reconfirmation were technically feasible, reasonable, cost-effective,
and practicable if PHMSA made certain changes. For Method 4, pipe
replacement, the committee had no significant comments or changes. For
Method 5, the small PIR and diameter pressure reduction method, the
GPAC recommended PHMSA delete the size and pressure criteria, limiting
the requirement to those lines with a PIR of 150 feet or less; remove
the external corrosion direct assessment, crack analysis program,
odorization, and fracture mechanics analysis requirements; and change
the frequency of patrols and surveys to 4 times per year in Class 1 and
Class 2 locations and 6 times per year in Class 3 and Class 4
locations. For Method 6, the ``other technology'' method, the GPAC
recommended PHMSA incorporate the same 90-day notification and
objection procedure the GPAC approved for the material properties
verification requirements.

MAOP Reconfirmation: Recordkeeping and Notification

    The GPAC also voted on the notification procedure and recordkeeping
requirements of the MAOP reconfirmation requirements. As there were no
substantial GPAC comments on these issues, the GPAC voted 11-0 that the
provisions are technically feasible, reasonable, cost-effective, and
practicable if PHMSA provided guidance regarding what ``traceable,
verifiable, and complete'' records are in the preamble, and if the
notification procedure is retained as it was proposed in the NPRM, but
incorporating the same 90-day notification and objection procedure the
committee approved for the material properties verification
requirements into any notification required under the MAOP
reconfirmation requirements.
Other MAOP Amendments (Sec. Sec.  192.503, 192.605(b)(5),
192.619(a)(2), 192.619(a)(4), 192.619(e), 192.619(f))
    PHMSA presented to the committee issues related to other portions
of MAOP determination \86\ that had cross-references to MAOP
reconfirmation methods or other areas of the proposed regulations. More
specifically, the GPAC was to consider recommending PHMSA eliminate
duplications in scope between the MAOP determination provisions and the
MAOP reconfirmation provisions, and eliminate a duplicative revision to
the subpart J pressure test general requirements that was referenced
adequately elsewhere in the proposal. PHMSA also proposed that the
establishment of MAOP under Sec.  192.619 should rely on traceable,
verifiable, and complete records, and therefore cross-referenced the
material properties verification provisions with the MAOP determination
provisions. Similarly, PHMSA added a paragraph to the existing MAOP
determination provisions to more clearly specify that operators must
have records to substantiate the MAOP of their pipeline segments. To
address an NTSB recommendation from the PG&E incident, PHMSA also
proposed requiring that the MAOP pressure limitation factor specified
in the MAOP determination section of the regulations for Class 1
pipeline segments be based on the subpart J test pressure divided by
1.25, whereas the existing requirement was the test pressure divided by
1.1. Finally, PHMSA proposed adding a clarification that the
requirement for overpressure protection applied to pipeline segments
where the MAOP was established using one of the six methods under MAOP
reconfirmation. However, PHMSA noted in response to public comment that
the clarification seemed to be overly confusing and should be
withdrawn.
---------------------------------------------------------------------------

    \86\ See Sec.  192.619.
---------------------------------------------------------------------------

    The GPAC reviewed and discussed PHMSA's proposed changes to the
other MAOP-related provisions, voting 12-0 that the provisions are
technically feasible, reasonable, cost-effective, and practicable if
PHMSA considered editorially restructuring the applicability of the
MAOP determination provisions; clarifying that the recordkeeping
requirements specified under MAOP determination only apply to onshore,
steel, gas transmission pipelines; and clarifying that the MAOP
recordkeeping requirements are not retroactive. The GPAC suggested this
be clarified by stating existing records for pipelines installed on or
before the effective date of the rule must be kept for the life of the
pipeline, that pipelines installed after the effective date of the rule
must make and retain records as required for the life of the pipeline,
and that MAOP records are required for any pipeline placed in service
after the effective date of the rule. The GPAC noted that other
sections, including the MAOP reconfirmation and material properties
verification requirements, would require when and for which pipeline
segments where MAOP records are not documented in a traceable,
verifiable, and complete manner would need to be verified.
Changes From the GPAC Recommendations
    In this final rule, PHMSA considered the recommendations of the
GPAC and adopted them as PHMSA deemed appropriate. However, there were
recommendations from the GPAC that PHMSA considered but did not adopt.
To summarize, the major changes PHMSA made in this rule that deviate
from the GPAC recommendations are as follows:
    (1) When discussing the other proposed issues related to the MAOP
requirements, the GPAC recommended

PHMSA consider moving Sec.  192.619(e) to be a subsection of Sec.
192.619(a) and consider referencing section Sec.  192.624 in Sec.
192.619(a). PHMSA did not implement this recommendation because MAOP
reconfirmation for grandfathered segments is not applicable for new
pipeline segments.
    (2) When considering the IM clarifications at Sec.  192.917, the
GPAC recommended PHMSA consider removing the term ``hydrostatic'' from
the testing requirements at Sec.  192.917(e)(3), which deals with
manufacturing and construction defects, and allow other authorized
testing procedures. PHMSA is not implementing this recommendation
because allowing pneumatic tests would be a safety concern to the
public and operating personnel.
    (3) When discussing the assessment requirements for non-HCAs under
proposed Sec.  192.710, the GPAC recommended PHMSA change the
``discovery of condition'' period allotted from 180 to 240 days. PHMSA
is not implementing this suggestion from the GPAC and is retaining the
180-day timeframe for operators to determine whether a condition
presents a potential threat to the integrity of the pipeline.
    (4) PHMSA added a notification requirement for the use of other
technology under the non-HCA assessment requirements at Sec.  192.710.
While the GPAC did not specifically request PHMSA make this change, the
GPAC was generally supportive of incorporating the notification
procedure the committee agreed to under the proposed material
properties verification requirements for other applications.
    (5) Regarding the requirements for the scope of MAOP
reconfirmation, the GPAC recommended PHMSA review the costs and
benefits of including Class 3 and Class 4 pipelines not located in HCAs
and that operate at less than 30 percent SMYS. PHMSA did consider this
as an alternative in the RIA but chose not to move forward with the
proposal as suggested as it is outside the scope of the mandate.
    (6) Regarding the MCA definition, the GPAC recommended PHMSA
consider modifying the term ``occupied sites'' within the definition by
removing reference to ``5 or more persons'' and the timeframe of 50
days and tying the requirement for identifying occupied sites to the
HCA ``identified sites'' survey requirement as discussed by members and
PHMSA at the meeting. In this final rule, PHMSA chose to delete the
term ``occupied sites'' from the MCA definition and from the general
definitions section of part 192.
    (7) PHMSA moved the specific ECA requirements outside of the MAOP
reconfirmation section into a new stand-alone Sec.  192.632. The MAOP
reconfirmation requirements regarding the ECA method at Sec.
192.624(c)(3) and the ECA requirements in Sec.  192.632 will cross-
reference each other. PHMSA made this change to streamline the MAOP
reconfirmation provisions and improve the readability of the
requirements. No substantive changes were made to the procedure in
connection with this reorganization; this was a stylistic change only.

V. Section-by-Section Analysis

Sec.  191.23 Reporting Safety-Related Conditions

    Section 23 of the 2011 Pipeline Safety Act requires operators to
report each exceedance of MAOP that exceeds the margin (build-up)
allowed for operation of pressure-limiting or control devices. On
December 21, 2012, PHMSA published advisory bulletin ADB-2012-11, which
advised operators of their responsibility under section 23 of the 2011
Pipeline Safety Act to report such exceedances. PHMSA is revising Sec.
191.23 to codify this statutory requirement.

Sec.  191.25 Filing Safety-Related Condition Reports

    Section 23 of the 2011 Pipeline Safety Act requires operators to
report each exceedance of the MAOP that exceeds the margin (build-up)
allowed for operation of pressure-limiting or control devices. As
described above, PHMSA is revising Sec.  191.23 to codify this
requirement. Section 191.25 is also revised to make conforming edits
and comply with the mandatory 5-day reporting deadline specified in
section 23 of the 2011 Pipeline Safety Act.

Sec.  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 proposed definition of ``Moderate
consequence area.'' This change will define this term as it is used
throughout part 192.
    The definition of a ``moderate consequence area,'' or MCA, is based
on similar methodology used to define ``high consequence area,'' or HCA
in Sec.  192.903. Moderate consequence areas will define the subset of
non-HCA locations where integrity assessments are required (Sec.
192.710) and where MAOP reconfirmation is required (Sec.  192.624). The
criteria for determining MCA locations differs from the criteria
currently used to identify HCAs in that the threshold for buildings
intended for human occupancy located within the potential impact radius
is lowered from 20 to 5, and identified sites are excluded. In response
to NTSB recommendation P-14-01, which was issued as a result of the
incident near Sissonville, WV, the MCA definition also includes
locations where interstate highways, freeways, expressways, and other
principal 4-or-more-lane arterial roadways are located within the
potential impact radius.
    PHMSA is also adopting a definition of an ``engineering critical
assessment,'' as that term will be used in Sec. Sec.  192.624 and
192.632. More specifically, the ECA is a documented analytical
procedure that operators can use to determine the maximum tolerable
size for pipeline imperfections based on the MAOP of the particular
pipeline segment. Operators can use an ECA in conjunction with an ILI
inspection as one of the methods to reconfirm MAOP, if required.

Sec.  192.5 Class Locations

    Section 23 of the 2011 Pipeline Safety Act requires the Secretary
of Transportation to require verification of records used to establish
MAOP to ensure they accurately reflect the physical and operational
characteristics of certain pipelines and to confirm the established
MAOP of the pipelines. PHMSA has determined that an important aspect of
compliance with this requirement is to assure that pipeline class
location records are complete and accurate. This final rule adds a new
paragraph, Sec.  192.5(d), to require each operator of transmission
pipelines to maintain records documenting the current class location of
each pipeline segment and demonstrating how an operator determined each
current class location in accordance with this section.

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

    Section 192.7 lists documents that are incorporated by reference in
part 192. PHMSA is making conforming amendments to Sec.  192.7 in the
rule text to reflect other changes adopted in this final rule.

Sec.  192.9 What requirements apply to gathering lines?

    This final rule codifies new standards for gas transmission
pipelines, most of which are not intended to be applied to gas
gathering pipelines. PHMSA is making conforming amendments to Sec.
192.9 to clarify which provisions

apply only to gas transmission pipelines and not to gas gathering
pipelines.

Sec.  192.18 How To Notify PHMSA

    This final rule allows operators to notify PHMSA of proposed
alternative approaches to achieving the objective of the minimum safety
standards in several different regulatory sections. These notification
procedures for alternative actions are comparable to the existing
notification requirements in subpart O for the integrity management
regulations. Because PHMSA is expanding the use of notifications to
pipeline segments for which subpart O does not apply (i.e., to non-HCA
pipeline segments), PHMSA is adding a new Sec.  192.18 in subpart A
that contains the procedure for submitting such notifications for any
pipeline segment.

Sec.  192.67 Records: Material Properties

    Section 23 of the 2011 Pipeline Safety Act requires the Secretary
of Transportation to require the verification of records to ensure they
accurately reflect the physical and operational characteristics of
certain pipelines and to confirm the established MAOP of the pipelines.
PHMSA has determined that compliance requires that pipeline material
properties records are complete and accurate. This final rule moves the
original Sec.  192.67 to Sec.  192.69 and adds in its place a new Sec.
192.67 that requires each operator of gas transmission pipelines
installed after the effective date of this final rule to collect or
make, and retain for the life of the pipeline, records that document
the physical characteristics of the pipeline, including tests,
inspections, and attributes required by the manufacturing specification
in effect at the time the pipe was manufactured. The physical
characteristics an operator must keep documented include diameter,
yield strength, ultimate tensile strength, wall thickness, seam type,
and chemical composition. These requirements also apply to any new
materials or components that are put on existing pipelines. For
pipelines installed prior to the effective date of this final rule,
operators are required to retain for the life of the pipeline all such
records in their possession as of the effective date of this final
rule. These recordkeeping requirements apply to offshore gathering
lines and Type A gathering lines in accordance with Sec.  192.9.
    Pipelines that lack the traceable, verifiable, and complete records
needed to substantiate MAOP may be subject to the MAOP reconfirmation
requirements at Sec.  192.624, as specified in that section.

Sec.  192.69 Storage and Handling of Plastic Pipe and Associated
Components

    Previous Sec.  192.67, titled ``Storage and handling of plastic
pipe and associated components,'' was created as a part of the Plastic
Pipe rule, which was published on November 20, 2018 (83 FR 58716).
PHMSA is redesignating that section in this final rule to a new Sec.
192.69. No other changes have been made to the section.

