Tensile testing is a measure of a material's resistance to pulling
forces. The revisions to Sec.  192.283(a)(3) made in the Plastic Pipe
Rule inadvertently removed the word ``tensile,'' though tensile
strength was still alluded to implicitly because elongation is a
measure of tensile strength. Reinserting the word tensile clarifies
this relationship.
Dates
    In Sec.  192.121(c)(2) and (e), PHMSA proposed to clarify that PE
pipe and PA-12 pipe respectively produced on or after January 22, 2019
may use a DF of 0.40 rather than 0.32, subject to applicable
restrictions in those paragraphs.
Corrections to 192.7
    PHMSA proposed editorial amendments to Sec.  192.7(a) to meet
incorporation by reference requirements of the Office of the Federal
Register and a revision to update the address for API.
2. Summary of Public Comments
ASTM D2513 and PE Pipe Diameter
    Several commenters provided their support, with no additional
comments, for the proposed amendments in the NPRM.
    AIPRO submitted comments supporting the incorporation by reference
of the 2018a edition of ASTM D2513 and conforming revisions to Sec.
192.121. Similarly, PPI stated their support to increase the allowable
dimensions for PE pipe using a 0.40 design factor up through 24 inches
along with the corresponding minimum wall thicknesses in Table 1 to
paragraph Sec.  192.121(c)(2)(iv). PPI stated that the revisions are
consistent with dimensions provided in ASTM D2513-18a and enables the
increased use of larger diameter PE in gas distribution, transmission,
and gathering systems.
    PPI provided suggested regulatory text revisions for Sec.
192.121(a) to permit an operator to allow an operator to operate a
plastic pipe at a temperature up to 180 [deg]F, provided that the
hydrostatic design basis (HDB) is established at that temperature. PPI
noted that a survey of AGA members indicated that local distribution
companies desire to use plastic pipe at higher operating temperatures
providing them with more application options, and that use of these
higher performance plastic materials results in increased long-term
performance of the piping system and a safer gas system.
    GPA Midstream supported incorporating by reference updated editions
of standards and believes that the latest editions should be adopted
wherever possible. GPA Midstream stated that relying on obsolete or
outdated editions of IBR standards creates unnecessary compliance
burdens, discourages innovation, and adversely affects the standards
development process. GPA Midstream noted that a significant number of
the IBR standards have undergone multiple revisions without being
updated to a newer or more recent edition. GPA Midstream requested that
PHMSA place a renewed emphasis on the timeliness of the incorporation
by reference process, particularly in cases where a prior edition of a
standard is already incorporated by reference. In such cases, PHMSA
should commit to adopting the latest edition of the standard or
providing an explanation for not doing so within 1 year of publication.
ASTM F2620 and Joining Requirements
    AGA et al. supported the changes proposed to Sec. Sec.  192.281 and
192.285. They commented that the proposed revisions in the NPRM aligned
with AGA's petition for reconsideration of the Plastic Pipe Rule, and
allow operators to use alternate procedures to join PE which are
equivalent or more stringent than the heat fusion procedure detailed in
the 2012 edition of ASTM F2620.
    PPI supported PHMSA's proposed revision to Sec. Sec.  192.281(c)
and 192.285 providing for alternative written heat fusion procedures
that provide an equivalent or superior level of safety.

PPI also suggested incorporating PPI-TR-33, ``Generic Butt Fusion
Joining Procedure for Field Joining Polyethylene Pipe'' and TR-41,
``Generic Saddle Fusion Joining Procedure for Polyethylene Gas Piping''
into Sec.  192.281(c) in addition to ASTM F2620. PPI explained that
these additions would help clarify the language and account for proven
procedures that have been successfully used in industry for many years.
A2LA suggested that PHMSA also incorporate by reference ISO/IEC 17025,
``General Requirements for the Competence of Testing and Calibration
Laboratories'' and require alternative written procedures be validated
by laboratories certified in accordance with that document. A2LA
commented that ISO/IEC 17025 recommends that a testing laboratory uses
consensus methods and has procedures for the selection of methods, and
verify that a testing laboratory can properly perform methods by
ensuring that it can achieve the required performance and maintain
records of the verification. Regarding PHMSA expecting operators to
document the differences from ASTM F2620 and demonstrate how the
alternate procedures provide an equivalent or superior level of safety,
A2LA recommended that the organizations conducting the inspections and
testing be accredited, in accordance with the relevant ISO/IEC
standards include requirements for impartiality.
    Southwest Gas Corporation (Southwest) raised concerns with the
addition of the language ``or superior'' in the proposed language of
both Sec. Sec.  192.281 and 192.285. Southwest believes that this
language ``or superior'' implies an increased performance standard not
defined in either ASTM F2620 or part 192. Southwest requested that
PHMSA consider removing the language ``or superior'' from the proposed
revisions to both Sec.  192.281(c) and Sec.  192.285(b)(2)(i) and
provided its preferred regulatory text.
1-Inch CTS Pipe
    The Associations and NAPSR commented that operators commonly use 1-
inch CTS pipe with a wall thickness of 0.099 inches, rather than 0.101
inches in the proposed rule. Both wall thickness specifications are
listed as options in Table 3 of ASTM D2513. NAPSR requested
clarification of whether operators are required to use a design factor
of 0.32 for PE pipe with a minimum wall thickness of 0.099-inch, and if
thicker pipe is required to use a 0.40 design factor. The Associations
raised concerns about the impact to operators and manufacturers who
have an inventory of 0.099-inch wall thickness PE pipe and suggested
that PHMSA correct the proposed amendments to the minimum wall
thickness table at Sec.  192.121(c)(2)(iv) to reference 0.099-inch
thick, 1-inch CTS pipe that is commonly in use.
Qualifying Joining Procedures
    PPI supported correcting Sec.  192.283(a)(3), and allowing visual
inspection in accordance with established written procedures in Sec.
192.285(b)(2)(i).
GPAC Recommendation
    The GPAC voted unanimously in favor of PHMSA's proposed amendment
with respect to plastic pipe requirements, provided PHMSA correct the
minimum wall thickness tables to specify a 0.099-inch wall thickness
for 1-inch CTS plastic pipe as recommended in the written comments from
the Associations and NAPSR.
3. PHMSA Response
    Based on the comments, the final rule adopts the plastic pipe
amendments as proposed except for a change to the minimum wall
thickness required to use plastic pipe with a size of 1-inch CTS with a
design factor of 0.40 rather than 0.32. The final rule incorporates the
0.099-inch minimum wall thickness for 1-inch CTS plastic pipe.
    PHMSA expects that the incorporation of updated industry standards
pertaining to plastic pipe design will not adversely affect safety. The
updated standards incorporated by reference in this final rule reflect
the benefit of testing, lessons learned, and operational best practices
from the increasingly widespread use of plastic pipe in gas
transmission, distribution and gathering applications. Significantly,
those updated industry standards reflect a greater comfort within
industry regarding the safety of the use in those applications of
larger-diameter plastic piping when subject to rigorous design
standards. Based on its review of those standards and the
administrative record in this rulemaking, PHMSA is similarly satisfied
that their incorporation within the PSR will not have a detrimental
impact on safety. PHMSA has provided a discussion of the changes in the
updated editions of ASTM D2513 and ASTM F2620 in the summary of the
proposed changes in section III.G.1 above.
ASTM D2513 and PE Pipe Diameter
    The final rule incorporates by reference the 2018a edition of ASTM
D2513 and allows the use of a 0.40 design factor for PE pipe produced
on or after the effective date of the rule with a maximum diameter of
24 inches as proposed in the NPRM. PHMSA proposed no changes to the
design pressure formula for PE pipe at Sec.  192.121(c)(2), and
therefore declines to adopt the design factor change for PE piping
suggested by PPI without the benefit of further technical evaluation
and public comment. Similarly, PHMSA may consider allowing an operator
to more directly establish a HDB rating at 180 [deg]F within the design
pressure formula at Sec.  192.121(a) in a future rulemaking after
further review of the safety effects of such a change. PHMSA notes that
Sec.  192.121(a) allows an operator to interpolate the design pressure
down from 180 [deg]F, meaning they could use a pipe with an HDB rating
at 180 [deg]F but have to use a formula to determine the design
pressure at a lower temperature listed in Sec.  192.121(a). PHMSA
cautions users that not all PE compounds are rated at 180 [deg]F.
    Regarding the GPA Midstream comment concerning other documents that
are currently incorporated into part 192, PHMSA periodically issues
rules updating the standards that are incorporated by reference,
provided the 2018 edition of ASTM D2513 has been evaluated and its
incorporation determined consistent with PHMSA's safety mission. More
recent versions of this and other standards incorporated by reference,
including those related to plastic pipe and components, that were not
included in the NPRM may be considered for updates in other rulemaking
proceedings.
ASTM F2620 and Joining Requirements
    The final rule also adopts the clarifications to joining
requirements as proposed with minor editorial revisions. PHMSA did not
propose in the NPRM to incorporate by reference PPI TR-33, PPI TR-41,
or ISO/IEC 17025, and therefore declines to incorporate them by
reference without the benefit of additional public comment and
technical evaluation. However, PHMSA understands that many of the
procedures in TR-33 and TR-41 are similar or identical to the
procedures specified in the 2019 edition of ASTM F2620. There are,
however, still some differences such as heating temperatures. If an
operator can demonstrate that their alternative procedure based on
those documents provides an equivalent or superior level of safety
compared with ASTM F2620, it would be acceptable under the amendments
adopted in this final rule.

    PHMSA disagrees with comments that including the phrase ``or
superior'' imposes new requirements or adds uncertainty to the changes
in Sec. Sec.  192.281 and 192.285. An operator need only demonstrate
that their alternative procedure provides an equivalent level of
safety; the addition of the term ``or superior'' exists to ensure that
a procedure with requirements that may be more conservative than ASTM
F2620 is also acceptable. PHMSA has revised the regulatory language at
Sec.  192.281 proposed in the NPRM to clarify that the operator need
only demonstrate that the alternative procedure provides an equivalent
or superior level of safety rather than demonstrate the alternative
procedure is itself superior.
1-Inch CTS Pipe
    PHMSA agrees with commenters that 0.099 is an acceptable minimum
wall thickness specification. While 0.101 inches more closely
corresponds to SDR 11, both 0.099-inch and 0.101-inch wall thickness
for 1-inch CTS pipe are technically SDR 11 specifications. In addition,
the two specifications are within allowable tolerances of each other in
the ASTM codes. Therefore, PHMSA does not have a safety concern with
using a 0.40 design factor with 0.099-inch wall thickness for 1-inch
CTS plastic pipe and recognizes that it is in common use.

