditch, Integrity management, Internal inspection device,
Management of change, Pipeline safety, Repair criteria, Surveillance.
    In consideration of the foregoing, PHMSA amends 49 CFR part 192 as
follows:

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

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

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

0
2. In Sec.  192.3:
0
a. Add definitions for ``Close interval survey'', ``Distribution
center'', ``Dry gas or dry natural gas'', ``Hard spot'', ``In-line
inspection (ILI)'', and ``In-line inspection tool or instrumented
internal inspection device'' in alphabetical order;
0
b. Revise the definition for ``Transmission line''; and
0
c. Add the definition ``Wrinkle bend'' in alphabetical order.
    The additions and revision read as follows:

Sec.  192.3   Definitions.

* * * * *
    Close interval survey means a series of closely and properly spaced
pipe-to-electrolyte potential measurements taken over the pipe to
assess the adequacy of cathodic protection or to identify locations
where a current may be leaving the pipeline that may cause corrosion
and for the purpose of quantifying voltage (IR) drops other than those
across the structure electrolyte boundary, such as when performed as a
current interrupted, depolarized, or native survey.
* * * * *
    Distribution center means the initial point where gas enters piping
used primarily to deliver gas to customers who purchase it for
consumption, as opposed to customers who purchase it for resale, for
example:
    (1) At a metering location;
    (2) A pressure reduction location; or
    (3) Where there is a reduction in the volume of gas, such as a
lateral off a transmission line.
* * * * *
    Dry gas or dry natural gas means gas above its dew point and
without condensed liquids.
* * * * *
    Hard spot means an area on steel pipe material with a minimum
dimension greater than two inches (50.8 mm) in any direction and
hardness greater than or equal to Rockwell 35 HRC (Brinell 327 HB or
Vickers 345 HV10).
* * * * *
    In-line inspection (ILI) means an inspection of a pipeline from the
interior of the pipe using an inspection tool also called intelligent
or smart pigging. This definition includes tethered and self-propelled
inspection tools.
    In-line inspection tool or instrumented internal inspection device
means an instrumented device or vehicle that uses a non-destructive
testing technique to inspect the pipeline from the inside in order to
identify and characterize flaws to analyze pipeline integrity; also
known as an intelligent or smart pig.
* * * * *
    Transmission line means a pipeline or connected series of
pipelines, other than a gathering line, that:
    (1) Transports gas from a gathering pipeline or storage facility to
a distribution center, storage facility, or large volume customer that
is not down-stream from a distribution center;
    (2) Has an MAOP of 20 percent or more of SMYS;
    (3) Transports gas within a storage field; or
    (4) Is voluntarily designated by the operator as a transmission
pipeline.
    Note 1 to transmission line. A large volume customer may receive
similar volumes of gas as a distribution center, and includes
factories, power plants, and institutional users of gas.
* * * * *
    Wrinkle bend means a bend in the pipe that:
    (1) Was formed in the field during construction such that the
inside radius of the bend has one or more ripples with:
    (i) An amplitude greater than or equal to 1.5 times the wall
thickness of the pipe, measured from peak to valley of the ripple; or
    (ii) With ripples less than 1.5 times the wall thickness of the
pipe and with a wrinkle length (peak to peak) to wrinkle height (peak
to valley) ratio under 12.
    (2)(i) If the length of the wrinkle bend cannot be reliably
determined, then wrinkle bend means a bend in the pipe where (h/D)*100
exceeds 2 when S is less than 37,000 psi (255 MPa), where (h/D)*100
exceeds for psi [ for MPa] when S is greater than 37,000 psi (255 MPa)
but less than 47,000 psi (324 MPa), and where (h/D)*100 exceeds 1 when
S is 47,000 psi (324 MPa) or more.
    (ii) Where:

    (A) D = Outside diameter of the pipe, in. (mm);
    (B) h = Crest-to-trough height of the ripple, in. (mm); and
    (C) S = Maximum operating hoop stress, psi (S/145, MPa).

0
3. In Sec.  192.7:
0
a. Revise paragraphs (a) and (c)(6);
0
b. Redesignate paragraph (h)(1) as paragraph (h)(4) and paragraph
(h)(2) as paragraph (h)(1);
0
c. Add new paragraph (h)(2) and paragraph (h)(3); and
0
d. Revise newly redesignated paragraph (h)(4).
    The revisions and additions read as follows:

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

    (a) Certain material is incorporated by reference into this part
with the approval of the Director of the Federal Register under 5
U.S.C. 552(a) and 1 CFR part 51. All approved material is available for
inspection at the Office of Pipeline Safety, Pipeline and Hazardous
Materials Safety Administration, 1200 New Jersey Avenue SE, Washington,
DC 20590,<PHONE_NUMBER>, https://www.phmsa.dot.gov/pipeline/regs, and at
the National Archives and Records Administration (NARA). For
information on the availability of this material at NARA, email
[email protected], or go to www.archives.gov/federal-register/cfr/ibr-locations.html. It is also available from the sources in the
following paragraphs of this section.
* * * * *
    (c) * * *
    (6) ASME/ANSI B31.8S-2004, ``Supplement to B31.8 on Managing System
Integrity of Gas Pipelines,'' approved January 14, 2005, (ASME/ANSI
B31.8S), IBR approved for Sec. Sec.  192.13(d); 192.714(c) and (d);
192.903 note to potential impact radius; 192.907 introductory text and
(b); 192.911 introductory text, (i), and (k) through (m); 192.913(a)
through (c); 192.917(a) through (e); 192.921(a); 192.923(b);
192.925(b); 192.927(b) and (c); 192.929(b); 192.933(c) and (d);
192.935(a) and (b); 192.937(c); 192.939(a); and 192.945(a).
* * * * *