Sec.  192.127 Records: Pipe Design

    Section 23 of the 2011 Pipeline Safety Act requires the Secretary
of Transportation to require the verification of records to ensure they
accurately reflect the physical and operational characteristics of
certain pipelines and to confirm the established MAOP of the pipelines.
PHMSA has determined that compliance requires that pipe design records
are complete and accurate. For pipelines installed after the effective
date of this final rule, this final rule adds a new Sec.  192.127 to
require each operator of gas transmission pipelines to collect or make,
and retain for the life of the pipeline, records documenting pipe
design to withstand anticipated external pressures and determination of
design pressure for steel pipe. For pipelines installed prior to the
effective date of this final rule, operators are required to retain for
the life of the pipeline all such records in their possession as of the
effective date of this final rule. Pipelines that lack the traceable,
verifiable, and complete records needed to substantiate MAOP may be
subject to the MAOP reconfirmation requirements at Sec.  192.624, as
specified in that section.

Sec.  192.150 Passage of Internal Inspection Devices

    The current pipeline safety regulations in Sec.  192.150 require
that pipelines be designed and constructed to accommodate in-line
inspection devices. Prior to this rulemaking, part 192 was silent on
technical standards or guidelines for implementing requirements to
assure pipelines are designed and constructed for in-line inspection
assessments. Previously, there was no consensus industry standard that
addressed design and construction requirements for in-line inspection
assessments. NACE Standard Practice, NACE SP0102-2010, ``In-line
Inspection of Pipelines,'' has since been published and provides
guidance on this issue in section 7. The incorporation of this standard
into the Federal Pipeline Safety Regulations at Sec.  192.150 will
promote a higher level of safety by establishing consistent standards
for the design and construction of pipelines to accommodate in-line
inspection devices.

Sec.  192.205 Records: Pipeline Components

    Section 23 of the 2011 Pipeline Safety Act requires the Secretary
of Transportation to require the verification of records to ensure they
accurately reflect the physical and operational characteristics of
certain pipelines and to confirm the established MAOP of the pipelines.
PHMSA has determined that compliance requires that pipeline component
records are complete and accurate. For pipelines installed after the
effective date of this final rule, this final rule adds a new Sec.
192.205 to require each operator of gas transmission pipelines to
collect or make, and retain for the operational life of the component,
records documenting manufacturing and testing information for valves
and other pipeline components. For pipelines installed prior to the
effective date of this final rule, operators are required to retain for
the life of the pipeline all such records in their possession as of the
effective date of this final rule. Pipelines that lack the traceable,
verifiable, and complete records needed to substantiate MAOP may be
subject to the MAOP reconfirmation requirements at Sec.  192.624, as
specified in that section.

Sec.  192.227 Qualification of Welders

    Section 23 of the 2011 Pipeline Safety Act requires the Secretary
of Transportation to require the verification of records to ensure they
accurately reflect the physical and operational characteristics of
certain pipelines and to confirm the established MAOP of the pipelines.
PHMSA has determined that compliance requires that pipeline welding
qualification records are complete and accurate. This final rule adds a
new paragraph, Sec.  192.227(c), to require each operator of gas
transmission pipelines to make and retain records demonstrating each
individual welder's qualification in accordance with this section for a
minimum of 5 years following construction. This requirement will apply
to pipelines installed after one year from the effective date of the
rule.

Sec.  192.285 Plastic Pipe: Qualifying Persons To Make Joints

    Section 23 of the 2011 Pipeline Safety Act requires the Secretary
of Transportation to require the verification of records to ensure they
accurately reflect the physical and

operational characteristics of certain pipelines and to confirm the
established MAOP of the pipelines. PHMSA has determined that compliance
requires that plastic pipeline qualification records are complete and
accurate. This final rule adds a new paragraph, Sec.  192.285(e), to
require each operator of gas transmission pipelines to make and retain
records demonstrating a person's plastic pipe joining qualifications in
accordance with this section for a minimum of 5 years following
construction. This requirement will apply to pipelines installed after
one year from the effective date of the rule.

Sec.  192.493 In-Line Inspection of Pipelines

    The current pipeline safety regulations at Sec. Sec.  192.921 and
192.937 require that operators assess the material condition of
pipelines in certain circumstances (e.g., IM assessments for pipelines
in HCAs) and allow the use of ILI tools for these assessments.
Operators of gas transmission pipelines are required to follow the
requirements of ASME/ANSI B31.8S, ``Managing System Integrity of Gas
Pipelines,'' in conducting their IM activities. ASME B31.8S provides
limited guidance for conducting ILI assessments. Presently, part 192 is
silent on the technical standards or guidelines for performing ILI
assessments or implementing these requirements. When the IM regulations
were initially promulgated, there were no uniform industry standards
for ILI assessments. Three related standards have since been published:
     API STD 1163-2013, ``In-Line Inspection Systems
Qualification Standard.'' This Standard serves as an umbrella document
to be used with and as a complement to the NACE and ASNT standards
below, which are incorporated by reference in API STD 1163.
     NACE Standard Practice, NACE SP0102-2010, ``In-line
Inspection of Pipelines.''
     ANSI/ASNT ILI-PQ-2005 (2010), ``In-line Inspection
Personnel Qualification and Certification.''
    API 1163-2013 is more comprehensive and rigorous than the current
requirements in 49 CFR part 192. The incorporation of this standard
into the Federal Pipeline Safety Regulations will promote a higher
level of safety by establishing consistent standards to qualify the
equipment, people, processes, and software utilized by the ILI
industry. The API standard addresses in detail each of the following
aspects of ILI inspections, most of which are not currently addressed
in the regulations:
     Systems qualification process.
     Personnel qualification.
     ILI system selection.
     Qualification of performance specifications.
     System operational validation.
     System results qualification.
     Reporting requirements.
     Quality management system.
    The NACE standard covers in detail each of the following aspects of
ILI assessments, most of which are not currently addressed in part 192
or in ASME B31.8S:
     Tool selection.
     Evaluation of pipeline compatibility with ILI.
     Logistical guidelines, which includes survey acceptance
criteria and reporting.
     Scheduling.
     New construction (planning for future ILI in new lines).
     Data analysis.
     Data management.
    The NACE standard provides a standardized questionnaire and
specifies that the completed questionnaire should be provided to the
ILI vendor. The questionnaire lists relevant parameters and
characteristics of the pipeline section to be inspected. PHMSA
determined that the consistency, accuracy, and quality of pipeline in-
line inspections would be improved by incorporating the consensus NACE
standard into the regulations.
    The NACE standard applies to ``free swimming'' inspection tools
that are carried down the pipeline by the transported product. It does
not apply to tethered or remotely controlled ILI tools, which can also
be used in special circumstances (e.g., examination of laterals). While
their use is less prevalent than free-swimming tools, some pipeline IM
assessments have been conducted using tethered or remotely controlled
ILI tools. PHMSA determined that many of the provisions in the NACE
standard can be applied to tethered or remotely controlled ILI tools.
Therefore, PHMSA is amending the Federal Pipeline Safety Regulations to
allow the use of these tools, provided they comply with the applicable
sections of the NACE standard.
    The ANSI/ASNT standard provides for qualification and certification
requirements that are not addressed by 49 CFR part 192. The
incorporation of this standard into the regulations will promote a
higher level of safety by establishing consistent standards to qualify
the equipment, people, processes and software utilized by the ILI
industry. The ANSI/ASNT standard addresses in detail each of the
following aspects, which are not currently addressed in the
regulations:
     Requirements for written procedures.
     Personnel qualification levels.
     Education, training and experience requirements.
     Training programs.
     Examinations (testing of personnel).
     Personnel certification and recertification.
     Personnel technical performance evaluations.
    The final rule adds a new Sec.  192.493 to require compliance with
the three consensus standards discussed above when conducting ILI of
pipelines.

Sec.  192.506 Transmission Lines: Spike Hydrostatic Pressure Test

    A pressure test that incorporates a short duration ``spike''
pressure is a proven means to confirm the strength of pipe with known
or suspected threats of cracks or crack-like defects (e.g., stress
corrosion cracking, longitudinal seam defects, etc.). Currently, part
192 does not include minimum standards for such a spike hydrostatic
pressure test. This final rule adds a new Sec.  192.506 to codify the
minimum standards for performing spike hydrostatic pressure tests when
operators are required to, or elect to, use this assessment method.
Under the spike hydrostatic pressure test requirements, an operator may
use other technologies or processes equivalent to a spike hydrostatic
pressure test with justification and notification in accordance with
Sec.  192.18.

Sec.  192.517 Records: Tests

    Section 192.517 prescribes the recordkeeping requirements for each
test performed under Sec. Sec.  192.505 and 192.507. PHMSA is making
conforming amendments to Sec.  192.517 to add the recordkeeping
requirements for the new Sec.  192.506.

Sec.  192.607 Verification of Pipeline Material Properties and
Attributes: Onshore Steel Transmission Pipelines

    Section 23 of the 2011 Pipeline Safety Act mandates the Secretary
of Transportation to require operators of gas transmission pipelines in
Class 3 and Class 4 locations and Class 1 and Class 2 locations in HCAs
to verify records to ensure the records accurately reflect the physical
and operational characteristics of the pipelines and confirm the MAOP
of the pipelines established by the operator (49 U.S.C. 60139). PHMSA
issued Advisory Bulletin 11-01 on January 10, 2011 (76

FR 1504), and Advisory Bulletin 12-06 on May 7, 2012 (77 FR 26822), to
inform operators of this requirement. Operators have submitted
information in their Annual Reports (starting for calendar year 2012)
indicating that a portion of transmission pipeline segments do not have
adequate records to establish MAOP and that some operators do not have
traceable, verifiable, and complete records that accurately reflect the
physical and operational characteristics of the pipeline. Therefore,
PHMSA has determined that additional regulations are needed to
implement the 2011 Pipeline Safety Act. This final rule promulgates
specific criteria for determining which pipeline segments must undergo
examinations and tests to understand and document physical and material
properties and reconfirm a proper MAOP. For operators that do not have
traceable, verifiable, and complete documentation for the physical
pipeline characteristics and attributes of a pipeline segment, PHMSA is
adding a new Sec.  192.607 that contains the procedure for verifying
and documenting pipeline physical properties and attributes that are
not documented in traceable, verifiable, and complete records and to
establish standards for performing these actions. For operators of
certain pipelines lacking the necessary records to substantiate MAOP,
PHMSA is also adding Sec.  192.624, which provides operators several
methods for reconfirming a pipeline segment's MAOP.
    The new material properties verification requirements at Sec.
192.607 include the scope of information needed and the methodology for
verifying material properties and attributes of pipelines. The most
difficult information to obtain, from a technical perspective, is the
strength of the pipeline's steel. Conventional techniques to obtain
that data would include cutting out a piece of pipe and destructively
testing it to determine the yield and ultimate tensile strength. In
this final rule, PHMSA is providing operators with flexibility by
allowing the use of non-destructive techniques that have been validated
to produce accurate results for the grade and type of pipe being
evaluated (see Sec.  192.624).
    Another issue regarding material properties verification is the
cost associated with excavating the pipeline to verify material
properties and determining how much pipeline needs to be exposed and
tested to have assurance of the accuracy of the verification. PHMSA
addresses these issues within this final rule by specifying that
operators can take advantage of opportunities when the pipeline is
already being exposed, such as when maintenance activity is occurring
and when anomaly repairs are being made, to verify material properties
that are not documented in traceable, verifiable, and complete records.
For example, PHMSA considers excavations associated with the direct
examination of anomalies, pipeline relocations at road crossings and
river or stream crossings, pipe upgrades for class location changes,
pipe cut-outs for hydrostatic pressure tests, and excavations where
pipe is replaced due to anomalies to be opportunities to perform
material properties verification. Over time, pipeline operators will
develop a substantial set of traceable, verifiable, and complete
material properties data, which will provide assurance that material
properties are reliably known for the population of segments that did
not have pipeline physical properties and attributes documented in
traceable, verifiable, and complete records previously. Through this
final rule, PHMSA is requiring that operators continue this
opportunistic material properties verification process until the
operator has completed enough verifications to obtain a high level of
confidence that only a small percentage of pipeline segments have
physical pipeline characteristics and attributes that are not verified
or are otherwise inconsistent with all available information or
operators' past assumptions. This final rule specifies the number of
excavations required for operators to achieve this level of confidence.
    Operators may use an alternative sampling approach that differs
from the sampling approach specified in the requirements if they notify
PHMSA in advance of using an alternative sampling approach in
accordance with Sec.  192.18.
    Requirements are also included in the material properties
verification section to ensure that operators document the results of
the material properties verification process in records that must be
retained for the life of the pipeline.