H. Test Requirements for Pressure Vessels (Section 192.153)

1. PHMSA's Proposal
    Section 192.153 defines design requirements for prefabricated units
and pressure vessels (hereafter referred to as pressure vessels)
fabricated by welding. In particular, Sec.  192.153(a) requires that
operators establish the design pressure of components fabricated by
welding whose strength cannot be determined to establish the design
pressure of those components in accordance with section VIII, division
1 of the 2007 edition of the American Society of Mechanical Engineers
(ASME) Boiler and Pressure Vessel Code (BPVC) which is incorporated by
reference in Sec.  192.7.\52\ Section 192.153(b) requires operators to
design, construct, and test prefabricated units that use plate and
longitudinal seams in accordance with either ASME BPVC section I,
section VIII, division 1, or section VIII, division 2. In addition,
Sec.  192.505(b) requires operators to pressure test compressor
station, regulator station, and measuring stations to Class 3 location
test requirements; for pipelines installed after November 11, 1970,
this represents a required test factor of at least 1.5 times the
maximum allowable operating pressure (MAOP).\53\
---------------------------------------------------------------------------

    \52\ ASME Boiler & Pressure Vessel Code, 2007 edition (July 1,
2007).
    \53\ Section 192.619(a)(2) requires a test pressure of at least
1.5 times the MAOP in a Class 3 or Class 4 location for pipelines
installed after November 11, 1970.
---------------------------------------------------------------------------

    On March 11, 2015, PHMSA published a final rule titled, ``Pipeline
Safety: Miscellaneous Changes to Pipeline Safety Regulations.'' \54\
The final rule created a new Sec.  192.153(e), which clarified that
pressure vessels subject to Sec.  192.505(b) must be pressure tested to
at least 1.5 times the MAOP of the pipeline. INGAA subsequently
submitted a petition for reconsideration of the Miscellaneous Rule
concerning the revision to Sec.  192.153.\55\ The petitioner argued
that PHMSA lacked technical justification for a 1.5 times MAOP test
factor versus the 1.3 times the Maximum Allowable Working Pressure
(MAWP) \56\ test factor permitted in the ASME BPVC since the 2001
edition and all subsequent editions of the standard. PHMSA had
incorporated by reference the 2001 edition of the ASME BPVC into part
192 effective July 14, 2004, and the divergence between the required
test factor in Sec.  192.505(b) and section VIII, division 1 of ASME
BPVC persisted until the Miscellaneous Rule became effective in
2015.\57\
---------------------------------------------------------------------------

    \54\ 80 FR 12762 (Miscellaneous Rule).
    \55\ Docket No. PHMSA-2018-0046-0055.
    \56\ MAWP is the design pressure in the ASME BPVC. The test
factors in the ASME BPVC refer to the MAWP and are used to
substantiate the design pressure of the vessel. Because the design
pressure of a pressure vessel (the MAWP) must be equal to or greater
than the MAOP of the pipeline, the PSR uses the more demanding MAOP
metric.
    \57\ PHMSA, ``Pipeline Safety: Periodic Updates to Pipeline
Safety Regulations,'' 80 FR 12762 (June 14, 2004).
---------------------------------------------------------------------------

    PHMSA, meanwhile, had commissioned a report by the Oak Ridge
National Laboratory (ORNL) on the safety equivalence between the 1992
edition and the 2015 edition of the ASME BPVC. PHMSA understands that
most pressure vessels in pipeline service are designed to ASME section
VIII, division 1. For hydrostatic pressure tests, the 1992 edition of
section VIII division 1 of the ASME BPVC provides for a hydrostatic
pressure test factor of 1.5 times MAWP, while the 2001 and all
subsequent editions provide for a hydrostatic pressure test factor of
1.3 times MAWP. The ORNL report found that these different editions of
ASME BPVC section VIII, division 1 maintain safety through the design
and fabrication of pressure vessels and hydrostatic pressure test,
notwithstanding the difference in their hydrostatic pressure test
factors of 1.3 and 1.5. A copy of this report is available in the
docket.
    In the NPRM, PHMSA proposed to revise the test requirements for the
pressure vessels described in Sec.  192.153. First, PHMSA proposed to
revise Sec.  192.153(e) to require a pressure test factor of at least
1.3 times the MAOP for all pressure vessels installed since July 14,
2004, provided the component has been tested in accordance with the
ASME BPVC, as required by existing Sec.  192.153(b). Consistent with
this change and the requirements in the ASME BPVC, PHMSA also proposed
to exempt vessels installed after July 14, 2004 from the strength
testing requirement at Sec. Sec.  192.505(b) and 192.619(a)(2), which
require a test factor of 1.5 times the MAOP. The test requirements for
any pressure vessel with an MAOP established under the alternative MAOP
requirements at Sec.  192.620 would remain unchanged.
    Second, PHMSA proposed a new Sec.  192.153(e)(2) that would exempt
pressure vessels installed after July 14, 2004 but before the effective
date of the final rule from testing duration requirements at Sec. Sec.
192.505(c), (d) and 192.507. In contrast, pressure vessels installed on
or after the effective date of the final rule would be subject to the
long-standing pressure test duration requirements in subpart J.
    Third, PHMSA proposed Sec.  192.153(e)(3)(ii) to accept, subject to
certain conditions, a pre-installation pressure test by the component
manufacturer for pressure vessels installed after the effective date of
the final rule but which have not previously been used in service.
PHMSA proposed to accept those manufacturer pressure tests for the
purposes of meeting the pressure testing and MAOP requirements in part
192 provided the operator conducts and documents an inspection
certifying that the pressure vessel has not been damaged during
transport and installation into the pipeline. If the inspection reveals
that the pressure vessel has been damaged, the component would have to
be remediated consistent with the ASME BPVC and part 192. A pressure
vessel used prior to installation on a pipeline facility would have to
be pressure tested again, consistent with the existing requirement at
Sec.  192.503(a).
2. Summary of Public Comments
    AGA et al. generally supported the PSR amendments proposed in the
NPRM but suggested substantive revisions to the requirements for
accepting a manufacturer's test of a pressure vessel. AGA et al.
emphasized that the NPRM's integration of ASME

BPVC requirements within its proposed PSR revisions leverages an
internationally recognized standard of safety applied by several
Federal regulators in their oversight activities. AGA et al. agreed
with the NPRM's approach of allowing operators to rely on a
manufacturer's pressure test accompanied by a visual inspection for
newly-manufactured vessels, but requested PHMSA extend this
authorization to relocations of existing components as well.
    AGA et al. noted that retesting ASME pressure vessels is not
required by the ASME BPVC--but if an operator voluntarily undertook
retesting, the ASME BPVC would require oversight by an authorized
inspector. They concluded that retesting is therefore unnecessary and
can lead to costs and operational disruptions because most operators do
not have an authorized inspector on staff to oversee that retesting.
They further commented that PHMSA should not require pressure vessels
be pressure tested or inspected after installation or in situ, because
in many cases it may be impracticable or unsafe to do so, especially
for pressure vessels used in compressor stations. Finally, AGA et al.
submitted comments opposing the NPRM's proposed requirement that
pressure vessels that have been used prior to being installed or
relocated must be retested in place in accordance with Subpart J. They
commented that retesting relocated vessels is not required by the ASME
BPVC, and that inspection rather than pressure testing is the
appropriate method to confirm the integrity of previously-used,
relocated pressure vessels.
    PST opposed the proposed revisions to Sec.  192.153, contending
that PHMSA lacked sufficient technical justification for the proposed
changes. PST argued that the ORNL report does not support PHMSA's
conclusion that safety would not be adversely affected by NPRM's
proposed reduction of the pressure test factor at Sec.  192.153(e). PST
asserted that the ORNL report did not conclude that components designed
and fabricated under the 2015 edition of the ASME BPVC standards and
tested to its lower (1.3 times MAWP) hydrostatic pressure test factor
were necessarily as safe as those designed and fabricated to the higher
hydrostatic pressure test factor (1.5 times MAWP) in the current text
of Sec. Sec.  192.153(e) and 192.505(b) (which were based on the test
factors from the 1998 and prior editions of the ASME BPVC). Rather, PST
characterizes the hydrostatic pressure test factor as only ``one of
[several] changes between [the] two editions'' (1992 and 2015) compared
by the ORNL report that would need to be evaluated to determine the
safety impact of the NPRM's revisions to Sec.  192.153 compared to the
current PSR. PST also noted that the NPRM proposed applying the lower
test factor in the 2015 ASME BPVC not only to components installed
since the 2015 edition, but also components installed over the previous
decade. Lastly, PST alleged that the NPRM's proposed reduction in the
test factor at Sec.  192.153(e) violates the prohibition in 49 U.S.C.
60104(b) on retroactive application of design standards insofar as it
purports to impose new design, installation, construction, and testing
standards on previously-installed components. PST representatives
reiterated their concerns in a conversation with PHMSA personnel after
the GPAC meeting.
    The GPAC members voted 11-2 in favor of PHMSA's proposed amendments
with respect to test requirements for pressure vessels provided that
PHMSA make the following changes:
     Clarify in the NPRM's Sec.  192.153(e)(3) that testing or
inspection of a pressure vessel must take place after being placed on
its supports at its installation location, but may occur prior to tie-
in with station piping.
     Clarify in the NPRM's Sec.  192.153(e)(3) that relocated
vessels must meet current design and construction requirements, be
retested by the operator, and be inspected as described in the previous
recommendation, to ensure there are no injurious defects.
     Clarify in a new Sec.  192.153(e)(4) that the retesting
requirements applicable to pressure vessels do not apply to those
pressure vessels that are used for temporary maintenance and repair
activities, such as portable launcher or receivers, temporary odorant
tanks, blow down equipment, and other similar equipment, but they must
be inspected for safety and integrity prior to usage.
    Two GPAC members representing EDF and PST voted against the
proposed amendments, expressing concern that the retroactivity
prohibition at 49 U.S.C. 60104(b) prohibits PHMSA from applying a
revised test factor to existing pressure vessels. During the meeting,
PHMSA committed to the GPAC members that it would consider the
application of 49 U.S.C. 60104(b)'s prohibition to the changes proposed
in the NPRM.
    INGAA, AGA, APGA, API, and GPA Midstream submitted joint
supplemental comments after the GPAC Meeting supporting the GPAC
recommendation and asserting that the proposed PSR amendments did not
violate the 49 U.S.C. 60104(b) retroactivity prohibition. GPA Midstream
separately submitted supplemental comments on that statutory
retroactivity prohibition, explaining by reference to its legislative
history, contemporaneous DOT interpretation of the relevant statutory
language, and subsequent PHMSA interpretations of the same that 49
U.S.C. 60104(b) prohibits only generically-applicable, retroactive
standards imposing new compliance burdens on relevant pipelines. Here,
in contrast, GPA Midstream contended the NPRM's proposed revisions to
Sec.  192.153(e) would relieve regulatory burdens and operators would
have to take no action to be in full compliance with the amended Sec.
192.153(e).
3. PHMSA Response
    After considering the comments and the GPAC, PHMSA is adopting the
proposed testing requirements for pressure vessels subject to certain
amendments to the proposed rule with respect to test requirements for
pressure vessels in Sec.  192.153. The final rule adopts the revision
to Sec.  192.153(e)(1), which specifies that a prefabricated unit or
pressure vessel that is installed after July 13, 2004 is not subject to
the strength testing requirements at Sec. Sec.  192.505(b) provided it
has been tested in accordance with Sec.  192.153(a) or (b) and with a
test factor of at least 1.3 times the intended MAOP, consistent with
the hydrostatic pressure test factors in section VIII, division 1 of
the ASME BPVC. The final rule also adds a footnote to table 1 to the
Sec.  192.619(a)(2)(ii) MAOP requirements specifying that the factor
for establishing the MAOP of a prefabricated unit or pressure vessel
installed after July 14, 2004 is 1.3 times the MAOP. These changes
ensure that an operator of a pressure vessel designed and
hydrostatically tested in accordance with section VIII, division 1 of
the ASME BPVC since the incorporation by reference of the 2001 edition
of that document is compliant with the PSR. This allows an operator of
a pressure vessel designed and hydrostatically tested in accordance
with section VIII, division 1 of the ASME BPVC to operate it at an MAOP
equal to its design pressure in most instances. PHMSA notes that if the
pressure vessel is tested at factor lower than 1.3 times the MAWP under
a pneumatic test or under section VIII division 2 of the ASME BPVC, the
MAOP of the pipeline must be

established such that the test pressure is 1.3 times the MAOP or
greater.
    PHMSA understands the administrative record shows that this
rulemaking's revision of the pressure test factors at Sec.  192.153
does not adversely affect the safety of pressure vessels designed,
constructed, and tested in accordance with the 2001 and subsequent
editions of the ASME BPVC, and designed, tested, constructed, and
operated in accordance with the PSR. PHMSA therefore disagrees with
PST's assertion that the ORNL report does not contribute to the
technical justification for that change. PST is correct to note that
the ORNL report compares the 1992 and 2015 editions of the ASME BPVC,
and that other changes have taken place within the intervening editions
of that standard (including the 2007 version currently incorporated by
reference in the PSR). However, the ORNL report did not provide only a
top-level statement of safety equivalence between the 1992 and 2015
editions of the ASME BPVC; it also evaluated the contributions to that
ultimate conclusion from each of the material elements of the 1992 and
2015 editions ASME BPVC--including the effects of a reduction in the
hydrostatic pressure test factor in ASME BPVC section VIII, division 1
from 1.5 times the MAWP to 1.3 times the MAWP.\58\
---------------------------------------------------------------------------