    (h) * * *
    (2) NACE SP0204-2008, Standard Practice, ``Stress Corrosion
Cracking (SCC) Direct Assessment Methodology,'' reaffirmed September
18, 2008, (NACE SP0204); IBR approved for Sec. Sec.  192.923(b);
192.929(b) introductory text, (b)(1) through (3), (b)(5) introductory
text, and (b)(5)(i).
    (3) NACE SP0206-2006, Standard Practice, ``Internal Corrosion
Direct Assessment Methodology for Pipelines Carrying Normally Dry
Natural Gas (DG-ICDA),'' approved December 1, 2006, (NACE SP0206), IBR
approved for Sec. Sec.  192.923(b); 192.927(b), (c) introductory text,
and (c)(1) through (4).
    (4) ANSI/NACE SP0502-2010, Standard Practice, ``Pipeline External
Corrosion Direct Assessment Methodology,'' revised June 24, 2010, (NACE
SP0502), IBR approved for Sec. Sec.  192.319(f); 192.461(h);
192.923(b); 192.925(b); 192.931(d); 192.935(b); and 192.939(a).
* * * * *

0
4. In Sec.  192.9, paragraphs (b), (c), (d)(1) and (2), and (e)(1)(i)
and (ii) are revised to read as follows:

Sec.  192.9   What requirements apply to gathering pipelines?

* * * * *
    (b) Offshore lines. An operator of an offshore gathering line must
comply with requirements of this part applicable to transmission lines,
except the requirements in Sec. Sec.  192.13(d), 192.150, 192.285(e),
192.319(d) through (g), 192.461(f) through (i), 192.465(d) and (f),
192.473(c), 192.478, 192.485(c), 192.493, 192.506, 192.607, 192.613(c),
192.619(e), 192.624, 192.710, 192.712, and 192.714 and in subpart O of
this part.
    (c) Type A lines. An operator of a Type A regulated onshore
gathering line must comply with the requirements of this part
applicable to transmission lines, except the requirements in Sec. Sec.
192.13(d), 192.150, 192.285(e), 192.319(d) through (g), 192.461(f)
through (i), 192.465(d) and (f), 192.473(c), 192.478, 192.485(c)
192.493, 192.506, 192.607, 192.613(c), 192.619(e), 192.624, 192.710,
192.712, and 192.714 and in subpart O of this part. However, an
operator of a Type A regulated onshore gathering line in a Class 2
location may demonstrate compliance with subpart N of this part by
describing the processes it uses to determine the qualification of
persons performing operations and maintenance tasks.
    (d) * * *
    (1) If a line is new, replaced, relocated, or otherwise changed,
the design, installation, construction, initial inspection, and initial
testing must be in accordance with requirements of this part applicable
to transmission lines. Compliance with Sec. Sec.  192.67, 192.127,
192.179(e) and (f), 192.205, 192.227(c), 192.285(e), 192.319(d) through
(g), 192.506, 192.634, and 192.636 is not required;
    (2) If the pipeline is metallic, control corrosion according to
requirements of subpart I of this part applicable to transmission
lines, except the requirements in Sec. Sec.  192.461(f) through (i),
192.465(d) and (f), 192.473(c), 192.478, 192.485(c), and 192.493;
* * * * *
    (e) * * *
    (1) * * *
    (i) Except as provided in paragraph (h) of this section for pipe
and components made with composite materials, the design, installation,
construction, initial inspection, and initial testing of a new,
replaced, relocated, or otherwise changed Type C gathering line, must
be done in accordance with the requirements in subparts B through G and
J of this part applicable to transmission lines. Compliance with
Sec. Sec.  192.67, 192.127, 192.179(e) and (f), 192.205, 192.227(c),
192.285(e), 192.319(d) through (g), 192.506, 192.634, and 192.636 is
not required;
    (ii) If the pipeline is metallic, control corrosion according to
requirements of subpart I of this part applicable to transmission
lines, except the requirements in Sec. Sec.  192.461(f) through (i),
192.465(d) and (f), 192.473(c), 192.478, 192.485(c), and 192.493;
* * * * *

0
5. In Sec.  192.13, paragraph (d) is added to read as follows:

Sec.  192.13   What general requirements apply to pipelines regulated
under this part?

* * * * *
    (d) Each operator of an onshore gas transmission pipeline must
evaluate and mitigate, as necessary, significant changes that pose a
risk to safety or the environment through a management of change
process. Each operator of an onshore gas transmission pipeline must
develop and follow a management of change process, as outlined in ASME/
ANSI B31.8S, section 11 (incorporated by reference, see Sec.  192.7),
that addresses technical, design, physical, environmental, procedural,
operational, maintenance, and organizational changes to the pipeline or
processes, whether permanent or temporary. A management of change
process must include the following: reason for change, authority for
approving changes, analysis of implications, acquisition of required
work permits, documentation, communication of change to affected
parties, time limitations, and qualification of staff. For pipeline
segments other than those covered in subpart O of this part, this
management of change process must be implemented by February 26, 2024.
The requirements of this paragraph (d) do not apply to gas gathering
pipelines. Operators may request an extension of up to 1 year by
submitting a notification to PHMSA at least 90 days before February 26,
2024, in accordance with Sec.  192.18. The notification must include a
reasonable and technically justified basis, an up-to-date plan for
completing all actions required by this section, the reason for the
requested extension, current safety or mitigation status of the
pipeline segment, the proposed completion date, and any needed
temporary safety measures to mitigate the impact on safety.

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

Sec.  192.18  How to notify PHMSA.

* * * * *
    (c) Unless otherwise specified, if an operator submits, pursuant to
Sec.  192.8, Sec.  192.9, Sec.  192.13, Sec.  192.179, Sec.  192.319,
Sec.  192.461, Sec.  192.506, Sec.  192.607, Sec.  192.619, Sec.
192.624, Sec.  192.632, Sec.  192.634, Sec.  192.636, Sec.  192.710,
Sec.  192.712, Sec.  192.714, Sec.  192.745, Sec.  192.917, Sec.
192.921, Sec.  192.927, Sec.  192.933, or Sec.  192.937, a notification
for use of a different integrity assessment method, analytical method,
compliance period, sampling approach, pipeline material, or technique
(e.g., ``other technology'' or ``alternative equivalent technology'')
than otherwise prescribed in those sections, that notification must be
submitted to PHMSA for review at least 90 days in advance of using the
other method, approach, compliance timeline, or technique. An operator
may proceed to use the other method, approach, compliance timeline, or
technique 91 days after submitting the notification unless it receives
a letter from the Associate Administrator for Pipeline Safety informing
the operator that PHMSA objects to the proposal or that PHMSA requires
additional time and/or more information to conduct its review.