Sec.  192.619 Maximum Allowable Operating Pressure: Steel or Plastic
Pipelines

    The NTSB report on the PG&E incident included a recommendation (P-
11-15) that PHMSA amend its regulations so that manufacturing-and
construction-related defects can only be considered ``stable'' if a gas
pipeline has been subjected to a post-construction hydrostatic pressure
test of at least 1.25 times the MAOP. This final rule revises the test
pressure factors in Sec.  192.619(a)(2)(ii) to correspond to at least
1.25 times MAOP for pipelines installed after the effective date of
this rule.
    The NTSB also recommended repealing Sec.  192.619(c), commonly
referred to as the ``grandfather clause,'' and requiring that all gas
transmission pipelines constructed before 1970 be subjected to a
hydrostatic pressure test that incorporates a spike test
(recommendation P-11-14). Similarly, section 23 of the 2011 Pipeline
Safety Act requires that selected pipeline segments in certain
locations with previously untested pipe (i.e., the MAOP is established
under Sec.  192.619(c)) or without MAOP records be tested with a
pressure test or equivalent means to reconfirm the pipeline's MAOP.
These requirements are addressed in the new Sec.  192.624 and are
described in more detail in the following section. This final rule also
makes conforming changes to Sec.  192.619 to require that operators of
pipeline segments to which Sec.  192.624 applies establish and document
the segment's MAOP in accordance with Sec.  192.624.

Sec.  192.624 Maximum Allowable Operating Pressure Reconfirmation:
Onshore Steel Transmission Pipelines

    Section 23 of the 2011 Pipeline Safety Act requires the
verification of records for pipe in Class 3 and Class 4 locations, and
high-consequence areas in Class 1 and Class 2 locations, to ensure they
accurately reflect the physical and operational characteristics of the
pipelines and confirm the established MAOP of the pipelines. Operators
have submitted information in annual reports (beginning in calendar
year 2012) indicating that some gas transmission pipeline segments do
not have adequate material properties records or testing records to
confirm physical and operational characteristics and to establish MAOP.
For these pipelines, the 2011 Pipeline Safety Act requires that PHMSA
promulgate regulations to require operators to reconfirm MAOP as
expeditiously as economically feasible. The statute also requires PHMSA
to issue regulations that require previously untested pipeline segments
located in HCAs and operating at greater than 30 percent SMYS be tested
to confirm the material strength of the pipelines. Such tests must be
performed by pressure testing or other methods determined by the
Secretary to be of equal or greater effectiveness.
    As a result of its investigation of the PG&E incident, the NTSB
issued two related recommendations. NTSB recommended that PHMSA repeal
Sec.  192.619(c), commonly referred to as

the ``grandfather clause,'' and require that all gas transmission
pipelines constructed before 1970 be subjected to a hydrostatic
pressure test that incorporates a spike test (P-11-14). The NTSB also
recommended that PHMSA amend the Federal Pipeline Safety Regulations so
that manufacturing- and construction-related defects can only be
considered stable if a pipeline has been subjected to a post-
construction hydrostatic pressure test of at least 1.25 times the MAOP
(P-11-15).
    Through this final rule, PHMSA is finalizing a new Sec.  192.624 to
address these mandates and recommendations. This final rule requires
that operators reconfirm and document MAOP for certain onshore steel
gas transmission pipelines located in HCAs or MCAs that meet one or
more of the criteria specified in Sec.  192.624(a). More specifically,
this section applies to (1) pipelines in HCAs or Class 3 or Class 4
locations lacking traceable, verifiable, and complete records necessary
to establish the MAOP (per Sec.  192.619(a)) for the pipeline segment,
including, but not limited to, hydrostatic pressure test records
required by Sec.  192.517(a); and (2) pipelines where the MAOP was
established in accordance with Sec.  192.619(c), the pipeline segment's
MAOP is greater than or equal to 30 percent of SMYS, and the pipeline
is located in an HCA, a Class 3 or Class 4 location, or an MCA that can
accommodate inspection by means of instrumented inline inspection tools
(i.e., ``smart pigs''). This approach implements the mandate in the
2011 Pipeline Safety Act for pipeline segments in HCAs and Class 3 and
Class 4 locations (49 U.S.C. 60139). In addition, the scope includes
pipeline segments in the newly defined MCAs. This approach is intended
to address the NTSB recommendations and to provide increased safety in
areas where a pipeline rupture would have a significant impact on the
public or the environment. Though PHMSA is subjecting certain
grandfathered pipeline segments to the MAOP reconfirmation requirements
of Sec.  192.624, PHMSA is not repealing Sec.  192.619(c) for pipeline
segments located outside of HCAs, Class 3 or Class 4 locations, or MCAs
that can accommodate inspection by means of instrumented ILI tools.
Previously grandfathered pipelines that reconfirm MAOP using one of the
methods of Sec.  192.624 that operate above 72 percent SMYS may
continue to operate at the reconfirmed pressure.
    The methods to reconfirm MAOP are specified in Sec.  192.624 and
are as follows:
    Method 1--Pressure test. The pressure test method as specified in
section 23 of the 2011 Pipeline Safety Act. Operators choosing to
pressure test must also verify material property records in accordance
with Sec.  192.607. PHMSA notes that a pressure test requires the
cutout of pipe at test manifold sites and those pipe cutouts would be a
prime example of pipe that could and should be tested through the
material properties verification procedure, if necessary. In accordance
with the statute, PHMSA determined that the following methods (2)
through (6) are equally effective as a pressure test for the purposes
of reconfirming MAOP.
    Method 2--Pressure reduction. De-rating the pipeline segment so
that the new MAOP is less than the historical actual sustained
operating pressure by using a pressure test safety factor of 0.80 (for
Class 1 and Class 2 locations) or 0.67 (for Class 3 and Class 4
locations) times the sustained operating pressure (equivalent to a
pressure test using gas or water as the test medium with a test
pressure of 1.25 times MAOP for Class 1 and Class 2 locations and 1.5
times MAOP for Class 3 and Class 4 locations).
    Method 3--Engineering critical assessment. An in-line inspection,
previously performed pressure test, or alternative technology and
engineering critical assessment process using technical analysis with
acceptance criteria to establish a safety margin equivalent to that
provided by a new pressure test. PHMSA organized the ECA process
requirements under a new Sec.  192.632 and established the technical
requirements for analyzing the predicted failure pressure as a part of
the ECA analysis in a new Sec.  192.712. If an operator chooses the ECA
method for MAOP reconfirmation but does not have any of the material
properties necessary to perform an ECA analysis (diameter, wall
thickness, seam type, grade, and Charpy V-notch toughness values, if
applicable), the operator must include the pipeline segment in its
program to verify the undocumented information in accordance with the
material properties verification requirements at Sec.  192.607.
    Method 4--Pipe replacement. Replacement of the pipe, which would
require a new pressure test that conforms with subpart J before the
pipe is placed into service.
    Method 5--Pressure reduction for pipeline segments with small
potential impact radii. For pipeline segments with a potential impact
radius of less than or equal to 150 feet, a pressure reduction using a
safety factor of 0.90 times the sustained operating pressure is allowed
(equivalent to a pressure test of 1.11 times MAOP), supplemented with
additional preventive and mitigative measures specified in this final
rule.
    Method 6--Alternative technology. Other technology that the
operator demonstrates provides an equivalent or greater level of
safety, provided PHMSA is notified in advance in accordance with Sec.
192.18.
    Lastly, this final rule includes a new paragraph, Sec.  192.624(f),
to clearly specify that records created while reconfirming MAOP must be
retained for the life of the pipeline.

Sec.  192.632 Engineering Critical Assessment for Maximum Allowable
Operating Pressure Reconfirmation: Onshore Steel Transmission Pipelines

    The requirements for reconfirming MAOP in the new Sec.  192.624
include an option for operators to perform an engineering critical
assessment, or ECA, to reconfirm MAOP in lieu of pressure testing and
the other methods provided. The requirements for conducting such an ECA
were proposed under the MAOP reconfirmation requirements at Sec.
192.624(c)(3); however, PHMSA has moved the ECA requirements to a new,
stand-alone section and cross-referenced those requirements in order to
improve the readability of the MAOP reconfirmation requirements.
    Operators choosing the ECA method for MAOP reconfirmation may
perform an in-line inspection and a technical analysis with acceptance
criteria to establish a safety margin equivalent to that provided by a
pressure test. PHMSA established the technical requirements for
analyzing the predicted failure pressure as a part of the ECA analysis
in a new Sec.  192.712, and those requirements are cross-referenced
within this ECA process.
    Although PHMSA expects that most operators will use an ECA in
conjunction with in-line inspection, PHMSA would also allow operators
with past, valid pressure tests to calculate the largest defects that
could have survived the pressure test and analyze the postulated
defects to calculate a predicted failure pressure with which to
establish MAOP. This approach might be desirable for operators in
certain circumstances, such as for line segments that have valid
pressure test records, but that lack other records (such as material
strength or pipe wall thickness) necessary to determine design pressure
and establish MAOP under the existing Sec.  192.619(a). Another
situation for which operators could use this approach would be if the
operator has a valid pressure test, but it was not conducted at a test
pressure that

was high enough to establish the current MAOP.
    Operators with pressure test records meeting the subpart J test
requirements may use an ECA by calculating the largest defect that
could have survived the pressure test and estimating the flaw growth
between the date of the test and the date of the ECA. The ECA is then
performed using these postulated defect sizes. In addition, operators
must calculate the remaining life of the most severe defects that could
have survived the pressure test and establish an appropriate re-
assessment interval in accordance with new Sec.  192.712.
    If an operator chooses to use ILI to characterize the defects
remaining in the pipe segment and the ECA method for MAOP
reconfirmation but does not have one or more of the material properties
necessary to perform an ECA analysis (diameter, wall thickness, seam
type, grade, and Charpy V-notch toughness values, if applicable), the
operator must use conservative assumptions and include the pipeline
segment in its program to verify the undocumented information in
accordance with the material properties verification requirements at
Sec.  192.607.

Sec.  192.710 Transmission Lines: Assessments Outside of High
Consequence Areas

    Section 5 of the 2011 Pipeline Safety Act requires, if appropriate,
the Secretary of Transportation to issue regulations expanding IM
system requirements, or elements thereof, beyond HCAs. Currently, part
192 does not contain any requirement for operators to conduct integrity
assessments of onshore transmission pipelines that are not HCA
segments, as defined in Sec.  192.903, and are therefore not subject to
subpart O. However, only approximately 7 percent of onshore gas
transmission pipelines are located in HCAs. Through this final rule,
operators are required to periodically assess Class 3 locations, Class
4 locations, and MCAs that can accommodate inspection by means of an
instrumented inline inspection tool. The periodic assessment
requirements under this section apply to pipelines in these locations
with MAOPs greater than or equal to 30 percent of SMYS.
    Industry has, as a practical matter, assessed portions of pipelines
in non-HCA segments coincident with integrity assessments of HCA
pipeline segments. For example, INGAA has noted in comment submissions
that approximately 90 percent of Class 3 and Class 4 mileage not in
HCAs are presently assessed during IM assessments. This is because, in
large part, ILI or pressure testing, by their nature, assess large
continuous pipeline segments that may contain some HCA segments but
that could also contain significant amounts of non-HCA segments.
    While INGAA does not represent all pipeline operators subject to
part 192, it does represent the majority of gas transmission operators.
PHMSA has determined that, given this level of assessment, it is
appropriate and consistent with industry direction to codify
requirements for operators to periodically assess certain gas
transmission pipelines outside of HCAs to monitor for, detect, and
remediate pipeline defects and anomalies. Additionally, to achieve the
desired outcome of performing assessments in areas where people live,
work, or congregate, while minimizing the cost of identifying such
locations, PHMSA is basing the requirements for identifying those
locations on processes already being implemented by pipeline operators.
More specifically, the MCA definition assumes a similar process used
for identifying HCAs, with the exception that the threshold for
buildings intended for human occupancy located within the potential
impact circle is reduced from 20 to 5.
    Because significant non-HCA pipeline mileage has been previously
assessed in conjunction with the regular assessment of HCA pipeline
segments, PHMSA is allowing operators to count those prior assessments
as compliant with the new Sec.  192.710 for the purposes of assessing
non-HCAs if those assessments were conducted, and threats remediated,
in conjunction with an integrity assessment required by subpart O.
    This final rule also requires that the assessment required by the
new Sec.  192.710 be conducted using the same methods as adopted for
HCAs (see Sec.  192.921, below). Operators may use ``other technology''
as an assessment method, provided the operator notifies PHMSA in
accordance with Sec.  192.18.