    \58\ ORNL report at Table 9.2 (summarizing Section <IP_ADDRESS> of
the ORNL report on the safety contribution of hydrostatic test
factors in different editions of ASME BPVC section VIII, division
1).
---------------------------------------------------------------------------

    The ORNL report predicated its top-level conclusion of safety
equivalence across the 1992 and 2015 editions of the BPVC section VIII,
division 1, notwithstanding their different hydrostatic pressure test
factors, in part on certain shared features. The most important of
those features was that both editions' hydrostatic pressure test
factors yield hydrostatic pressure testing limits that ensure primary
membrane stresses remain at or below plastic collapse stress limits for
a pressure vessel, thereby reducing the risk of permanent distortion
that would result in rejection of the pressure vessel at qualification.
Other features shared between the 1992 and 2015 editions of BPVC
section VIII, division 1 contributing to ORNL's safety equivalence
finding include the following: Pressure testing by an authorized
inspector at qualification verifying leak-tight integrity and the
absence of gross deformations and anomalies indicative of design
errors, material defects, or weld defects; pressure testing after
fabrication verifying leak-tight integrity and the absence of gross
deformations and anomalies indicative of design errors, material
defects, or weld defects; and overpressure protection in the event of
design basis heat exposure ensuring that maximum overpressure does not
exceed 1.3 MAWP.
    Each of the features listed above are also shared by the 2007
edition of the BPVC section VIII, section 1 incorporated by reference
in the PSR, notwithstanding any other differences between that edition
and the 1992 and 2015 editions evaluated in the ORNL report. Like the
1992 and 2015 editions, the various design requirements of the 2007
edition of the ASME BPVC ensure that plastic stresses on a pressure
vessel remain at or below plastic collapse stress limits to avoid
permanent distortion. And like the 1992 and 2015 editions, the 2007
edition backstops that design basis by qualified inspections to
identify defects, post-fabrication pressure testing, and overpressure
protection from a design basis heat exposure. Insofar as ORNL
determined that these shared features contributed to its top-level
conclusion of safety equivalence between the 1992 and 2015 editions of
the ASME BPVC, PHMSA understands them to support its conclusion in this
final rule that that a lower (1.3) test factor will not adversely
affect safety.
    PHMSA also submits that other elements of this final rule and the
PSR's comprehensive safety regime support the conclusion that lowering
the test factor to 1.3 will not adversely affect safety. The
applicability of the ASME BPVC in the PSR is limited to the design,
testing and fabrication of pressure vessels. On the other hand, the PSR
applies additional requirements throughout the lifecycle of a pressure
vessel to ensure its continued integrity and safe operation. These
requirements pertain to construction (subpart G), corrosion control
(subpart I), testing (subpart J), operation (subpart L), maintenance
(subpart M), and integrity management (subparts O and P) standards.
Further, even with respect to design and installation standards that
are the focus of ASME BPVC section VIII, division 1, PSR requirements
provide additional assurance that stresses remain within safe limits.
For example, Sec.  192.201(a)(2)(i) requires overpressure protection
devices be set to discharge at 1.1 times MAOP or at a pressure
producing a hoop stress of 75 percent of SMYS, whichever is lower--a
requirement that is more conservative than analogous overpressure
specifications in the ASME BPVC referenced in the ORNL report.
Similarly, the ASME BPVC does not specify a minimum pressure test
duration. In contrast, the PSR at subpart J requires a minimum pressure
test durations of 8 hours (Sec.  192.505(c)), 4 hours (Sec.
192.505(d)), 1 hour (Sec.  192.507(c)), or with a procedure sufficient
to ensure discovery of all potentially hazardous leaks (Sec.  192.509).
    PHMSA further notes that exemption in this final rule from subpart
J's minimum pressure duration requirements are consistent with that
conclusion. Prior to the changes adopted by this final rule, if an
operator tested a pressure vessel to 1.3 times the MAOP consistent with
section VIII, division 1 of the ASME BPVC rather than 1.5 times the
MAOP, it would not comply with the PSR. An operator of such a vessel
would need to reduce the MAOP of the pressure vessel such that the test
pressure is 1.3 times the reduced MAOP, retest the vessel to 1.5 times
the MAOP, or replace the pressure vessel entirely. Likewise, a pressure
vessel that was not tested for a duration specified in subpart J would
need to be retested or replaced to remain in compliance. While
retesting or replacing existing pressure vessels with a longer test
duration or higher test factor could conceivably decrease the risk of
an overpressure event causing a vessel failure on affected pipelines,
PHMSA understands any such safety benefit could be speculative;
incident reports indicate that pressure vessel failure has not been an
issue on existing vessels in-service.
    This is further supported by the conclusions of the ORNL report
with respect to the hydrostatic pressure testing limits described
above. Further, any potential safety benefit from retesting or
replacing pressure vessels already in service would need to be weighed
against new safety risks that may emerge from such activity. And here
PHMSA understands that re-testing and replacing in-service pressure
vessels in pipeline facilities can entail its own safety hazards for
operator personnel due to the mass, volume, and installation location
of a typical pressure vessel compared with other types of pipeline
facilities. Specifically, retesting or replacement of a pressure vessel
requires purging of gas, disconnection from local piping, and likely
removal from service and reinstallation. The pipeline facilities
involved in such efforts may be very heavy and large, which increases
hazards to operator personnel when the pressure vessel or other
equipment is removed from its installation location and prepared for
testing. The layout of compressor stations and other facilities may
exacerbate these safety risks if there

is limited space to safely remove the pressure vessel or to maneuver
lifting equipment. Each of these steps therefore introduces certain
safety risks to operator personnel performing the work that PHMSA
believes could outweigh any marginal, speculative safety benefit from
re-testing and replacement of previously-installed pressure vessels.
Lastly, as pointed out by multiple comments submitted on the NPRM, such
re-testing and replacement of existing pipe could entail significant
costs and operational disruptions that similarly militate in favor of
the exemption in the final rule.
    Finally, PHMSA notes that the ASME BPVC does not specify minimum
test duration requirements and part 192 does not currently require
post-installation inspection of pressure vessels. The final rule's PSR
amendment clarifying that these requirements apply to new, replaced,
relocated, or otherwise changed pressure vessels installed after the
effective date of the final rule are expected to result in an increased
level of safety.
    The final rule retains the proposed requirement to inspect pre-
tested pressure vessels after being placed at the vessel's installation
location on its support structure in Sec.  192.153(e)(3). However,
consistent with the GPAC's recommendations, the final rule clarifies
that those inspections may occur prior to the pressure vessel tie-in
on-site with the pipeline. PHMSA appreciates comments that testing
vessels after they have been tied-in to station piping may be
problematic depending on what or how it is being connected. But one of
the risks of transporting pressure vessels and other large components
is damage to the vessel including vessel outlets or its support
structure while it is being moved within the facility itself. Many of
the considerations raised by commenters that may complicate an
inspection likewise raise the likelihood of potential damage during
installation. For example, it would be unusual for a pressure vessel to
be completely inaccessible in a typical compressor station
configuration. In addition, since the Sec.  192.153(e)(3) requirement
applies to new, replaced, and relocated vessels, operators can ensure
access during initial design, construction, and testing stages. The
final rule also clarifies that operators must visually inspect the
steel structure for damage including, at a minimum: Inlets, outlets,
and lifting points. If damage is found, the pressure vessel must be
non-destructively tested, re-pressure tested, or remediated in
accordance with part 192 and ASME BPVC requirements. Test, inspection,
and repair records must be kept for the operational life of the
pressure vessel. These clarifying revisions to Sec.  192.153(e)(3) are
designed to enhance safety, address the most significant concerns
operators had with post-installation inspection, and help ensure that
damage incurred during movements within the facility are detected and
remediated before the pressure vessel is put into service.
    PHMSA has also, consistent with the GPAC's recommendations,
clarified when testing and inspection under Sec.  192.153(e)(3) is
required. The final rule clarifies that any pressure vessel that is
temporarily or permanently installed in a pipeline facility must be
inspected for damage as described above unless it has been pressure
tested on its supports at its installation location. This includes
pressure vessels that are pressure tested by the operator prior to
installation when a post-installation pressure test is impracticable
(Sec. Sec.  192.505(d) and 192.507(d) in the final rule) and to
pressure vessels where a manufacturer's pressure test is used under
Sec.  192.153(e)(4) in the final rule. This change is consistent with
pretesting authorizations under Sec.  192.507(d) in the final rule or
Sec.  192.505(d) in existing part 192. It preserves the flexibility
provided under those authorizations while the post-installation
inspection ensures that pre-tested components are not damaged after
being tested by the manufacturer or the operator.
    The final rule also clarifies design, testing, and inspection
requirements for pressure vessels that are relocated. Consistent with
the GPAC's recommendations, PHMSA is adding a new Sec.  192.153(e)(6)
that clarifies testing and inspection requirements for relocating an
existing pressure vessel that has previously been used in service for
permanent installation at a new location in a pipeline facility. An
operator must have documentation that a relocated pressure vessel meets
the design, construction, and testing requirements in place at the time
of relocation and pressure test the pressure vessel. If a pre-
installation pressure test is performed, the operator must inspect the
pressure vessel after installation.
    The final rule does not adopt suggestions from commenters to accept
a manufacturer's initial pressure test for all relocated pressure
vessels. PHMSA did not propose specific changes to the initial pressure
testing requirements for relocated, existing pressure vessels. Rather,
the requirements in the final rule for permanently relocated vessels
complement existing part 192 requirements for relocation of existing
facilities with the addition of a new, general requirement in Sec.
192.153(e)(3) to inspect pressure vessels that are not pressure tested
in place. Using a manufacturer's initial pressure test of an existing
vessel raises safety concerns because the vessel could have been
subject to corrosion, fatigue, external force damage, and other threats
to the vessel's integrity during its prior operational life or during
transportation to the new facility.
    The GPAC's discussion noted that operators commonly use such
temporary devices for temporary launchers and receivers for integrity
assessments and to reduce methane emissions during blowdowns (natural
gas is predominately methane, a greenhouse gas). PHMSA did not intend
to impair the use of pressure vessels that are relocated temporarily in
order to perform maintenance, repair, or emergency-response-related
tasks. To prevent this unintended result, PHMSA is incorporating a new
Sec.  192.153(e)(4)(ii) to allow the use of a manufacturer's initial
test of a pressure vessel temporarily installed in a pipeline facility
to complete a testing, integrity assessment, repair, odorization, or
emergency response-related task, including noise or pollution
abatement. This revision addresses temporary and mobile pressure
vessels that were discussed during the GPAC meeting, including portable
launcher or receivers, temporary odorant tanks, mobile blow down
equipment, and other similar equipment. This change reduces barriers to
using temporary equipment to perform integrity assessment, maintenance,
and pollution mitigation-related tasks (provided the equipment meets
the MAOP, design, and inspection requirements in part 192) and thereby
is expected to result in greater efficiency for operators and safety
and environmental benefits associated with encouraging inspections and
repairs. These devices are subject to the new general requirement in
Sec.  192.153(e)(3)(ii) to inspect pressure vessels that are not
pressure tested in place after installation. Reducing regulatory
burdens associated with performing maintenance, repair, emergency
response, and pollution abatement tasks could result in safety and
environmental benefits by making such actions more attractive to
operators.
    To prevents misuse of this flexibility, a pressure vessel that is
installed under Sec.  192.153(e)(4)(ii) must be removed when the task
it is associated with is completed. Operators should define the
procedures for employing temporary or mobile pressure vessels in their
written procedure manuals. The final rule