0
7. In Sec.  192.319, paragraphs (d) through (g) are added to read as
follows:

Sec.  192.319   Installation of pipe in a ditch.

* * * * *
    (d) Promptly after a ditch for an onshore steel transmission line
is backfilled (if the construction project involves 1,000 feet or more
of continuous backfill length along the

pipeline), but not later than 6 months after placing the pipeline in
service, the operator must perform an assessment to assess any coating
damage and ensure integrity of the coating using direct current voltage
gradient (DCVG), alternating current voltage gradient (ACVG), or other
technology that provides comparable information about the integrity of
the coating. Coating surveys must be conducted, except in locations
where effective coating surveys are precluded by geographical,
technical, or safety reasons.
    (e) An operator must notify PHMSA in accordance with Sec.  192.18
at least 90 days in advance of using other technology to assess
integrity of the coating under paragraph (d) of this section.
    (f) An operator must repair any coating damage classified as severe
(voltage drop greater than 60 percent for DCVG or 70 dB[micro]V for
ACVG) in accordance with section 4 of NACE SP0502 (incorporated by
reference, see Sec.  192.7) within 6 months after the pipeline is
placed in service, or as soon as practicable after obtaining necessary
permits, not to exceed 6 months after the receipt of permits.
    (g) An operator of an onshore steel transmission pipeline must make
and retain for the life of the pipeline records documenting the coating
assessment findings and remedial actions performed under paragraphs (d)
through (f) of this section.

0
8. In Sec.  192.461, paragraph (a)(4) is revised and paragraphs (f)
through (i) are added to read as follows:

Sec.  192.461  External corrosion control: Protective coating.

    (a) * * *
    (4) Have sufficient strength to resist damage due to handling
(including, but not limited to, transportation, installation, boring,
and backfilling) and soil stress; and
* * * * *
    (f) Promptly after the backfill of an onshore steel transmission
pipeline ditch following repair or replacement (if the repair or
replacement results in 1,000 feet or more of backfill length along the
pipeline), but no later than 6 months after the backfill, the operator
must perform an assessment to assess any coating damage and ensure
integrity of the coating using direct current voltage gradient (DCVG),
alternating current voltage gradient (ACVG), or other technology that
provides comparable information about the integrity of the coating.
Coating surveys must be conducted, except in locations where effective
coating surveys are precluded by geographical, technical, or safety
reasons.
    (g) An operator must notify PHMSA in accordance with Sec.  192.18
at least 90 days in advance of using other technology to assess
integrity of the coating under paragraph (f) of this section.
    (h) An operator of an onshore steel transmission pipeline must
develop a remedial action plan and apply for any necessary permits
within 6 months of completing the assessment that identified the
deficiency. The operator must repair any coating damage classified as
severe (voltage drop greater than 60 percent for DCVG or 70 dB[micro]V
for ACVG) in accordance with section 4 of NACE SP0502 (incorporated by
reference, see Sec.  192.7) within 6 months of the assessment, or as
soon as practicable after obtaining necessary permits, not to exceed 6
months after the receipt of permits.
    (i) An operator of an onshore steel transmission pipeline must make
and retain for the life of the pipeline records documenting the coating
assessment findings and remedial actions performed under paragraphs (f)
through (h) of this section.

0
9. In Sec.  192.465, the section heading and paragraph (d) are revised
and paragraph (f) is added to read as follows:

Sec.  192.465  External corrosion control: Monitoring and remediation.

* * * * *
    (d) Each operator must promptly correct any deficiencies indicated
by the inspection and testing required by paragraphs (a) through (c) of
this section. For onshore gas transmission pipelines, each operator
must develop a remedial action plan and apply for any necessary permits
within 6 months of completing the inspection or testing that identified
the deficiency. Remedial action must be completed promptly, but no
later than the earliest of the following: prior to the next inspection
or test interval required by this section; within 1 year, not to exceed
15 months, of the inspection or test that identified the deficiency; or
as soon as practicable, not to exceed 6 months, after obtaining any
necessary permits.
* * * * *
    (f) An operator must determine the extent of the area with
inadequate cathodic protection for onshore gas transmission pipelines
where any annual test station reading (pipe-to-soil potential
measurement) indicates cathodic protection levels below the required
levels in appendix D to this part.
    (1) Gas transmission pipeline operators must investigate and
mitigate any non-systemic or location-specific causes.
    (2) To address systemic causes, an operator must conduct close
interval surveys in both directions from the test station with a low
cathodic protection reading at a maximum interval of approximately 5
feet or less. An operator must conduct close interval surveys unless it
is impractical based upon geographical, technical, or safety reasons.
An operator must complete close interval surveys required by this
section with the protective current interrupted unless it is
impractical to do so for technical or safety reasons. An operator must
remediate areas with insufficient cathodic protection levels, or areas
where protective current is found to be leaving the pipeline, in
accordance with paragraph (d) of this section. An operator must confirm
the restoration of adequate cathodic protection following the
implementation of remedial actions undertaken to mitigate systemic
causes of external corrosion.

0
10. In Sec.  192.473, paragraph (c) is added to read as follows:

Sec.  192.473  External corrosion control: Interference currents.