Sec.  192.712 Analysis of Predicted Failure Pressure

    The new requirements for reconfirming MAOP in the new Sec.  192.624
include an option for operators to perform an engineering critical
assessment, or ECA, to reconfirm MAOP in lieu of pressure testing and
the other methods provided. A key aspect of the ECA analysis is the
detailed analysis of the remaining strength of pipe with known or
assumed defects. The current Federal Pipeline Safety Regulations in
subparts I and O refer to methods for predicting the failure pressure
for pipe with corrosion metal loss defects. However, the regulations
are silent on performing such analysis for pipe with cracks (including
crack-like defects such as selective seam weld corrosion). Therefore,
in this final rule, PHMSA is inserting a new section to address the
techniques and procedures for analyzing the predicted failure pressures
for pipe with corrosion metal loss and cracks or crack-like defects.
Examples of technically proven models for calculating predicted failure
pressures include: For the brittle failure mode, the Newman-Raju Model
\87\ and PipeAssess PITM software; \88\ and for the ductile
failure mode, Modified Log-Secant Model,\89\ API RP 579-1 \90\--Level
II or Level III, CorLasTM software,\91\ PAFFC Model,\92\ and
PipeAssess PITM software. All failure models used for the
ECA analysis must be used within its technical parameters for the
defect type and the pipe or weld material properties. Conforming
changes are being made to applicable sections in subparts I and O to
refer to this new section, for consistency, but the basic techniques
are unchanged.
---------------------------------------------------------------------------

    \87\ Newman, J.C., and Raju; ``Stress Intensity Factors for
Cracks in Three Dimensional Finite Bodies Subjected to Tension and
Bending Loads;'' Computational Methods in the Mechanics of Fracture;
Elsevier; 1986; pp. 311-334.
    \88\ Interim Report for Phase II--Task 5 of the Comprehensive
Study to Understand Longitudinal ERW Seam Failures, ``Summary Report
for an Integrity Management Software Tool,'' May 2017. https://primis.phmsa.dot.gov/matrix/FilGet.rdm?fil=11469.
    \89\ ASTM International, ASTM STP 536, ``Failure Stress Levels
of Flaws in Pressurized Cylinders,'' 1973.
    \90\ American Petroleum Institute and American Society of
Mechanical Engineers, API 579-1/ASME FFS-1, ``Fitness-For-Service,''
Second Edition, June 2007.
    \91\ NACE International, NACE Corrosion 96 Paper 255, ``Effect
of Stress Corrosion Cracking on Integrity and Remaining Life of
Natural Gas Pipelines,'' March 1996.
    \92\ Pipeline Research Council International, Inc., Topical
Report NG-18 No. 193, ``Development and Validation of a Ductile Flaw
Growth Analysis for Gas Transmission Line Pipe,'' June 1991.
---------------------------------------------------------------------------

    As a part of this section, PHMSA is including a new paragraph to
address cracks and crack-like defects, which as stated above is a
critical function of the ECA analysis. The ECA analysis requires the
conservative analysis of any in-service cracks, crack-like defects
remaining in the pipe, or the largest possible crack that could remain
in the pipe, including crack dimensions (length and depth) to determine
the predicted failure pressure (PFP) of each defect; the failure mode
(ductile, brittle, or both) for the microstructure; the defect's
location and type; the pipeline's operating conditions (including
pressure cycling); and failure stress and

crack growth analysis to determine the remaining life of the pipeline.
An ECA must use the techniques and procedures developed and confirmed
through the research findings provided by PHMSA and other reputable
technical sources for longitudinal seam and crack growth, such as the
Comprehensive Study to Understand Longitudinal ERW Seam Research &
Development study task reports: Battelle Final Reports (``Battelle's
Experience with ERW and Flash Weld Seam Failures: Causes and
Implications''--Task 1.4), Report No. 13-002 (``Models for Predicting
Failure Stress Levels for Defects Affecting ERW and Flash-Welded
Seams''--Subtask 2.4), Report No. 13-021 (``Predicting Times to Failure
for ERW Seam Defects that Grow by Pressure-Cycle-Induced Fatigue''--
Subtask 2.5), and ``Final Summary Report and Recommendations for the
Comprehensive Study to Understand Longitudinal ERW Seam Failures--Phase
1''--Task 4.5), which can be found online at: https://primis.phmsa.dot.gov/matrix/PrjHome.rdm?prj=390. Operators wanting to
use assumed Charpy V-notch toughness values differing from the
prescribed values as a part of fracture mechanics analysis must notify
PHMSA in accordance with Sec.  192.18.

Sec.  192.750 Launcher and Receiver Safety

    PHMSA has determined that more explicit requirements are needed for
safety when performing maintenance activities that use launchers and
receivers to insert and remove maintenance tools and devices, as such
facilities are subject to pipeline system pressures. The current
regulations for hazardous liquid pipelines at 49 CFR part 195 have,
since 1981, contained such safety requirements for scraper and sphere
facilities (Sec.  195.426). However, the regulations for natural gas
pipelines do not similarly require controls or instrumentation to
protect against inadvertent breaches of system integrity due to the
incorrect operation of launchers and receivers for ILI tools, scraper,
and sphere facilities. Accordingly, this final rule is adding a new
Sec.  192.750 to require a suitable means to relieve pressure in the
barrel and either a means to indicate the pressure in the barrel or a
means to prevent opening if pressure has not been relieved.

Sec.  192.805 Qualification Program

    PHMSA is revising the Federal Pipeline Safety Regulations to
include a new Sec.  192.18 that provides instructions for submitting
notifications to PHMSA whenever required by part 192. PHMSA is making
conforming changes to Sec.  192.805 to refer to the new Sec.  192.18.

Sec.  192.909 How can an operator change its integrity management
program?

    PHMSA is revising the Federal Pipeline Safety Regulations to
include a new Sec.  192.18 that provides instructions for submitting
notifications to PHMSA whenever required by part 192. PHMSA is making
conforming changes to Sec.  192.909 to refer to the new Sec.  192.18.

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

    Section 29 of the 2011 Pipeline Safety Act requires operators to
consider seismicity when evaluating threats. Accordingly, PHMSA is
revising Sec.  192.917(a)(3) to include seismicity of the area in
evaluating the threat of outside force damage. To address NTSB
recommendation P-11-15, PHMSA is also revising the criteria in Sec.
192.917(e)(3) for addressing the threat of manufacturing and
construction defects by requiring that a pipeline segment must have
been pressure tested to a minimum of 1.25 times MAOP to conclude latent
defects are stable. Section 192.917(e)(4) has additional requirements
for the assessment of low-frequency ERW pipe with seam failures. It now
requires usage of the appropriate technology to assess low-frequency
ERW pipe, including seam cracking and selective seam weld corrosion.
Pipe with seam cracks must be evaluated using fracture mechanics
modeling for failure stress pressures and cyclic fatigue crack growth
analysis to estimate the remaining life of the pipe in accordance with
Sec.  192.712.
    Lastly, the integrity management requirements to address specific
threats in Sec.  192.917(e) include requirements for the major causes
of pipeline incidents, such as corrosion, third-party damage, cyclic
fatigue, manufacturing and construction defects, and electric
resistance welded pipe. However, Sec.  192.917(e) does not address
cracks and crack-like defects. Therefore, PHMSA is adding a new
paragraph, Sec.  192.917(e)(6), to include specific IM requirements for
addressing the threat of cracks and crack-like defects (including, but
not limited to, stress corrosion cracking or other environmentally
assisted cracking, seam defects, selective seam weld corrosion, girth
weld cracks, hook cracks, and fatigue cracks) comparable to the other
types of threats addressed in Sec.  192.917(e).

Sec.  192.921 How is the baseline assessment to be conducted?

    Section 192.921 requires that pipelines subject to the IM
regulations have an integrity assessment. The current regulations allow
operators to use ILI tools; pressure testing in accordance with subpart
J; direct assessment for the threats of external corrosion, internal
corrosion, and stress corrosion cracking; and other technology that the
operator demonstrates provides an equivalent level of understanding of
the condition of the pipeline. Following the PG&E incident, PHMSA
determined that the baseline assessment methods should be clarified and
strengthened to emphasize ILI use and pressure testing over direct
assessment. At San Bruno, PG&E relied heavily on direct assessment
under circumstances for which direct assessment was not effective nor
appropriate for the pipeline seam type and the threats to the pipeline.
Therefore, this final rule requires that direct assessment only be
allowed to assess the threats for which the specific direct assessment
process is appropriate.
    This final rule also adds three additional assessment methods for
operators to use: (1) A ``spike'' hydrostatic pressure test, which is
particularly well-suited to address time-dependent threats, such as
stress corrosion cracking and other cracking or crack-like defects that
can include manufacturing- and construction-related defects; (2) guided
wave ultrasonic testing (GWUT), which is particularly appropriate in
cases where short pipeline segments, such as road or railroad
crossings, are difficult to assess; and (3) excavation with direct in
situ examination. Based upon the threat assessed, examples of
appropriate non-destructive examination methods for in situ examination
can include ultrasonic testing, phased array ultrasonic testing,
inverse wave field extrapolation, radiography, or magnetic particle
inspection.
    The current regulations indicate that ILI tools are an acceptable
assessment method for the threats that the particular ILI tool type can
assess. PHMSA is clarifying in this final rule that the use of ILI
tools is appropriate for threats such as corrosion, deformation and
mechanical damage (including dents, gouges, and grooves), material
cracking and crack-like defects (e.g., stress corrosion cracking,
selective seam weld corrosion, environmentally assisted cracking, and
girth weld cracks), and hard spots with cracking. As discussed above,
this final rule

strengthens guidance in this area by adding a new Sec.  192.493 to
require compliance with the requirements and recommendations of API STD
1163-2005, NACE SP0102-2010, and ANSI/ASNT ILI-PQ-2005 when conducting
in-line inspection of pipelines. Accordingly, PHMSA revises Sec.
192.921(a)(1) in this final rule to require compliance with Sec.
192.493 instead of ASME B31.8S for baseline ILI assessments for covered
segments.
    GWUT has been used by pipeline operators for several years.
Previously, operators were required by Sec.  192.921(a)(4) to submit a
notification to PHMSA as an ``other technology'' assessment method to
use GWUT. In 2007, PHMSA developed guidelines for how it would evaluate
notifications for the use of GWUT. These guidelines have been
effectively used for over 9 years, and PHMSA has confidence that
operators can use GWUT to assess the integrity of short segments of
pipe against corrosion threats. In this final rule, PHMSA is
incorporating these guidelines into a new Appendix F, which is
referenced in Sec.  192.921. Therefore, operators would no longer be
required to notify PHMSA to use GWUT.
    ASME B31.8S, section 6.1, describes both excavation and direct in
situ examination as specialized integrity assessment methods applicable
to particular circumstances:

    It is important to note that some of the integrity assessment
methods discussed in para. 6 only provide indications of defects.
Examination using visual inspection and a variety of nondestructive
examination (NDE) techniques are required, followed by evaluation of
these inspection results in order to characterize the defect. The
operator may choose to go directly to examination and evaluation for
the entire length of the pipeline segment being assessed, in lieu of
conducting inspections. For example, the operator may wish to
conduct visual examination of aboveground piping for the external
corrosion threat. Since the pipe is accessible for this technique
and external corrosion can be readily evaluated, performing in-line
inspection is not necessary.

    PHMSA is clarifying its requirements to explicitly add excavation
and direct in situ examination as an acceptable assessment method. As
previously discussed under Sec.  192.710, PHMSA intends for operators
to assess non-HCA pipe with the same methods as HCA pipe. Therefore,
PHMSA has standardized the assessment methods between both the IM and
non-IM sections. Operators wishing to use ``other technology''
differing from the prescribed acceptable assessment methods must notify
PHMSA in accordance with Sec.  192.18.

Sec.  192.933 What actions must be taken to address integrity issues?

    PHMSA is revising the Federal Pipeline Safety Regulations to
include a new Sec.  192.18 that provides instructions for submitting
notifications to PHMSA whenever required by part 192. PHMSA is making
conforming changes to Sec.  192.933 to refer to the new Sec.  192.18.

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

    Section 29 of the 2011 Pipeline Safety Act requires operators to
consider seismicity when evaluating threats. Accordingly, PHMSA is
revising Sec.  192.935(b)(2) to include seismicity of the area when
evaluating preventive and mitigative measures with respect to the
threat of outside force damage.

Sec.  192.937 What is a continual process of evaluation and assessment
to maintain a pipeline's integrity?

    Section 192.937 requires that operators continue to periodically
assess HCA pipeline segments and periodically evaluate the integrity of
each covered pipeline segment. PHMSA determined that conforming
amendments would be needed to implement, and be consistent with, the
changes discussed above for Sec.  192.921. Accordingly, this final rule
requires that reassessments use the same assessment methods specified
in Sec.  192.921. Operators wishing to use ``other technology''
differing from the prescribed acceptable assessment methods must notify
PHMSA in accordance with Sec.  192.18.

Sec.  192.939 What are the required reassessment intervals?

