[Federal Register Volume 91, Number 9 (Wednesday, January 14, 2026)]
[Rules and Regulations]
[Pages 1608-1655]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2026-00566]
[[Page 1607]]
Vol. 91
Wednesday,
No. 9
January 14, 2026
Part II
Department of Transportation
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Pipeline and Hazardous Materials Safety Administration
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49 CFR Part 192
Pipeline Safety: Class Location Change Requirements; Final Rule
Federal Register / Vol. 91, No. 9 / Wednesday, January 14, 2026 /
Rules and Regulations
[[Page 1608]]
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DEPARTMENT OF TRANSPORTATION
Pipeline and Hazardous Materials Safety Administration
49 CFR Part 192
[Docket No. PHMSA-2017-0151; Amdt. No. 192-155]
RIN 2137-AF29
Pipeline Safety: Class Location Change Requirements
AGENCY: Pipeline and Hazardous Materials Safety Administration (PHMSA),
Department of Transportation (DOT).
ACTION: Final rule.
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SUMMARY: PHMSA is updating its regulations to allow operators to apply
modern risk management principles in addressing the safety of gas
pipelines affected by class location changes. Relying on an approach
originally developed in the 1950s, PHMSA's regulations use class
locations to provide an additional margin of safety in the design,
construction, testing, operation, and maintenance of gas pipelines
based on population density. When the class location of a pipeline
changes due to an increase in population density, an operator may need
to take certain actions to confirm or to revise the maximum allowable
operating pressure of a segment. Because the methods traditionally used
for that purpose do not account for modern risk management principles,
PHMSA has granted special permits for more than two decades allowing
operators to use an integrity-management-based alternative. This final
rule adopts that `IM alternative' by regulation to provide operators
with an additional method for confirming or restoring the maximum
allowable operating pressure of certain eligible segments that
experience class location changes.
DATES: This rule is effective March 16, 2026. The incorporation by
reference of certain material listed in this rule is approved by the
Director of the Federal Register as of March 16, 2026. Comment related
to the information collection may be submitted by March 16, 2026, as
detailed in Section VII.H.
FOR FURTHER INFORMATION CONTACT: Robert Jagger, Senior Transportation
Specialist, at 202-557-6765 or [email protected].
SUPPLEMENTARY INFORMATION:
I. Executive Summary
A. Purpose of the Regulatory Action
B. Summary of the Major Regulatory Provisions
C. Costs and Benefits
II. Background
A. Overview of Class Location Requirements
B. Origin of Class Location Requirements
C. Integrity Management Program Requirements
D. Class Location Special Permits
III. Summary of the NPRM
IV. Discussion of the Final Rule and Analysis of Comments
A. General
B. Definitions
C. Eligibility Criteria
i. General
ii. Original Class
iii. SMYS Limitations
iv. Subpart J Pressure Test
v. TVC Material Records
vi. Grandfathered or Alternative MAOP
vii. Wrinkle Bends and Geohazards
viii. Vintage Seam Types
ix. Pipe Coating for Cathodic Protection
x. Cracking
xi. Class Location Change Date--Special Permits
xii. Class Location Change Date--Prior Pressure Reductions
xiii. Previously Denied Special Permits
D. IM Program Requirements
i. Subpart O Incorporation
ii. Assessment Methods
iii. ILI Validation
iv. Baseline Assessment
v. Remediation Schedule
E. Additional Programmatic Requirements--One-Time and Recurring
Obligations
i. General Programmatic Requirements
ii. Clear Shorted Casings
iii. Valve Requirements
iv. Notification Upon Use of the Program
v. Class Location Study
F. Adjustments to Class Locations Through Clustering
V. Section-by-Section Analysis
VI. Statutory Authority
VII. Regulatory Analysis and Notices
VIII. Regulatory Text
I. Executive Summary
A. Purpose of the Regulatory Action
The idea of using ``class locations'' to provide an additional,
population-density-based margin of safety in the design, construction,
and testing of gas pipelines dates to the second edition of the
American Standard Code for Pressure Piping, Section 8, Gas Transmission
and Distribution Piping Systems, ASA B31.1.8-1955.\1\ Published in
1955, B31.1.8-1955 directed operators to use one-mile and 10-mile
population density indices to determine the appropriate class location
of a pipeline at the time of construction. B31.1.8-1955 recognized four
different class locations, ranging from Class 1 for areas with the
lowest population density to Class 4 for areas with the highest
population density.
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\1\ Am. Soc. of Mech. Eng'rs (ASME), American Standard Code for
Pressure Piping, Section 8, ASA B31.1.8-1955, Gas Transmission and
Distribution Piping Systems (1955).
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B31.1.8-1955 also included provisions for operators to follow in
determining the maximum allowable operating pressure (MAOP) of a
pipeline. B31.1.8-1955 directed operators to select the lowest of three
pressures in determining MAOP: (1) the design pressure, (2) the test
pressure, and (3) the maximum safe operating pressure of the pipeline
based on the information known about the strength and operating
history. To provide an additional margin of safety, B31.1.8-1955
accounted for the class location of a pipeline in providing operators
with more conservative design and test pressure factors to use in
determining MAOP.\2\
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\2\ ASME retained these provisions in the ensuing editions of
that standard, which became known as the B31.8. ASME, American
Standard Code for Pressure Piping, Section 8, ASA B31.8-1958, Gas
Transmission and Distribution Piping Systems (1959); ASME, American
Standard Code for Pressure Piping, Section 8, ASA B31.8-1963, Gas
Transmission and Distribution Piping Systems (1963); ASME, USA
Standard Code for Pressure Piping, USAS B31.8-1967, Gas Transmission
and Distribution Piping Systems (1967); ASME, USA Standard Code for
Pressure Piping, USAS B31.8-1968, Gas Transmission and Distribution
Piping Systems (1968).
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The 1968 edition of the B31.8 added a new provision for addressing
class location changes. The provision directed operators to conduct a
study if an increase in the population density indicated that the class
location of a pipeline had changed since the original installation.
And, depending on the results of that study, the provision directed
operators to confirm or to revise the MAOP of the pipeline, either by
relying on a prior pressure test, by reducing the MAOP, or by
conducting a new pressure test. Operators could also maintain the
current MAOP by replacing the pipe in the affected segment.
Adopted by PHMSA \3\ in 1970, the original version of the Federal
Gas Pipeline Safety Regulations incorporated the B31.8's class location
concept, albeit with certain modifications.\4\ Rather than using
population density indices, the 1970 final rule required operators to
determine the class location of a pipeline based on the number of
buildings intended for human occupancy in a ``class location unit,''
defined as an area extending 220 yards on either side of the centerline
of any
[[Page 1609]]
continuous one-mile length of pipeline. The final rule also required
operators to follow more stringent operation and maintenance (O&M)
requirements as the class location increased in value.
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\3\ For ease of reference, PHMSA and its predecessor agencies at
the U.S. Department of Transportation that have regulated pipeline
safety are referred to as PHMSA throughout this document.
\4\ Establishment of Minimum Standards, 35 FR 13248 (Aug. 19,
1970) (Minimum Standards).
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Of particular significance here, the 1970 final rule required
operators to consider class location in establishing the MAOP of a
pipeline segment as well. Like the B31.8, the final rule required
operators to consider the design pressure, test pressure, and maximum
safe operating pressure of a pipeline in determining MAOP, along with
the highest actual operating pressure experienced during the preceding
five years for existing lines. To provide an additional margin of
safety based on population density, the final rule also accounted for
the class location of a pipeline in the design and test pressure
factors that operators had to use in determining MAOP.
Finally, as in the B31.8, the 1970 final rule included requirements
for addressing class location changes. The final rule required
operators to conduct a study and, if necessary, to confirm or to revise
the MAOP of a segment, either by relying on the results of a prior
pressure test, by reducing the MAOP, or by conducting a new pressure
test. An operator could also maintain the current MAOP by replacing the
pipe in the affected segment.
After adopting the integrity management (IM) program for gas
transmission lines in the early 2000s, PHMSA established a new policy
for granting special permits (or waivers) of the requirements for
addressing class location changes.\5\ PHMSA adopted that policy on the
grounds that IM principles could be used to manage effectively the
integrity of class change segments, provided operators complied with a
series of additional terms, conditions, and limitations. PHMSA has
granted special permits to more than 45 operators in the two decades
since issuing that policy, and no pipeline segment subject to a class
location special permit has ever experienced a failure.
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\5\ Pipeline Safety: Development of Class Location Change Waiver
Criteria, 69 FR 38948 (June 29, 2004).
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In this final rule, PHMSA is adopting an IM alternative as an
additional option for addressing class location changes on gas
transmission lines. Modeled on the successful class location special
permit program, operators can use the IM alternative to confirm the
MAOP of eligible Class 3 segments by complying with a comprehensive set
of initial and recurring programmatic requirements. Operators can also
use the IM alternative to restore the previously established MAOP of
eligible Class 3 segments by complying with certain additional
requirements. PHMSA concludes that the benefits and cost-savings of
allowing operators to use the IM alternative justify their costs. PHMSA
therefore adopts the IM alternative in this final rule.
B. Summary of the Major Regulatory Provisions
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Subject Final rule
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Applicability..................... Section 192.611(a)(4) authorizes an
IM alternative for managing class
location changes that affect
certain eligible gas transmission
line segments in Class 3 locations.
Eligibility....................... Section 192.3 defines the eligible
Class 3 segments that may use the
IM alternative. That definition
excludes segments that (1) contain
bare pipe; (2) contain wrinkle
bends; (3) have a longitudinal seam
formed by lap welding or another
method with a joint factor below
1.0; or (4) have experienced an in-
service leak or rupture due to
cracking on the segment or a pipe
with similar characteristics within
5 miles.
A segment that experiences an in-
service rupture or leak from the
pipe body cannot continue using the
IM alternative.
Subpart O Compliance.............. An eligible Class 3 segment applying
the IM alternative must be
designated as a high consequence
area and comply with the
requirements in Subpart O.
Initial Programmatic Requirements. An operator must comply with certain
initial programmatic requirements
within 24 months to use the IM
alternative. Those requirements
address: (1) integrity assessments
and remediation, (2) pressure
testing, (3) material records
verification, (4) rupture
mitigation valves, (5) cathodic
protection and coating, and (6)
depth of cover. An operator must
also provide a notification to
PHMSA.
Recurring Programmatic An operator must comply with certain
Requirements. recurring programmatic requirements
to use the IM alternative. Those
requirements address: (1) gas
quality, (2) close interval
surveys, (3) patrolling, (4) leak
surveys, (5) line markers, (6)
class location studies, (7) shorted
casings, and (8) exposed pipe and
weld surface examinations.
Other Requirements................ MAOP of a segment using the IM
alternative may not exceed a hoop
stress corresponding to 72 percent
of specified minimum yield
strength.
An operator of an eligible Class 3
segment may use the IM alternative
to restore a previously established
MAOP after complying with certain
uprating and initial programmatic
requirements.
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C. Costs and Benefits
This final rule is expected to produce substantial cost-savings of
$461 million annually, after accounting for the expected $61.5 million
cost for operators to implement the IM alternative on segments that
experience class location changes in a given year (both discounted at
7%). The final rule is also expected to avoid an estimated 1.3 billion
cubic feet of gas losses per year from pipeline replacements. Other
non-quantified benefits include reducing service disruptions and
increasing regulatory certainty and flexibility. The Regulatory Impact
Analysis (RIA) provided in the docket for this rulemaking includes
additional information about the costs, benefits, and other impacts of
the final rule.
II. Background
A. Overview of Class Location Requirements
Class locations use population density to provide an additional
margin of safety for gas pipelines. Four class locations are used for
that purpose, with Class 1 representing the areas with the least
population density, Class 4 representing the areas with the highest
population density, and Class 2 and Class 3 representing areas of
[[Page 1610]]
intermediate population density. To account for the additional risk to
public safety, more stringent safety standards apply as the class
location of a gas pipeline increases in value.
That principle, which is commonly referred to as a safety factor,
is reflected in the first instance in determining the design pressure
of a pipeline. Design pressure is calculated using a modified version
of Barlow's formula, the results of which specify the maximum internal
pressure piping can withstand before failure. A class-location-based
design factor is incorporated into that formula to provide more
margin--i.e., a lower safety factor--as population density
increases.\6\ A similar concept applies in determining the test
pressure of a pipeline.\7\ Design and test pressure are two of the
factors that limit MAOP, which is the highest pressure that a pipeline
is permitted to operate at while in service.\8\
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\6\ See 49 CFR 192.105. See also ASME, Code for Pressure Piping,
B31.8, Gas Transmission and Distribution Piping Systems, Sec.
805.2.3 (2018). This equation in full is: Design pressure =
((2*Yield Strength*wall thickness)/outside diameter) * class design
factor * longitudinal joint factor * temperature factor.
\7\ 49 CFR 192.619(a) (test requirements for establishing MAOP
at time of installation, incorporating a class-location-based test
factor which lowers MAOP as the class location increases).
\8\ See 49 CFR 192.3 (defining MAOP), 192.619 (prescribing
requirements for determining MAOP).
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Because Barlow's formula captures the relationship between maximum
pressure, stress (i.e., specified minimum yield strength (SMYS)), wall
thickness, and diameter with the class safety factor, an increase in
any one input will increase the other inputs.\9\ In practical terms,
this means that pipe with additional strength or wall thickness must be
installed to maintain the same design pressure in higher class
locations. That is because, as Figure 1 shows, a higher class location
will lead to a lower MAOP if the other variables used in the formula
remain constant.
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\9\ See, e.g., Reid T. Stewart, Strength of Steel Tubes, Pipes,
and Cylinders under Internal Fluid Pressure, 34 J. Fluids Eng'g 312,
312-18 (1912); Barlow's Formula, Am. Piping Prods., https://amerpipe.com/reference/charts-calculators/barlows-formula/ (last
accessed June 18, 2025).
[GRAPHIC] [TIFF OMITTED] TR14JA26.015
This phenomenon governs in applying Barlow's formula both at the
time of installation and if the class location of a gas pipeline
changes at a later point in time due to an increase in population
density.\10\
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\10\ See, e.g., Confirmation or Revision of Maximum Allowable
Operating Pressure; Alternative Method, 54 FR 24173, 24173-74 (June
6, 1989) (``Section 192.611 requires that, when the class location
(population density) of a pipeline segment increases, the maximum
allowable operating pressure (MAOP) must be confirmed or revised to
be compatible with the existing class location.'').