* * * * *
    (c) For onshore gas transmission pipelines, the program required by
paragraph (a) of this section must include:
    (1) Interference surveys for a pipeline system to detect the
presence and level of any electrical stray current. Interference
surveys must be conducted when potential monitoring indicates a
significant increase in stray current, or when new potential stray
current sources are introduced, such as through co-located pipelines,
structures, or high voltage alternating current (HVAC) power lines,
including from additional generation, a voltage up-rating, additional
lines, new or enlarged power substations, or new pipelines or other
structures;
    (2) Analysis of the results of the survey to determine the cause of
the interference and whether the level could cause significant
corrosion, impede safe operation, or adversely affect the environment
or public;
    (3) Development of a remedial action plan to correct any instances
where interference current is greater than or equal to 100 amps per
meter squared or if it impedes the safe operation of a pipeline, or if
it may cause a condition that would adversely impact the environment or
the public; and
    (4) Application for any necessary permits within 6 months of
completing the interference survey that identified

the deficiency. An operator must complete remedial actions promptly,
but no later than the earliest of the following: within 15 months after
completing the interference survey that identified the deficiency; or
as soon as practicable, but not to exceed 6 months, after obtaining any
necessary permits.

0
11. Section 192.478 is added to read as follows:

Sec.  192.478  Internal corrosion control: Onshore transmission
monitoring and mitigation.

    (a) Each operator of an onshore gas transmission pipeline with
corrosive constituents in the gas being transported must develop and
implement a monitoring and mitigation program to mitigate the corrosive
effects, as necessary. Potentially corrosive constituents include, but
are not limited to: carbon dioxide, hydrogen sulfide, sulfur, microbes,
and liquid water, either by itself or in combination. An operator must
evaluate the partial pressure of each corrosive constituent, where
applicable, by itself or in combination, to evaluate the effect of the
corrosive constituents on the internal corrosion of the pipe and
implement mitigation measures as necessary.
    (b) The monitoring and mitigation program described in paragraph
(a) of this section must include:
    (1) The use of gas-quality monitoring methods at points where gas
with potentially corrosive contaminants enters the pipeline to
determine the gas stream constituents.
    (2) Technology to mitigate the potentially corrosive gas stream
constituents. Such technologies may include product sampling, inhibitor
injections, in-line cleaning pigging, separators, or other technology
that mitigates potentially corrosive effects.
    (3) An evaluation at least once each calendar year, at intervals
not to exceed 15 months, to ensure that potentially corrosive gas
stream constituents are effectively monitored and mitigated.
    (c) An operator must review its monitoring and mitigation program
at least once each calendar year, at intervals not to exceed 15 months,
and based on the results of its monitoring and mitigation program,
implement adjustments, as necessary.

0
12. In Sec.  192.485, paragraph (c) is revised to read as follows:

Sec.  192.485   Remedial measures: Transmission lines.

* * * * *
    (c) Calculating remaining strength. Under paragraphs (a) and (b) of
this section, the strength of pipe based on actual remaining wall
thickness must be determined and documented in accordance with Sec.
192.712.

0
13. In Sec.  192.613, paragraph (c) is added to read as follows:

Sec.  192.613   Continuing surveillance.

* * * * *
    (c) Following an extreme weather event or natural disaster that has
the likelihood of damage to pipeline facilities by the scouring or
movement of the soil surrounding the pipeline or movement of the
pipeline, such as a named tropical storm or hurricane; a flood that
exceeds the river, shoreline, or creek high-water banks in the area of
the pipeline; a landslide in the area of the pipeline; or an earthquake
in the area of the pipeline, an operator must inspect all potentially
affected onshore transmission pipeline facilities to detect conditions
that could adversely affect the safe operation of that pipeline.
    (1) An operator must assess the nature of the event and the
physical characteristics, operating conditions, location, and prior
history of the affected pipeline in determining the appropriate method
for performing the initial inspection to determine the extent of any
damage and the need for the additional assessments required under this
paragraph (c)(1).
    (2) An operator must commence the inspection required by paragraph
(c) of this section within 72 hours after the point in time when the
operator reasonably determines that the affected area can be safely
accessed by personnel and equipment, and the personnel and equipment
required to perform the inspection as determined by paragraph (c)(1) of
this section are available. If an operator is unable to commence the
inspection due to the unavailability of personnel or equipment, the
operator must notify the appropriate PHMSA Region Director as soon as
practicable.
    (3) An operator must take prompt and appropriate remedial action to
ensure the safe operation of a pipeline based on the information
obtained as a result of performing the inspection required by paragraph
(c) of this section. Such actions might include, but are not limited
to:
    (i) Reducing the operating pressure or shutting down the pipeline;
    (ii) Modifying, repairing, or replacing any damaged pipeline
facilities;
    (iii) Preventing, mitigating, or eliminating any unsafe conditions
in the pipeline right-of-way;
    (iv) Performing additional patrols, surveys, tests, or inspections;
    (v) Implementing emergency response activities with Federal, State,
or local personnel; or
    (vi) Notifying affected communities of the steps that can be taken
to ensure public safety.

0
14. In Sec.  192.710, paragraph (f) is revised as follows:

Sec.  192.710  Transmission lines: Assessments outside of high
consequence areas.

* * * * *
    (f) Remediation. An operator must comply with the requirements in
Sec. Sec.  192.485, 192.711, 192.712, 192.713, and 192.714, where
applicable, if a condition that could adversely affect the safe
operation of a pipeline is discovered.
* * * * *

0
15. In Sec.  192.711, paragraph (b)(1) is revised to read as follows:

Sec.  192.711  Transmission lines: General requirements for repair
procedures.

* * * * *
    (b) * * *
    (1)(i) Non-integrity management repairs for gathering lines and
offshore transmission lines: For gathering lines subject to this
section in accordance with Sec.  192.9 and for offshore transmission
lines, an operator must make permanent repairs as soon as feasible.
    (ii) Non-integrity management repairs for onshore transmission
lines: Except for gathering lines exempted from this section in
accordance with Sec.  192.9 and offshore transmission lines, after May
24, 2023, whenever an operator discovers any condition that could
adversely affect the safe operation of a pipeline segment not covered
by an integrity management program under subpart O of this part, it
must correct the condition as prescribed in Sec.  192.714.
* * * * *

0
16. In Sec.  192.712, the section heading and paragraph (b) are revised
and paragraphs (c) and (h) are added to read as follows:

Sec.  192.712  Analysis of predicted failure pressure and critical
strain level.