    Section 192.939 specifies reassessment intervals for pipelines
subject to IM requirements. Section 5 of the 2011 Pipeline Safety Act
includes a technical correction that clarified that periodic
reassessments must occur at a minimum of once every 7 calendar years,
but that the Secretary may extend such deadline for an additional 6
months if the operator submits written notice to the Secretary with
sufficient justification of the need for the extension. PHMSA expects
that any justification, at a minimum, must demonstrate that the
extension does not pose a safety risk. In this final rule, PHMSA is
codifying this technical correction.
    As explained in PHMSA IM FAQ-41, the maximum interval for
reassessment may be set using the specified number of calendar years.
The use of calendar years is specific to gas pipeline reassessment
interval years and does not alter the actual year interval requirements
which appear elsewhere in the code for various inspection and
maintenance requirements.
    Additionally, PHMSA is revising Sec.  192.939 to include a new
Sec.  192.18 that provides instructions for submitting notifications to
PHMSA whenever required by part 192. PHMSA is making conforming changes
to Sec.  192.939 to refer to the new Sec.  192.18.

Sec.  192.949 How does an operator notify PHMSA? (Removed and Reserved)

    This rulemaking includes several requirements that allow operators
to notify PHMSA of proposed alternative approaches to achieving the
objective of the minimum safety standards. This is comparable to
existing notification requirements in subpart O for pipelines subject
to the IM regulations. Because PHMSA is expanding the use of
notifications to pipeline segments for which subpart O does not apply
(i.e., to non-HCA pipeline segments), PHMSA is adding a new Sec.
192.18 that contains the procedure for submitting such notifications.
As such, Sec.  192.949 is no longer needed and is being removed and
reserved.

Appendix F to Part 192--Criteria for Conducting Integrity Assessments
Using Guided Wave Ultrasonic Testing (GWUT)

    As discussed under Sec.  192.921 above, a new Appendix F to part
192 is needed to provide specific requirements and acceptance criteria
for the use of GWUT as an integrity assessment method. Operators must
apply all 18 criteria defined in Appendix F to use GWUT as an integrity
assessment method. If an operator applies GWUT technology in a manner
that does not conform with the guidelines in Appendix F, it would be
considered ``other technology'' for the purposes of Sec. Sec.  192.710,
192.921, and 192.937.

VI. Standards Incorporated by Reference

A. Summary of New and Revised Standards

    Consistent with the amendments in this document, PHMSA is
incorporating by reference several standards as described below. Some
of these standards are already incorporated by reference into the
Federal Pipeline Safety Regulations and are being extended to other
sections of the regulations. Other standards provide a technical basis
for corresponding regulatory changes in this final rule.

     API STD 1163, ``In-Line Inspection Systems
Qualification,'' Second edition, April 2013, Reaffirmed August 2018.
    This standard covers the use of ILI systems for onshore and
offshore gas and hazardous liquid pipelines. This includes, but is not
limited to, tethered, self-propelled, or free-flowing systems for
detecting metal loss, cracks, mechanical damage, pipeline geometries,
and pipeline location or mapping. The standard applies to both existing
and developing technologies. This standard is an umbrella document that
provides performance-based requirements for ILI systems, including
procedures, personnel, equipment, and associated software. The
incorporation of this standard into the Federal Pipeline Safety
Regulations will provide rigorous processes for qualifying the
equipment, people, processes, and software used in in-line inspections.
     ANSI/ASNT ILI-PQ-2005(2010), ``In-line Inspection
Personnel Qualification and Certification,'' Reapproved October 11,
2010.
    This standard establishes minimum requirements for the
qualification and certification of in-line inspection personnel whose
jobs demand specific knowledge of the technical principles of in-line
inspection technologies, operations, regulatory requirements, and
industry standards as those are applicable to pipeline systems. The
employer-based standard includes qualification and certification for
Levels I, II, and III. The incorporation of this standard into the
Federal Pipeline Safety Regulations provides for certification and
qualification requirements that are not otherwise addressed in part 192
and will promote a higher level of safety by establishing consistent
standards to qualify the equipment, people, processes, and software
used in in-line inspections.
     NACE Standard Practice 0102-2010, ``In-Line Inspection of
Pipelines,'' Revised 2010-03-13.
    This standard outlines a process of related activities that a
pipeline operator can use to plan, organize, and execute an ILI
project, and it includes guidelines pertaining to ILI data management
and data analysis. This standard is intended for individuals and teams,
including engineers, O&M personnel, technicians, specialists,
construction personnel, and inspectors, involved in planning,
implementing, and managing ILI projects and programs. The incorporation
of this standard into the Federal Pipeline Safety Regulations would
promote a higher level of safety by establishing consistent standards
to qualify the equipment, people, processes, and software used in in-
line inspections.
    PHMSA is also extending the applicability of the following three
currently incorporated-by-reference standards to new sections of the
Federal Pipeline Safety Regulations:
     ASME/ANSI B16.5-2003, ``Pipe Flanges and Flanged
Fittings,'' October 2004, IBR approved for Sec.  192.607(f).
    This standard covers pressure-temperature ratings, materials,
dimensions, tolerances, marking, testing, and methods of designating
openings for pipe flanges and flanged fittings. The standard includes
requirements and recommendations regarding flange bolting, flange
gaskets, and flange joints. This standard is intended for
manufacturers, owners, employers, users, and others concerned with the
specification, buying, maintenance, training, and safe use of valves
with pressure equipment. The incorporation of this standard promotes
industry best practices and operational, cost, and safety benefits.
     ASME/ANSI B31G-1991 (Reaffirmed 2004), ``Manual for
Determining the Remaining Strength of Corroded Pipelines,'' 2004, IBR
approved for Sec. Sec.  192.632(a) and 192.712(b).
    This document provides guidance for the evaluation of metal loss in
pressurized pipelines and piping systems. It is applicable to all
pipelines and piping systems that are part of the scope of the
transportation pipeline codes that are part of ASME B31 Code for
Pressure Piping, namely: ASME B31.4, Pipeline Transportation Systems
for Liquid Hydrocarbons and Other Liquids; ASME B31.8, Gas Transmission
and Distribution Piping Systems; ASME B31.11, Slurry Transportation
Piping Systems; and ASME B31.12, Hydrogen Piping and Pipelines, Part
PL.
     AGA, Pipeline Research Committee Project, PR-3-805, ``A
Modified Criterion for Evaluating the Remaining Strength of Corroded
Pipe,'' (December 22, 1989), IBR approved for Sec. Sec.  192.632(a) and
192.712(b).
    This document was developed from the Modified B31G method to allow
assessment of a river bottom profile of a corroded area on a pipeline
to provide more accurate predictions of the pipeline's remaining
strength, and it was adapted into a software program known as RSTRENG.
Pipeline operators can use RSTRENG to calculate a pipeline's predicted
failure pressure and safe pressure when determining operating pressures
and anomaly response times.
    The incorporation by reference of ASME/ANSI B31.8S 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.

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 60 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. ASTM
often updates some of its more widely used standards every year, and
sometimes multiple editions of standards are published in a given year.
    In accordance with the National Technology Transfer and Advancement
Act of 1995 (Pub. L. 104-113), PHMSA has the responsibility for
determining which currently referenced standards should be updated,
revised, or removed, and which standards should be added to 49 CFR
parts 192, 193, and 195. Revisions to incorporated by reference
materials in parts 192, 193, and 195 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.
    On January 3, 2012, President Obama signed the Pipeline Safety,
Regulatory Certainty, and Job Creation Act of 2011, Public Law 112-90.
Section 24 of that law states: ``Beginning 1 year after the date of
enactment of this subsection, the Secretary may not issue guidance or a
regulation pursuant to this chapter that incorporates by reference any
documents or portions thereof unless the documents or portions thereof
are made available to the public, free of charge, on an internet
website.'' 49 U.S.C. 60102(p).
    On August 9, 2013, Public Law 113-30 revised 49 U.S.C. 60102(p) to
replace ``1 year'' with ``3 years'' and remove the phrases ``guidance
or'' and, ``on an internet website.'' This resulted in the current
language in 49 U.S.C. 60102(p), which now reads as follows:
    Beginning 3 years after the date of enactment of this subsection,
the Secretary may not issue a regulation pursuant to this chapter that
incorporates by reference any documents or portions thereof unless the
documents or portions thereof are made available to the public, free of
charge.

    On November 7, 2014, the Office of the Federal Register issued a
final rule that revised 1 CFR 51.5 to require that Federal agencies
include a discussion in the preamble of the final rule ``the ways the
materials it incorporates by reference are reasonably available to
interested parties and how interested parties can obtain the
materials.'' 79 FR 66278. In relation to this rulemaking, PHMSA has
contacted each SDO and has requested free public access of each
standard that has been incorporated by reference. The SDOs agreed to
make viewable copies of the incorporated standards available to the
public at no cost. Pipeline operators interested in purchasing these
standards can contact the individual and applicable standards
organizations. The contact information is provided in this rulemaking
action, see Sec.  192.7.
    In addition, PHMSA will provide individual members of the public
temporary access to any standard that is incorporated by reference that
is not otherwise available for free. Requests for access can be sent to
the following email address<EMAIL_ADDRESS>
VII. Regulatory Analysis and Notices

A. Statutory/Legal Authority for This Rulemaking

    This final rule is published under the authority of the Federal
Pipeline Safety Statutes (49 U.S.C. 60101 et seq.). Section 60102
authorizes the Secretary of Transportation to issue regulations
governing design, installation, inspection, emergency plans and
procedures, testing, construction, extension, operation, replacement,
and maintenance of pipeline facilities, as delegated to the PHMSA
Administrator under 49 CFR 1.97.
    PHMSA is revising the ``Authority'' entry for parts 191 and 192 to
include a citation to a provision of the Mineral Leasing Act (MLA),
specifically, 30 U.S.C. 185(w)(3). Section 185(w)(3) provides that
``[p]eriodically, but at least once a year, the Secretary of the
Department of Transportation shall cause the examination of all
pipelines and associated facilities on Federal lands and shall cause
the prompt reporting of any potential leaks or safety problems.'' The
Secretary has delegated this responsibility to PHMSA (49 CFR 1.97).
PHMSA has traditionally complied with Sec.  185(w)(3) through the
issuance of its pipeline safety regulations, which require annual
examinations and prompt reporting for all or most of the pipelines they
cover. PHMSA is making this change to be consistent with and make clear
its long-standing position that the agency complies with the MLA
through the issuance of pipeline safety regulations.

B. Executive Orders 12866 and 13771, and DOT Regulatory Policies and
Procedures

    Executive Order 12866 requires agencies to regulate in the ``most
cost-effective manner,'' to make a ``reasoned determination that the
benefits of the intended regulation justify its costs,'' and to develop
regulations that ``impose the least burden on society.'' This action
has been determined to be significant under Executive Order 12866. It
is also considered significant under the Regulatory Policies and
Procedures of the Department of Transportation because of substantial
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 (Regulatory Planning and
Review) and is consistent with the Executive Order 12866 requirements
and 49 U.S.C. 60102(b)(5)-(6). Pursuant to the Congressional Review Act
(5 U.S.C. 801 et seq., the Office of Information and Regulatory Affairs
designated this rule as not a ``major rule,'' as defined by 5 U.S.C.
804(2). This final rule is considered an Executive Order 13771
regulatory action. Details on the estimated costs of this final rule
can be found in the rule's RIA.
    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
21 years and discounted to 2017 using rates of 3 percent and 7 percent.
PHMSA estimates incremental costs for the final requirements in Section
5 of the RIA. PHMSA finds that the other final rule requirements will
not result in an incremental cost. Additionally, PHMSA did not quantify
the cost savings from the material properties verification provisions
under this final rule compared to the existing regulations. The costs
of this final rule reflect incremental integrity assessments, MAOP
reconfirmation actions, and ILI launcher and receiver upgrades; PHMSA
estimates the annualized cost of this rule is $32.7 million at a 7
percent discount rate.

                 Summary of Annualized Costs, 2019-2039
                            [$2017 thousands]
------------------------------------------------------------------------
                                                  Annualized cost
                                         -------------------------------
                Provision                   3% Discount     7% Discount
                                               rate            rate
------------------------------------------------------------------------
1. MAOP Reconfirmation & Material                  $25.9           $27.9
 Properties Verification................
2. Seismicity...........................               0               0
3. Six-Month Grace Period for Seven                    0               0
 Calendar-Year Reassessment Intervals...
4. In-Line Inspection Launcher/Receiver             0.03            0.04
 Safety.................................
5. MAOP Exceedance Reports..............               0               0
6. Strengthening Requirements for                      0               0
 Assessment Methods.....................
7. Assessments Outside HCAs.............            5.48            4.71
8. Related Records Provisions...........               0               0
                                         -------------------------------
    Total...............................            31.4            32.7
------------------------------------------------------------------------

    The benefits of the final rule will depend on the degree to which
compliance actions result in additional safety measures, relative to
the current baseline, and the effectiveness of these measures in
preventing or mitigating future pipeline releases or other incidents.
For the final rule RIA, PHMSA did not monetize benefits. The rule's
benefits are discussed qualitatively instead.
    For more information, please see the RIA in the docket for this
rulemaking.