requires operators to submit a notification to PHMSA and applicable
State pipeline safety authorities in accordance with Sec.  192.18 if a
temporary pressure vessel must be left in place for longer than 30
days; however, PHMSA does not reference this section in Sec.  192.18(c)
and therefore the objection process and advance notice requirements do
not apply. Likewise, Sec.  192.153(e)(5) clarifies that an operator is
not required to pressure test a pressure vessel that is temporarily
removed from a facility to perform a maintenance task and later re-
installed at the same location. However, the re-installed pressure
vessel must be inspected in accordance with Sec.  192.153(e)(3)(ii)
after it is re-installed. Generally, PHMSA does not consider small
movements within the same location (e.g. within a compressor station)
with no other operational changes as a relocation, however the operator
should inspect the vessel for damage after installation.
    PHMSA has considered the comments by PST and members of the GPAC
regarding the nonapplication requirement and finds the revisions to 49
CFR 192.153(e) are not inconsistent with 49 U.S.C. 60104(b). Section
60104(b) provides that a ``design, installation, construction, initial
inspection, or initial testing standard does not apply to a pipeline
facility existing when the standard is adopted.'' Under the revised
Sec.  192.153, operators of existing pressure vessels that meet minimum
testing requirements will not be required to take any additional action
to comply. While the revised section requires that components be
pressure tested with a test factor of at least 1.3 times MAOP, the
current Sec.  192.153(e) already required such testing at even higher
pressures; in other words, a pressure vessel compliant with the
existing Sec.  192.153(e) would also be compliant with Sec.  192.153(e)
as revised by this final rule. The revisions to the PSR, therefore,
cannot be said to impose a new standard on existing facilities in
conflict with 49 U.S.C. 60104(b).
    In addition, as described in the preamble to the NPRM, the
amendment to 49 CFR 192.153(e) responds to a petition for
reconsideration of the Miscellaneous Rule.\59\ This final rule
addresses the issues raised by the petition challenging the addition of
Sec.  192.153(e) in the Miscellaneous Rule pursuant to the
reconsideration procedures in part 190. The petition for
reconsideration of the Miscellaneous Rule argues PHMSA's modifications
to Sec.  192.153 were not merely clarifications regarding the required
testing standard for pressure vessels as PHMSA stated in the
Miscellaneous Rule, but rather were departures from the testing
standard for pressure vessels in the ASME BPVC standard that was
incorporated in the regulations at the time. PHMSA maintains that the
Miscellaneous Rule merely clarified the required testing standard for
pressure vessels, but understands there was ambiguity in the
regulations regarding the testing standard for pressure vessels before
the Miscellaneous Rule was passed and that the Miscellaneous Rule
codified a higher testing standard than many operators reasonably
believed was compliant with the regulations at the time. Also, based on
the discussion above, PHMSA was able to verify that the provisions in
the final rule will not adversely affect safety. PHMSA is therefore
allowing pressure vessels tested in accordance with the 1.3 test factor
after 2004 to continue operating without retesting in order not to
penalize conduct some operators believed complied with the PSR at the
time.
---------------------------------------------------------------------------

    \59\ Available in docket No. PHMSA-2010-0026 and the docket for
this final rule.
---------------------------------------------------------------------------

    Lastly, because PHMSA understands the PSR revisions in this final
rule obviate the need for its unpublished October 27, 2015 letter to
INGAA announcing a stay of enforcement pertaining to certain pressure
vessels in violation of Sec. Sec.  192.153(e) and 192.505(b), it
withdraws that document as of the effective date of this final rule.
This letter is also available in the docket for this final rule.

I. Welding Process Requirement (Section 192.229)

1. PHMSA's Proposal
    Section 192.229(b) currently bars welders from welding with a
welding process if they have not engaged in welding with that same
process within the previous six months. GPTC submitted a petition for
rulemaking requesting PHMSA revise Sec.  192.229(b) to allow welders to
demonstrate they have engaged in welding with a welding process at
least twice each calendar year, but at intervals not exceeding 7\1/2\
months, provided the welds were tested and found acceptable in
accordance with API Standard (Std) 1104.\60\ API Std 1104 is the
primary standard for welding steel piping and for testing welds on
steel pipelines, and covers the requirements for welding and
nondestructive testing of pipeline welds. API Std 1104 is used within
part 192 requirements for qualifying welders, welding procedures, and
welding operators, and interpreting the results of non-destructive
tests.
---------------------------------------------------------------------------

    \60\ Docket No. PHMSA-2014-0015.
---------------------------------------------------------------------------

    GPTC also noted that the 6-month frequency requirement for the
welding process requirement at Sec.  192.229(b) is different than other
requirements in Sec.  192.229(c)(1) and (d)(2) governing welder
requalification frequency. Those welder requalification requirements
demand requalification within the preceding 7\1/2\ months, but at least
twice each calendar year. GPTC pointed out that this discrepancy
between welder process requirements and welder requalification
requirements obliged operators either to maintain alternative
recordkeeping procedures for the process requirement or perform welds
to comply with both the process requirement and the requalification
requirements on a 6-month interval. In other words, if a welder wishes
to use the same weld to comply with both requirements, they are unable
to benefit from the more flexible welder requalification requirements
at Sec.  192.229(c)(1) and (d)(2).
    PHMSA proposed in the NPRM to revise Sec.  192.229(b) to specify
that welders or welding operators may not weld with a particular
welding process unless they have engaged in welding with that process
within the preceding 7\1/2\ months and the welds were tested and found
acceptable in accordance with API Std 1104. This change would provide
operators some flexibility in scheduling welding activities to maintain
welder requalification. PHMSA agrees with GPTC that the proposed
revision is more consistent with Sec.  192.229(d)(2). This is
potentially beneficial for welders who weld relatively infrequently.
PHMSA does not anticipate a decrease in safety, as a 7\1/2\-month
interval is already permitted for requalification under Sec.
192.229(d)(2)(i), and the change will only affect welders who are not
welding throughout the year.
2. Summary of Public Comments
    AmeriGas, AIPRO, FreedomWorks, NPGA, Oleksa and Associates, and SPP
supported the proposed requalification scheduling for welders. Oleksa
and Associates stated that there will be no negative impact on pipeline
safety. FreedomWorks stated that the changes would allow welders, many
of whom are self-employed freelancers, greater flexibility in their
trade. AIPRO commented that the changes would establish regulatory
expectations and create more scheduling opportunity for vendors to
perform the welding tests and for companies to comply with the
standard. The GPAC voted unanimously

in favor of PHMSA's proposed amendments regarding the welding process
requirement.
3. PHMSA Response
    Based on the comments and the GPAC recommendations, PHMSA has
adopted this amendment as proposed. This change will streamline
compliance and recordkeeping activities related to Sec.  192.229(b) and
will not have a detrimental impact on safety.

J. Pre-Test Applicability (Section 192.507)

1. PHMSA's Proposal
    Section 192.505(d) permits operators to test fabricated units and
short segments of pipe prior to installation on steel pipelines
operated at a hoop stress of 30 percent or more of SMYS if a post-
installation test is not practicable. PHMSA proposed in the NPRM to add
a new paragraph (d) to Sec.  192.507 to extend this authorization to
steel pipelines operated at a hoop stress less than 30 percent of SMYS
and at or above 100 psig.\61\
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    \61\ ``Pounds per square inch gauge'' refers to internal
pressure relative to outside atmospheric pressure.
---------------------------------------------------------------------------

    The NPRM's proposed revision is in response to a petition for
rulemaking submitted by GPTC for PHMSA to relocate the pre-installation
strength testing requirement at Sec.  192.505(d) to the general test
requirements in Sec.  192.503 to permit broader application of this
authorization. GPTC argued this change would permit operators to use
pre-tested pipe and fabricated units in applications outside of higher
stress transmission pipelines. GPTC further asserted that as this
provision is currently applicable only to higher-stress pipelines
operating at a hoop stress at or greater than 30 percent of SMYS,
extending the broader pre-testing provision to lower-stress pipelines
would not increase pipeline safety risks. Rather, GPTC predicted this
proposed change will provide greater flexibility and efficiency for
operators of lower-stress pipelines, especially during maintenance
activities.
    Instead of adding pre-testing provisions to the general
requirements at Sec.  192.503 as suggested by the GPTC petition, PHMSA
proposed in the NPRM to add Sec.  192.507(d) to permit pre-testing on
steel pipelines operating at a hoop stress less than 30 percent of SMYS
and at or above 100 psig. The proposal did not extend pre-testing
provisions to pipelines operating below 100 psig (Sec.  192.509),
service lines (Sec.  192.511), or plastic pipelines (Sec.  192.513).
Individual components, excluding short segments of pipe, may still be
installed on those facilities with a pre-installation test pursuant to
Sec.  192.503(e). PHMSA requested comments on whether it is appropriate
to extend pre-testing provisions to such facilities, and solicited
proposed requirements that should apply if pre-testing provisions are
extended to such facilities.
2. Summary of Public Comments
    AmeriGas, NPGA, and SPP supported the proposed changes to Sec.
192.507 to allow operators to extend the authorization for pre-testing
fabricated assemblies to include steel pipelines that operate at a hoop
stress less than 30 percent of SMYS and at or above 100 psig.
Similarly, PST commented that they did not object to extending the pre-
testing provisions to lower stress pipelines as proposed in the NPRM.
    AGA et al., National Fuel, and Oleksa and Associates recommended
that PHMSA consider extending the pre-testing allowance to other
pipelines that also pose less of a safety risk. Specifically, they
recommended that PHMSA extend the allowance for pre-tested short
segments of pipe and fabricated units to steel pipelines that operate
at pressures less than 100 psig (Sec.  192.509), plastic pipelines
(Sec.  192.511), and service lines (Sec.  192.513) to provide clarity
and consistency within the regulations. These commenters suggested the
addition of enabling regulatory text. Oleksa and Associates agreed with
these commenters, stating that the rationale that applies to permitting
pre-tested pipe on steel pipelines operating at a stress less than 30
percent of SMYS and at or above 100 psig applies in the same way to
pipelines operating below 100 psig, service lines, and plastic
pipelines. They suggested that the simplest way to accomplish this is
to modify the wording in Sec.  192.503.
    Similarly, NAPSR opposed the proposed revision unless it is revised
to allow the use of pre-tested pipe for main repairs under 100 psig.
Specifically, NAPSR commented that it may be impracticable to pressure
test Type B gathering lines and mains post-installation. They commented
that if pre-tested pipe is allowed for systems that operate above 100
psig and above 30 percent SMYS, then pre-tested pipe should also be
allowed for all pipe that operates below 100 psig and low stress pipe.
NAPSR believes that most operators use pre-tested pipe for main and
Type B gathering line repairs as a standard practice; that pipe is soap
tested and visually inspected for leaks after installation. They stated
that the proposed change in the NPRM could unnecessarily restrict
operators from safely and quickly repairing damages, and that
distribution operators could potentially experience prolonged outages
(especially in cold weather) and increased repair times and cost if
pre-tested pipe is not allowed.
    AGA et al. commented that in 2019, distribution system operators
reported 84,608 leaks caused by excavation damage on their Gas
Distribution Annual Reports. Assuming each excavation damage related
leak required a pressure test, and assuming a cost of $200 per post-
installation pressure test, they stated that the cost would be nearly
$17 million annually to pressure test pipe replaced due to excavation
damage alone. National Fuel's comment included a similar calculation
and estimated $8.8 million in cost savings if pre-tested pipe is
allowed for such repairs. These commenters asserted that the use of
pre-tested pipe would significantly reduce these costs as operators
could pre-test full joints or coils of pipe for use on multiple short
segment replacements and repairs without compromising safety.
    National Fuel commented that extending pre-testing to distribution
lines would allow the use of pre-tested pipe for short segment
replacements for leak repairs, excavation damage repairs and
replacement of visually questionable welds or plastic fusion joints.
They noted that without this change operators are required to test
short replacement segments in place, which is inefficient, time
consuming, and often results in extended shutdown durations and
inconvenience to customers. They further stated that based on current
regulatory language, an excavation damage repair that involves
replacement of two feet of plastic distribution main requires that the
operator: (1) Fuse end caps on each end of the replacement segment, (2)
pressure test the pipe in place for the required duration, (3) remove
the end caps, (4) tie-in the replacement segment by electrofusion or
coupling, and (5) purge, gas and soap test the joints. They stated that
allowing the use of pre-tested pipe would significantly reduce the
repair time and costs to complete the repair and would still result in
a pipe segment that is both strength tested and leak tested to ensure
an equal level of safety while limiting interruptions to customers.
    AGA et al. recommended that PHMSA remove the term ``hydrostatic''
from the test requirements for short segments of pipe and pre-
fabricated units from Sec.  192.507 because natural gas, inert gas, and
air are also allowable test media for pipelines operating at a