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Operators currently have three options for confirming or revising
MAOP in response to class location changes. First, an operator may
reduce the MAOP to reflect the design and test pressure factor
applicable to the current class location. Second, an operator may
confirm the MAOP through pressure testing, either based on the results
of a previous test or by conducting a new test. Third, an operator may
replace the pipeline with material of additional strength or wall
thickness to maintain the current MAOP.
Each of these methods has drawbacks, particularly if a segment
remains in satisfactory condition and can be safely operated at the
current MAOP. Pipeline replacements cause construction-related impacts
and can lead to service disruptions and natural gas emissions. Pressure
testing requires a pipeline to be taken out of service--albeit for a
shorter time--and results in similar service disruptions and natural
gas emissions. MAOP reductions can affect all aspects of the supply
chain, leading to service interruptions and higher costs for consumers.
These drawbacks can be avoided if operators are allowed to use
modern risk management principles to confirm or restore the MAOP of
class change segments. This final rule achieves that objective by
adopting an IM alternative that operators can implement without
resorting to unnecessary MAOP reductions, pressure testing, or pipeline
replacements.
B. Origin of Class Location Requirements
In 1952, the American Society of Mechanical Engineers (ASME)
released the American Standard Code for Gas Transmission and
Distribution Piping Systems (B31.1.8-1952), the first industry safety
standard specifically dedicated to gas transmission and distribution
pipelines. In 1955, the second edition of that standard, B31.1.8-1955,
introduced a new concept--using class locations to provide an
additional margin of safety in the design, installation, and testing of
[[Page 1611]]
gas transmission and distribution pipelines.\11\
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\11\ Michael Rosenfeld & Rick Gailing, Pressure Testing and
Recordkeeping: Reconciling Historic Pipeline Practices with New
Requirements, at 2-3, 8-9 (Feb. 2013), available at: https://www.applus.com/dam/Energy-and-Industry/GLOBAL/userfiles/file/Pressure-Testing-and-Recordkeeping-Reconciling-Historic-Pipeline-Practic.pdf.
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B31.1.8-1955 directed operators to use two population density
indices to classify the initial location of gas transmission and
distribution lines at the time of construction.\12\ The first
population density index, applicable to one-mile lengths of the
pipeline, required operators to count the number of buildings intended
for human occupancy within a half-mile-wide zone that ran along those
lengths. The second population density index, applicable to 10-mile
lengths of the pipeline, directed operators to add the one-mile lengths
together into 10-mile sections and divide the sum by 10.
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\12\ ASA B31.1.8-1955, Sec. 841.001(a)-(c).
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B31.1.8-1955 provided four class locations that could be assigned
based on the results of the one-mile and 10-mile population density
indices. The least populated areas, known as Class 1 locations,
included ``waste lands, deserts, rugged mountains, grazing land, and
farm land'' with a 10-mile population density index of 12 or less and a
one-mile population density index of 20 or less. Class 2 locations
included ``areas where the degree of development [was] intermediate,''
such as ``[f]ringe areas around cities and towns, and farm or
industrial areas,'' with a 10-mile index of 12 or more and a one-mile
index of 20 or more. Class 3 locations included ``areas subdivided for
residential or commercial purposes where, at the time of construction
of the pipeline or piping system, 10 percent or more of the lots
abutting on the street or right-of-way in which the pipe is to be
located are built upon.'' Class 4 locations included ``areas where
multistory buildings'' with four or more floors aboveground were
``prevalent, and where traffic [was] heavy or dense and where there may
be numerous other utilities underground.'' \13\
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\13\ ASA B31.1.8-1955, Sec. Sec. 841.011, 841.012, 841.013,
841.014. For ease of reading and public accessibility, in this
document a string of cited material may be cited by a footnote in
the final sentence of the paragraph addressing all material from
that source.
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To account for the additional risk to public safety, B31.1.8-1955
directed operators to consider the class location at the time of
construction in determining the design pressure of the pipeline.
Operators had to use a prescribed formula in making design pressure
determinations, and that formula accounted for the SMYS, nominal
outside diameter, nominal wall thickness, construction type design
factor, longitudinal joint factor, and temperature derating factor for
the pipe.\14\ The construction type design factors used in the design
pressure formula--0.72, 0.60, 0.50, and 0.40--were inversely
proportional to the class location, which had the effect of lowering
the MAOP of the pipeline as the population density increased. B31.1.8-
1955 also directed operators to consider class location in testing the
pipeline at the time of installation, generally requiring a
progressively higher minimum test pressure to be achieved as the
population density increased.\15\ ASME retained these provisions in
subsequently published editions of that standard, which became known as
B31.8.\16\
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\14\ ASA B31.1.8-1955, Sec. 841.1, tbl. 841.11.
\15\ ASA B31.1.8-1955, tbl. 841.412(d).
\16\ E.g., ASA B31.8-1958; ASA B31.8-1963; USAS B31.8-1967.
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In 1968, ASME published an updated edition of the B31.8 that
contained a new provision for addressing class location changes. The
provision directed operators to conduct a study if an increase in the
population density indicated that the class location of a pipeline had
changed since the original installation. Depending on the results of
that study, the provision directed operators to confirm or to revise
the MAOP of the pipeline, either by relying on a prior pressure test,
by reducing the MAOP, or by conducting a new pressure test. An operator
could also maintain the current MAOP by replacing the pipe in the
affected segment to provide the necessary design and test pressure.\17\
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\17\ USAS B31.8-1968, Sec. 850.4.
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In 1970, PHMSA incorporated the class location concept in adopting
the original version of the Federal Gas Pipeline Safety Regulations in
part 192.\18\ But instead of requiring operators to use the one-mile
and 10-mile population density indices as in B31.8, PHMSA required
operators to count the number of buildings intended for human occupancy
in a ``class location unit,'' defined as an area extending 220 yards on
either side of the centerline of any continuous one-mile length of
pipeline.\19\ In other words, PHMSA narrowed the width of the zone to
be considered in making class location determinations and replaced the
one-mile and 10-mile population density indices with a continuous, or
sliding, mile approach.
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\18\ See Minimum Standards, 35 FR 13248. See also Natural Gas
Pipeline Safety Act of 1968, Pub. L. 90-481, 82 Stat. 720 (Aug. 12,
1968) (authorizing PHMSA to prescribe and enforce minimum Federal
safety standards for gas pipeline facilities and persons engaged in
the transportation of gas). PHMSA discussed the full history of
class locations in the notice of proposed rulemaking, 85 FR 65142,
65145-52 (proposed Oct. 14, 2020) (NPRM).
\19\ Minimum Standards, 35 FR at 13251, 13258.
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PHMSA also used different criteria in defining the four class
locations that could be assigned to each class location unit. PHMSA
defined a Class 1 location as any class location unit that has ``10 or
less buildings intended for human occupancy,'' and a Class 2 location
as any class location unit that has ``more than 10 but less than 46
buildings intended for human occupancy.'' PHMSA defined a Class 3
location as any class location unit that has ``46 or more buildings
intended for human occupancy,'' as well as an area where the pipeline
lies within 100 yards of a ``building that is occupied by 20 or more
persons during normal use'' or a ``small, well-defined outside area
that is occupied by 20 or more persons during normal use, such as a
playground, recreation area, outdoor theater, or other place of public
assembly.'' PHMSA defined a Class 4 location as any class location unit
``where buildings with four or more stories above ground are
prevalent.'' \20\
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\20\ Minimum Standards, 35 FR at 13259 (codifying Sec. 192.5).
For additional information about the treatment of Class 3 locations,
see PHMSA, PI-81-001, Letter of Interpretation (Jan. 13, 1981),
available at: https://www.phmsa.dot.gov/regulations/title49/interp/pi-81-001.
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Like B31.8, PHMSA required operators to follow more stringent
construction and initial testing practices as the class location
increased. The design and test pressure factors used in determining the
MAOP of a pipeline had the same inversely proportional relationship to
the class location, resulting in a lower MAOP for segments in more
populated areas. PHMSA also went beyond B31.8 in requiring operators to
consider class location in determining O&M requirements that applied
after a pipeline went into service. As a result, class locations played
a much greater role in determining the standards applicable to a
pipeline under part 192 than had been the case under the comparable
provisions in B31.8.
Of particular significance here, PHMSA included requirements in the
1970 regulations for confirming or revising the MAOP of a segment that
experienced a change in class location after installation. Operators
had to perform a study ``[w]henever an increase in population density
indicates a change in class location for a segment of an existing steel
pipeline operating at hoop stress that is more than 40 percent
[[Page 1612]]
of SMYS, or indicates that the hoop stress corresponding to the
established maximum allowable operating pressure for a segment of
existing pipeline is not commensurate with the present class
location.'' \21\ After completing that study, operators had to take
certain actions to confirm or to revise the MAOP of the segment to
align with the new class location. Those actions included reducing the
MAOP, relying on a previous pressure test, conducting a new pressure
test, or replacing the pipe.\22\ In addition, to ensure that pipelines
installed prior to the adoption of the part 192 regulations had an MAOP
commensurate with the current location, PHMSA required operators to
complete an initial study and, if necessary, to take action to confirm
or to revise the MAOP of existing segments by certain deadlines.\23\
The framework established in the original part 192 regulations for
addressing class location changes has remained largely unchanged.\24\
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\21\ Minimum Standards, 35 FR at 13272 (codifying Sec.
192.609).
\22\ PHMSA originally required these actions to be completed
within one year of the date of the class location change, but
subsequently extended that deadline to two years. See Extension of
Time for Confirmation or Revision of Maximum Allowable Operating
Pressure, 36 FR 18194 (Sept. 10, 1971) (extending period to 18
months); Pipeline Safety: Periodic Updates to Pipeline Safety
Regulations (2001), 69 FR 32886, 32890 (June 14, 2004) (extending
period to 2 years).
\23\ Minimum Standards, 35 FR at 13272 (codifying original
version of Sec. 192.607); Regulatory Review; Gas Pipeline Safety
Standards, 61 FR 28770, 28785 (June 6, 1996) (repealing original
version Sec. 192.607 as obsolete).
\24\ Slight modification extended the time to complete MAOP
confirmation to two years, see supra note 23, repealing the class
location study for pre-part 192 pipelines when that had completed,
see supra note 24, and the specific test pressure, see Confirmation
or Revision of Maximum Allowable Operating Pressure; Alternative
Method, 54 FR 24173 (June 6, 1989) (allowing the MAOP to be
confirmed or revised based on a past pressure test, with test
pressure tied to class location, rather than requiring a test
pressure to at least 90 percent SMYS).
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C. Integrity Management Program Requirements
In 2003, PHMSA issued a final rule establishing new IM program
requirements for gas transmission lines (2003 Gas IM Rule). The 2003
Gas IM Rule required operators to apply modern risk management
principles to ensure the integrity of pipeline segments located in high
consequence areas (HCAs), i.e., areas where an incident could cause
more harm to people and property, such as Class 3 and Class 4
locations, areas containing facilities that house individuals who are
confined, mobility impaired, or hard to evacuate, or places where
people gather for recreational or other purposes.\25\ The ability to
use inline inspection (ILI) tools to conduct integrity assessments of
covered segments was a core feature of the 2003 Gas IM Rule.
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\25\ Pipeline Safety: Pipeline Integrity Management in High
Consequence Areas, 68 FR 69778 (Dec. 15, 2003) (2003 Gas IM Rule);
see Pipeline Safety Improvement Act of 2002, 49 U.S.C. 60109.
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By way of background, the use of ILI tools as an internal
inspection technology for pipelines dates to the 1960s.\26\ Early
generation ILI tools could only detect metal loss anomalies in the
bottom quarter of a pipeline, and limitations in battery power capacity
meant that inspections could extend for no more than 30 miles.\27\
However, as the technology advanced, ILI tools became capable of
detecting more anomalies and inspecting greater lengths of pipeline.
Modern ILI technology allows multiple types of tools to be attached
together, permitting detection of different threats at once. Modern ILI
tools are also equipped with improved sensor technology, enabling
detection of a wider range of defects with greater accuracy. These
advances have increased both the probability of detection and
probability of identification of pipeline anomalies--commercially
available ILI tools today can detect pipe body crack sizing with 90
percent certainty to 1 millimeter via an Electromagnetic Acoustic
Transducer (EMAT) tool, and corrosion depth sizing with 80 percent
certainty to 0.1 times the wall thickness via axial Magnetic Flux
Leakage (MFL-A) tools.\28\
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\26\ See T.D. Williamson, Comments, Docket ID PHMSA-2017-0151-
0024, at 1 (Sept. 29, 2018).
\27\ See INGAA, Fact Sheet, Response to NTSB Recommendation:
Historic and Future Development of Advanced In-line Inspection (ILI)
Platforms for Natural Gas Transmission Pipelines (April 2012),
available at: https://ingaa.org/wp-content/uploads/2013/01/19697.pdf; Anand Gupta & Anirbid Sircar, Introduction to Pigging & a
Case Study on Pigging of an Onshore Crude Oil Trunkline, V Int'l J.
Latest Tech in Eng'g, Mgmt. & Applied Sci. at 21 (Feb. 2016),
available at: https://www.researchgate.net/publication/307583466_Introduction_to_Pigging_a_Case_Study_on_Pigging_of_an_Onshore_Crude_Oil_Trunkline.
\28\ See, e.g., Rosen Swiss AG, RoCorr MFL-A Service: In-line
Ultra-High-Resolution Metal Loss Detection and Sizing (2024),
available at: https://contenthub.rosen-group.com/api/public/content/729e05931aca4953ac0a47dbdf2c6566?v=f9378e13; Rosen Swiss AG, RoCD
EMAT-C Service: In-line High-Resolution Detection and Sizing of
Axial Cracks (2024), available at: https://contenthub.rosen-group.com/api/public/content/7e9f40578f924917a4403fa7fc5ba41e?v=0071d845.
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Dramatic improvements in ILI technology have occurred in the 20
years since the adoption of the 2003 Gas IM Rule, facilitated, in part,
by PHMSA's other technology notification process that allows operators
to deploy more modern tools for conducting integrity assessments.\29\
Tool manufacturers and operators have incorporated the experience
gained by deploying ILI--which operators have expanded to a greater
number of pipelines--to advance their ability to detect and model
increasingly complex defect types.\30\ Innovation in data processing
and machine learning algorithms have enabled real-time analysis and
improved interpretation of complex signals and deformation shapes,
expediting decision-making.\31\ Models can now overlay multiple data
inputs involving different threats to provide a clearer understanding
of the pipeline and greater knowledge about each possible anomaly.
Compared with historical assessment practices like hydrostatic testing
and direct assessment, modern ILI tools discover and identify more
anomalies, offering greater proactive remediation.\32\
---------------------------------------------------------------------------
\29\ See Rosen USA, Comments, Docket ID PHMSA-2017-0151-0025, at
1 (Sept. 28, 2018). See also The Williams Companies, Inc.