C. Regulatory Flexibility Act

    The Regulatory Flexibility Act (RFA), as amended by the Small
Business Regulatory Flexibility Fairness Act of 1996, requires Federal
regulatory agencies to prepare a Final Regulatory Flexibility Analysis
(FRFA) for any final rule subject to notice-and-comment rulemaking
under the Administrative Procedure Act unless the agency head certifies
that the rule will not have a significant economic impact on a
substantial number of small entities. PHMSA prepared a FRFA which is
available in the docket for the rulemaking.

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.'' Because this final rule would not significantly
or uniquely affect the communities of the Indian tribal governments or
impose substantial direct compliance costs, the funding and
consultation requirements of Executive Order 13175 do not apply.

E. Paperwork Reduction Act

    Pursuant to 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 18, 2016, PHMSA published an NPRM seeking public
comments on the revision of the Federal Pipeline Safety Regulations
applicable to the safety of gas transmission pipelines and gas
gathering pipelines. During that time, PHMSA proposed changes to
information collections that are no longer included in this final rule.
PHMSA determined it would be more effective to advance a rulemaking
that focuses on the mandates from the 2011 Pipeline Safety Act and
split out the other provisions contained in the NPRM into two other
separate rules. As such, PHMSA has removed all references to those
collections previously contained in the NPRM and will submit
information collection revision requests to OMB based on the
requirements solely contained within this final rule.
    PHMSA estimates that the proposals in this final rule will impact
the information collections described below. These information
collections are contained in the PSR, 49 CFR parts 190-199. 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. The information collection burden for the
following information collections are estimated to be revised as
follows:

    1. Title: Recordkeeping Requirements for Gas Pipeline Operators.
    OMB Control Number: 2137-0049.
    Current Expiration Date: 09/30/2021.
    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 at the Secretary's
request. Based on the proposed revisions in this rule, 25 new
recordkeeping requirements are being added to the pipeline safety
regulations for owners and operators of natural gas pipelines.
Therefore, PHMSA expects to add 24,609 responses and 3,740 hours to
this information collection because of the provisions in this final
rule.
    Affected Public: Natural Gas Pipeline Operators.
    Annual Reporting and Recordkeeping Burden:
    Total Annual Responses: 3,861,470.
    Total Annual Burden Hours: 1,674,810.
    Frequency of Collection: On occasion.

    2. Title: Notification Requirements for Gas Transmission Pipeline
Operators.
    OMB Control Number: New Collection. Will Request from OMB.
    Current Expiration Date: TBD.
    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. Based on the proposed
revisions in this rule, 10 new notification requirements are being
added to the pipeline safety regulations for owners and operators of
natural gas pipelines. Therefore, PHMSA expects to add 721 responses
and 1,070 hours because of the notification requirements in this final
rule.
    Affected Public: Gas Transmission operators.
    Annual Reporting and Recordkeeping Burden:
    Total Annual Responses: 721.
    Total Annual Burden Hours: 1,070.
    Frequency of Collection: On occasion.

    3. Title: Annual Reports for Gas Pipeline Operators.
    OMB Control Number: 2137-0522.
    Current Expiration Date: 8/31/2020.
    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 additional information including mileage
of pipe subject to the MAOP reconfirmation and MCA criteria. Based on
the proposed revisions, PHMSA estimates that the Annual Report will
take an additional 5 hours per report to complete to include the newly
required data, increasing the burden for each report to 47 burden hours
for an overall burden increase of 7,200 burden hours across all
operators.
    Affected Public: Natural Gas Pipeline Operators.
    Annual Reporting and Recordkeeping Burden:
    Total Annual Responses: 10,852.
    Total Annual Burden Hours: 83,151.
    Frequency of Collection: On occasion.

    4. Title: Incident for Natural Gas Pipeline Operators.
    OMB Control Number: 2137-0635.
    Current Expiration Date: 4/30/2022.
    Abstract: This information collection covers the collection of
incident report data from natural gas pipeline operators. PHMSA is
revising the Gas Transmission Incident Report to have operators
indicate whether incidents occur inside Moderate Consequence Areas.
PHMSA does not expect there to be an increase in burden for the
reporting of Gas Transmission incident data.
    Affected Public: Natural Gas Pipeline Operators.
    Annual Reporting and Recordkeeping Burden:
    Total Annual Responses: 301.
    Total Annual Burden Hours: 3,612.
    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>.

    Comments are invited on:
    (a) The need for the proposed collection of information for the
proper performance of the functions of the agency, including whether
the information will have practical utility;
    (b) The accuracy of the agency's estimate of the burden of the
revised collection of information, including the validity of the
methodology and assumptions used;
    (c) Ways to enhance the quality, utility, and clarity of the
information to be collected; and
    (d) Ways to minimize the burden of the collection of information on
those

who are to respond, including the use of appropriate automated,
electronic, mechanical, or other technological collection techniques.
    Those desiring to comment on these information collections should
send comments directly to the Office of Management and Budget, Office
of Information and Regulatory Affairs, Attn: Desk Officer for the
Department of Transportation, 725 17th Street NW, Washington, DC 20503.
Comments should be submitted on or prior to October 31, 2019. Comments
may also be sent via email to the Office of Management and Budget at
the following address<EMAIL_ADDRESS>OMB is required to
make a decision concerning the collection of information requirements
contained in this final rule between 30 and 60 days after publication
of this document in the Federal Register. Therefore, a comment to OMB
is best assured of having its full effect if received within 30 days of
publication.

F. Unfunded Mandates Reform Act of 1995

    An evaluation of Unfunded Mandates Reform Act (UMRA) considerations
is performed as part of the Final Regulatory Impact Assessment. 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, adjusted for inflation, in any one year and therefore
does not have implications under Section 202 of the UMRA of 1995. A
copy of the RIA is available for review in the docket.

G. National Environmental Policy Act

    PHMSA analyzed this final rule in accordance with the National
Environmental Policy Act (42 U.S.C. 4332) and determined this action
will not significantly affect the quality of the human environment. The
Environmental Assessment for this final rule is in the docket.

H. Executive Order 13132: Federalism

    PHMSA analyzed this final rule in accordance with Executive Order
13132 (``Federalism''). The final rule does not have a substantial
direct effect on the States, the relationship between the national
government and the States, or the distribution of power and
responsibilities among the various levels of government. This
rulemaking action does not impose substantial direct compliance costs
on State and local governments. The pipeline safety laws, specifically
49 U.S.C. 60104(c), prohibits State safety regulation of interstate
pipelines. Under the pipeline safety law, States have the ability to
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 PHMSA does not regulate. It is these statutory
provisions, not the rule, that govern preemption of State law.
Therefore, the consultation and funding requirements of Executive Order
13132 do not apply.

I. Executive Order 13211

    This final rule is not a ``significant energy action'' under
Executive Order 13211 (Actions Concerning Regulations That
Significantly Affect Energy Supply, Distribution, or Use). It is not
likely to have a significant adverse effect on supply, distribution, or
energy use. Further, the Office of Information and Regulatory Affairs
has not designated this final rule as a significant energy action.

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, published on April 11, 2000 (65 FR 19476), in the Federal
Register at: https://www.govinfo.gov/content/FR-2000-04-11/pdf/00-8505.pdf.

K. Regulation Identifier Number (RIN)

    A regulation identifier number (RIN) is assigned to each regulatory
action listed in the Unified Agenda of Federal Regulations. The
Regulatory Information Service Center publishes the Unified Agenda in
April and October of each year. The RIN number contained in the heading
of this document can be used to cross-reference this action with the
Unified Agenda.

List of Subjects

49 CFR Part 191

    MAOP exceedance, Pipeline reporting requirements.

49 CFR Part 192

    Incorporation by reference, Integrity assessments, Material
properties verification, MAOP reconfirmation, Pipeline safety,
Predicted failure pressure, Recordkeeping, Risk assessment, Safety
devices.

    In consideration of the foregoing, PHMSA is amending 49 CFR parts
191 and 192 as follows:

PART 191--TRANSPORTATION OF NATURAL AND OTHER GAS BY PIPELINE;
ANNUAL, INCIDENT, AND OTHER REPORTING

0
1. The authority citation for part 191 is revised to read as follows:

    Authority:  30 U.S.C. 185(w)(3), 49 U.S.C. 5121, 60101 et. seq.,
and 49 CFR 1.97.

0
2. In Sec.  191.23, paragraph (a)(6) is revised, paragraph (a)(10) is
added, and paragraph (b)(4) is revised to read as follows:

Sec.  191.23  Reporting safety-related conditions.

    (a) * * *
    (6) Any malfunction or operating error that causes the pressure--
plus the margin (build-up) allowed for operation of pressure limiting
or control devices--to exceed either the maximum allowable operating
pressure of a distribution or gathering line, the maximum well
allowable operating pressure of an underground natural gas storage
facility, or the maximum allowable working pressure of an LNG facility
that contains or processes gas or LNG.
* * * * *
    (10) For transmission pipelines only, each exceedance of the
maximum allowable operating pressure that exceeds the margin (build-up)
allowed for operation of pressure-limiting or control devices as
specified in the applicable requirements of Sec. Sec.  192.201,
192.620(e), and 192.739. The reporting requirement of this paragraph
(a)(10) is not applicable to gathering lines, distribution lines, LNG
facilities, or underground natural gas storage facilities (See
paragraph (a)(6) of this section).
    (b) * * *
    (4) Is corrected by repair or replacement in accordance with
applicable safety standards before the deadline for filing the safety-
related condition report. Notwithstanding this exception, a report must
be filed for:
    (i) Conditions under paragraph (a)(1) of this section, unless the
condition is localized corrosion pitting on an effectively coated and
cathodically protected pipeline; and
    (ii) Any condition under paragraph (a)(10) of this section.
* * * * *

0
3. Section 191.25 is revised to read as follows:

Sec.  191.25  Filing safety-related condition reports.

    (a) Each report of a safety-related condition under Sec.
191.23(a)(1) through (9) must be filed (received by the Associate
Administrator) in writing

within 5 working days (not including Saturday, Sunday, or Federal
holidays) after the day a representative of an operator first
determines that the condition exists, but not later than 10 working
days after the day a representative of an operator discovers the
condition. Separate conditions may be described in a single report if
they are closely related. Reporting methods and report requirements are
described in paragraph (c) of this section.
    (b) Each report of a maximum allowable operating pressure
exceedance meeting the requirements of criteria in Sec.  191.23(a)(10)
for a gas transmission pipeline must be filed (received by the
Associate Administrator) in writing within 5 calendar days of the
exceedance using the reporting methods and report requirements
described in paragraph (c) of this section.
    (c) Reports must be filed by email to
<EMAIL_ADDRESS>or by facsimile to<PHONE_NUMBER>.
For a report made pursuant to Sec.  191.23(a)(1) through (9), the
report must be headed ``Safety-Related Condition Report.'' For a report
made pursuant to Sec.  191.23(a)(10), the report must be headed
``Maximum Allowable Operating Pressure Exceedances.'' All reports must
provide the following information:
    (1) Name, principal address, and operator identification number
(OPID) of the operator.
    (2) Date of report.
    (3) Name, job title, and business telephone number of person
submitting the report.
    (4) Name, job title, and business telephone number of person who
determined that the condition exists.
    (5) Date condition was discovered and date condition was first
determined to exist.
    (6) Location of condition, with reference to the State (and town,
city, or county) or offshore site, and as appropriate, nearest street
address, offshore platform, survey station number, milepost, landmark,
or name of pipeline.
    (7) Description of the condition, including circumstances leading
to its discovery, any significant effects of the condition on safety,
and the name of the commodity transported or stored.
    (8) The corrective action taken (including reduction of pressure or
shutdown) before the report is submitted and the planned follow-up or
future corrective action, including the anticipated schedule for
starting and concluding such action.

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

0
4. The authority citation for part 192 is revised 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
5. In Sec.  192.3, the definitions for ``Engineering critical
assessment (ECA)'' and ``Moderate consequence area'' are added in
alphabetical order to read as follows:

Sec.  192.3  Definitions.