hoop stress less than 30 percent of SMYS under Sec.  192.503(c).
    The GPAC voted unanimously in favor of PHMSA's proposed PSR
amendments regarding the welding process requirement but recommended
removing the word ``hydrostatic'' from the proposed Sec.  192.507(d).
3. PHMSA Response
    Based on the comments received and the recommendation of the GPAC,
the final rule adopts the amendments related to pre-testing fabricated
assemblies and short segments of pipe as proposed in the NPRM, except
that PHMSA has removed the term ``hydrostatic'' from the new Sec.
192.507(d). PHMSA agrees that removing the term ``hydrostatic'' is
appropriate since other test media other than water are approved for
use in that new section.
    The final rule does not extend the authorization in Sec.  192.507
(as revised) for pre-tested segments of pipe and fabricated assemblies
beyond steel pipe with an MAOP producing a hoop stress less than 30
percent of SMYS but at or above 100 psig. Operators must still perform
leak tests after installing fabricated units and short segments of pipe
installed on such pipelines. The remaining categories in subpart J
(metallic pipe with an MAOP less than 100 psig, plastic pipe, and
service lines) generally represent distribution lines rather than
transmission lines. It is not clear that there is adequate safety
justification for extending the pre-testing allowance to these
categories of lines due to the proximity of such facilities to
customers and the differences in design, construction, inspection, and
testing requirements for such facilities compared with higher-pressure
transmission lines. For example, welds on higher-pressure metallic
lines require inspection with non-destructive testing techniques under
Sec.  192.241, while plastic pipe joints and welds on lower-pressure
metallic lines can be visually inspected instead. The leak tests
required for lower-pressure lines in subpart J are, therefore,
necessary to ensure the leak-tight integrity of welds and joints on
such lines. Commenters did not suggest alternative inspection
requirements or other conditions for using pre-tested pipe and
fabricated units on such pipelines. PHMSA therefore determined that
additional analysis is necessary to consider the safety effects of
extending the pre-testing allowance to such facilities, and what, if
any, additional conditions may be necessary. The GPAC voted unanimously
in favor of this recommended approach. PHMSA may consider this issue in
future rulemaking.
    PHMSA notes that Sec. Sec.  192.509, 192.511, and 192.513 require
only a leak test. NAPSR presented a scenario where, for a replacement
repair, an operator installed pre-tested pipe and then performed a leak
test after installation. The leak test described in this scenario meets
the post-installation leak test requirement in Sec.  192.509, provided
that the operator's test procedure ensures the discovery of all
potentially hazardous leaks.

IV. Availability of Standards Incorporated by Reference

    PHMSA currently incorporates by reference into 49 CFR parts 192,
193, and 195 all or parts of more than 80 standards and specifications
developed and published by standard development organizations (SDO). In
general, SDOs update and revise their published standards every 2 to 5
years to reflect modern technology and best technical practices.
    The National Technology Transfer and Advancement Act of 1995 (Pub.
L. 104-113; NTTAA) directs Federal agencies to use standards developed
by voluntary consensus standards bodies in lieu of government-written
standards whenever possible. Voluntary consensus standards bodies
develop, establish, or coordinate technical standards using agreed-upon
procedures. In addition, the Office of Management and Budget (OMB)
issued Circular A-119 \62\ to implement section 12(d) of the NTTAA
relative to the utilization of consensus technical standards by Federal
agencies. This circular provides guidance for agencies participating in
voluntary consensus standards bodies and describes procedures for
satisfying the reporting requirements in the NTTAA.
---------------------------------------------------------------------------

    \62\ OMB, Circular A-119, ``Federal Participation in the
Development and Use of Voluntary Consensus Standards and in
Conformity Assessment Activities'' (Jan. 27, 2016). Circular A-119
and revisions thereto are available at https://www.whitehouse.gov/omb/information-for-agencies/circulars/.
---------------------------------------------------------------------------

    Accordingly, PHMSA is responsible for determining, via petitions or
otherwise, which currently referenced standards should be updated,
revised, or removed, and which standards should be added to the PSR.
Pursuant to 49 U.S.C. 60102(p), PHMSA may not issue a regulation that
incorporates by reference any documents or portions thereof unless the
documents or portions thereof are made available to the public, free of
charge. Revisions to materials incorporated by reference in the PSR are
handled via the rulemaking process, which allows for the public and
regulated entities to provide input. During the rulemaking process,
PHMSA must also obtain approval from the Office of the Federal Register
to incorporate by reference any new materials. The Office of the
Federal Register issued a rulemaking on November 7, 2014, that revised
1 CFR 51.5 to require that agencies detail in the preamble of an NPRM
the ways the materials it proposes to incorporate by reference are
reasonably available to interested parties, or how the agency worked to
make those materials reasonably available to interested parties.\63\
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    \63\ 79 FR 66278.
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    To meet these obligations for this rulemaking, PHMSA negotiated
agreements with API and ASTM to provide viewable copies of standards
incorporated by reference in the pipeline safety regulations available
to the public at no cost. API Std 1104 is available at https://www.api.org/products-and-services/standards/rights-and-usage-policy#tab-ibr-reading-room and is discussed in greater detail in
section I.1 of this preamble. The ASTM standards are available at
https://www.astm.org/READINGLIBRARY/ and are discussed in greater
detail in section G.1 of this preamble. PHMSA will also provide
individual members of the public temporary access to any standard that
is incorporated by reference. Requests for access can be sent to the
following email address<EMAIL_ADDRESS>PHMSA also notes
that standards incorporated by reference in the PSR can be obtained
from the organization developing each standard. Section 192.7 provides
the contact information for each of those standard-developing
organizations.

V. Regulatory Analyses and Notices

A. Legal Authority for This Rulemaking

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

Administrator of PHMSA in 49 CFR 1.97.

B. Executive Order 12866 and DOT Rulemaking Procedures

    E.O. 12866, ``Regulatory Planning and Review,'' \64\ 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.'' E.O. 12866 and DOT regulations governing
rulemaking procedures at 49 CFR part 5 require that PHMSA submit
``significant regulatory actions'' to OMB for review. This rule is
considered significant under Sec.  3(f) of E.O. 12866, and was reviewed
by OMB. It is also significant under the DOT's rulemaking procedures at
49 CFR part 5.
---------------------------------------------------------------------------

    \64\ 58 FR 51735; Oct. 4, 1993.
---------------------------------------------------------------------------

    Similarly, DOT regulations at Sec.  5.5(f)-(g) require that
regulations issued by PHMSA and other DOT Operating Administrations
``should be designed to minimize burdens and reduce barriers to market
entry whenever possible, consistent with the effective promotion of
safety'' and should generally ``not be issued unless their benefits are
expected to exceed their costs.''
    E.O. 12866 and DOT implementing regulations at 49 CFR 5.5(i) also
require PHMSA to provide a meaningful opportunity for public
participation, which also reinforces requirements for notice and
comment under the Administrative Procedure Act (5 U.S.C. 551, et seq.).
Therefore, in the NPRM, PHMSA sought public comment on its proposed
revisions to the PSR and the preliminary cost and cost savings analyses
in the Preliminary RIA, as well as any information that could assist in
quantifying the benefits of this rulemaking. Those comments are
addressed in this final rule, and additional discussion about the
economic impacts of the final rule are provided within the final RIA
posted in the rulemaking docket.
    PHMSA estimated that this final rule would have economic benefits
to the public and the regulated community by reducing unnecessary cost
burdens without increasing risks to public safety or the environment.
PHMSA estimates that the final rule will result in annualized cost
savings of approximately $129.8 million per year, based on a 7 percent
discount rate. Most of the quantified cost savings in the final rule
are from the revisions to farm tap requirements and the revised
atmospheric corrosion reassessment interval for distribution service
lines. The final RIA in the rulemaking docket analyzes these economic
impacts in detail.

C. Executive Order 13771, ``Reducing Regulation and Controlling
Regulatory Cost''

    This final rule is an E.O. 13771 \65\ deregulatory action. Details
on the estimated cost savings of this final rule can be found in the
rule's economic analysis within the RIA in the rulemaking docket.
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    \65\ 82 FR 9339 (Feb. 3, 2017).
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D. Executive Order 13132--``Federalism''

    PHMSA analyzed this final rule in accordance with E.O. 13132.\66\
E.O. 13132 requires agencies to assure meaningful and timely input by
State and local officials in the development of regulatory policies
that may have ``substantial direct effects on the States, on the
relationship between the national government and the States, or on the
distribution of power and responsibilities among the various levels of
government.''
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    \66\ 64 FR 43255 (Aug. 10, 1999).
---------------------------------------------------------------------------

    This final rule does not impose a substantial direct effect on the
States, the relationship between the national government and the
States, or the distribution of power and responsibilities among the
various levels of government. This final rule also does not impose
substantial direct compliance costs on State and local governments.
    The final rule could have preemptive effect because the Federal
Pipeline Safety Law, specifically 49 U.S.C. 60104(c), prohibits certain
State safety regulation of interstate pipelines. Under the Federal
Pipeline Safety Law, States may 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. In this instance, the preemptive effect of the final rule is
limited to the minimum level necessary to achieve the objectives of the
Federal Pipeline Safety Law under which the final rule is promulgated.
Therefore, the consultation and funding requirements of E.O. 13132 do
not apply.