(Williams), Comments, Docket ID PHMSA-2024-0005-0421 at 3, 5 (Aug.
27, 2024) (noting how study and application between industry and
PHMSA ``drives the vendors to constantly improve and refine their
tools,'' and today ``[o]perators . . . who regularly deploy this
[ILI] technology across its enterprise of pipeline systems[] can
assess risk with a level of detail and certainty that was not
available 10 years ago'').
\30\ Just since 2012, operators have expanded the number of
pipelines able to accommodate ILI from 60 percent to 74 percent of
all gas transmission mileage in 2024. See PHMSA, Annual Reports.
That number is likely to continue to increase in part as a result of
continued PHMSA regulation driving inspection of these gas
transmission pipelines. See Alisdair Blackley et. al., Argus,
Pigging Previously Unpiggable Pipelines, Pipeline Pigging and
Integrity Management Conference (Feb. 12-16, 2024), available at:
https://www.argusinnovates.com/public/download/files/244219.
\31\ See Rosen, Comments, Docket ID PHMSA-2011-0151-0025, at 1;
T.D. Williamson, Comments, Docket ID PHMSA-2017-0151-0024, at 2.
\32\ See NTSB, SS-15-01, Integrity Management of Gas
Transmission Pipelines in High Consequence Areas at 58 (Jan 27,
2015), available at: https://www.ntsb.gov/safety/safety-studies/documents/ss1501.pdf (finding 663 repairs per 1,000 miles assessed
for ILI, compared to 264 for direct assessment, 35 for pressure
tests, and 26 for other assessment techniques). See also Williams,
Docket ID PHMSA-2024-0005-0421 at 5 (noting how ``the data provided
by the current generation of [ILI] tools gives [an operator]
certainty and clarity around the risk assessment decisions . . .
regarding potential threats'').
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PHMSA has updated the IM regulations in Subpart O to capitalize on
the recent advances in ILI technology. In 2022, PHMSA completed a
multi-year process of strengthening its IM regulations to address
congressional mandates and National Transportation Safety Board (NTSB)
recommendations issued in response to a significant gas transmission
line incident that occurred in San Bruno, California, in 2011.\33\ The
[[Page 1613]]
enhancements to the IM regulations included new assessment procedures
for ILI tools and updated requirements for the detection and
remediation of anomalies. PHMSA's 2019 and 2022 Safety of Gas
Transmission Rules also established a companion assessment and response
schedule for other Class 3 and 4 pipelines.\34\ These changes have
created a comprehensive, risk-based scheme for pipeline anomaly
detection and remediation, driven in large part by continuing
improvements in ILI technology.
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\33\ Safety of Gas Transmission Pipelines: Repair Criteria,
Integrity Management Improvements, Cathodic Protection, Management
of Change, and Other Related Amendments, 87 FR 52224 (Aug. 24, 2022)
(2022 Safety of Gas Transmission Rule); Safety of Gas Transmission
Pipelines: MAOP Reconfirmation, Expansion of Assessment
Requirements, and Other Related Amendments, 84 FR 52180 (Oct. 1,
2019) (2019 Safety of Gas Transmission Rule).
\34\ For these non-high consequence segments, the assessment is
every 10 years and scheduled repair is designated to occur within 2
years of detection, highlighting the different safety factor found
in high consequence areas. See 49 CFR 192.710(b)(2); 192.714(d)(2).
---------------------------------------------------------------------------
D. Class Location Special Permits
PHMSA's experience administering a comprehensive class location
special permit program demonstrates that IM principles can be used
safely to confirm or to restore the MAOP of pipeline segments in Class
3 locations. When issuing the original IM program requirements for gas
transmission lines in 2003, PHMSA acknowledged that ``[e]xperience may
lead to future changes in the [regulatory] requirements,'' and that the
waiver, or ``special permit,'' process authorized by 49 U.S.C. 60118
and codified in 49 CFR 190.341 could be used to review segments
changing class location for suitability to leverage IM principles in
place of pipe replacement.\35\ Specifically, PHMSA stated that:
---------------------------------------------------------------------------
\35\ 2003 Gas IM Rule, 68 FR at 69782.
[a] benefit to be realized from implementing this rule is reduced cost
to the pipeline industry for assuring safety in areas along pipelines
with relatively more population. The improved knowledge of pipeline
integrity that will result from implementing this rule will provide a
technical basis for providing relief to operators from current
requirements to reduce operating stresses in pipelines when population
near them increases. Regulations currently require that pipelines with
higher local population density operate at lower pressures. This is
intended to provide an extra safety margin in those areas. Operators
typically replace pipeline when population increases, because reducing
pressure to reduce stresses reduces the ability of the pipeline to
carry gas. Areas with population growth typically require more, not
less, gas. Replacing pipeline, however, is very costly. Providing
safety assurance in another manner, such as by implementing this
[integrity management] rule, could allow [the Agency] to waive some
pipe replacement. [The Agency] estimates that such waivers could result
in a reduction in costs to industry of $1 billion over the next 20
years, with no reduction in public safety.\36\
---------------------------------------------------------------------------
\36\ 2003 Gas IM Rule, 68 FR at 69812. See also Final Regulatory
Evaluation, 2003 Gas IM Rule, Docket ID PHMSA-RSPA-2000-7666-0356
(Dec. 2023).
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While special permits are considered on a case-by-case basis, PHMSA
developed certain threshold requirements for segments to be considered
as candidates for a special permit.\37\ As explained in the 2004 notice
articulating those threshold requirements, PHMSA would only consider
pipeline segments that operate below 72 percent of SMYS for a Class 3
location; underwent an eight-hour hydrostatic test to at least 1.25
times the MAOP; and did not have bare pipe, wrinkle bends, or
significant anomalies. Older pipe and specific seam types would require
further justification. PHMSA also explained that operators would be
required to apply their IM program and assess the segment using ILI
techniques for a distance upstream and downstream.
---------------------------------------------------------------------------
\37\ Pipeline Safety: Development of Class Location Change
Waiver Criteria, 69 FR 38948 (June 29, 2004); PHMSA, Criteria for
Considering Class Location Waiver Requests (June 30, 2024),
available at: https://www.phmsa.dot.gov/sites/phmsa.dot.gov/files/docs/technical-resources/pipeline/class-location-special-permits/64091/classchangewaivercriteria.pdf (PHMSA, 2004 Special Permit
Criteria).
---------------------------------------------------------------------------
PHMSA has issued 46 class location special permits since 2004.
Thirty-six are active. Each special permit application undergoes
individual review by PHMSA, is subject to public notice and comment,
includes operational conditions if issued, and must be renewed after 10
years. There has never been a leak or rupture reported on a segment
managed by a class location special permit. PHMSA has denied
approximately half of the requests submitted, generally for having
unsuitable pipe characteristics based on design and operating
parameters. Having spent the past twenty years reviewing data, detail,
and pipe characteristics in administering the class location special
permit program, PHMSA is confident that IM principles can be used to
confirm or restore the MAOP of Class 1 to Class 3 and Class 2 to Class
3 change segments.\38\
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\38\ PHMSA has never issued a special permit to waive the class
location requirements for a pipeline segment in a Class 4 location.
---------------------------------------------------------------------------
III. Summary of the NPRM
On July 31, 2018, PHMSA published an advance notice of proposed
rulemaking (ANPRM) seeking public comment on whether to amend the
requirements in part 192 for addressing class location changes.\39\
PHMSA received 24 comments from a variety of stakeholders in response
to the ANPRM, including operators such as Kinder Morgan, Inc. and the
Williams Companies (Williams), the Pipeline Safety Trust (PST), the
National Association of Pipeline Safety Representatives (NAPSR), the
GPA Midstream Association, individual engineers and citizens, and a
joint comment by the American Gas Association, American Petroleum
Institute, American Public Gas Association, and Interstate Natural Gas
Association of America. Many of the commenters reiterated concerns that
had been raised in earlier proceedings, particularly from the industry
perspective.\40\ PHMSA also received a similar submission from 4,831
commenters recommending that current class location change requirements
``remain in place pending further review through proposed rulemaking
protocols'' and to consider recommendations of the NTSB in light of
prominent gas pipeline safety incidents.\41\
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\39\ Pipeline Safety: Class Location Change Requirements, 83 FR
36861 (July 31, 2018) (ANPRM).
\40\ This included feedback from a Notice of Inquiry in 2013,
Class Location Requirements, 78 FR 46560 (Aug. 1, 2013); public
meetings in 2014; comments on the gas transmission NPRM in 2016; and
comments to a DOT notice of regulatory review in 2017, Notification
of Regulatory Review, 82 FR 45750 (Oct. 2, 2017).
\41\ Comments, Docket ID PHMSA-2017-0151-0028 (Sept. 25, 2018).
These NTSB recommendations were addressed in the 2019 Safety of Gas
Transmission Rule. See 84 FR at 52189.
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After considering these comments, PHMSA issued a notice of proposed
rulemaking (NPRM) on October 14, 2020.\42\ The NPRM proposed to add an
IM alternative for confirming the MAOP of certain class change
segments. The NPRM reflected the extensive back and forth on the topic
that had occurred between PHMSA, Congress, the public, and the
regulated community over the previous years.\43\
---------------------------------------------------------------------------
\42\ NPRM, 85 FR 65142.
\43\ See, e.g., supra note 40; PHMSA, Report to Congress:
Evaluation of Expanding Pipeline Integrity Management beyond High-
Consequence Areas and Whether Such Expansion Would Mitigate the Need
for Gas Pipeline Class Location Requirements (June 6, 2016),
available at: https://www.phmsa.dot.gov/sites/phmsa.dot.gov/files/docs/news/55521/report-congress-evaluation-expanding-pipeline-imp-hcas-full.pdf.
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[[Page 1614]]
PHMSA proposed a set of operating parameters and eligibility
criteria in the NPRM for using an IM alternative. The segment would
have to be changing from a Class 1 to a Class 3 location, be operating
below a hoop stress corresponding to 72 percent SMYS, and be capable of
assessment using ILI tools. Pipe with certain additional
characteristics would be ineligible: bare pipe; pipe with wrinkle
bends; pipe lacking traceable, verifiable, and complete material
records; pipe without traceable, verifiable, and complete records of a
pressure test to 1.25 times MAOP for at least eight hours; where the
longitudinal seam had been formed by certain more vulnerable methods;
poor external coating; pipe transporting gas not suitable for sale;
pipelines with grandfathered MAOPs under Sec. 192.619(c) or an
alternative MAOP under Sec. 192.619(d); or where the segment
previously had a special permit denied. Many kinds of cracking found in
or within five miles of the segment, or past experience of a leak or
rupture due to cracking, would make a pipeline ineligible; cracking
that may develop could subsequently remove a segment from eligibility.
The NPRM proposed to also exclude pipe moving into Class 4 locations
which are the areas of highest population density.
PHMSA further proposed that pipe coming into the program would need
to follow the IM program in Subpart O and be assessed within 24 months
of the change in class location by ILI tools validated to Level 3 under
API Standard 1163.\44\ Along with a reassessment interval of at least
every seven years, the NPRM included a detailed anomaly response
schedule for repairs needed based on the results of these assessments.
The proposal included several other preventive and mitigative measures
as well, such as requirements to perform close interval surveys,
install a cathodic protection test station, install line markers,
perform interference surveys, have adequate depth of cover, perform
patrols and leak surveys at more frequent intervals, and clear shorted
casings. Operators would also have to notify PHMSA of a new segment
using this method, install remote-control or automatic shutoff valves,
and examine pipe when otherwise excavated or uncovered.
---------------------------------------------------------------------------
\44\ Am. Petroleum Inst. (API), API Standard 1163, In-line
Inspection Systems Qualification (2nd Ed. 2013).
---------------------------------------------------------------------------
A 60-day public comment period followed publication of the NPRM.
PHMSA received 14 initial comments from a variety of stakeholders,
including pipeline industry trade associations, members of NAPSR, the
NTSB, public advocacy groups such as the PST and Accufacts Inc.
(Accufacts), and operators including TC Energy Corporation (TC Energy).
The pipeline trade associations submitted a joint comment from the
American Gas Association, American Petroleum Institute, American Public
Gas Association, GPA Midstream Association, Interstate Natural Gas
Association of America, and NACE International Institute (collectively,
the ``Associations''). Several other operators, including NiSource,
Southwest Gas, and Paiute Pipeline Company, submitted comments
supporting the Associations' comment. Commenters across the spectrum
supported expanding a strong IM option to manage class location
changes. Industry representatives noted the efficiencies it would
provide without a drop in safety, while public advocates appreciated
how the proposal balanced eligible pipe, the IM requirements, and other
supplemental program requirements.
PHMSA held a public meeting of the Gas Pipeline Advisory Committee
(GPAC) on March 27 to 29, 2024, to review the NPRM and supporting
analyses.\45\ The meeting afforded time for additional public comments
and discussion by members of the committee. Pursuant to 49 U.S.C.
60115, the GPAC assessed the technical feasibility, reasonableness,
cost-effectiveness, and practicability of the standard proposed in the
NPRM. The transcripts and the vote slides constitute the GPAC report
for this rulemaking under 49 U.S.C. 60115; PHMSA acknowledged receipt
of this report and responded.\46\
---------------------------------------------------------------------------
\45\ See GPAC, Minutes for GPAC March 2024 Meeting, Docket ID
PHMSA-2024-0005-0408; GPAC, Voting Slides, Docket ID PHMSA-2017-
0151-0068. The transcript for each day is available via docket
number PHMSA-2024-0005 accessible through regulations.gov. GPAC
members also reviewed comments received on the NPRM.
\46\ PHMSA, Response to the GPAC's Report on the `Class Location
Change Requirements' Proposed Rule, Docket ID PHMSA-2024-0005-0424
(Dec. 11, 2024).
---------------------------------------------------------------------------
PHMSA provided an additional 150-day period for written public
comment following the GPAC meeting.\47\ PHMSA received 10 additional
comments during that period from the Associations, the PST, individual
operators including Enbridge and Williams, several members of the
general public, as well as two then-members of the Committee, Andy
Drake and Chad Zamarin, acting in their individual capacity.
---------------------------------------------------------------------------
\47\ Meeting Notice, 89 FR 26118 (Apr. 15, 2024). PHMSA extended
the period for submitting written comments after the GPAC meeting to
150 days at the request of several industry associations.