* * * * *
    (b) Corrosion metal loss. When analyzing corrosion metal loss under
this section, an operator must use a suitable remaining strength
calculation method including, ASME/ANSI B31G (incorporated by
reference, see Sec.  192.7); R-STRENG (incorporated by reference, see
Sec.  192.7); or an alternative equivalent method of remaining strength
calculation that will provide an equally conservative result.
    (1) If an operator would choose to use a remaining strength
calculation method that could provide a less conservative result than
the methods listed in

paragraph (b) introductory text, the operator must notify PHMSA in
advance in accordance with Sec.  192.18(c).
    (2) The notification provided for by paragraph (b)(1) of this
section must include a comparison of its predicted failure pressures to
R-STRENG or ASME/ANSI B31G, all burst pressure tests used, and any
other technical reviews used to qualify the calculation method(s) for
varying corrosion profiles.
    (c) Dents and other mechanical damage. To evaluate dents and other
mechanical damage that could result in a stress riser or other
integrity impact, an operator must develop a procedure and perform an
engineering critical assessment as follows:
    (1) Identify and evaluate potential threats to the pipe segment in
the vicinity of the anomaly or defect, including ground movement,
external loading, fatigue, cracking, and corrosion.
    (2) Review high-resolution magnetic flux leakage (HR-MFL) high-
resolution deformation, inertial mapping, and crack detection inline
inspection data for damage in the dent area and any associated weld
region, including available data from previous inline inspections.
    (3) Perform pipeline curvature-based strain analysis using recent
HR-Deformation inspection data.
    (4) Compare the dent profile between the most recent and previous
in-line inspections to identify significant changes in dent depth and
shape.
    (5) Identify and quantify all previous and present significant
loads acting on the dent.
    (6) Evaluate the strain level associated with the anomaly or defect
and any nearby welds using Finite Element Analysis, or other technology
in accordance with this section. Using Finite Element Analysis to
quantify the dent strain, and then estimating and evaluating the damage
using the Strain Limit Damage (SLD) and Ductile Failure Damage
Indicator (DFDI) at the dent, are appropriate evaluation methods.
    (7) The analyses performed in accordance with this section must
account for material property uncertainties, model inaccuracies, and
inline inspection tool sizing tolerances.
    (8) Dents with a depth greater than 10 percent of the pipe outside
diameter or with geometric strain levels that exceed the lessor of 10
percent or exceed the critical strain for the pipe material properties
must be remediated in accordance with Sec.  192.713, Sec.  192.714, or
Sec.  192.933, as applicable.
    (9) Using operational pressure data, a valid fatigue life
prediction model that is appropriate for the pipeline segment, and
assuming a reassessment safety factor of 5 or greater for the
assessment interval, estimate the fatigue life of the dent by Finite
Element Analysis or other analytical technique that is technically
appropriate for dent assessment and reassessment intervals in
accordance with this section. Multiple dent or other fatigue models
must be used for the evaluation as a part of the engineering critical
assessment.
    (10) If the dent or mechanical damage is suspected to have cracks,
then a crack growth rate assessment is required to ensure adequate life
for the dent with crack(s) until remediation or the dent with crack(s)
must be evaluated and remediated in accordance with the criteria and
timing requirements in Sec.  192.713, Sec.  192.714, or Sec.  192.933,
as applicable.
    (11) An operator using an engineering critical assessment
procedure, other technologies, or techniques to comply with paragraph
(c) of this section must submit advance notification to PHMSA, with the
relevant procedures, in accordance with Sec.  192.18.
* * * * *
    (h) Reassessments. If an operator uses an engineering critical
assessment method in accordance with paragraphs (c) and (d) of this
section to determine the maximum reevaluation intervals, the operator
must reassess the anomalies as follows:
    (1) If the anomaly is in an HCA, the operator must reassess the
anomaly within a maximum of 7 years in accordance with Sec.
192.939(a), unless the safety factor is expected to go below what is
specified in paragraph (c) or (d) of this section.
    (2) If the anomaly is outside of an HCA, the operator must perform
a reassessment of the anomaly within a maximum of 10 years in
accordance with Sec.  192.710(b), unless the anomaly safety factor is
expected to go below what is specified in paragraph (c) or (d) of this
section.

0
17. Section 192.714 is added to read as follows:

Sec.  192.714  Transmission lines: Repair criteria for onshore
transmission pipelines.

    (a) Applicability. This section applies to onshore transmission
pipelines not subject to the repair criteria in subpart O of this part,
and which do not operate under an alternative MAOP in accordance with
Sec. Sec.  192.112, 192.328, and 192.620. Pipeline segments that are
located in high consequence areas, as defined in Sec.  192.903, must
comply with the applicable actions specified by the integrity
management requirements in subpart O. Pipeline segments operating under
an alternative MAOP in accordance with Sec. Sec.  192.112, 192.328, and
192.620 must comply with Sec.  192.620(d)(11).
    (b) General. Each operator must, in repairing its pipeline systems,
ensure that the repairs are made in a safe manner and are made to
prevent damage to persons, property, and the environment. A pipeline
segment's operating pressure must be less than the predicted failure
pressure determined in accordance with Sec.  192.712 during repair
operations. Repairs performed in accordance with this section must use
pipe and material properties that are documented in traceable,
verifiable, and complete records. If documented data required for any
analysis, including predicted failure pressure for determining MAOP, is
not available, an operator must obtain the undocumented data through
Sec.  192.607.
    (c) Schedule for evaluation and remediation. An operator must
remediate conditions according to a schedule that prioritizes the
conditions for evaluation and remediation. Unless paragraph (d) of this
section provides a special requirement for remediating certain
conditions, an operator must calculate the predicted failure pressure
of anomalies or defects and follow the schedule in ASME/ANSI B31.8S
(incorporated by reference, see Sec.  192.7), section 7, Figure 4. If
an operator cannot meet the schedule for any condition, the operator
must document the reasons why it cannot meet the schedule and how the
changed schedule will not jeopardize public safety. Each condition that
meets any of the repair criteria in paragraph (d) of this section in an
onshore steel transmission pipeline must be--
    (1) Removed by cutting out and replacing a cylindrical piece of
pipe that will permanently restore the pipeline's MAOP based on the use
of Sec.  192.105 and the design factors for the class location in which
it is located; or
    (2) Repaired by a method, shown by technically proven engineering
tests and analyses, that will permanently restore the pipeline's MAOP
based upon the determined predicted failure pressure times the design
factor for the class location in which it is located.
    (d) Remediation of certain conditions. For onshore transmission
pipelines not located in high consequence areas, an operator must
remediate a listed condition according to the following criteria:
    (1) Immediate repair conditions. An operator must repair the
following conditions immediately upon discovery:
    (i) Metal loss anomalies where a calculation of the remaining
strength of the pipe at the location of the anomaly