E. Executive Order 13175--``Consultation and Coordination With Indian
Tribal Governments''

    PHMSA analyzed this final rule in accordance with the principles
and criteria in E.O. 13175 \67\ and DOT Order 5301.1, ``Department of
Transportation Programs, Polices, and Procedures Affecting American
Indians, Alaska Natives, and Tribes.'' E.O. 13175 requires agencies to
assure meaningful and timely input from Tribal government
representatives in the development of rules that significantly or
uniquely affect Tribal communities by imposing ``substantial direct
compliance costs'' or ``substantial direct effects'' on such
communities or the relationship and distribution of power between the
Federal Government and Tribes. PHMSA assessed the impact of the final
rule on Indian Tribal communities and determined that it would not
significantly or uniquely affect Tribal communities or Indian Tribal
governments. Therefore, the funding and consultation requirements of
E.O. 13175 do not apply. PHMSA received no comments to the effect that
this rulemaking would have Tribal implications.
---------------------------------------------------------------------------

    \67\ 65 FR 67249 (Nov. 6, 2000).
---------------------------------------------------------------------------

F. Executive Order 13211--``Actions Concerning Regulations That
Significantly Affect Energy Supply, Distribution, or Use''

    E.O. 13211 \68\ requires Federal agencies to prepare a Statement of
Energy Effects for any ``significant energy action.'' Under E.O. 13211,
a ``significant energy action'' is defined as any action by an agency
(normally published in the Federal Register) that promulgates, or is
expected to lead to the promulgation of, a final rule or regulation
(including a notice of inquiry, ANPRM, and NPRM) that: (1)(i) Is a
significant regulatory action under E.O. 12866 or any successor order,
and (ii) is likely to have a significant adverse effect on the supply,
distribution, or use of energy; or (2) is designated by the
Administrator of the Office of Information and Regulatory Affairs as a
significant energy action.
---------------------------------------------------------------------------

    \68\ 66 FR 28355 (May 22, 2001).
---------------------------------------------------------------------------

    This final rule is not a ``significant energy action'' under E.O.
13211. It is not likely to have a significant adverse effect on supply,
distribution, or energy use; rather, it is expected to reduce
regulatory burdens on the natural gas pipeline sector without adversely
affecting safety. Further, the Office of Information and Regulatory
Affairs has not designated this final rule as a significant energy
action.

G. Regulatory Flexibility Act and Executive Order 13272

    The Regulatory Flexibility Act (5 U.S.C. 601 et seq.), as
implemented by E.O. 13272, ``Proper Consideration of Small Entities in
Agency

Rulemaking,'' \69\ and Sec.  5.13(f) of DOT regulations, 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.
---------------------------------------------------------------------------

    \69\ 68 FR 7990 (Feb. 19, 2003).
---------------------------------------------------------------------------

    PHMSA has determined that the cost-savings in the final rule may
result in significant economic impacts on a substantial number of small
entities. These impacts on regulated entities are beneficial. PHMSA has
included a FRFA within the final RIA posted in the docket for this
rulemaking.

H. Paperwork Reduction Act of 1995

    The Paperwork Reduction Act of 1995 (44 U.S.C. 3501 et seq.)
establishes policies and procedures for controlling paperwork burdens
imposed by Federal agencies on the public.
    Pursuant to 44 U.S.C. 3506(c)(2)(B) and 5 CFR 1320.8(d), PHMSA is
required to provide interested members of the public and affected
agencies with an opportunity to comment on information collection and
recordkeeping requests. PHMSA expects this final rule to impact the
information collections described below.
    PHMSA will submit an information collection revision request to OMB
for approval based on the requirements in this final rule. The
information collections are contained in the PSR. 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: Incident Reports for Gas Pipeline Operators.
    OMB Control Number: 2137-0635.
    Current Expiration Date: 01/31/2023.
    Abstract: This information collection covers the collection of
information from gas pipeline operators for incident reporting. PHMSA
estimates that due to the revised monetary damage threshold for
reporting incidents operators will submit 28 fewer gas distribution
incident reports, and 14 fewer gas transmission reports. Operators
currently spend 12 hours completing each incident report. Therefore,
PHMSA expects to eliminate 42 responses and 504 hours from this
information collection per year as a result of the provisions in the
proposed rule. PHMSA is also revising PHMSA F 7100.1, the Gas
Distribution Incident Report, to collect data on mechanical joint
failures that arise to the level of an incident as stipulated in 49 CFR
191.3. PHMSA does not expect operators to incur additional burden due
to this change.
    Affected Public: All gas pipeline operators.
    Annual Reporting and Recordkeeping Burden:
    Total Annual Responses: 259.
    Total Annual Burden Hours: 3,108.
    Frequency of Collection: On Occasion.
    2. Title: Annual and Incident Reports for Gas Pipeline Operators.
    OMB Control Number: 2137-0522.
    Current Expiration Date: 01/31/2023.
    Abstract: This information collection covers the collection of
information from gas pipeline operators for immediate notice of
incidents and Annual reports. Based on the proposals in this rule,
PHMSA plans to eliminate the MFF report form under this OMB Control
Number and have operators submit the annual total of mechanical joint
failures on the Gas Distribution Annual Report under OMB Control Number
2137-0629. In the currently-approved information collection, it is
estimated that PHMSA currently receives, on average, 8,300 MFF reports
each year with each operator spending, on average, 1 hour to complete
each report. By eliminating this report, PHMSA plans to reduce the
burden for this information collection by 8,300 responses and 8,300
burden hours.
    Affected Public: All gas pipeline operators.
    Annual Reporting and Recordkeeping Burden:
    Total Annual Responses: 2,247.
    Total Annual Burden Hours: 71,801.
    Frequency of Collection: Regular.
    3. Title: Pipeline Safety: Integrity Management Program for Gas
Distribution Pipelines.
    OMB Control Number: 2137-0625.
    Current Expiration Date: 06/30/2022.
    Abstract: The PSR require operators of gas distribution pipelines
to develop and implement IM programs.
    PHMSA proposed to eliminate this requirement for master meter
operators. Based on the currently approved information collection,
PHMSA estimates that, on average, 5,461 master meter operators spend 26
hours, annually, developing new IM plans and/or updating their existing
IM plans. Eliminating this requirement for master meter operators will
eliminate recordkeeping burdens attributable to these 5,461 existing
master meter operators, saving 141,986 hours of burden annually.
    Affected Public: Natural Gas Pipeline Operators.
    Annual Reporting and Recordkeeping Burden:
    Total Annual Responses: 3,882.
    Total Annual Burden Hours: 723,192.
    Frequency of Collection: On occasion.
    4. Title: Gas Distribution Annual Report.
    OMB Control Number: 2137-0629.
    Current Expiration Date: 10/31/2021.
    Abstract: The PSR require distribution operators to prepare and
submit annual reports with summary information on their pipeline
infrastructure. PHMSA proposed to shift the mechanical fitting failure
form requirements to a count of hazardous leaks involving a failure of
a mechanical joint on the distribution annual report form. PHMSA
estimates that it will take gas distribution operators approximately 30
minutes (0.5 hours; calculated as 13,075 mechanical joint failures
divided by 1,446 operators times 3 minutes per mechanical joint
failure) to add this information to the annual report. As a result, the
burden for this information collection will increase by approximately
723 hours. This addition will have no effect on the total number of
reports submitted.
    Affected Public: Natural Gas Distribution Pipeline Operators.
    Annual Reporting and Recordkeeping Burden:
    Total Annual Responses: 1,446.
    Total Annual Burden Hours: 25,305.
    Frequency of Collection: Annually.

I. Unfunded Mandates Reform Act of 1995

    Unfunded Mandates Reform Act (2 U.S.C. 1501 et seq.) requires
agencies to assess the effects of Federal regulatory actions on State,
local, and Tribal governments, and the private sector. For any NPRM or
final rule that includes a Federal mandate that may result in the
expenditure by State, local, and Tribal governments in the aggregate of
$100 million or more in 1996 dollars in any given year, the agency must
prepare, amongst other things, a written statement that qualitatively
and quantitatively assesses the costs and benefits of the Federal
mandate.
    PHMSA prepared a final RIA and determined that this final rule does
not impose enforceable duties on State, local, or Tribal governments or
on the private sector of $164 million in 2019 dollars or more in any
one year. A copy of the final RIA is available for review in the docket
of this rulemaking.

J. National Environmental Policy Act

    The National Environmental Policy Act (NEPA) (42 U.S.C. 4321 et.
seq.) requires Federal agencies to prepare a detailed statement on
major Federal actions significantly affecting the quality of the human
environment.
    PHMSA analyzed this rule in accordance with NEPA, NEPA implementing
regulations (40 CFR parts 1500-1508), and DOT Order 5610.1C. PHMSA
prepared a draft environmental assessment (EA) for the NPRM and posted
it in the rulemaking docket; PHMSA received no comments on the draft
EA. For this final rule, PHMSA has prepared a Final Environmental
Assessment (EA) and has determined that this final rule will not
significantly affect the quality of the human environment. The final EA
for this final rule is available in the docket.

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
the spring and fall of each year. The RIN number contained in the
heading of this document is a cross-reference for this action to the
Unified Agenda.

List of Subjects

49 CFR Part 191

    Pipeline reporting requirements, Integrity management, Pipeline
safety, Gas gathering.

49 CFR Part 192

    Incorporation by reference, Pipeline safety, Fire prevention,
Security measures.

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

PART 191--TRANSPORTATION OF NATURAL AND OTHER GAS BY PIPELINE;
ANNUAL REPORTS, INCIDENT REPORTS, AND SAFETY-RELATED CONDITION
REPORTS

0
1. The authority citation for 49 CFR part 191 continues 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.  191.3, in the definition of ``Incident'' revise paragraph
(1)(ii) to read as follows:

Sec.  191.3   Definitions.

* * * * *
    Incident means any of the following events:
    (1) * * *
    (ii) Estimated property damage of $122,000 or more, including loss
to the operator and others, or both, but excluding the cost of gas
lost. For adjustments for inflation observed in calendar year 2021
onwards, changes to the reporting threshold will be posted on PHMSA's
website. These changes will be determined in accordance with the
procedures in appendix A to part 191.
* * * * *

0
3. In Sec.  191.11, revise paragraph (b) to read as follows:

Sec.  191.11   Distribution system: Annual Report.

* * * * *
    (b) Not required. The annual report requirement in this section
does not apply to a master meter system, a petroleum gas system that
serves fewer than 100 customers from a single source, or an individual
service line directly connected to a production pipeline or a gathering
line other than a regulated gathering line as determined in Sec.
192.8.

Sec.  191.12   [Removed and Reserved]

0
4. Remove and reserve Sec.  191.12.

0
5. Appendix A to part 191 is added to read as follows:

Appendix A to Part 191--Procedure for Determining Reporting Threshold

I. Property Damage Threshold Formula

    Each year after calendar year 2021, the Administrator will
publish a notice on PHMSA's website announcing the updates to the
property damage threshold criterion that will take effect on July 1
of that year and will remain in effect until the June 30 of the next
year. The property damage threshold used in the definition of an
Incident at Sec.  191.3 shall be determined in accordance with the
following formula:
[GRAPHIC] [TIFF OMITTED] TR11JA21.019

Where:

Tr is the revised damage threshold,
Tp is the previous damage threshold,
CPIr is the average Consumer Price Indices for all Urban Consumers
(CPI-U) published by the Bureau of Labor Statistics each month
during the most recent complete calendar year, and
CPIp is the average CPI-U for the calendar year used to establish
the previous property damage criteria.