* * * * *
    Engineering critical assessment (ECA) means a documented analytical
procedure based on fracture mechanics principles, relevant material
properties (mechanical and fracture resistance properties), operating
history, operational environment, in-service degradation, possible
failure mechanisms, initial and final defect sizes, and usage of future
operating and maintenance procedures to determine the maximum tolerable
sizes for imperfections based upon the pipeline segment maximum
allowable operating pressure.
* * * * *
    Moderate consequence area means:
    (1) An onshore area that is within a potential impact circle, as
defined in Sec.  192.903, containing either:
    (i) Five or more buildings intended for human occupancy; or
    (ii) Any portion of the paved surface, including shoulders, of a
designated interstate, other freeway, or expressway, as well as any
other principal arterial roadway with 4 or more lanes, as defined in
the Federal Highway Administration's Highway Functional Classification
Concepts, Criteria and Procedures, Section 3.1 (see: https://www.fhwa.dot.gov/planning/processes/statewide/related/highway_functional_classifications/fcauab.pdf), and that does not meet
the definition of high consequence area, as defined in Sec.  192.903.
    (2) The length of the moderate consequence area extends axially
along the length of the pipeline from the outermost edge of the first
potential impact circle containing either 5 or more buildings intended
for human occupancy; or any portion of the paved surface, including
shoulders, of any designated interstate, freeway, or expressway, as
well as any other principal arterial roadway with 4 or more lanes, to
the outermost edge of the last contiguous potential impact circle that
contains either 5 or more buildings intended for human occupancy, or
any portion of the paved surface, including shoulders, of any
designated interstate, freeway, or expressway, as well as any other
principal arterial roadway with 4 or more lanes.
* * * * *

0
6. In Sec.  192.5, paragraph (d) is added to read as follows:

Sec.  192.5  Class locations.

* * * * *
    (d) An operator must have records that document the current class
location of each pipeline segment and that demonstrate how the operator
determined each current class location in accordance with this section.

0
7. Amend Sec.  192.7 as follows:
0
a. Revise paragraph (a)(1)(ii);
0
b. Add paragraph (b)(12);
0
c. Revise paragraphs (c)(2) and (4);
0
d. Re-designate paragraphs (d) through (j) as paragraphs (e) through
(k), respectively;
0
e. Add new paragraphs (d) and (h)(2); and
0
f. Revise newly redesignated paragraph (j)(1).
    The revisions and additions read as follows:

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

    (a) * * *
    (1) * * *
    (ii) The National Archives and Records Administration (NARA). For
information on the availability of this material at NARA, email
<EMAIL_ADDRESS>or go to www.archives.gov/federal-register/cfr/ibr-locations.html.
    (b) * * *
    (12) API STANDARD 1163, ``In-Line Inspection Systems
Qualification,'' Second edition, April 2013, Reaffirmed August 2018,
(API STD 1163), IBR approved for Sec.  192.493.
    (c) * * *
    (2) ASME/ANSI B16.5-2003, ``Pipe Flanges and Flanged Fittings,''
October 2004, (ASME/ANSI B16.5), IBR approved for Sec. Sec.
192.147(a), 192.279, and 192.607(f).
* * * * *
    (4) ASME/ANSI B31G-1991 (Reaffirmed 2004), ``Manual for Determining
the Remaining Strength of Corroded Pipelines,'' 2004, (ASME/ANSI B31G),
IBR approved for Sec. Sec.  192.485(c), 192.632(a), 192.712(b), and
192.933(a).
* * * * *
    (d) American Society for Nondestructive Testing (ASNT), P.O. Box
28518, 1711 Arlingate Lane, Columbus, OH 43228, phone:<PHONE_NUMBER>,
website: https://www.asnt.org/.

    (1) ANSI/ASNT ILI-PQ-2005(2010), ``In-line Inspection Personnel
Qualification and Certification,'' Reapproved October 11, 2010, (ANSI/
ASNT ILI-PQ), IBR approved for Sec.  192.493.
    (2) [Reserved]
* * * * *
    (h) * * *
    (2) NACE Standard Practice 0102-2010, ``In-Line Inspection of
Pipelines,'' Revised 2010-03-13, (NACE SP0102), IBR approved for
Sec. Sec.  192.150(a) and 192.493.
* * * * *
    (j) * * *
    (1) AGA, Pipeline Research Committee Project, PR-3-805, ``A
Modified Criterion for Evaluating the Remaining Strength of Corroded
Pipe,'' (December 22, 1989), (PRCI PR-3-805 (R-STRENG)), IBR approved
for Sec. Sec.  192.485(c); 192.632(a); 192.712(b); 192.933(a) and (d).
* * * * *

0
8. In Sec.  192.9, paragraphs (b), (c), and (d)(1), (2), and (6) are
revised to read as follows:

Sec.  192.9  What requirements apply to gathering lines?

* * * * *
    (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.  192.150, 192.285(e), 192.493,
192.506, 192.607, 192.619(e), 192.624, 192.710, 192.712, 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.
192.150, 192.285(e), 192.493, 192.506, 192.607, 192.619(e), 192.624,
192.710, 192.712, and in subpart O of this part. However, operators of
Type A regulated onshore gathering lines in a Class 2 location may
demonstrate compliance with subpart N 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 except the requirements in Sec. Sec.  192.67,
192.127, 192.205, 192.227(c), 192.285(e), and 192.506;
    (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.  192.493;
* * * * *
    (6) Establish the MAOP of the line under Sec.  192.619(a), (b), and
(c);
* * * * *

0
9. Section 192.18 is added to read as follows:

Sec.  192.18  How to notify PHMSA.

    (a) An operator must provide any notification required by this part
by--
    (1) Sending the notification by electronic mail to
<EMAIL_ADDRESS>or
    (2) Sending the notification by mail to ATTN: Information Resources
Manager, DOT/PHMSA/OPS, East Building, 2nd Floor, E22-321, 1200 New
Jersey Ave. SE, Washington, DC 20590.
    (b) An operator must also notify the appropriate State or local
pipeline safety authority when an applicable pipeline segment is
located in a State where OPS has an interstate agent agreement, or an
intrastate applicable pipeline segment is regulated by that State.
    (c) Unless otherwise specified, if the notification is made
pursuant to Sec.  192.506(b), Sec.  192.607(e)(4), Sec.  192.607(e)(5),
Sec.  192.624(c)(2)(iii), Sec.  192.624(c)(6), Sec.  192.632(b)(3),
Sec.  192.710(c)(7), Sec.  192.712(d)(3)(iv), Sec.
192.712(e)(2)(i)(E), Sec.  192.921(a)(7), or Sec.  192.937(c)(7) to use
a different integrity assessment method, analytical method, sampling
approach, or technique (i.e., ``other technology'') that differs from
that prescribed in those sections, the operator must notify PHMSA at
least 90 days in advance of using the other technology. An operator may
proceed to use the other technology 91 days after submittal of the
notification unless it receives a letter from the Associate
Administrator for Pipeline Safety informing the operator that PHMSA
objects to the proposed use of other technology or that PHMSA requires
additional time to conduct its review.

Sec.  192.67  [Redesignated as Sec.  192.69]

0
10. Redesignate Sec.  192.67 as Sec.  192.69.
0
11. Section 192.67 is added to read as follows:

Sec.  192.67  Records: Material properties.

    (a) For steel transmission pipelines installed after [July 1, 2020,
an operator must collect or make, and retain for the life of the
pipeline, records that document the physical characteristics of the
pipeline, including diameter, yield strength, ultimate tensile
strength, wall thickness, seam type, and chemical composition of
materials for pipe in accordance with Sec. Sec.  192.53 and 192.55.
Records must include tests, inspections, and attributes required by the
manufacturing specifications applicable at the time the pipe was
manufactured or installed.
    (b) For steel transmission pipelines installed on or before July 1,
2020], if operators have records that document tests, inspections, and
attributes required by the manufacturing specifications applicable at
the time the pipe was manufactured or installed, including diameter,
yield strength, ultimate tensile strength, wall thickness, seam type,
and chemical composition in accordance with Sec. Sec.  192.53 and
192.55, operators must retain such records for the life of the
pipeline.
    (c) For steel transmission pipeline segments installed on or before
July 1, 2020], if an operator does not have records necessary to
establish the MAOP of a pipeline segment, the operator may be subject
to the requirements of Sec.  192.624 according to the terms of that
section.

0
12. Section 192.127 is added to read as follows:

Sec.  192.127  Records: Pipe design.

    (a) For steel transmission pipelines installed after July 1, 2020],
an operator must collect or make, and retain for the life of the
pipeline, records documenting that the pipe is designed to withstand
anticipated external pressures and loads in accordance with Sec.
192.103 and documenting that the determination of design pressure for
the pipe is made in accordance with Sec.  192.105.
    (b) For steel transmission pipelines installed on or before July 1,
2020, if operators have records documenting pipe design and the
determination of design pressure in accordance with Sec. Sec.  192.103
and 192.105, operators must retain such records for the life of the
pipeline.
    (c) For steel transmission pipeline segments installed on or before
July 1, 2020, if an operator does not have records necessary to
establish the MAOP of a pipeline segment, the operator may be subject
to the requirements of Sec.  192.624 according to the terms of that
section.

0
13. In Sec.  192.150, paragraph (a) is revised to read as follows:

Sec.  192.150  Passage of internal inspection devices.

    (a) Except as provided in paragraphs (b) and (c) of this section,
each new transmission line and each replacement of line pipe, valve,
fitting, or other line component in a transmission line, must

be designed and constructed to accommodate the passage of instrumented
internal inspection devices in accordance with NACE SP0102, section 7
(incorporated by reference, see Sec.  192.7).
* * * * *

0
14. Section 192.205 is added to read as follows:

Sec.  192.205  Records: Pipeline components.

    (a) For steel transmission pipelines installed after July 1, 2020,
an operator must collect or make, and retain for the life of the
pipeline, records documenting the manufacturing standard and pressure
rating to which each valve was manufactured and tested in accordance
with this subpart. Flanges, fittings, branch connections, extruded
outlets, anchor forgings, and other components with material yield
strength grades of 42,000 psi (X42) or greater and with nominal
diameters of greater than 2 inches must have records documenting the
manufacturing specification in effect at the time of manufacture,
including yield strength, ultimate tensile strength, and chemical
composition of materials.
    (b) For steel transmission pipelines installed on or before July 1,
2020, if operators have records documenting the manufacturing standard
and pressure rating for valves, flanges, fittings, branch connections,
extruded outlets, anchor forgings, and other components with material
yield strength grades of 42,000 psi (X42) or greater and with nominal
diameters of greater than 2 inches, operators must retain such records
for the life of the pipeline.
    (c) For steel transmission pipeline segments installed on or before
July 1, 2020, if an operator does not have records necessary to
establish the MAOP of a pipeline segment, the operator may be subject
to the requirements of Sec.  192.624 according to the terms of that
section.

0
15. In Sec.  192.227, paragraph (c) is added to read as follows:

Sec.  192.227  Qualification of welders.

* * * * *
    (c) For steel transmission pipe installed after July 1, 2021,
records demonstrating each individual welder qualification at the time
of construction in accordance with this section must be retained for a
minimum of 5 years following construction.

0
16. In Sec.  192.285, paragraph (e) is added to read as follows:

Sec.  192.285  Plastic pipe: Qualifying persons to make joints.

* * * * *
    (e) For transmission pipe installed after July 1, 2021, records
demonstrating each person's plastic pipe joining qualifications at the
time of construction in accordance with this section must be retained
for a minimum of 5 years following construction.

0
17. Section 192.493 is added to read as follows:

Sec.  192.493   In-line inspection of pipelines.

    When conducting in-line inspections of pipelines required by this
part, an operator must comply with API STD 1163, ANSI/ASNT ILI-PQ, and
NACE SP0102, (incorporated by reference, see Sec.  192.7). Assessments
may be conducted using tethered or remotely controlled tools, not
explicitly discussed in NACE SP0102, provided they comply with those
sections of NACE SP0102 that are applicable.

0
18. Section 192.506 is added to read as follows:

Sec.  192.506  Transmission lines: Spike hydrostatic pressure test.

    (a) Spike test requirements. Whenever a segment of steel
transmission pipeline that is operated at a hoop stress level of 30
percent or more of SMYS is spike tested under this part, the spike
hydrostatic pressure test must be conducted in accordance with this
section.
    (1) The test must use water as the test medium.
    (2) The baseline test pressure must be as specified in the
applicable paragraphs of Sec.  192.619(a)(2) or Sec.  192.620(a)(2),
whichever applies.
    (3) The test must be conducted by maintaining a pressure at or
above the baseline test pressure for at least 8 hours as specified in
Sec.  192.505.
    (4) After the test pressure stabilizes at the baseline pressure and
within the first 2 hours of the 8-hour test interval, the hydrostatic
pressure must be raised (spiked) to a minimum of the lesser of 1.5
times MAOP or 100% SMYS. This spike hydrostatic pressure test must be
held for at least 15 minutes after the spike test pressure stabilizes.
    (b) Other technology or other technical evaluation process.
Operators may use other technology or another process supported by a
documented engineering analysis for establishing a spike hydrostatic
pressure test or equivalent. Operators must notify PHMSA 90 days in
advance of the assessment or reassessment requirements of this
subchapter. The notification must be made in accordance with Sec.
192.18 and must include the following information:
    (1) Descriptions of the technology or technologies to be used for
all tests, examinations, and assessments;
    (2) Procedures and processes to conduct tests, examinations,
assessments, perform evaluations, analyze defects, and remediate
defects discovered;
    (3) Data requirements, including original design, maintenance and
operating history, anomaly or flaw characterization;
    (4) Assessment techniques and acceptance criteria;
    (5) Remediation methods for assessment findings;
    (6) Spike hydrostatic pressure test monitoring and acceptance
procedures, if used;
    (7) Procedures for remaining crack growth analysis and pipeline
segment life analysis for the time interval for additional assessments,
as required; and
    (8) Evidence of a review of all procedures and assessments by a
qualified technical subject matter expert.