---------------------------------------------------------------------------
PHMSA considered all comments submitted in response to the NPRM in
developing this final rule, including the initial written comments, the
oral comments provided at the GPAC meeting, and the written comments
filed after the GPAC meeting. Public comments to the NPRM are available
on the docket for this rulemaking, PHMSA-2017-0151, while comments in
response to the GPAC are available on the docket PHMSA-2024-0005. Both
are accessible through regulations.gov.
IV. Discussion of the Final Rule and Analysis of Comments
The following subsections summarize the proposals in the NPRM, the
relevant issues raised by the commenters, and the discussions and
recommendations of the GPAC. Subsections conclude by providing PHMSA's
responses as developed in preparing and issuing the final rule.
A. General
1. Summary of Proposal
The NPRM proposed to allow operators to use an IM alternative to
confirm the MAOP of certain segments that experience class location
changes. Modeled on PHMSA's class location special permit program, the
proposed IM alternative included a list of eligibility criteria and
required compliance with an ongoing program of IM and supplemental O&M
requirements.
2. Comments Received
The Associations supported the IM alternative, stating that the
objective of class locations to ensure an appropriate safety margin
when population growth occurs around an existing pipeline ``can now be
accomplished using modern integrity management programs, which are a
more effective, efficient, environmentally sound and less disruptive
means of managing pipeline safety.'' \48\ The Associations suggested
that the IM alternative in general will improve safety, is more cost
effective, will reduce emissions, and reduce community impacts. Mr.
Drake commented that the historical approach for addressing class
changes is outdated and inefficient, observing that the
[[Page 1615]]
approach fails to account for the diameter, strength, and operating
pressure of a pipeline, and for recent advancements in threat detection
and assessment technology.\49\
---------------------------------------------------------------------------
\48\ Associations, Comments, Docket ID PHMSA-2017-0151-0061 at 4
(Dec. 14, 2020).
\49\ See Andy Drake, Comments, Docket ID PHMSA-2024-0005-0419 at
2 (Aug. 27, 2024).
---------------------------------------------------------------------------
Williams, which operates approximately one third of the Nation's
natural gas transmission and gathering infrastructure, commended the
regulatory flexibility provided by the IM alternative, noting that
technological and methodological improvements allow operators to
``assess risk with a level of detail and certainty that was not
available 10 years ago.'' \50\ The proposed rule, Williams commented,
would allow operators to benefit from these advancements in technology
and improvements to IM in Subpart O through the 2022 Safety of Gas
Transmission Rule and increase pipeline safety nationwide. Several
private citizens similarly supported the proposal, noting that the IM
alternative ``offers solutions and incentives to improve'' pipeline
systems and provides benefits to consumers, as reductions in MAOP from
population increases near pipelines would likely result in less
reliable gas distribution.\51\
---------------------------------------------------------------------------
\50\ Williams, Comments, Docket ID PHMSA-2024-0005-0421 at 3
(Aug. 27, 2024).
\51\ Alina Rutherford, Comments, Docket ID PHMSA-2017-0151-0031
(Dec. 2, 2020).
---------------------------------------------------------------------------
Members of NAPSR, an organization comprised of PHMSA's State
pipeline safety partners, were divided on the proposal. Several members
expressed support for the NPRM if each of the proposed requirements
were accepted, noting that ``it appears that adequate safeguards are in
place to ensure safety is not compromised.'' \52\ On the other hand,
several NAPSR members were concerned about relaxing class-based design
requirements and using IM to manage class location changes based on
their experience observing operators ``poor management and decision
making in implementing [IM] requirements,'' pointing to the 2010
Marshall, Michigan incident.\53\ Some of these NAPSR members feared
that PHMSA would be sacrificing pipeline safety by adopting the
proposed rule, stating that the issues of managing and implementing the
IM alternative would be less reliable and effective than the design
measures that would be replaced. Accufacts noted that though it had
anticipated the implementation of IM would reduce the number of
pipeline ruptures, several ruptures on pipelines operating at pressure
below MAOP well before the times predicted by operators engineering
assessments under IM had undercut that assumption. Accufacts stated
that the number of ruptures occurring shortly after ILI tool runs is
creating a ``credibility gap'' with the public that will only be
compounded if ILI effectiveness continues to be ``oversold and
misrepresented as to its capability.'' \54\ But, Accufacts found that
the proposal addressed these concerns by an articulated response
schedule for eligible segments.\55\
---------------------------------------------------------------------------
\52\ NAPSR, Comments, Docket ID PHMSA-2017-0151-0059 at 5 (Dec.
14, 2020).
\53\ Id. at 2.
\54\ See Accufacts, Comments, Docket ID PHMSA-2017-0151-0058 at
2 (Dec. 14, 2020).
\55\ Docket ID PHMSA-2017-0151-0058 at 3-4.
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While the PST was ``not convinced of the necessity of this rule,
given the existing options for operators to manage their class location
changes,'' it appreciated the seriousness of PHMSA's proposal. The PST
agreed that PHMSA's limitation on eligibility, plus O&M requirements
added to the IM requirements, increased the likelihood that the rule
will not decrease safety. However, the PST preferred the status quo of
class location design requirements, plus special permits on a case-by-
case basis, as a ``safety backstop. . .to reduce the risk of a failure
resulting from shortcomings in an IM plan.'' \56\
---------------------------------------------------------------------------
\56\ PST, Comments, Docket ID PHMSA-2017-0151-0063 at 2, 8 (Dec.
14, 2020).
---------------------------------------------------------------------------
NAPSR members agreed that, as proposed, the requirements for
managing a class change without an improvement in design standards
should exceed the IM requirements.\57\ The PST agreed that PHMSA's
limitation on eligibility, plus O&M requirements added to the IM
requirements, demonstrated a careful proposal to ``maintain[] an
equivalent level of safety'' that is provided by the historical
management options.\58\ Accufacts supported the proposal as written
with the additional prescriptive requirements beyond the then-current
IM regulations, noting that the additional requirements would help
offset the limitations of ILI assessment methods. Accufacts noted how
pipeline failures observed after operators perform ILI tool runs
justified excluding certain pipe from eligibility and ``the need to
include a combination of additional prescriptive requirements to
address shortcomings in many company applications of their IM
approaches defined in Subpart O,'' as did the proposal.\59\ In
addition, Mr. Drake argued that PHMSA's final rule should incorporate
the ``standard of care based on the latest technology for inspection,
assessment, and repair criteria'' established under the 2019 and 2022
Safety of Gas Transmission Rules.\60\
---------------------------------------------------------------------------
\57\ See Docket ID PHMSA-2017-0151-0059 at 2-3.
\58\ Docket ID PHMSA-2017-0151-0063 at 8.
\59\ Docket ID PHMSA-2017-0151-0058 at 2.
\60\ Docket ID PHMSA-2024-0005-0419 at 2.
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An anonymous commenter viewed the GPAC recommendations for the rule
(which are discussed in the ensuing sections) as ``major changes'' and
suggested PHMSA ``re-review the safety and integrity of changes
proposed in the GPAC Voting Slides . . . and then re-notice the rule
for public comment.'' \61\ Another anonymous commenter suggested that
an environmental, cost-benefit, and safety analysis on the overall
effect of the GPAC recommendations to the public in the area around
pipelines should be developed and publicly noticed.\62\
---------------------------------------------------------------------------
\61\ Anonymous, Comments, Docket ID PHMSA-2024-0005-0415 at 1
(Aug. 28, 2024).
\62\ Anonymous, Comments, Docket ID PHMSA-2024-0005-0422 at 1
(Aug. 28, 2024).
---------------------------------------------------------------------------
Many commenters lauded PHMSA's class location special permit
program and noted the similarities between that program and the
proposed rule. Highlighting how PHMSA stated in the 2003 Gas IM Rule
that experience and data from special permits using IM may lead to
future regulatory changes in the class change requirements, the
Associations offered that decades of experience demonstrate the
effectiveness of IM for managing class location changes.\63\ Mr. Drake
noted the ``excellent performance record'' of pipelines in the special
permit program--improving pipeline safety and reducing environmental
impacts--demonstrating ``the feasibility and effectiveness of IM as an
alternative to class location change pipe replacements or pressure
reductions.'' \64\
---------------------------------------------------------------------------
\63\ See Docket ID PHMSA-2017-0151-0061 at 5-8.
\64\ Docket ID PHMSA-2024-0005-0419 at 2.
---------------------------------------------------------------------------
The NTSB expressed concern with drawing conclusions from the
operating history of special permit segments, based on the small sample
size and small percentage of Class 3 gas transmission mileage. The NTSB
noted how special permits are ``rigorous by design'' and encouraged
PHMSA to ``consider how [to] provide the same level of scrutiny and
attention to detail on the larger scale of locations impacted by this
regulation.'' \65\
---------------------------------------------------------------------------
\65\ NTSB, Comments, Docket ID PHMSA-2017-0151-0055 at 3-4 (Dec.
10, 2020).
---------------------------------------------------------------------------
The PST expressed appreciation for the ``hard look'' PHMSA engages
in when considering each special permit, noting that it allows PHMSA to
impose prescriptive measures specific to an operator's past performance
and the type of pipe and environment in which
[[Page 1616]]
the pipe is located. In addition, the PST stated that the data and
documents required for special permit applications, including National
Environmental Policy Act compliance, benefit the public by providing
notice of the application, the location of the waivers, material
characteristics about the pipeline, and ensures PHMSA has the
opportunity to review the details of each application before acting on
it.\66\
---------------------------------------------------------------------------
\66\ Docket ID PHMSA-2017-0151-0063 at 2.
---------------------------------------------------------------------------
While commending the record of special permits to date, the
Associations raised several complications posed by the existing special
permit process, including: the length of the review process, changing
compliance conditions, an uncertain renewal process, and burdensome
administrative work--all of which reduce operator participation.
Codifying the IM alternative, the Associations argued, would provide
more clarity, consistency, and alignment with other previously existing
regulations.\67\
---------------------------------------------------------------------------
\67\ Docket ID PHMSA-2017-0151-0061 at 11.
---------------------------------------------------------------------------
Commenters also noted the significant benefits of authorizing the
IM alternative. Williams argued that the proposal would provide an
additional benefit of lowering emissions by ``avoiding [blowdowns and]
the unnecessary replacement of perfectly good pipe.'' \68\ The
Associations likewise observed that ``the environmental benefits of
applying integrity management requirements instead of replacing. .
.pipe are as compelling as the safety benefits,'' estimating that class
change pipe replacements under the former regulatory regime resulted in
up to ``800 million standard cubic feet of natural gas blowdown to the
atmosphere each year,'' which ``could meet the [natural gas] needs of
over 10,000 homes for a year.'' \69\
---------------------------------------------------------------------------
\68\ Docket ID PHMSA-2024-0005-0421 at 3.
\69\ Docket ID PHMSA-2017-0151-0061 at 10-11.
---------------------------------------------------------------------------
The Associations estimated that ``gas transmission pipeline
operators spend $200-$300 million annually to replace pipe solely to
satisfy the [historical] class location change regulations.'' Instead
of being allocated to replacing less than 75 miles of pipe per year,
the Associations argued that this capital investment could be
reallocated to ``assess over 25,000 miles [of pipe] with in-line
inspection, install [ILI tool] launchers and receivers to enable over
5,000 miles of pipeline to be assessed with in-line inspection tools
for the first time, or conduct over 4,000 anomaly evaluation digs.''
\70\ Focusing these resources on segments changing class and expanding
the 2019 and 2022 revisions to Subpart O IM regulations to greater
pipeline mileage, Williams suggested, will increase safety in these
class change segments, improve the IM program, and ``reduc[e] risk
across natural gas pipelines [throughout] the United States.'' \71\
---------------------------------------------------------------------------
\70\ Id. at 5. The Associations note that this mileage figure
equates to a replacement of less than 0.05 percent of the gas
transmission pipeline network.
\71\ Docket ID PHMSA-2024-0005-0421 at 2.
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3. PHMSA Response
PHMSA appreciates the strong public engagement that occurred
throughout the rulemaking process. The NTSB, public advocates, and
industry groups each commended the success of the class location
special permit program, which provides two decades of data and real-
world experience implementing the IM alternative. That data and
experience, when combined with the significant improvements to the IM
program that have occurred in recent years, strongly support adopting
the requirements in this final rule.
PHMSA and operators have gained valuable experience applying the IM
alternative through the class location special permit program. That
program has led to the development of eligibility criteria and special
permit conditions that have a proven track record of ensuring the
safety and reliability of gas transmission lines. Rather than
continuing to require the use of the special permit process to provide
relief from outdated and unduly burdensome requirements, the final rule
adopts the relevant eligibility criteria and conditions by regulation.
This allows operators and PHMSA to direct their limited resources
toward performing other critical safety functions.
As discussed in more detail in the ensuing subsections, the IM
alternative that PHMSA is adopting in this final rule sets forth a
standardized set of requirements to safely manage class location
changes without requiring unnecessary MAOP reductions, pipe
replacements, or pressure tests. The key features of the IM alternative
include:
First, the final rule defines under eligibility those
pipeline characteristics that can safely be managed by the program.
Second, to use the program, an eligible class change
segment must be designated as an HCA and incorporated into an
operator's IM program in Subpart O. The final rule also includes IM
requirements for the baseline assessment, periodic reassessment,
assessment methods, and remediation schedule specific to class change
segments and their surrounding inspection area.
Third, the final rule includes supplemental O&M measures
based on historical special permit conditions.
Fourth, the final rule requires maintaining an operating
pressure no greater than the design factor corresponding to the
original class location and retention of pipeline records. Any segment
which experiences an in-service leak from the pipe itself cannot use
the IM alternative.
Compliance with these requirements provides a margin of safety that
meets or exceeds the historical approach for confirming the MAOP of
segments that experience class location changes.
As multiple commenters favorably noted, the IM alternative proposed
in the NPRM and adopted in this final rule retains the core elements of
the successful class location special permit program. PHMSA agrees with
commenters that each of these core elements is necessary to provide for
the safety of the eligible Class 3 segments. PHMSA is incorporating the
IM alternative directly into Sec. 192.611 as a new paragraph (a)(4)
instead of in an entirely new Sec. 192.618 as proposed in the NPRM.
For clarity, the program requirements are bifurcated into ``one-time''
programmatic requirements under Sec. 192.611(a)(4)(i), which must be
in place within a 24-month window, and ``ongoing'' programmatic
requirements listed at Sec. 192.611(a)(4)(ii) that must be carried out
periodically. The requirements standardized in this final rule, based
on years of success through the special permit program, no longer
require the individual review of a special permit excepting regulatory
requirements.