shows a predicted failure pressure, determined in accordance with Sec.
192.712(b), of less than or equal to 1.1 times the MAOP.
    (ii) A dent located between the 8 o'clock and 4 o'clock positions
(upper \2/3\ of the pipe) that has metal loss, cracking, or a stress
riser, unless an engineering analysis performed in accordance with
Sec.  192.712(c) demonstrates critical strain levels are not exceeded.
    (iii) Metal loss greater than 80 percent of nominal wall regardless
of dimensions.
    (iv) Metal loss preferentially affecting a detected longitudinal
seam, if that seam was formed by direct current, low-frequency or high-
frequency electric resistance welding, electric flash welding, or has a
longitudinal joint factor less than 1.0, and the predicted failure
pressure determined in accordance with Sec.  192.712(d) is less than
1.25 times the MAOP.
    (v) A crack or crack-like anomaly meeting any of the following
criteria:
    (A) Crack depth plus any metal loss is greater than 50 percent of
pipe wall thickness;
    (B) Crack depth plus any metal loss is greater than the inspection
tool's maximum measurable depth; or
    (C) The crack or crack-like anomaly has a predicted failure
pressure, determined in accordance with Sec.  192.712(d), that is less
than 1.25 times the MAOP.
    (vi) An indication or anomaly that, in the judgment of the person
designated by the operator to evaluate the assessment results, requires
immediate action.
    (2) Two-year conditions. An operator must repair the following
conditions within 2 years of discovery:
    (i) A smooth dent located between the 8 o'clock and 4 o'clock
positions (upper \2/3\ of the pipe) with a depth greater than 6 percent
of the pipeline diameter (greater than 0.50 inches in depth for a
pipeline diameter less than Nominal Pipe Size (NPS) 12), unless an
engineering analysis performed in accordance with Sec.  192.712(c)
demonstrates critical strain levels are not exceeded.
    (ii) A dent with a depth greater than 2 percent of the pipeline
diameter (0.250 inches in depth for a pipeline diameter less than NPS
12) that affects pipe curvature at a girth weld or at a longitudinal or
helical (spiral) seam weld, unless an engineering analysis performed in
accordance with Sec.  192.712(c) demonstrates critical strain levels
are not exceeded.
    (iii) A dent located between the 4 o'clock and 8 o'clock positions
(lower \1/3\ of the pipe) that has metal loss, cracking, or a stress
riser, unless an engineering analysis performed in accordance with
Sec.  192.712(c) demonstrates critical strain levels are not exceeded.
    (iv) For metal loss anomalies, a calculation of the remaining
strength of the pipe shows a predicted failure pressure, determined in
accordance with Sec.  192.712(b) at the location of the anomaly, of
less than 1.39 times the MAOP for Class 2 locations, or less than 1.50
times the MAOP for Class 3 and 4 locations. For metal loss anomalies in
Class 1 locations with a predicted failure pressure greater than 1.1
times MAOP, an operator must follow the remediation schedule specified
in ASME/ANSI B31.8S (incorporated by reference, see Sec.  192.7),
section 7, Figure 4, as specified in paragraph (c) of this section.
    (v) Metal loss that is located at a crossing of another pipeline,
is in an area with widespread circumferential corrosion, or could
affect a girth weld, and that has a predicted failure pressure,
determined in accordance with Sec.  192.712(b), less than 1.39 times
the MAOP for Class 1 locations or where Class 2 locations contain Class
1 pipe that has been uprated in accordance with Sec.  192.611, or less
than 1.50 times the MAOP for all other Class 2 locations and all Class
3 and 4 locations.
    (vi) Metal loss preferentially affecting a detected longitudinal
seam, if that seam was formed by direct current, low-frequency or high-
frequency electric resistance welding, electric flash welding, or that
has a longitudinal joint factor less than 1.0, and where the predicted
failure pressure determined in accordance with Sec.  192.712(d) is less
than 1.39 times the MAOP for Class 1 locations or where Class 2
locations contain Class 1 pipe that has been uprated in accordance with
Sec.  192.611, or less than 1.50 times the MAOP for all other Class 2
locations and all Class 3 and 4 locations.
    (vii) A crack or crack-like anomaly that has a predicted failure
pressure, determined in accordance with Sec.  192.712(d), that is less
than 1.39 times the MAOP for Class 1 locations or where Class 2
locations contain Class 1 pipe that has been uprated in accordance with
Sec.  192.611, or less than 1.50 times the MAOP for all other Class 2
locations and all Class 3 and 4 locations.
    (3) Monitored conditions. An operator must record and monitor the
following conditions during subsequent risk assessments and integrity
assessments for any change that may require remediation.
    (i) A dent that is located between the 4 o'clock and 8 o'clock
positions (bottom \1/3\ of the pipe) with a depth greater than 6
percent of the pipeline diameter (greater than 0.50 inches in depth for
a pipeline diameter less than NPS 12).
    (ii) A dent located between the 8 o'clock and 4 o'clock positions
(upper \2/3\ of the pipe) with a depth greater than 6 percent of the
pipeline diameter (greater than 0.50 inches in depth for a pipeline
diameter less than NPS 12), and where an engineering analysis performed
in accordance with Sec.  192.712(c) determines that critical strain
levels are not exceeded.
    (iii) A dent with a depth greater than 2 percent of the pipeline
diameter (0.250 inches in depth for a pipeline diameter less than NPS
12) that affects pipe curvature at a girth weld or longitudinal or
helical (spiral) seam weld, and where an engineering analysis of the
dent and girth or seam weld, performed in accordance with Sec.
192.712(c), demonstrates critical strain levels are not exceeded. These
analyses must consider weld mechanical properties.
    (iv) A dent that has metal loss, cracking, or a stress riser, and
where an engineering analysis performed in accordance with Sec.
192.712(c) demonstrates critical strain levels are not exceeded.
    (v) Metal loss preferentially affecting a detected longitudinal
seam, if that seam was formed by direct current, low-frequency or high-
frequency electric resistance welding, electric flash welding, or that
has a longitudinal joint factor less than 1.0, and where the predicted
failure pressure, determined in accordance with Sec.  192.712(d), is
greater than or equal to 1.39 times the MAOP for Class 1 locations or
where Class 2 locations contain Class 1 pipe that has been uprated in
accordance with Sec.  192.611, or is greater than or equal to 1.50
times the MAOP for all other Class 2 locations and all Class 3 and 4
locations.
    (vi) A crack or crack-like anomaly for which the predicted failure
pressure, determined in accordance with Sec.  192.712(d), is greater
than or equal to 1.39 times the MAOP for Class 1 locations or where
Class 2 locations contain Class 1 pipe that has been uprated in
accordance with Sec.  192.611, or is greater than or equal to 1.50
times the MAOP for all other Class 2 locations and all Class 3 and 4
locations.
    (e) Temporary pressure reduction. (1) Immediately upon discovery
and until an operator remediates the condition specified in paragraph
(d)(1) of this section, or upon a determination by an