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

0
5. The authority citation for 49 CFR part 192 continues to read as
follows:

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

0
6. In Sec.  192.7:
0
a. Revise paragraph (a), paragraph (b) introductory text, and paragraph
(b)(9);
0
b. Remove and reserve paragraph (c)(7); and
0
c. Revise paragraph (e) introductory text and paragraphs (e)(11) and
(20).
    The revisions read as follows:

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

    (a) Certain material is incorporated by reference into this part
with the approval of the Director of the Federal Register under 5
U.S.C. 552(a) and 1 CFR part 51. The materials listed in this section
have the full force of law. All approved material is available for
inspection at Office of Pipeline Safety, Pipeline and Hazardous
Materials Safety Administration, 1200 New Jersey Avenue SE, Washington,
DC 20590,<PHONE_NUMBER> https://www.phmsa.dot.gov/pipeline/regs, and is
available from the sources listed in the remaining paragraphs of this
section. It is also available for inspection at 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) American Petroleum Institute (API), 200 Massachusetts Ave. NW,
Suite 1100, Washington, DC 20001, and phone:<PHONE_NUMBER>, website:
https://www.api.org/.
* * * * *
    (9) API Standard 1104, ``Welding of Pipelines and Related
Facilities,'' 20th edition, October 2005, including errata/addendum
(July 2007) and errata 2 (2008), (API Std 1104), IBR approved for
Sec. Sec.  192.225(a); 192.227(a); 192.229(b) and (c); 192.241(c); and
Item II, Appendix B.
* * * * *
    (e) ASTM International (formerly American Society for Testing and
Materials), 100 Barr Harbor Drive, PO Box C700, West Conshohocken, PA
19428, phone:<PHONE_NUMBER>, website: http://astm.org.
* * * * *
    (11) ASTM D2513-18a, ``Standard Specification for Polyethylene (PE)
Gas Pressure Pipe, Tubing, and Fittings,'' approved August 1, 2018,
(ASTM D2513), IBR approved for Item I, Appendix B to Part 192.
* * * * *
    (20) ASTM F2620-19, ``Standard Practice for Heat Fusion Joining of
Polyethylene Pipe and Fittings,'' approved February 1, 2019, (ASTM

F2620), IBR approved for Sec. Sec.  192.281(c) and 192.285(b).
* * * * *

0
7. In Sec.  192.121:
0
a. In the first sentence of paragraph (a), remove the words ``Design
formula. Design formulas for plastic pipe are'' and add in their place
the words ``Design pressure. The design pressure for plastic pipe is'';
0
b. In paragraph (c)(2) introductory text add the words ``on or'' after
the word ``produced'';
0
c. Revise paragraphs (c)(2)(iii) and (iv), and (d)(2)(iv);
0
d. In paragraph (e) introductory text add the words ``on or'' after the
word ``produced''; and
0
e. Revise paragraph (e)(4).
    The revisions read as follows:

Sec.  192.121   Design of plastic pipe.

* * * * *
    (c) * * *
    (2) * * *
    (iii) The pipe has a nominal size (IPS or CTS) of 24 inches or
less; and
    (iv) The wall thickness for a given outside diameter is not less
than that listed in table 1 to this paragraph (c)(2)(iv).

                     Table 1 to Paragraph (c)(2)(iv)
------------------------------------------------------------------------
             PE pipe: minimum wall thickness and SDR values
-------------------------------------------------------------------------
                                           Minimum wall
           Pipe size  (inches)               thickness     Corresponding
                                             (inches)      SDR  (values)
------------------------------------------------------------------------
\1/2\'' CTS.............................           0.090               7
\1/2\'' IPS.............................           0.090             9.3
\3/4\'' CTS.............................           0.090             9.7
\3/4\'' IPS.............................           0.095              11
1'' CTS.................................           0.099              11
1'' IPS.................................           0.119              11
1 \1/4\'' IPS...........................           0.151              11
1 \1/2\'' IPS...........................           0.173              11
2''.....................................           0.216              11
3''.....................................           0.259            13.5
4''.....................................           0.265              17
6''.....................................           0.315              21
8''.....................................           0.411              21
10''....................................           0.512              21
12''....................................           0.607              21
16''....................................           0.762              21
18''....................................           0.857              21
20''....................................           0.952              21
22''....................................           1.048              21
24''....................................           1.143              21
------------------------------------------------------------------------

    (d) * * *
    (2) * * *
    (iv) The minimum wall thickness for a given outside diameter is not
less than that listed in table 2 to paragraph (d)(2)(iv):

                     Table 2 to Paragraph (d)(2)(iv)
------------------------------------------------------------------------
            PA-11 pipe: minimum wall thickness and SDR values
-------------------------------------------------------------------------
                                           Minimum wall
           Pipe size  (inches)               thickness     Corresponding
                                             (inches)      SDR  (values)
------------------------------------------------------------------------
\1/2\'' CTS.............................           0.090             7.0
\1/2\'' IPS.............................           0.090             9.3
\3/4\'' CTS.............................           0.090             9.7
\3/4\'' IPS.............................           0.095              11
1'' CTS.................................           0.099              11
1'' IPS.................................           0.119              11
1 \1/4\ IPS.............................           0.151              11
1 \1/2\'' IPS...........................           0.173              11
2'' IPS.................................           0.216              11
3'' IPS.................................           0.259            13.5
4'' IPS.................................           0.333            13.5
6'' IPS.................................           0.491            13.5
------------------------------------------------------------------------

    (e) * * *
    (4) The minimum wall thickness for a given outside diameter is not
less than that listed in table 3 to paragraph (e)(4).

                       Table 3 to Paragraph (e)(4)
------------------------------------------------------------------------
            PA-12 pipe: minimum wall thickness and SDR values
-------------------------------------------------------------------------
                                           Minimum wall
           Pipe size  (inches)               thickness     Corresponding
                                             (inches)      SDR  (values)
------------------------------------------------------------------------
\1/2\'' CTS.............................           0.090               7
\1/2\'' IPS.............................           0.090             9.3
\3/4\'' CTS.............................           0.090             9.7
\3/4\'' IPS.............................           0.095              11
1'' CTS.................................           0.099              11
1'' IPS.................................           0.119              11
1 \1/4\'' IPS...........................           0.151              11
1 \1/2\'' IPS...........................           0.173              11
2'' IPS.................................           0.216              11
3'' IPS.................................           0.259            13.5
4'' IPS.................................           0.333            13.5
6'' IPS.................................           0.491            13.5
------------------------------------------------------------------------

* * * * *

0
8. In Sec.  192.153 revise paragraphs (b) and paragraph (e) to read as
follows:

Sec.  192.153   Components fabricated by welding.

* * * * *
    (b) Each prefabricated unit that uses plate and longitudinal seams
must be designed, constructed, and tested in accordance with the ASME
BPVC (Rules for Construction of Pressure Vessels as defined in either
Section VIII, Division 1 or Section VIII, Division 2; incorporated by
reference, see Sec.  192.7), except for the following:
    (1) Regularly manufactured butt-welding fittings.
    (2) Pipe that has been produced and tested under a specification
listed in appendix B to this part.
    (3) Partial assemblies such as split rings or collars.
    (4) Prefabricated units that the manufacturer certifies have been
tested to at least twice the maximum pressure to which they will be
subjected under the anticipated operating conditions.
* * * * *
    (e) The test requirements for a prefabricated unit or pressure
vessel, defined for this paragraph as components with a design pressure
established in accordance with paragraph (a) or paragraph (b) of this
section are as follows.
    (1) A prefabricated unit or pressure vessel installed after July
14, 2004 is not subject to the strength testing requirements at Sec.
192.505(b) provided the component has been tested in accordance with
paragraph (a) or paragraph (b) of this section and with a test factor
of at least 1.3 times MAOP.
    (2) A prefabricated unit or pressure vessel must be tested for a
duration specified as follows:
    (i) A prefabricated unit or pressure vessel installed after July
14, 2004, but before October 1, 2021 is exempt from Sec. Sec.
192.505(c) and (d) and 192.507(c) provided it has been tested for a
duration consistent with the ASME BPVC requirements referenced in
paragraph (a) or (b) of this section.
    (ii) A prefabricated unit or pressure vessel installed on or after
October 1, 2021 must be tested for the duration specified in either
Sec.  192.505(c) or (d), Sec.  192.507(c), or Sec.  192.509(a),
whichever is applicable for the pipeline in which the component is
being installed.
    (3) For any prefabricated unit or pressure vessel permanently or
temporarily installed on a pipeline facility, an operator must either:
    (i) Test the prefabricated unit or pressure vessel in accordance
with this section and Subpart J of this part after it has been placed
on its support structure at its final installation location. The test
may be performed before or after it has been tied-in to the pipeline.
Test records that meet Sec.  192.517(a) must be kept for the
operational life of the prefabricated unit or pressure vessel; or
    (ii) For a prefabricated unit or pressure vessel that is pressure
tested prior to installation or where a manufacturer's pressure test is
used in accordance with paragraph (e) of this section, inspect the
prefabricated unit or pressure vessel after it has been placed on its
support structure at its final installation location and confirm that
the prefabricated unit or pressure vessel was not damaged during any
prior operation, transportation, or installation into the pipeline. The
inspection procedure and documented inspection must include visual
inspection for vessel damage, including, at a minimum, inlets, outlets,
and lifting locations. Injurious defects that are an integrity threat
may include dents, gouges, bending, corrosion, and cracking. This
inspection must be performed prior to operation but may be performed
either before or after it has been tied-in to the pipeline. If
injurious defects that are an integrity threat are found, the
prefabricated unit or pressure vessel must be either non-destructively
tested, re-pressure tested, or remediated in accordance with applicable
part 192 requirements for a fabricated unit or with the applicable ASME
BPVC requirements referenced in paragraphs (a) or (b) of this section.
Test, inspection, and repair records for the fabricated unit or
pressure vessel must be kept for the operational life of the component.
Test records must meet the requirements in Sec.  192.517(a).
    (4) An initial pressure test from the prefabricated unit or
pressure vessel manufacturer may be used to meet the requirements of
this section with the following conditions:
    (i) The prefabricated unit or pressure vessel is newly-manufactured
and installed on or after October 1, 2021, except as provided in
paragraph (e)(4)(ii) of this section.
    (ii) An initial pressure test from the fabricated unit or pressure
vessel manufacturer or other prior test of a new or existing
prefabricated unit or pressure vessel may be used for a component that
is temporarily installed in a pipeline facility in order to complete a
testing, integrity assessment, repair, odorization, or emergency
response-related task, including noise or pollution abatement. The
temporary component must be promptly removed after that task is
completed. If operational and environmental constraints require leaving
a temporary prefabricated unit or pressure vessel under this paragraph
in place for longer than 30 days, the operator must notify PHMSA and
State or local pipeline

safety authorities, as applicable, in accordance with Sec.  192.18.
    (iii) The manufacturer's pressure test must meet the minimum
requirements of this part; and
    (iv) The operator inspects and remediates the prefabricated unit or
pressure vessel after installation in accordance with paragraph
(e)(3)(ii) of this section.
    (5) An existing prefabricated unit or pressure vessel that is
temporarily removed from a pipeline facility to complete a testing,
integrity assessment, repair, odorization, or emergency response-
related task, including noise or pollution abatement, and then re-
installed at the same location must be inspected in accordance with
paragraph (e)(3)(ii) of this section; however, a new pressure test is
not required provided no damage or threats to the operational integrity
of the prefabricated unit or pressure vessel were identified during the
inspection and the MAOP of the pipeline is not increased.
    (6) Except as provided in paragraphs (e)(4)(ii) and (5) of this
section, on or after October 1, 2021, an existing prefabricated unit or
pressure vessel relocated and operated at a different location must
meet the requirements of this part and the following:
    (i) The prefabricated unit or pressure vessel must be designed and
constructed in accordance with the requirements of this part at the
time the vessel is returned to operational service at the new location;
and
    (ii) The prefabricated unit or pressure vessel must be pressure
tested by the operator in accordance with the testing and inspection
requirements of this part applicable to newly installed prefabricated
units and pressure vessels.