0
19. In Sec.  192.517, paragraph (a) introductory text is revised to
read as follows:

Sec.  192.517   Records: Tests.

    (a) An operator must make, and retain for the useful life of the
pipeline, a record of each test performed under Sec. Sec.  192.505,
192.506, and 192.507. The record must contain at least the following
information:
* * * * *

0
20. Section 192.607 is added to read as follows:

Sec.  192.607  Verification of Pipeline Material Properties and
Attributes: Onshore steel transmission pipelines.

    (a) Applicability. Wherever required by this part, operators of
onshore steel transmission pipelines must document and verify material
properties and attributes in accordance with this section.
    (b) Documentation of material properties and attributes. Records
established under this section documenting physical pipeline
characteristics and attributes, including diameter, wall thickness,
seam type, and grade (e.g., yield strength, ultimate tensile strength,
or pressure rating for valves and flanges, etc.), must be maintained
for the life of the pipeline and be traceable, verifiable, and
complete. Charpy v-notch toughness values established under this
section needed to meet the requirements of the ECA method at Sec.
192.624(c)(3) or the fracture mechanics requirements at Sec.  192.712
must be maintained for the life of the pipeline.

    (c) Verification of material properties and attributes. If an
operator does not have traceable, verifiable, and complete records
required by paragraph (b) of this section, the operator must develop
and implement procedures for conducting nondestructive or destructive
tests, examinations, and assessments in order to verify the material
properties of aboveground line pipe and components, and of buried line
pipe and components when excavations occur at the following
opportunities: Anomaly direct examinations, in situ evaluations,
repairs, remediations, maintenance, and excavations that are associated
with replacements or relocations of pipeline segments that are removed
from service. The procedures must also provide for the following:
    (1) For nondestructive tests, at each test location, material
properties for minimum yield strength and ultimate tensile strength
must be determined at a minimum of 5 places in at least 2
circumferential quadrants of the pipe for a minimum total of 10 test
readings at each pipe cylinder location.
    (2) For destructive tests, at each test location, a set of material
properties tests for minimum yield strength and ultimate tensile
strength must be conducted on each test pipe cylinder removed from each
location, in accordance with API Specification 5L.
    (3) Tests, examinations, and assessments must be appropriate for
verifying the necessary material properties and attributes.
    (4) If toughness properties are not documented, the procedures must
include accepted industry methods for verifying pipe material
toughness.
    (5) Verification of material properties and attributes for non-line
pipe components must comply with paragraph (f) of this section.
    (d) Special requirements for nondestructive Methods. Procedures
developed in accordance with paragraph (c) of this section for
verification of material properties and attributes using nondestructive
methods must:
    (1) Use methods, tools, procedures, and techniques that have been
validated by a subject matter expert based on comparison with
destructive test results on material of comparable grade and vintage;
    (2) Conservatively account for measurement inaccuracy and
uncertainty using reliable engineering tests and analyses; and
    (3) Use test equipment that has been properly calibrated for
comparable test materials prior to usage.
    (e) Sampling multiple segments of pipe. To verify material
properties and attributes for a population of multiple, comparable
segments of pipe without traceable, verifiable, and complete records,
an operator may use a sampling program in accordance with the following
requirements:
    (1) The operator must define separate populations of similar
segments of pipe for each combination of the following material
properties and attributes: Nominal wall thicknesses, grade,
manufacturing process, pipe manufacturing dates, and construction
dates. If the dates between the manufacture or construction of the
pipeline segments exceeds 2 years, those segments cannot be considered
as the same vintage for the purpose of defining a population under this
section. The total population mileage is the cumulative mileage of
pipeline segments in the population. The pipeline segments need not be
continuous.
    (2) For each population defined according to paragraph (e)(1) of
this section, the operator must determine material properties at all
excavations that expose the pipe associated with anomaly direct
examinations, in situ evaluations, repairs, remediations, or
maintenance, except for pipeline segments exposed during excavation
activities pursuant to Sec.  192.614, until completion of the lesser of
the following:
    (i) One excavation per mile rounded up to the nearest whole number;
or
    (ii) 150 excavations if the population is more than 150 miles.
    (3) Prior tests conducted for a single excavation according to the
requirements of paragraph (c) of this section may be counted as one
sample under the sampling requirements of this paragraph (e).
    (4) If the test results identify line pipe with properties that are
not consistent with available information or existing expectations or
assumed properties used for operations and maintenance in the past, the
operator must establish an expanded sampling program. The expanded
sampling program must use valid statistical bases designed to achieve
at least a 95% confidence level that material properties used in the
operation and maintenance of the pipeline are valid. The approach must
address how the sampling plan will be expanded to address findings that
reveal material properties that are not consistent with all available
information or existing expectations or assumed material properties
used for pipeline operations and maintenance in the past. Operators
must notify PHMSA in advance of using an expanded sampling approach in
accordance with Sec.  192.18.
    (5) An operator may use an alternative statistical sampling
approach that differs from the requirements specified in paragraph
(e)(2) of this section. The alternative sampling program must use valid
statistical bases designed to achieve at least a 95% confidence level
that material properties used in the operation and maintenance of the
pipeline are valid. The approach must address how the sampling plan
will be expanded to address findings that reveal material properties
that are not consistent with all available information or existing
expectations or assumed material properties used for pipeline
operations and maintenance in the past. Operators must notify PHMSA in
advance of using an alternative sampling approach in accordance with
Sec.  192.18.
    (f) Components. For mainline pipeline components other than line
pipe, an operator must develop and implement procedures in accordance
with paragraph (c) of this section for establishing and documenting the
ANSI rating or pressure rating (in accordance with ASME/ANSI B16.5
(incorporated by reference, see Sec.  192.7)),
    (1) Operators are not required to test for the chemical and
mechanical properties of components in compressor stations, meter
stations, regulator stations, separators, river crossing headers,
mainline valve assemblies, valve operator piping, or cross-connections
with isolation valves from the mainline pipeline.
    (2) Verification of material properties is required for non-line
pipe components, including valves, flanges, fittings, fabricated
assemblies, and other pressure retaining components and appurtenances
that are:
    (i) Larger than 2 inches in nominal outside diameter,
    (ii) Material grades of 42,000 psi (Grade X-42) or greater, or
    (iii) Appurtenances of any size that are directly installed on the
pipeline and cannot be isolated from mainline pipeline pressures.
    (3) Procedures for establishing material properties of non-line
pipe components must be based on the documented manufacturing
specification for the components. If specifications are not known,
usage of manufacturer's stamped, marked, or tagged material pressure
ratings and material type may be used to establish pressure rating.
Operators must document the method used to determine the pressure
rating and the findings of that determination.
    (g) Uprating. The material properties determined from the
destructive or nondestructive tests required by this

section cannot be used to raise the grade or specification of the
material, unless the original grade or specification is unknown and
MAOP is based on an assumed yield strength of 24,000 psi in accordance
with Sec.  192.107(b)(2).

0
21. In Sec.  192.619, the introductory text of paragraphs (a)
introductory text and (a)(2) and (4) are revised and paragraphs (e) and
(f) are added to read as follows:

Sec.  192.619   Maximum allowable operating pressure: Steel or plastic
pipelines.

    (a) No person may operate a segment of steel or plastic pipeline at
a pressure that exceeds a maximum allowable operating pressure (MAOP)
determined under paragraph (c), (d), or (e) of this section, or the
lowest of the following:
* * * * *
    (2) The pressure obtained by dividing the pressure to which the
pipeline segment was tested after construction as follows:
    (i) For plastic pipe in all locations, the test pressure is divided
by a factor of 1.5.
    (ii) For steel pipe operated at 100 psi (689 kPa) gage or more, the
test pressure is divided by a factor determined in accordance with the
Table 1 to paragraph (a)(2)(ii):

                                         Table 1 to Paragraph (a)(2)(ii)
----------------------------------------------------------------------------------------------------------------
                                                                          Factors,\1\ segment--
                                                        --------------------------------------------------------
                                       Installed before   Installed after
           Class location              (Nov. 12, 1970)    (Nov. 11, 1970)    Installed on or    Converted under
                                                          and before July     after July 1,      Sec.   192.14
                                                              1, 2020              2020
----------------------------------------------------------------------------------------------------------------
1...................................                1.1                1.1               1.25               1.25
2...................................               1.25               1.25               1.25               1.25
3...................................                1.4                1.5                1.5                1.5
4...................................                1.4                1.5                1.5                1.5
----------------------------------------------------------------------------------------------------------------
\1\ For offshore pipeline segments installed, uprated or converted after July 31, 1977, that are not located on
  an offshore platform, the factor is 1.25. For pipeline segments installed, uprated or converted after July 31,
  1977, that are located on an offshore platform or on a platform in inland navigable waters, including a pipe
  riser, the factor is 1.5.

* * * * *
    (4) The pressure determined by the operator to be the maximum safe
pressure after considering and accounting for records of material
properties, including material properties verified in accordance with
Sec.  192.607, if applicable, and the history of the pipeline segment,
including known corrosion and actual operating pressure.
* * * * *
    (e) Notwithstanding the requirements in paragraphs (a) through (d)
of this section, operators of onshore steel transmission pipelines that
meet the criteria specified in Sec.  192.624(a) must establish and
document the maximum allowable operating pressure in accordance with
Sec.  192.624.
    (f) Operators of onshore steel transmission pipelines must make and
retain records necessary to establish and document the MAOP of each
pipeline segment in accordance with paragraphs (a) through (e) of this
section as follows:
    (1) Operators of pipelines in operation as of [July 1, 2020 must
retain any existing records establishing MAOP for the life of the
pipeline;
    (2) Operators of pipelines in operation as of July 1, 2020 that do
not have records establishing MAOP and are required to reconfirm MAOP
in accordance with Sec.  192.624, must retain the records reconfirming
MAOP for the life of the pipeline; and
    (3) Operators of pipelines placed in operation after July 1, 2020
must make and retain records establishing MAOP for the life of the
pipeline.

0
22. Section 192.624 is added to read as follows:

Sec.  192.624  Maximum allowable operating pressure reconfirmation:
Onshore steel transmission pipelines.

    (a) Applicability. Operators of onshore steel transmission pipeline
segments must reconfirm the maximum allowable operating pressure (MAOP)
of all pipeline segments in accordance with the requirements of this
section if either of the following conditions are met:
    (1) Records necessary to establish the MAOP in accordance with
Sec.  192.619(a), including records required by Sec.  192.517(a), are
not traceable, verifiable, and complete and the pipeline is located in
one of the following locations:
    (i) A high consequence area as defined in Sec.  192.903; or
    (ii) A Class 3 or Class 4 location.
    (2) The pipeline segment's MAOP was established in accordance with
Sec.  192.619(c), the pipeline segment's MAOP is greater than or equal
to 30 percent of the specified minimum yield strength, and the pipeline
segment is located in one of the following areas:
    (i) A high consequence area as defined in Sec.  192.903;
    (ii) A Class 3 or Class 4 location; or
    (iii) A moderate consequence area as defined in Sec.  192.3, if the
pipeline segment can accommodate inspection by means of instrumented
inline inspection tools.
    (b) Procedures and completion dates. Operators of a pipeline
subject to this section must develop and document procedures for
completing all actions required by this section by July 1, 2021. These
procedures must include a process for reconfirming MAOP for any
pipelines that meet a condition of Sec.  192.624(a), and for performing
a spike test or material verification in accordance with Sec. Sec.
192.506 and 192.607, if applicable. All actions required by this
section must be completed according to the following schedule:
    (1) Operators must complete all actions required by this section on
at least 50% of the pipeline mileage by July 3, 2028.
    (2) Operators must complete all actions required by this section on
100% of the pipeline mileage by July 2, 2035 or as soon as practicable,
but not to exceed 4 years after the pipeline segment first meets a
condition of Sec.  192.624(a) (e.g., due to a location becoming a high
consequence area), whichever is later.
    (3) If operational and environmental constraints limit an operator
from meeting the deadlines in Sec.  192.624, the operator may petition
for an extension of the completion deadlines by up to 1 year, upon
submittal of a notification in accordance with Sec.  192.18. The
notification must include an up-to-date plan for completing all actions
in accordance with this section, the reason for the requested
extension, current status, proposed completion date, outstanding
remediation activities, and

any needed temporary measures needed to mitigate the impact on safety.
    (c) Maximum allowable operating pressure determination. Operators
of a pipeline segment meeting a condition in paragraph (a) of this