operator that it is unable to respond within the time limits for the
conditions specified in paragraph (d)(2) of this section, the operator
must reduce the operating pressure of the affected pipeline to any one
of the following based on safety considerations for the public and
operating personnel:
    (i) A level not exceeding 80 percent of the operating pressure at
the time the condition was discovered;
    (ii) A level not exceeding the predicted failure pressure times the
design factor for the class location in which the affected pipeline is
located; or
    (iii) A level not exceeding the predicted failure pressure divided
by 1.1.
    (2) An operator must notify PHMSA in accordance with Sec.  192.18
if it cannot meet the schedule for evaluation and remediation required
under paragraph (c) or (d) of this section and cannot provide safety
through a temporary reduction in operating pressure or other action.
Notification to PHMSA does not alleviate an operator from the
evaluation, remediation, or pressure reduction requirements in this
section.
    (3) When a pressure reduction, in accordance with paragraph (e) of
this section, exceeds 365 days, an operator must notify PHMSA in
accordance with Sec.  192.18 and explain the reasons for the
remediation delay. This notice must include a technical justification
that the continued pressure reduction will not jeopardize the integrity
of the pipeline.
    (4) An operator must document and keep records of the calculations
and decisions used to determine the reduced operating pressure and the
implementation of the actual reduced operating pressure for a period of
5 years after the pipeline has been repaired.
    (f) Other conditions. Unless another timeframe is specified in
paragraph (d) of this section, an operator must take appropriate
remedial action to correct any condition that could adversely affect
the safe operation of a pipeline system in accordance with the
criteria, schedules, and methods defined in the operator's operating
and maintenance procedures.
    (g) In situ direct examination of crack defects. Whenever an
operator finds conditions that require the pipeline to be repaired, in
accordance with this section, an operator must perform a direct
examination of known locations of cracks or crack-like defects using
technology that has been validated to detect tight cracks (equal to or
less than 0.008 inches crack opening), such as inverse wave field
extrapolation (IWEX), phased array ultrasonic testing (PAUT),
ultrasonic testing (UT), or equivalent technology. ``In situ''
examination tools and procedures for crack assessments (length, depth,
and volumetric) must have performance and evaluation standards,
including pipe or weld surface cleanliness standards for the
inspection, confirmed by subject matter experts qualified by knowledge,
training, and experience in direct examination inspection for accuracy
of the type of defects and pipe material being evaluated. The
procedures must account for inaccuracies in evaluations and fracture
mechanics models for failure pressure determinations.
    (h) Determining predicted failure pressures and critical strain
levels. An operator must perform all determinations of predicted
failure pressures and critical strain levels required by this section
in accordance with Sec.  192.712.

0
18. In Sec.  192.911, paragraph (k) is revised to read as follows:

Sec.  192.911   What are the elements of an integrity management
program?

* * * * *
    (k) A management of change process as required by Sec.  192.13(d).
* * * * *

0
19. In Sec.  192.917, paragraphs (a) through (d) are revised to read as
follows:

Sec.  192.917   How does an operator identify potential threats to
pipeline integrity and use the threat identification in its integrity
program?