While several commenters expressed concerns with deficiencies or
gaps identified in past incident investigations involving covered
segments subject to Subpart O, PHMSA has taken significant actions to
address those concerns in other recent rulemaking proceedings. As
discussed in section II.C, PHMSA updated the Subpart O requirements in
the 2022 Safety of Gas Transmission Rule in response to incidents that
occurred after the original adoption of the IM program. PHMSA is
confident in the strengthened IM framework that exists today, as were
many participants at the GPAC and commenters following the meeting who
encouraged PHMSA to incorporate those requirements into this rule.
Many of the requirements of the 2022 Safety of Gas Transmission
Rule, such as the remediation criteria, were proposed in this NPRM and
have historically been included in class location special permits.
Those parts of the NPRM that have since been codified
[[Page 1617]]
into Subpart O no longer need duplication in this final rule and are
included in the IM alternative by cross-reference to Subpart O, as was
recommended by commenters and during the GPAC meeting. This streamlines
and clarifies the IM alternative without substantive change. By
incorporating the amendments from the 2022 Safety of Gas Transmission
Rule into the IM alternative, PHMSA is responding to the concerns
expressed by some commenters about incidents that occurred in the early
stages of the IM program. PHMSA is also aligning the IM alternative
with the conditions developed during the class location special
program, as recommended by the commenters.
PHMSA reiterates its appreciation for the input received throughout
the rulemaking process, particularly the comments submitted in response
to the ANRPM, the NPRM, and the GPAC's report. These comments have
allowed PHMSA to develop a final rule that embodies the views of
multiple stakeholders and is supported by a well-developed
administrative record.
B. Definitions
1. Summary of Proposal
The NPRM proposed to add definitions for three new terms in Sec.
192.3. First, the NPRM proposed to define the precise segment changing
class as the ``Class 1 to Class 3 location segment.'' Second, the NPRM
proposed to define the span of the pipeline from the nearest upstream
ILI launcher and downstream ILI receiver containing the class change
segment as the ``in-line inspection segment.'' That definition was
proposed to align with the phrase ``special permit inspection area'' as
used in the class location special permit program. Third, the NPRM
proposed to define the term ``predicted failure pressure'' as used in
the Federal Pipeline Safety Regulations for many years.
2. Comments Received
Several commenters found using the term ``Class 1 to Class 3
segment'' to be confusing and restrictive, and sought a simpler
definitional term. Further substantive comments regarding this term are
expanded on in section IV.C.ii. Editorially, the Gas Piping Technology
Committee (GPTC) stated that the inclusion of the word ``and'' between
the numbered list within the ``Class 1 to Class 3 location segment''
could imply that if an operator does not confirm or revise a pipeline
segment's MAOP in accordance with Sec. 192.611(a)(4), the operator
does not come into the IM alternative program and therefore cannot be
eligible.\72\ Oleksa and Associates suggested that the proposed changes
to Sec. 192.903 were ``circular and confusing,'' and that they seemed
to imply that ``an operator might not designate a Class 1 to Class 3
location segment as [an HCA] and that there might be some Class 1 to
Class 3 location segments that are not [HCAs.]'' \73\ They requested
PHMSA clarify and provided editorial suggestions for doing so.
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\72\ See GPTC, Comments, Docket ID PHMSA-2017-0151-0065 at 3
(Dec. 14, 2020).
\73\ Oleksa and Associates, Docket ID PHMSA-2017-0151-0067 at 1
(Dec. 9, 2020).
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Regarding the proposed definition of ``in-line inspection
segment,'' multiple commenters, including NAPSR, Sander Resources, and
GPTC, recommended focusing on the IM alternative program only, since
many operators already use that term to refer to any section of a
pipeline between ILI launchers and receivers. In addition, commenters
were concerned that the term could be misapplied or cause confusion
because applicable segments may or may not contain segments using the
IM alternative option.\74\ Further, Sander Resources stated that PHMSA
used the word ``adjacent'' within the proposed definition of ``in-line
inspection segment'' without guidance to what that word means. It noted
that the historical 25-mile distance PHMSA references in the NPRM is
``significant and appears to be arbitrary without further direction''
and requested PHMSA clarify that operators need not assume ``large
segments of pipe are subject to the review and [MAOP reestablishment]
process'' but can instead establish and justify their own area of
review as appropriate.\75\
---------------------------------------------------------------------------
\74\ See, e.g., GPTC, Docket ID PHMSA-2017-0151-0065 at 3-4;
Sander Resources, Comments, Docket ID PHMSA-2017-0151-0064 at 3
(Dec. 14, 2020); NAPSR, Docket ID PHMSA-2017-0151-0059 at 4.
\75\ Docket ID PHMSA-2017-0151-0064 at 3.
---------------------------------------------------------------------------
Regarding the proposed definition of ``predicted failure
pressure,'' NAPSR and GPTC recommended that PHMSA consider adding the
phrase ``as determined by the procedures in ASME/ANSI B31G or PRCI PR-
3-805 (as incorporated by reference in Sec. 192.7).'' Each suggested
that this addition would be consistent with similar language used in
Sec. Sec. 192.485 and 192.933(a) and would ``provide the same
limitations as currently found in [the] code.'' \76\ NAPSR members also
recommended changing the term ``appropriate engineering evaluation'' to
``acceptable engineering evaluation,'' which, they argued, might
provide ``a stronger basis from which to argue potentially subjective
engineering evaluations.'' \77\ The Associations suggested a minor
change to the proposed definition clarifying that the safety factor is
``added,'' rather than ``included.'' \78\ Oleksa and Associates
requested PHMSA clarify the definition to indicate that it ``applies
only to failure by rupture'' by modifying it such ``that it would not
apply to low-pressure, low-stress steel transmission lines'' and limit
its application ``to steel pipelines operating at pressures above 20
percent SMYS.'' \79\
---------------------------------------------------------------------------
\76\ NAPSR, Docket ID PHMSA-2017-0151-0059 at 4; GPTC, Docket ID
PHMSA-2017-0151-0065 at 4.
\77\ Docket ID PHMSA-2017-0151-0059 at 4.
\78\ Docket ID PHMSA-2017-0151-0061 at 32.
\79\ Docket ID PHMSA-2017-0151-0067 at 1.
---------------------------------------------------------------------------
3. PHMSA Response
PHMSA has made clarifying edits to the definitions as suggested by
commenters to simplify application of the IM alternative. This final
rule does not finalize a definition of ``predicted failure pressure''
as proposed in the NPRM. PHMSA adopted new anomaly assessment and
remediation criteria that use the predicted failure pressure concept in
a final rule issued after publication of the NPRM and is not modifying
those requirements in this proceeding. PHMSA concludes that the new
anomaly assessment and remediation criteria render the proposed
definition of predicted failure pressure definition unnecessary, and
that the term has been consistently used in the regulations for many
years without need for additional clarity.
This final rule adopts the term ``eligible Class 3 segment'' to
define the specific segments changing class using this IM alternative
option. This replaces the proposed term ``Class 1 to Class 3 location
segment,'' which numerous commenters noted was unnecessary lengthy and
confusing, and resolves other editorial comments by GPTC and Oleksa and
Associates. This final rule explicitly includes the eligible Class 3
segment in the definition of an HCA at Sec. 192.903. PHMSA has also
included several eligibility factors into this definition as discussed
in section IV.C.
This final rule adopts the term ``eligible Class 3 inspection
area'' to define the eligible Class 3 segment and the portion of
pipeline extending to the nearest upstream ILI launcher and downstream
ILI receiver. This term includes the eligible Class 3 segment and the
surrounding ILI inspection area. While conceptually equivalent to what
PHMSA proposed as an ``in-line inspection area'' and the ``special
permit inspection area'' in class location
[[Page 1618]]
change special permits, this language avoids conflict with the oft used
term ``in-line inspection,'' as commenters requested. Clearly defining
the term also addresses concerns raised by Sander Resources regarding
potential confusion with how pipelines outside of the class change area
were handled in historical special permits. While the eligible Class 3
inspection area is not itself defined as an HCA under Sec. 192.903, it
is subject to certain IM requirements as specified in Sec.
192.611(a)(4). These requirements are described in greater detail in
section IV.D of this final rule.
The definitions of ``eligible Class 3 segment'' and ``eligible
Class 3 inspection area'' are specifically limited to gas transmission
lines. Section 192.611(a)(4)(vii) further clarifies that the IM
alternative is not authorized for gas gathering or gas distribution
lines. While the class location change requirements in Sec. 192.611
apply broadly to all gas pipelines, PHMSA indicated in the NPRM and
preliminary RIA that the proposed IM alternative would only apply to
gas transmission lines. Having failed to address the applicability of
that proposal to gas gathering or distribution lines in either
document, PHMSA concludes that the IM alternative should be limited to
gas transmission lines in the final rule.\80\
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\80\ PHMSA recognizes that some regulated gas gathering lines
may experience class location changes that are subject to the
requirements in Sec. 192.611. See 49 CFR 192.8, 192.9. However,
PHMSA is not aware of any regulated gas gathering line operator ever
filing an application for a class location special permit and does
not have the information necessary to determine whether and to what
extent the use of the IM alternative should be extended to gas
gathering lines.
---------------------------------------------------------------------------
C. Eligibility Criteria
i. General
1. Summary of Proposal
The NPRM set out proposed eligibility criteria for use of the IM
alternative. PHMSA developed these eligibility criteria from its
experience applying the 2004 Special Permit Criteria, published
following the initial 2003 Gas IM Rule. In the 2004 criteria and
guidance, PHMSA established pipe criteria and conditions that would
lead to ``probable acceptance'' of a special permit to manage a class
location change consistent with pipeline safety.\81\ Each of the
criteria are discussed in further detail in individual sections below.
---------------------------------------------------------------------------
\81\ PHMSA, 2004 Special Permit Criteria.
---------------------------------------------------------------------------
2. Initial Comments
The NTSB supported the proposed eligibility criteria, observing how
``[t]he majority of the restrictions . . . concur[red] with the NTSB's
historical knowledge of higher risk pipelines.'' \82\ The PST found the
eligibility exclusions appropriate and ``absolutely necessary to ensure
that [the IM alternative does] not jeopardize pipeline safety in these
newly-populous areas.'' \83\ The PST was pleased the NPRM did not leave
identification of eligible segments up to the operator. Accufacts
similarly supported the eligibility criteria as technically sound and
noted how the attributes reflect the strengths and weaknesses (or
limitations) of various assessment approaches used in Subpart O and
what pipe could suitably be assessed and managed by ILI.\84\ Operators,
like TC Energy, also agreed with the majority of the eligibility
criteria.\85\
---------------------------------------------------------------------------
\82\ Docket ID PHMSA-2017-0151-0055 at 4.
\83\ Docket ID PHMSA-2017-0151-0063 at 4.
\84\ Docket ID PHMSA-2017-0151-0058 at 3.
\85\ See TC Energy, Comments, Docket ID PHMSA-2017-0151-0062 at
4-5 (Dec. 14, 2020). Oleksa and Associates, observing how the rule
was aimed at protecting against pipeline incidents, noted that steel
pipe operating at low stress levels cannot rupture and recommended
that PHMSA make clear several eligibility criteria and other
provisions do not apply to ``pipe that operates at 100 psig or
more,'' or ``pipelines that operate with an MAOP less than 20
percent of SMYS.'' Docket ID PHMSA-2017-0151-0067 at 2. As this 20
percent of SMYS limit corresponds to the threshold at which a
pipeline is a gas transmission line under Sec. 192.3, and given
this rule applies only to gas transmission lines, further
clarification is not needed.
---------------------------------------------------------------------------
Sander Resources requested clarification that an operator with a
pipe segment that does not meet the eligibility requirements may still
use the special permit process governing class location changes.\86\
Relatedly, the NTSB urged PHMSA to consider how to ensure operators
will comply with the criteria without the extensive, individualized
special permit process.\87\
---------------------------------------------------------------------------
\86\ Docket ID PHMSA-2017-0151-0064 at 2.
\87\ Docket ID PHMSA-2017-0151 at 3-4.
---------------------------------------------------------------------------
3. GPAC Consideration
The GPAC discussed the NPRM's eligibility criteria during the
public meeting on March 28 and March 29, 2024, with most members
supporting the criteria establishing the types of pipe segments deemed
suitable for the program, as discussed below in individual subsections.
4. Post-GPAC Comments
During the public comment period following the GPAC meeting, an
anonymous commenter recommended PHMSA make no changes to the proposed
eligibility criteria in consideration of the GPAC recommendations,
stating they were not publicly noticed for comments and reviewed by the
public for their impact on pipeline integrity, public safety, and
environmental consequences.\88\
---------------------------------------------------------------------------
\88\ Docket ID PHMSA-2024-0005-0422 at 1-2 (Aug. 28, 2024). But
see GPAC, Class Location NPRM GPAC Voting Slides, Docket ID PHMSA-
2024-0005-0275 (Apr. 5, 2024).
---------------------------------------------------------------------------
5. PHMSA Response
PHMSA is including eligibility criteria in the final rule to ensure
that the IM alternative is only used to confirm or restore the MAOP of
pipe or segments with appropriate characteristics. PHMSA has determined
that segments with certain characteristics present an unacceptable risk
to public safety and should not be eligible. That determination is
supported by PHMSA's technical expertise and two decades of experience
administering the class location special permit program. Operators of
pipeline segments that do not meet the eligibility criteria may
continue to seek special permits to manage class location changes.
PHMSA may also consider modifying some of the eligibility criteria in
subsequent rulemaking proceedings as additional information becomes
available.
To eliminate unnecessary text and ensure consistency in the
application of the IM alternative, the eligibility criteria are
incorporated into the definition of an eligible Class 3 segment in
Sec. 192.3. Moreover, to more accurately account for their role as
compliance obligations, several of the eligibility requirements
proposed in the NPRM have been incorporated into the initial or ongoing
programmatic requirements in the IM alternative. This better reflects
that, for example, an operator can perform a pressure test on an
eligible Class 3 segment to use the IM alternative, so that requirement
is not per se a pipeline characteristic that dictates eligibility. The
gas quality assurance is also an ongoing compliance requirement, not a
criterion that needs to be satisfied beforehand to use the IM
alternative. With those retained as compliance obligations, the
eligibility criteria in Sec. 192.3 are limited to immutable pipeline
characteristics which define a segment as eligible to use the program.
Considering recommendations from the GPAC, public comments, and
additional study by the Agency, PHMSA makes certain adjustments to the
eligibility criteria in this final rule, as discussed throughout
section IV.C below.
ii. Original Class
1. Summary of Proposal
The NPRM proposed an IM alternative to manage changes to Class
[[Page 1619]]
3 locations and specifically excluded pipe moving to a Class 4
location. The NPRM referred to the segment applying the IM alternative
as the ``Class 1 to Class 3 location segment'' and proposed defining
that term in Sec. 192.3. PHMSA's class location special permit
criteria categorizes as ``probable acceptance'' Class 2 to 3 changes,
and Class 1 to Class 3 changes as ``possible acceptance.'' \89\
---------------------------------------------------------------------------
\89\ PHMSA, 2004 Special Permit Criteria at 4.