0
9. In Sec.  192.229, revise paragraph (b) to read as follows:

Sec.  192.229   Limitations on welders and welding operators.

* * * * *
    (b) A welder or welding operator may not weld with a particular
welding process unless, within the preceding 6 calendar months, the
welder or welding operator was engaged in welding with that process.
Alternatively, welders or welding operators may demonstrate they have
engaged in a specific welding process if they have performed a weld
with that process that was tested and found acceptable under section 6,
9, 12, or Appendix A of API Std 1104 (incorporated by reference, see
Sec.  192.7) within the preceding 7\1/2\ months.
* * * * *

0
10. In Sec.  192.281, revise paragraph (c) to read as follow:

Sec.  192.281   Plastic Pipe.

* * * * *
    (c) Heat-fusion joints. Each heat fusion joint on a PE pipe or
component, except for electrofusion joints, must comply with ASTM F2620
(incorporated by reference in Sec.  192.7), or an alternative written
procedure that has been demonstrated to provide an equivalent or
superior level of safety and has been proven by test or experience to
produce strong gastight joints, and the following:
* * * * *

0
11. In Sec.  192.283 revise paragraph (a)(3) to read as follows:

Sec.  192.283   Plastic pipe: Qualifying joining procedures.

    (a) * * *
    (3) For procedures intended for non-lateral pipe connections,
perform tensile testing in accordance with a listed specification. If
the test specimen elongates no less than 25% or failure initiates
outside the joint area, the procedure qualifies for use.
* * * * *

0
12. In Sec.  192.285, revise paragraph (b) to read as follows

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

* * * * *
    (b) The specimen joint must be:
    (1) Visually examined during and after assembly or joining and
found to have the same appearance as a joint or photographs of a joint
that is acceptable under the procedure; and
    (2) In the case of a heat fusion, solvent cement, or adhesive
joint:
    (i) Tested under any one of the test methods listed under Sec.
192.283(a), and for PE heat fusion joints (except for electrofusion
joints) visually inspected in accordance with ASTM F2620 (incorporated
by reference, see Sec.  192.7), or a written procedure that has been
demonstrated to provide an equivalent or superior level of safety,
applicable to the type of joint and material being tested;
    (ii) Examined by ultrasonic inspection and found not to contain
flaws that would cause failure; or
    (iii) Cut into at least 3 longitudinal straps, each of which is:
    (A) Visually examined and found not to contain voids or
discontinuities on the cut surfaces of the joint area; and
    (B) Deformed by bending, torque, or impact, and if failure occurs,
it must not initiate in the joint area.
* * * * *

0
13. In Sec.  192.465, revise paragraph (b) to read as follows:

Sec.  192.465   External corrosion control: Monitoring.

* * * * *
    (b) Cathodic protection rectifiers and impressed current power
sources must be periodically inspected as follows:
    (1) Each cathodic protection rectifier or impressed current power
source must be inspected six times each calendar year, but with
intervals not exceeding 2\1/2\ months between inspections, to ensure
adequate amperage and voltage levels needed to provide cathodic
protection are maintained. This may be done either through remote
measurement or through an onsite inspection of the rectifier.
    (2) After January 1, 2022, each remotely inspected rectifier must
be physically inspected for continued safe and reliable operation at
least once each calendar year, but with intervals not exceeding 15
months.
* * * * *

0
14. In Sec.  192.481, revise paragraph (a) and add paragraph (d) to
read as follows:

Sec.  192.481   Atmospheric corrosion control: Monitoring.

    (a) Each operator must inspect and evaluate each pipeline or
portion of the pipeline that is exposed to the atmosphere for evidence
of atmospheric corrosion, as follows:

------------------------------------------------------------------------
                                              Then the frequency of
             Pipeline type:                       inspection is:
------------------------------------------------------------------------
(1) Onshore other than a Service Line..  At least once every 3 calendar
                                          years, but with intervals not
                                          exceeding 39 months.
(2) Onshore Service Line...............  At least once every 5 calendar
                                          years, but with intervals not
                                          exceeding 63 months, except as
                                          provided in paragraph (d) of
                                          this section.
(3) Offshore...........................  At least once each calendar
                                          year, but with intervals not
                                          exceeding 15 months.
------------------------------------------------------------------------

* * * * *
    (d) If atmospheric corrosion is found on a service line during the
most recent inspection, then the next inspection of that pipeline or
portion of pipeline must be within 3 calendar years, but with intervals
not exceeding 39 months.

0
15. In 192.491, revise paragraph (c) to read as follows:

Sec.  192.491   Corrosion control records.

* * * * *
    (c) Each operator shall maintain a record of each test, survey, or
inspection required by this subpart in sufficient detail to demonstrate
the adequacy of corrosion control measures or that a corrosive
condition does not exist. These records must be retained for at least 5
years with the following exceptions:
    (1) Operators must retain records related to Sec. Sec.  192.465(a)
and (e) and 192.475(b) for as long as the pipeline remains in service.
    (2) Operators must retain records of the two most recent
atmospheric corrosion inspections for each distribution service line
that is being inspected under the interval in Sec.  192.481(a)(2).

0
16. In Sec.  192.505, revise paragraph (c) to read as follows

Sec.  192.505   Strength test requirements for steel pipelines to
operate at a hoop stress of 30 percent or more of SMYS.

* * * * *
    (c) Except as provided in paragraph (d) of this section, the
strength test must be conducted by mai ntaining the pressure at or
above the test pressure for at least 8 hours.
* * * * *

0
17. In Sec.  192.507, add paragraph (d) to read as follows:

Sec.  192.507   Test requirements for pipelines to operate at a hoop
stress less than 30 percent of SMYS and at or above 100 p.s.i. (689
kPa) gage.

* * * * *
    (d) For fabricated units and short sections of pipe, for which a
post installation test is impractical, a pre-installation hydrostatic
pressure test must be conducted in accordance with the requirements of
this section.

0
18. In Sec.  192.619, revise Table 1 to paragraph (a)(2)(ii) to read as
follows:

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

* * * * *
    (a) * * *
    (2) * * *
    (ii) * * *

                                         Table 1 to Paragraph (a)(2)(ii)
----------------------------------------------------------------------------------------------------------------
                                                                            Factors,1 2 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.
\2\ For a component with a design pressure established in accordance with Sec.   192.153(a) or (b) installed
  after July 14, 2004, the factor is 1.3.

0
19. In Sec.  192.740, revise the section heading, paragraph (a) and
paragraph (c) to read as follows:

Sec.  192.740   Pressure regulating, limiting, and overpressure
protection--Individual service lines directly connected to regulated
gathering or transmission pipelines.

    (a) This section applies, except as provided in paragraph (c) of
this section, to any service line directly connected to a transmission
pipeline or regulated gathering pipeline as determined in Sec.  192.8
that is not operated as part of a distribution system.
* * * * *
    (c) This section does not apply to equipment installed on:
    (1) A service line that only serves engines that power irrigation
pumps;
    (2) A service line included in a distribution integrity management
plan meeting the requirements of subpart P of this part; or
    (3) A service line directly connected to either a production or
gathering pipeline other than a regulated gathering line as determined
in Sec.  192.8 of this part.

0
20. Revise Sec.  192.1003 to read as follows:

Sec.  192.1003   What do the regulations in this subpart cover?

    (a) General. Unless exempted in paragraph (b) of this section, this
subpart prescribes minimum requirements for an IM program for any gas
distribution pipeline covered under this part, including liquefied
petroleum gas systems. A gas distribution operator must follow the
requirements in this subpart.
    (b) Exceptions. This subpart does not apply to:
    (1) Individual service lines directly connected to a production
line or a gathering line other than a regulated onshore gathering line
as determined in Sec.  192.8;
    (2) Individual service lines directly connected to either a
transmission or regulated gathering pipeline and maintained in
accordance with Sec.  192.740(a) and (b); and
    (3) Master meter systems.

0
21. In Sec.  192.1005, revise the section heading to read as follows:

Sec.  192.1005   What must a gas distribution operator (other than a
small LPG operator) do to implement this subpart?

* * * * *

0
22. In Sec.  192.1007, revise paragraph (b) to read as follows:

Sec.  192.1007   What are the required elements of an integrity
management plan?

* * * * *
    (b) Identify threats. The operator must consider the following
categories of threats to each gas distribution pipeline: Corrosion
(including atmospheric corrosion), natural forces, excavation damage,
other outside force damage, material or welds, equipment failure,
incorrect operations, and other issues that could threaten the
integrity of its pipeline. An operator must consider reasonably
available information to identify existing and potential threats.

Sources of data may include incident and leak history, corrosion
control records (including atmospheric corrosion records), continuing
surveillance records, patrolling records, maintenance history, and
excavation damage experience.
* * * * *

Sec.  192.1009   [Removed and Reserved]

0
23. Remove and reserve Sec.  192.1009.

0
24. In Sec.  192.1015, revise the section heading, and paragraphs (a)
and (b) to read as follows:

Sec.  192.1015   What must a small LPG operator do to implement this
subpart?

    (a) General. No later than August 2, 2011, a small LPG operator
must develop and implement an IM program that includes a written IM
plan as specified in paragraph (b) of this section. The IM program for
these pipelines should reflect the relative simplicity of these types
of pipelines.
    (b) Elements. A written integrity management plan must address, at
a minimum, the following elements:
    (1) Knowledge. The operator must demonstrate knowledge of its
pipeline, which, to the extent known, should include the approximate
location and material of its pipeline. The operator must identify
additional information needed and provide a plan for gaining knowledge
over time through normal activities conducted on the pipeline (for
example, design, construction, operations or maintenance activities).
    (2) Identify threats. The operator must consider, at minimum, the
following categories of threats (existing and potential): Corrosion
(including atmospheric corrosion), natural forces, excavation damage,
other outside force damage, material or weld failure, equipment
failure, and incorrect operation.
    (3) Rank risks. The operator must evaluate the risks to its
pipeline and estimate the relative importance of each identified
threat.
    (4) Identify and implement measures to mitigate risks. The operator
must determine and implement measures designed to reduce the risks from
failure of its pipeline.
    (5) Measure performance, monitor results, and evaluate
effectiveness. The operator must monitor, as a performance measure, the
number of leaks eliminated or repaired on its pipeline and their
causes.
    (6) Periodic evaluation and improvement. The operator must
determine the appropriate period for conducting IM program evaluations
based on the complexity of its pipeline and changes in factors
affecting the risk of failure. An operator must re-evaluate its entire
program at least every 5 years. The operator must consider the results
of the performance monitoring in these evaluations.
* * * * *

Appendix B to Part 192 [Amended]

0
25. Amend Appendix B to part 192 as follows:
0
a. In section I.A., remove the entry for ``ASTM D2513-12ae1'' and add
in its place a new entry for ``ASTM D2513'', and
0
b. In Section I.B., remove the entry for ``ASTM D2513-12ae1'' and add
in its place a new entry for ``ASTM D2513''.

    Issued in Washington, DC, on January 1, 2021, under authority
delegated in 49 CFR 1.97.
Howard R. Elliott,
Administrator.
[FR Doc. 2021-00208 Filed 1-8-21; 8:45 am]
BILLING CODE 4910-60-P