    (a) Threat identification. An operator must identify and evaluate
all potential threats to each covered pipeline segment. Potential
threats that an operator must consider include, but are not limited to,
the threats listed in ASME/ANSI B31.8S (incorporated by reference, see
Sec.  192.7), section 2, which are grouped under the following four
threat categories:
    (1) Time dependent threats such as internal corrosion, external
corrosion, and stress corrosion cracking;
    (2) Stable threats, such as manufacturing, welding, fabrication, or
construction defects;
    (3) Time independent threats, such as third party damage,
mechanical damage, incorrect operational procedure, weather related and
outside force damage, to include consideration of seismicity, geology,
and soil stability of the area; and
    (4) Human error, such as operational or maintenance mishaps, or
design and construction mistakes.
    (b) Data gathering and integration. To identify and evaluate the
potential threats to a covered pipeline segment, an operator must
gather and integrate existing data and information on the entire
pipeline that could be relevant to the covered segment. In performing
data gathering and integration, an operator must follow the
requirements in ASME/ANSI B31.8S, section 4.
    Operators must begin to integrate all pertinent data elements
specified in this section starting on May 24, 2023, with all available
attributes integrated by February 26, 2024. An operator may request an
extension of up to 1 year by submitting a notification to PHMSA at
least 90 days before February 26, 2024, in accordance with Sec.
192.18. The notification must include a reasonable and technically
justified basis, an up-to-date plan for completing all actions required
by this paragraph (b), the reason for the requested extension, current
safety or mitigation status of the pipeline segment, the proposed
completion date, and any needed temporary safety measures to mitigate
the impact on safety. An operator must gather and evaluate the set of
data listed in paragraph (b)(1) of this section. The evaluation must
analyze both the covered segment and similar non-covered segments, and
it must:
    (1) Integrate pertinent information about pipeline attributes to
ensure safe operation and pipeline integrity, including information
derived from operations and maintenance activities required under this
part, and other relevant information, including, but not limited to:
    (i) Pipe diameter, wall thickness, seam type, and joint factor;
    (ii) Manufacturer and manufacturing date, including manufacturing
data and records;
    (iii) Material properties including, but not limited to, grade,
specified minimum yield strength (SMYS), and ultimate tensile strength;
    (iv) Equipment properties;
    (v) Year of installation;
    (vi) Bending method;
    (vii) Joining method, including process and inspection results;
    (viii) Depth of cover;
    (ix) Crossings, casings (including if shorted), and locations of
foreign line crossings and nearby high voltage power lines;
    (x) Hydrostatic or other pressure test history, including test
pressures and test leaks or failures, failure causes, and repairs;
    (xi) Pipe coating methods (both manufactured and field applied),
including the method or process used to apply girth weld coating,
inspection reports, and coating repairs;
    (xii) Soil, backfill;

    (xiii) Construction inspection reports, including but not limited
to:
    (A) Post backfill coating surveys; and
    (B) Coating inspection (``jeeping'' or ``holiday inspection'')
reports;
    (xiv) Cathodic protection installed, including, but not limited to,
type and location;
    (xv) Coating type;
    (xvi) Gas quality;
    (xvii) Flow rate;
    (xviii) Normal maximum and minimum operating pressures, including
maximum allowable operating pressure (MAOP);
    (xix) Class location;
    (xx) Leak and failure history, including any in-service ruptures or
leaks from incident reports, abnormal operations, safety-related
conditions (both reported and unreported) and failure investigations
required by Sec.  192.617, and their identified causes and
consequences;
    (xxi) Coating condition;
    (xxii) Cathodic protection (CP) system performance;
    (xxiii) Pipe wall temperature;
    (xxiv) Pipe operational and maintenance inspection reports,
including, but not limited to:
    (A) Data gathered through integrity assessments required under this
part, including, but not limited to, in-line inspections, pressure
tests, direct assessments, guided wave ultrasonic testing, or other
methods;
    (B) Close interval survey (CIS) and electrical survey results;
    (C) CP rectifier readings;
    (D) CP test point survey readings and locations;
    (E) Alternating current, direct current, and foreign structure
interference surveys;
    (F) Pipe coating surveys, including surveys to detect coating
damage, disbonded coatings, or other conditions that compromise the
effectiveness of corrosion protection, including, but not limited to,
direct current voltage gradient or alternating current voltage gradient
inspections;
    (G) Results of examinations of exposed portions of buried pipelines
(e.g., pipe and pipe coating condition, see Sec.  192.459), including
the results of any non-destructive examinations of the pipe, seam, or
girth weld (i.e. bell hole inspections);
    (H) Stress corrosion cracking excavations and findings;
    (I) Selective seam weld corrosion excavations and findings;
    (J) Any indication of seam cracking; and
    (K) Gas stream sampling and internal corrosion monitoring results,
including cleaning pig sampling results;
    (xxv) External and internal corrosion monitoring;
    (xxvi) Operating pressure history and pressure fluctuations,
including an analysis of effects of pressure cycling and instances of
exceeding MAOP by any amount;
    (xxvii) Performance of regulators, relief valves, pressure control
devices, or any other device to control or limit operating pressure to
less than MAOP;
    (xxviii) Encroachments;
    (xxix) Repairs;
    (xxx) Vandalism;
    (xxxi) External forces;
    (xxxii) Audits and reviews;
    (xxxiii) Industry experience for incident, leak, and failure
history;
    (xxxiv) Aerial photography; and
    (xxxv) Exposure to natural forces in the area of the pipeline,
including seismicity, geology, and soil stability of the area.
    (2) Use validated information and data as inputs, to the maximum
extent practicable. If input is obtained from subject matter experts
(SME), an operator must employ adequate control measures to ensure
consistency and accuracy of information. Control measures may include
training of SMEs or the use of outside technical experts (independent
expert reviews) to assess the quality of processes and the judgment of
SMEs. An operator must document the names and qualifications of the
individuals who approve SME inputs used in the current risk assessment.
    (3) Identify and analyze spatial relationships among anomalous
information (e.g., corrosion coincident with foreign line crossings or
evidence of pipeline damage where overhead imaging shows evidence of
encroachment).
    (4) Analyze the data for interrelationships among pipeline
integrity threats, including combinations of applicable risk factors
that increase the likelihood of incidents or increase the potential
consequences of incidents.
    (c) Risk assessment. An operator must conduct a risk assessment
that follows ASME/ANSI B31.8S, section 5, and that analyzes the
identified threats and potential consequences of an incident for each
covered segment. An operator must ensure the validity of the methods
used to conduct the risk assessment considering the incident, leak, and
failure history of the pipeline segments and other historical
information. Such a validation must ensure the risk assessment methods
produce a risk characterization that is consistent with the operator's
and industry experience, including evaluations of the cause of past
incidents, as determined by root cause analysis or other equivalent
means, and include sensitivity analysis of the factors used to
characterize both the likelihood of loss of pipeline integrity and
consequences of the postulated loss of pipeline integrity. An operator
must use the risk assessment to determine additional preventive and
mitigative measures needed for each covered segment in accordance with