---------------------------------------------------------------------------
2. Initial Comments
Many commenters questioned whether PHMSA intended to limit the IM
alternative to Class 1 to Class 3 changes. TC Energy noted that the
NPRM seemed to include all Class 1 design pipe, even if that pipe may
first have changed to a Class 2 location before later changing into a
Class 3 location.\90\ Several commenters, including TC Energy and
Sander Resources, recommended a different term than ``Class 1 to Class
3 location segment'' to avoid uncertainty over whether this method
could include Class 2 to Class 3 changes.\91\ The Associations
suggested changing the term to ``Class 3 location change segment.''
---------------------------------------------------------------------------
\90\ See Docket ID PHMSA-2017-0151-0062 at 2.
\91\ See id.; Docket ID PHMSA-2017-0151-0064 at 3-4.
---------------------------------------------------------------------------
The Associations recommended that the IM alternative be available
for Class 2 to Class 3 changes as well, explaining that ``segments with
a [C]lass 1 design factor that experienced a change to [C]lass 2 in
prior years and then to [C]lass 3 . . . are no different than segments
that jump'' directly from Class 1 to Class 3. The Associations also
observed that Class 2 pipe is required under Sec. 192.619(a)(2) to be
pressure tested to 1.25 times MAOP at the time of installation; while
noting that ``many operators `over test' [C]lass 2 segments today'' to
the Class 3 test pressure ``to allow for the one-class bump provided
under Sec. 192.611,'' the Associations stated that ``this has not
always been common practice'' and there may be Class 2 segments with a
1.25 times MAOP pressure test that should be eligible for the IM
alternative. Extending the IM alternative to Class 2 to Class 3 changes
could avoid the higher 1.5 times MAOP pressure test required by Sec.
192.611(a)(1) or (3) for a Class 2 design pipe ``to continue operating
at its original MAOP'' after a change to a Class 3.\92\
---------------------------------------------------------------------------
\92\ Docket ID PHMSA-2017-0151-0061 at 15.
---------------------------------------------------------------------------
3. GPAC Consideration
The GPAC voted 13-0 \93\ in favor of allowing operators to apply
the IM alternative to Class 2 design pipe with a 1.25 times MAOP
pressure. The GPAC also included the 1.25 times MAOP pressure test in
its recommendations on grandfathered pipe and MAOP restoration.
---------------------------------------------------------------------------
\93\ Two votes occurred with this language, following extended
discussions. First, a vote combining this recommendation and
consideration of a public notification requirement passed 10-3.
Second, a vote isolated just to this Class 2 pressure test passed
13-0.
---------------------------------------------------------------------------
4. Post-GPAC Comments
The Associations expressed support for the GPAC recommendation,
observing that a 1.25 times MAOP pressure test provides an ``acceptable
safety factor to mitigate manufacturing and construction risks'' for
pipeline segments that experience Class 2 to Class 3 changes.\94\ The
PST also agreed with the GPAC recommendation to expand eligibility to
Class 2 design pipe, so long as the other eligibility criteria are
met.\95\
---------------------------------------------------------------------------
\94\ Associations, Comments, Docket ID PHMSA-2024-0005-0423 at 5
(Aug. 27, 2024).
\95\ PST, Comments, Docket ID PHMSA-2024-0005-0417 at 2 (Aug.
27, 2024).
---------------------------------------------------------------------------
5. PHMSA Response
PHMSA agrees that the IM alternative should be available for Class
2 to 3 changes. PHMSA's 2004 Special Permit Criteria provided Class 2
to 3 changes merited ``probable acceptance,'' even more likely to
warrant a special permit than the Class 1 to 3 changes that were marked
for ``possible acceptance.'' After beginning primarily with one class
changes, PHMSA's successful history with operators managing class
location changes from Class 2 to 3 under special permits issued since
2004 led to more regular issuance of special permits for Class 1 to 3
changes. As a result, special permits have been granted in about equal
part between segments moving from Class 1 locations into Class 3 and
those moving from Class 2 locations into Class 3. PHMSA finds it
consistent with pipeline safety to extend the applicability of this
final rule to segments that have changed from Class 2 to Class 3. As
several commenters note, this also makes clear that pipelines of Class
1 original design that were in a Class 2 location until subsequently
changing to Class 3 can use the IM alternative all the same as if they
transitioned directly from Class 1 to 3.
Ultimately, PHMSA does not expect a significant number of Class 2
to 3 changes to apply the IM alternative. Operators of these segments
are likely to use the ``one-class bump'' afforded by a pressure test in
accordance with Sec. 192.611(a)(1) or (3). A pipeline is generally
designed to tolerate the test pressure required for the next highest
class location, enabling Class 2 design pipe to conduct the ``one-class
bump'' pressure test to Class 3 design standards and complete the
obligations to manage the class change. Managing a class change by
pressure test lacks the additional program management requirements of
the IM alternative. Because Class 1 design pipe often cannot tolerate a
test pressure to two classes higher, the IM alternative enables a lower
(1.25 times MAOP) test pressure balanced with additional program
management requirements. There is no reason to apply a different
approach to Class 2 design pipe. For example, as the Associations note,
there may be some Class 2 pipe where an operator already has a 1.25
times MAOP pressure test, does not have a higher pressure test to Class
3 standards, and prefers the IM alternative program rather than perform
a new pressure test at a higher test pressure. There is no reasonable
safety basis to prohibit providing this option to operators of these
lesser included pipelines.
As discussed in section IV.B, PHMSA is replacing the proposed term
``Class 1 to Class 3 location segment'' with the defined term
``eligible Class 3 segment'' in the final rule. PHMSA agrees with the
commenters that the use of the former term in the NPRM created
uncertainty as to whether the IM alternative could be applied to Class
2 to Class 3 changes. PHMSA is eliminating that uncertainty by using
the term ``eligible Class 3 segment'' as defined in Sec. 192.3.
iii. SMYS Limitations
1. Summary of Proposal
The NPRM proposed that pipeline segments eligible for the IM
alternative must operate with an MAOP producing a hoop stress of 72
percent or less of SMYS. SMYS is an indication of the minimum stress
that a steel pipe may experience before becoming permanently deformed.
A 72 percent of SMYS limitation corresponds to the general requirement
for steel pipe in Class 1 locations to satisfy a design factor of 0.72.
PHMSA's class location change special permit criteria lists as
``probable acceptance'' pipelines operated at ``less than or equal to
72 percent of SMYS.'' \96\
---------------------------------------------------------------------------
\96\ PHMSA, 2004 Special Permit Criteria at 4.
---------------------------------------------------------------------------
2. Initial Comments
Commenters generally agreed that 72 percent of SMYS threshold is
[[Page 1620]]
appropriate. Some industry commenters sought clarification on how this
requirement would apply to Class 2 design pipe. TC Energy observed that
the NPRM seemed to permit use of the IM alternative for pipeline
segments ``operating at a hoop stress over 60 [percent] of the SMYS and
up to and including 72 [percent] of the SMYS'' that have moved to a
``Class 3 [location], independent of whether the original class
location area was Class 1 or 2.'' \97\
---------------------------------------------------------------------------
\97\ Docket ID PHMSA-2017-0151-0062 at 2.
---------------------------------------------------------------------------
3. GPAC Consideration
Public comment from members representing industry noted the long
history of the 72 percent SMYS limit, dating back to industry standards
adopted in the 1950s. Recognizing that this requirement is well
established, the GPAC did not offer a direct recommendation on the
merits of PHMSA's proposed SMYS limitations for the IM alternative. The
Committee, through its debates and votes on restoration of MAOP (see
section IV.C.xii), grandfathered pipe (see section IV.C.vi), and
vintage seam types (see section IV.C.viii), implicitly endorsed this
longstanding element as a fundamental requirement for use of the IM
alternative.
4. Post-GPAC Comments
No significant additional comments on this issue were submitted
after the GPAC.
5. PHMSA Response
The 72 percent of SMYS limitation in the IM alternative is
consistent across part 192 as the maximum safety limit of operating
steel gas pipelines.\98\ It corresponds to the 0.72 steel pipe design
factor of Class 1 pipe under Sec. 192.111. Without a design change,
the SMYS limitation for a pipeline must remain consistent with the
original design factor.
---------------------------------------------------------------------------
\98\ It is also consistent in the prevailing industry consensus
standard, ASME B31.8-2022, Sec. Sec. 840.2.2, 841.1.1(c). A design
factor of up to 0.80 is authorized for Class 1 locations in limited
circumstances in accordance with Sec. 192.620 or with a special
permit for waiving certain requirements at Sec. Sec. 192.111 and
192.201; such segments would be ineligible for the IM alternative to
class location changes.
---------------------------------------------------------------------------
In addition to retaining the 72 percent SMYS requirement, PHMSA has
added a hoop stress threshold to facilitate Class 2 design pipe
applying the IM alternative. Where a Class 2 design pipe changes to a
Class 3 location, the IM alternative requires that the operator
maintain an MAOP corresponding to a hoop stress of no more than 60
percent of SMYS. The 60 percent of SMYS limit for Class 2 design pipe
corresponds to the 0.60 steel pipe design factor of Class 2 pipe under
Sec. 192.111.
iv. Subpart J Pressure Test
1. Summary of Proposal
The NPRM proposed that an operator must have records documenting an
8-hour test in accordance with Subpart J to a minimum test pressure of
1.25 times MAOP, or that the operator perform such a pressure test
within 24 months of the class location change, for a segment to be
eligible for the IM alternative. PHMSA has consistently requested
records of a 1.25 times MAOP pressure test during consideration of
class location special permit applications.
2. Initial Comments
Commenters generally supported the proposed pressure testing
requirements. TC Energy and the Associations both observed that Subpart
J includes limited circumstances under Sec. 192.505(d) where
fabricated units and short section of pipe may be tested for four
hours, not eight.\99\ TC Energy was also concerned that specifying the
pressure test as Subpart J-compliant could, contrary to intent, exclude
tests which meet the testing requirements but were conducted before
Subpart J was adopted in 1970. NAPSR indicated that some of its members
favored requiring a new Subpart J test within 24 months of the class
change in all cases.\100\
---------------------------------------------------------------------------
\99\ See Docket ID PHMSA-2017-0151-0062 at 8; Docket ID PHMSA-
2017-0151-0061 at 27.
\100\ Docket ID PHMSA-2017-0151-0059 at 5.
---------------------------------------------------------------------------
3. GPAC Consideration
While not separately offering a recommendation as to this proposal,
the GPAC voted 13-0 to extend the 1.25 times MAOP pressure test
requirement to Class 2 design pipe during the public meeting on the
NPRM.
4. Post-GPAC Comments
The Associations repeated similar points as before requesting
allowance for those limited circumstances where Subpart J permits a 4-
hour pressure test.\101\
---------------------------------------------------------------------------
\101\ See Docket ID PHMSA-2024-0005-0423 at 15. INGAA provided
similar comments in a May 2025 response to a DOT request for
information, see INGAA, Comments, Docket ID DOT-OST-2025-0026-0872,
6-7 (May 5, 2025), regarding Ensuring Lawful Regulation; Reducing
Regulation and Controlling Regulatory Costs, 90 FR 14593 (Apr. 4,
2025).
---------------------------------------------------------------------------
5. PHMSA Response
A 1.25 times MAOP pressure test is required to use the IM
alternative. This same test pressure requirement applies to Class 1 and
Class 2 design pipe using the IM alternative. To meet this requirement,
an operator may rely on a prior pressure test or conduct a new pressure
test, consistent with the proposal in the NPRM.\102\ As PHMSA has
stated previously, ``the safety margin [provided by the test] rather
than the act of retesting is the critical factor under Sec. 192.611.''
\103\ Operators must comply with the pressure testing requirement
within the initial, 24-month compliance window.
---------------------------------------------------------------------------
\102\ See NPRM, 85 FR at 65175 (proposed Sec. 192.618(a)(4)(v))
(``Pipe that has not been pressure tested in accordance with subpart
J for 8 hours at a minimum test pressure of 1.25 times MAOP (unless
the segment passes a subpart J pressure test for a minimum of 8
hours at a minimum pressure of 1.25 times MAOP within 24 months
after the Class 1 to Class 3 location segment change'' (emphasis
added)).
\103\ Confirmation or Revision of Maximum Allowable Operating
Pressure; Alternative Method, 53 FR 1043, 1044 (proposed Jan. 15,
1988).
---------------------------------------------------------------------------
The test hold time must meet the requirements of Subpart J. This
addresses those limited circumstances where an 8-hour test is not
required under Sec. 192.505(d). In most cases, Subpart J will require
at least an 8-hour test hold time. But this provides for, as noted by
INGAA and TC Energy, use of the IM alternative for fabricated units and
short sections of pipe where a shorter duration pressure test is
permitted under Sec. 192.505(d). PHMSA understands that tests using
the hold time designated by Subpart J provide an equivalent and
acceptable level of safety compared to the proposed requirement for an
8-hour post-installation strength test--a 4-hour test under Sec.
192.505(d) applies only in narrow cases for ``small valve and gate
sites or any other small segments of pipeline that have been tested
off-site.'' \104\ Because fabricated units or short sections of pipe
are aboveground during the preinstallation test, and operators can
continuously and directly inspect them for leaks during the test, PHMSA
sees no reason to disadvantage these tests against the application of
Sec. 192.611(c) or (d).
---------------------------------------------------------------------------
\104\ INGAA, Docket ID DOT-OST-2025-0026-0872, 6-7.
---------------------------------------------------------------------------
The pressure test must be for a duration consistent with the
requirements in Subpart J, to a pressure of at least 1.25 times MAOP,
to use the IM alternative. An operator may use a prior test, as PHMSA
has previously clarified that the duration of the test is the key
factor for a pressure test to manage a class change, rather than its
date.\105\ A test performed after 1970 must meet the requirements in
Subpart J. A test performed before 1970 must have been for a consistent
duration as under Subpart J. An operator without
[[Page 1621]]
such a test may successfully complete one during the initial 24-month
compliance window and then benefit from this IM alternative.
---------------------------------------------------------------------------
\105\ Confirmation or Revision of Maximum Allowable Operating
Pressure; Alternative Method, 54 FR 24173, 24174 (June 6, 1989).
---------------------------------------------------------------------------
Some commenters sought clarification regarding application to pre-
1970 pressure tests. PHMSA addressed this very issue in a late 1980s
rulemaking, noting that many pressure tests performed prior to the
establishment of the Federal Pipeline Safety Regulations (and so before
the Subpart J requirements were established) met the industry best
practice or standard in place at the time and could provide an adequate
level of safety to manage a class change.\106\ A pre-1970 pressure test
for a hold time of 8 hours, except where a 4-hour duration would be
permitted consistent with Subpart J, provides equivalent safety.
---------------------------------------------------------------------------
\106\ See 53 FR at 1044; 54 FR at 24174 (permitting ``any prior
test pressure held for at least 8 hours''). See also Minimum Federal
Safety Standards for Gas Pipelines, 35 FR 5724 (proposed Apr. 8,
1970) (noting wide similarity between the Minimum Standards for
pressure testing with pre-1970 industry standards).
---------------------------------------------------------------------------
v. TVC Material Records
1. Summary of Proposal
The NPRM proposed requiring that a pipeline segment have traceable,
verifiable, and complete (TVC) material records to be eligible for the
IM alternative.\107\ The TVC records had to include the diameter, wall
thickness, grade, seam type, yield strength, and tensile strength \108\
of the class change segment.
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\107\ Further explanation of TVC records is available at 2019
Safety of Gas Transmission Rule, 84 FR at 52218-19 and PHMSA, [First
Batch of] Frequently Asked Questions for the [2019 Safety of Gas
Transmission Rule]: MAOP Establishment and Reconfirmation FAQs, FAQ-
30 (Sept. 15, 2020), available at: https://www.phmsa.dot.gov/sites/phmsa.dot.gov/files/2023-06/Batch-1-FAQs-PHMSA-2019-0225-9-15-20.pdf.
\108\ Ultimate tensile strength, or tensile strength as used in
this final rule, is defined as the maximum stress that a material
can withstand while being stretched or pulled before breaking. This
is compared to yield strength, which is the stress at which a
material starts to deform permanently.
---------------------------------------------------------------------------
The TVC records requirement proposed in the NPRM is consistent with
PHMSA's longstanding practice of requesting records related to, among
other things, testing, in-line inspections, and cathodic protection
when reviewing class location special permit applications. Class
location special permits have previously required TVC pressure test
records and imposed additional testing and examination requirements on
pipeline segments lacking such records.
2. Initial Comments
Commenters supported the proposed TVC records requirement. The
Associations suggested that segments without complete TVC material
records should be allowed to obtain those records within the initial
24-month compliance window using the process prescribed in Sec.
192.607.\109\ The Associations opposed requiring TVC records of tensile
strength, which they characterized as a data point ``without practical
utility'' that is ``not required for anomaly evaluation or MAOP
calculations, whereas diameter, wall thickness, grade, seam type, and
yield strength are needed for those calculations.'' \110\
---------------------------------------------------------------------------
\109\ See Docket ID PHMSA-2017-0151-0061 at 20-21.
\110\ Docket ID PHMSA-2017-0151-0061 at 21.
---------------------------------------------------------------------------
3. GPAC Consideration
Industry representatives on the GPAC stressed that operators should
be allowed to use the IM alternative so long as TVC records are
collected within the initial 24-month compliance period. Industry GPAC
members offered that TVC records of tensile strength are not necessary
because, while yield strength plays a role in design and safety
decisions, tensile strength is only used as a buffer or an extra
measure of confidence. Public representatives on the GPAC noted that
the specification API 5L \111\ sets limits for both yield strength and
tensile strength for steel line pipe and suggested that having TVC
records with information about each would likely be valuable.
---------------------------------------------------------------------------
\111\ API Specification 5L, Line Pipe (46th ed. Apr. 6, 2018).
---------------------------------------------------------------------------
The GPAC voted 12-0 in favor of allowing operators to use Sec.
192.607 to obtain any necessary missing pipe properties within 24
months of the class change. The Committee also recommended that PHMSA
consider not requiring the TVC records for tensile strength.
4. Post-GPAC Comments
The Associations repeated similar points as before the GPAC
meeting.\112\ An anonymous commenter emphasized the importance of TVC
records to include ultimate tensile strength, stating that operators
cannot obtain an accurate value for pipe steel yield strength without
that information. The anonymous commenter also noted that TVC records
are required under Sec. Sec. 192.619 and 192.624, and suggested
barring use of the IM alternative if an operator lacks such
records.\113\
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\112\ See Docket ID PHMSA-2024-0005-0423 at 6.
\113\ See Docket ID PHMSA-2024-0005-0415 at 1.
---------------------------------------------------------------------------
5. PHMSA Response
PHMSA is retaining the TVC records requirement in the final rule.
The IM alternative requires an operator to have or obtain TVC records
for the diameter, wall thickness, grade, seam type, yield strength, and
tensile strength of an eligible Class 3 segment. Consistent with the
industry comments and GPAC's unanimous recommendation, an operator may
obtain any necessary TVC records during the initial 24-month compliance
window by following the requirements in Sec. 192.607. Section 192.607
prescribes a comprehensive process for verifying and documenting the
material properties and attributes of pipeline segments through the
performance of nondestructive or destructive tests, examinations, and
assessments.
The IM alternative imposes a more stringent deadline for completing
the materials verification process. Section 192.607 itself only applies
on an ``opportunistic'' or ``as needed'' basis, i.e., operators may
verify the material properties and attributes of pipeline segments on a
continuous or rolling basis.\114\ Section 192.611(a)(4) requires that
any necessary TVC records for an eligible Class 3 segment be obtained
within the initial 24-month compliance window. This accelerates the
collection of TVC records under Sec. 192.607 and advances public
safety.
---------------------------------------------------------------------------
\114\ Section 192.607(c) requires operators without adequate
documentation of pipeline material properties and characteristics to
``develop and implement procedures for conducting nondestructive or
destructive tests, examinations, and assessments in order to verify
the material properties of aboveground line pipe and components, and
of buried line pipe and components.'' As explained in FAQs,
``[m]aterial properties, when unknown, must the gathered wherever
the pipeline is excavated as defined in Sec. 192.607(c). The data
collection process for material properties must be completed however
prior to completing the reconfirmation method [in Sec. 192.624] if
that method requires material properties.'' PHMSA, First Batch of
FAQs for the 2019 Safety of Gas Transmission Rule, FAQ-17 (Sept. 15,
2020).
---------------------------------------------------------------------------
In response to the GPAC's recommendation, PHMSA considered whether
to exclude tensile strength from the TVC records requirement but
decided to retain that provision. Many methodologies, including R-
STRENG, B31G, and APTITUDE,\115\ use tensile
[[Page 1622]]
strength to calculate the predicted failure pressure or remaining life
of a pipeline in accordance with Sec. 192.712, or require or use as an
input the ultimate tensile strength of the pipe being modeled.\116\
Having TVC records of the tensile strength for eligible Class 3
segments facilitates compliance with these provisions. Operators also
benefit from having information about low or variable ultimate tensile
strength properties in high-strength steel pipelines, which presents
integrity concerns.\117\
---------------------------------------------------------------------------
\115\ Y.S. Wang, Pipeline Research Committee Project, PRCI PR-3-
805 (R-STRENG), A Modified Criterion for Evaluating the Remaining
Strength of Corroded Pipe, (Dec. 22, 1989), available at: https://doi.org/10.55274/R0012046 (software for evaluating the remaining
strength of corroded pipe); ASME, American Standard Code for
Pressure Piping, ASME/ANSI B31G-1991, Manual for Determining the
Remaining Strength of Corroded Pipelines (June 27, 1991, Reaffirmed
2004) (evaluation of pipeline metal loss); APTITUDE: Crack
Evaluation For Pressurized Cylinders, Calculate A Predicted Failure
Pressure And Remaining Life, Structural Integrity Assocs. (Aug.
2022) available at: https://www.structint.com/wp-content/uploads/2022/08/APTITUDE-Crack-Evaluation-for-Pressurized-Cylinders.pdf
(model that calculates predicted failure pressure of crack or crack-
like anomalies and ``incorporates . . . if available, measured
material properties such as material fracture toughness, yield
strength, and ultimate tensile strength'').
\116\ See PHMSA, Second Batch of Frequently Asked Questions for
the [2019 Safety of Gas Transmission Rule]: MAOP Establishment and
Reconfirmation FAQs, FAQ-62 (Apr. 19, 2023), available at: https://www.phmsa.dot.gov/sites/phmsa.dot.gov/files/2023-05/Batch-2-RIN-1-FAQs.pdf.
\117\ See PHMSA, ADB-09-01, Pipeline Safety: Potential Low and
Variable Yield and Tensile Strength and Chemical Composition
Properties in High Strength Line Pipe, 74 FR 23930, 23931 (May 21,
2009).
---------------------------------------------------------------------------
PHMSA does not expect that obtaining tensile strength information
will impose an undue burden on pipeline operators. An operator
typically will receive tensile strength data in conducting the tests,
examinations, and assessments needed to verify other properties and
attributes of the pipe.\118\ Only in the absence of TVC pipe grade
records would an operator be required to obtain both yield strength and
ultimate tensile strength information.\119\ An operator may also be
able to use an assumed value where actual tensile strength information
is lacking. Common practice, as illustrated by a special permit issued
to Alliance Pipeline, indicates that, at least in the case of modern
pipe, an operator can assume that the ultimate tensile strength is the
SMYS plus an additional 10,000 pounds per square inch (psi).\120\ This
assumption would need to be validated for older pipe vintages.\121\
---------------------------------------------------------------------------
\118\ Common destructive tests will provide measurements of the
yield strength, tensile strength, and other material properties of
the specimen at the same time. See ASTM Intl'l, E8/E8M-22, Standard
Test Methods for Tension Testing of Metallic Materials, Sec. Sec.
7.7, 7.10 (2022). Note that destructive testing is not the only
method to determine material properties under Sec. 192.607.
\119\ See PHMSA, Second Batch of FAQs for the 2019 Safety of Gas
Transmission Rule, FAQ-62 (``If an operator does not have TVC
records demonstrating the grade, the operator must conduct future
testing for both minimum yield strength and ultimate tensile
strength per Sec. 192.607(c)(1) and (2).'' (emphasis in original)).
\120\ See Kiefner & Assoc., Inc., Validity of Standard Defect
Assessment Methods for the Alliance Pipeline Operating at 80 percent
of SMYS (Sept. 6, 2018), available at: https://www.phmsa.dot.gov/sites/phmsa.dot.gov/files/docs/technical-resources/pipeline/gas-transmission-integrity-management/65316/validityofcorrosionassessmentsr1.pdf.
\121\ See Barry Oland, Mark Lower & Simon Rose, Oak Ridge Nat'l
Lab., Review of Methods for Determining the Strength of Corroded
Natural Gas Pipelines Based on Actual Remaining Wall Thickness (May
2019), available at: https://info.ornl.gov/sites/publications/Files/Pub126720.pdf.
---------------------------------------------------------------------------
vi. Grandfathered or Alternative MAOP
1. Summary of Proposal
The NPRM proposed that segments with an MAOP established under
Sec. 192.619(c) or (d) would not be eligible for the IM alternative.
Section 192.619(c), commonly referred to as the ``grandfather clause,''
allows operators to establish the MAOP of pipeline segments in
existence before the adoption of the original version of part 192 based
solely on the highest actual operating pressure experienced during a
five-year historical window that runs from July 1, 1965, to July 1,
1970. Section 192.619(d) refers to the alternative MAOP provisions in
Sec. 192.620, which permits a pipeline to operate with a less
conservative design factor than would ordinarily be allowed in
accordance with Sec. 192.111 (i.e., above 0.72 for Class 1 locations,
above 0.67 for Class 2 locations, and 0.56 for Class 3 locations).
2. Initial Comments
While acknowledging that Sec. 192.619(c) allows some grandfathered
pipelines to operate at hoop stresses above 72 percent of SMYS, TC
Energy stated that an operator should be permitted to use the IM
alternative for these pipelines if adequate documentation is available
to establish an MAOP under Sec. 192.619(a) and the operator is willing
to comply with the applicable requirements, including the 72 percent of
SMYS limitation. Assuming those conditions are met, TC Energy argued
that grandfathered pipelines ``should be no less safe than [any other]
pipelines that are currently operating at or below 72 [percent] of the
SMYS that are eligible for'' the IM alternative.\122\
---------------------------------------------------------------------------
\122\ Docket ID PHMSA-2017-0151-0062 at 5.
---------------------------------------------------------------------------
3. GPAC Consideration
The GPAC recommended, with a unanimous 12-0 vote, that PHMSA
consider whether to allow pipe segments operating in accordance with
Sec. 192.619(c) or (d) to be eligible for the IM alternative, provided
the segment has an appropriate 1.25 times MAOP pressure test and an
equivalent or greater level of pipeline safety can be maintained.
4. Post-GPAC Comments
The Associations and Enbridge agreed with the GPAC's unanimous
recommendation. The Associations stated that ``certain grandfathered
pipe . . . with a pressure test greater than or equal to 1.25 [times]
MAOP . . . can continue to be safely managed.'' \123\ Mr. Zamarin
agreed, adding that the 1.25 times MAOP pressure test to permit
pipelines operated in accordance with Sec. 192.619(c) or (d) would
provide the same safety assurance as other qualifying pipeline
segments.\124\ Mr. Drake did as well, noting that, ``in many cases,
[these grandfathered pipelines] have been pressure tested to at least
1.25 times the MAOP and, in some cases, for durations exceeding 24
hours,'' which essentially meets or exceeds current Subpart J pressure
testing requirements.\125\ An anonymous commenter was concerned that
``[a]llowing pipeline MAOPs above 72 [percent] SMYS was not publicly
noticed'' so any allowance of pressure above that threshold on
pipelines operated in accordance with Sec. 192.619(c) or (d) should be
``re-notice[d] . . . for public comment.'' \126\
---------------------------------------------------------------------------
\123\ Docket ID PHMSA-2024-0005-0423 at 10. See also Enbridge,
Comments, Docket ID PHMSA-2024-0005-0418 at 2 (Aug. 27, 2024).
\124\ See Chad Zamarin, Comments, Docket ID PHMSA-2024-0005-0420
at 3 (Aug. 26, 2024).
\125\ Docket ID PHMSA-2024-0005-0419 at 3.
\126\ Docket ID PHMSA-2024-0005-0415 at 1.
---------------------------------------------------------------------------
5. PHMSA Response
PHMSA is not retaining the broad Sec. 192.619(c) and (d)
exclusions in the final rule. Two primary concerns led to these
exclusions in the NPRM: (1) that pipelines with MAOPs established under
Sec. 192.619(c) and (d) may be operating at design factors above those
specified at Sec. 192.111 and at a stress level exceeding 72 percent
SMYS, and (2) that pipelines with MAOPs established under Sec.
192.619(c) and (d) may lack appropriate pressure test records or
records of materials to properly establish the design pressure of the
pipeline. Because operators must address both concerns to use the IM
alternative, the Sec. 192.619(c) and (d) exclusions are unnecessary.
The requirements in the final rule effectively prohibit pipelines with
MAOPs established under Sec. 192.619(c) and (d) from using the IM
alternative, eliminating the need for the exclusion proposed in the
NPRM.\127\
---------------------------------------------------------------------------
\127\ See NPRM, 85 FR at 65159 (``PHMSA proposes that operators
of pipelines that were previously operating in accordance with Sec.
192.619(c) that operate at or below 72 percent SMYS be eligible for
the IM alternative only if the operator pressure tests any of those
pipelines that do not have a record of a previous pressure test
within 24 months after the class location change and have pipe
material records for the segment.'').
---------------------------------------------------------------------------
[[Page 1623]]
As to the first concern, the IM alternative requires the MAOP of an
eligible Class 3 segment to be confirmed or revised in accordance with
the design limits in Sec. 192.619(a), rather than the grandfather
clause in Sec. 192.619(c). Section 192.611(a)(4) explicitly recognizes
that limitation and states that the MAOP of a segment confirmed under
the IM alternative may not exceed 72 percent of SMYS. As to the second
concern, the MAOP of an eligible Class 3 segment may only be confirmed
or revised under the IM alternative if an operator satisfies the
pressure testing and materials properties requirements, both of which
are subject to recordkeeping provisions. These recordkeeping provisions
directly address PHMSA's concerns about the potential absence of TVC
design and test pressure records. For these reasons, there is no basis
for retaining the proposed Sec. 192.619(c) and (d) exclusions in the
final rule.
vii. Wrinkle Bends and Geohazards
1. Summary of Proposal
The NPRM proposed to exclude pipeline segments with wrinkle bends
from the IM alternative. Wrinkle bends are defined at Sec. 192.3 as a
bend formed in the field during construction that has ripples exceeding
certain amplitude and length parameters. PHMSA has historically
disfavored pipe segments with wrinkle bends when considering
applications for class location special permits due to safety
concerns.\128\
---------------------------------------------------------------------------
\128\ See PHMSA, 2004 Special Permit Criteria at 3.
---------------------------------------------------------------------------
2. Initial Comments
TC Energy recommended a ``case-by-case'' ILI assessment of wrinkle
bends, stating that ``[w]rinkle bends are generally stable features and
excluding them entirely would do little to benefit pipeline safety,''
noting the low failure rates across approximately 230,000 wrinkle bends
in service.\129\ The Associations suggested limiting this exclusion to
those wrinkle bends presenting a geohazard threat.\130\ Given that
``only about 1 in 8,000 wrinkle bends have failed over approximately
seventy years of service,'' they saw ``little safety benefit'' to
broadly excluding all wrinkle bends. The Associations were also
concerned that requiring pipe replacement could create new risk of
failure by presenting outside force on wrinkle bends just outside the
class change segment.\131\
---------------------------------------------------------------------------
\129\ Docket ID PHMSA-2017-0151-0062 at 5.
\130\ ``Geohazard threats'' are also known as geological
hazards, geophysical hazards, or geo-technical hazards. PHMSA refers
to these phenomena as ``geohazards.'' Geohazards include soil
movement from natural causes--e.g., earthquakes, landslides,
sinkholes, erosion, and ground subsistence--and man-made causes--
e.g., construction activities. These hazards can occur independent
of the product transported and have been observed in all 50 U.S.
States and territories. See Stephen L. Slaughter, Landslide Basics,
U.S. Geological Survey, available at: https://www.usgs.gov/programs/landslide-hazards/landslide-basics (last visited Aug. 18, 2025).
\131\ Docket ID PHMSA-2017-0151-0061 at 20.
---------------------------------------------------------------------------
The NTSB also encouraged PHMSA to consider excluding from the IM
alternative pipe segments with a ``known history of pipe movement,''
i.e., geohazards, noting the ``significant risk to the integrity of
natural gas pipelines'' geohazards can pose.\132\
---------------------------------------------------------------------------
\132\ Docket ID PHMSA-2017-0151-0055 at 4.
---------------------------------------------------------------------------
3. GPAC Consideration
Industry GPAC members noted that failures in segments containing
wrinkle bends occur because those bends are not as strong as normal
bends, which is why soil movement near a wrinkle bend can cause an
incident. Public comments from industry representatives during the GPAC
meeting added that while ``there should be no wrinkle bends in
geohazard areas,'' wrinkle bends in non-geohazard areas should remain
eligible for the IM alternative. GPAC members representing the public
supported the eligibility criteria related to geohazards and
recommended the identification and mitigation of geohazards under the
IM alternative. GPAC members generally agreed that geohazards can
constitute a threat to pipeline operations and safety and should be
mitigated under the IM alternative. Members representing the public
suggested that no pipe segment within 600 feet of a known geohazard
should be eligible for the IM alternative, while members representing
the industry disagreed with a blanket eligibility provision tied to the
presence of geohazards near a pipeline segment.
The GPAC offered two recommendations that are relevant to the
exclusion for wrinkle bends. First, with a 9-3 vote, the GPAC
recommended that the IM alternative require operators to survey and
assess a segment for an identified geohazard using procedures for pipe
movement. This vote further recommended that, until PHMSA addresses
geohazards in a future rulemaking, a pipeline segment should not be
eligible for the IM alternative: (1) if an identified geohazard affects
or could affect within 600 feet of the class change segment; or (2) if
an identified geohazard affects or could affect pipe movement within
600 feet of the class change segment. Second, with a 12-0 vote, the
GPAC recommended that where a geohazard is found on a segment using the
IM alternative, PHMSA should require operators to develop procedures on
how to evaluate and remediate the geohazard threat. This vote also
recommended that the procedures operators develop address certain
specified elements, e.g., inspection tools, inspection intervals,
patrols, employee and contractor training, finite element analysis, and
girth weld repairs.
4. Post-GPAC Comments
Williams supported the recommendation that operators develop
procedures to evaluate, remediate, and mitigate geohazard threats for a
segment to be eligible for the IM alternative. Williams noted how
``[i]n many circumstances, an operator can stabilize this threat. Where
stabilization is adequately demonstrated, the segment should be
eligible for inclusion into an operator's IM program.'' \133\ An
anonymous commenter agreed that PHMSA should require the assessments
and procedures discussed at the GPAC meeting related to geohazards
because the rule allows Class 1 design pipe to remain in a Class 3
location.\134\
---------------------------------------------------------------------------
\133\ See Docket ID PHMSA-2024-0005-0421 at 10.
\134\ See Docket ID PHMSA-2024-0005-0415 at 1.
---------------------------------------------------------------------------
The Associations opposed using geohazards as an independent
eligibility factor, arguing that the GPAC recommendation to require
operators to develop geohazard procedures was ``duplicative and
unnecessary.'' ``[G]eohazards can be extremely unique,'' they argued,
making a ``blanket geohazard eligibility'' exclusion unnecessary. The
Associations further argued that ``Subpart O already provides a
rigorous and appropriate approach to manage geohazard threats,'' noting
that Sec. 192.917 requires that ``operators must evaluate potential
weather related and outside force damage, including consideration of
seismicity, geology, and soil stability.'' \135\
---------------------------------------------------------------------------
\135\ Docket ID PHMSA-2024-0005-0423 at 9-10.
---------------------------------------------------------------------------
The Associations also observed that ``[i]dentification of weather-
related and outside force damage threats trigger the same [IM]
requirements to assess, monitor, remediate, and adopt preventative and
mitigative measures as any other integrity-related threat.'' The
Associations noted that Sec. 192.613(c) requires operators to assess
their pipelines 72 hours after extreme weather events or natural
disasters likely to damage pipeline facilities, and
[[Page 1624]]
suggested that such measures already ensure ``operators will quickly
evaluate the safety of the pipeline and determine if further actions
are necessary to address a geohazard or other impacts to the
pipeline.'' \136\
---------------------------------------------------------------------------
\136\ Id. at 9-10.
---------------------------------------------------------------------------
5. PHMSA Response
PHMSA is retaining the wrinkle bend exclusion. The GPAC's proposal
to limit the exclusion to wrinkle bends on segments with an identified
geohazard risk does not address all concerns associated with using the
IM alternative, though an operator may seek a special permit from PHMSA
to remove the exclusion on a case-by-case basis.
PHMSA has historically excluded pipe segments with wrinkle bends
from consideration under the class location special permit program.
Operators used obsolete construction practices in forming wrinkle bends
on pipelines prior to emergence of more modern bending technologies.
Wrinkle bends are generally prohibited in pipelines that operate at a
hoop stress of 30 percent or more of SMYS under Sec. 192.315(a); they
are known to fail in response to movement from temperature changes and
other factors.\137\
---------------------------------------------------------------------------
\137\ John F. Kiefner, Kiefner & Assoc., Inc., Final Report No.
05-12R, Evaluating the Stability of Manufacturing and Construction
Defects in Natural Gas Pipelines (Apr. 2007), available at: https://www.phmsa.dot.gov/sites/phmsa.dot.gov/files/docs/technical-resources/pipeline/gas-transmission-integrity-management/65321/evaluatingstabilityofdefects.pdf.
---------------------------------------------------------------------------
Wrinkle bends experience failures which may not be detectable using
modern ILI technology. Suitability for assessment using ILI--or another
appropriate integrity assessment method--is a fundamental element of
the IM alternative. PHMSA's understanding is that ILI tools may not yet
be able to conduct an effective integrity assessment of wrinkle bends.
A study on ILI tools commissioned for PHMSA in 2004 supports that
conclusion, noting that ``[w]hile current ILI tools can accurately
detect localized pitting and general metal loss in cylindrical pipe
segments (i.e., in sections without wrinkles or buckles) and
standardized procedures are available to assess the pressure integrity
of the pipe accounting for metal loss, it is unclear whether current
ILI technology can accurately detect these same defects if they occur
on or near a wrinkle or buckle because the effects of the pipe wall
local curvature on the ILI tool signals can cause inaccuracies.'' \138\
PHMSA acknowledges that ILI technology, data analysis, and
understanding of wrinkle bends is improving, but failures in 2010 and
2024 following ILI tool runs suggest room for further improvement.\139\
Moreover, though the rate of rupture with wrinkle bends is low--most
wrinkle bend failures are expressed as leaks--that may be aided by
Sec. 192.315 restricting pipe with wrinkle bends from being operated
at or above 30 percent SMYS.
---------------------------------------------------------------------------
\138\ Michael Baker Jr., Inc, TTO No. 11 Final Report, Pipe
Wrinkle Study (Oct. 2004), available at: https://www.phmsa.dot.gov/sites/phmsa.dot.gov/files/docs/technical-resources/pipeline/gas-transmission-integrity-management/65286/tto11pipewrinklestudyfinalreportoct2004.pdf. PHMSA notes that more
recent ruptures also suggest that ILI technology may be limited in
its ability to detect anomalies on pipe with wrinkle bends, as 7 of
the 10 wrinkle-bend-related failures from 2009 to 2024 occurred
within 7 years of the most recent axial magnetic flux leakage (MFL)
and geometry/deformation ILI tool assessments.
\139\ PHMSA, Pipeline Incident Flagged Files, Gas Transmission &
Gathering 2010 to Present, Incident Rep. No. 20100106-15588 (Dec.
21, 2010) and Incident Rep. No. 20240029-39272 (Mar. 1, 2024)
(Pipeline Incident Files). See also id. Incident Rep. No. 20240029-
41286 (Feb. 03, 2024) (wrinkle-bend related failure in Mississippi).
In this case, the failure analysis found that ILI plus remediation
criteria would not have prevented the incident, though the improved
remediation criteria may have prevented nearby wrinkle bend failure
that occurred in 2011, one year after an MFL ILI survey had been
conducted. In the Matter of Tennessee Gas Pipeline Co., LLC, CPF No.
2-2024-009-CAO, 2024 WL 664786 (PHMSA Feb. 9, 2024), available at:
https://primis.phmsa.dot.gov/enforcement-documents/22024009CAO/22024009CAO_Corrective%20Action%20Order%20(Amended)_02092024_(24-
298988)_text.pdf. The failure analysis further found that the 2024
failure mechanism was different than the 2011 failure, and the 2024
failure was not associated with a previous repair.
---------------------------------------------------------------------------
PHMSA disagrees with the Associations' concern that pipe
replacement activity might introduce new outside forces that could
cause more wrinkle bends failures. Excluding pipe segments with wrinkle
bends from the IM alternative should not result in additional outside
forces to nearby segments if operators exhibit due care in performing
construction activities. PHMSA expects operators to install pipe
consistent with the requirements at Sec. 192.319 ``so that the pipe
fits the ditch so as to minimize stresses and protect the pipe
coating'' and backfilling prevents damage to the pipe.
For these reasons, the IM alternative excludes pipe segments with
wrinkle bends regardless of whether the wrinkle bend is in an area with
an identified geohazard threat, consistent with the proposal and
PHMSA's longstanding practice not to issue special permits to these
segments. PHMSA continues to find it inconsistent with historical leak
and failure history, current state of assessment technology, and the
safety of populations near pipeline segments that have experienced a
change in class location, for pipeline segments with wrinkle bends to
be eligible for the IM alternative.
The wrinkle bend exclusion cannot be effectively narrowed to only
those associated with an identified geohazard threat as recommended by
the GPAC. Wrinkle bends are vulnerable to cold-weather conditions \140\
and can fail more quickly due to geohazards, but that is not the only
concern. While wrinkle bend failures sometimes involve areas of
understood and studied geohazards,\141\ PHMSA's analysis of historical
failures involving wrinkle bends shows that they do not always
correspond with the threat of land or pipe movement. For example, a
2015 wrinkle bend failure was caused by tensile overload,\142\ and in
2023, a pipeline failed under a North Carolina highway due to corrosion
in a wrinkle bend.\143\ Neither involved a geohazard. A wrinkle bend
exclusion limited to geohazard interactions might allow this type of
threat into the IM alternative program, which the program is not suited
to manage at this time.
---------------------------------------------------------------------------
\140\ See, e.g., PHMSA, Pipeline Incident Files, Incident Rep.
No. 20210024-35593 (Feb. 20, 2021) (observing that ``the temperature
drop during the polar vortex in the [prior] week could have
contributed to the failure in the wrinkle bend'').
\141\ Between 2009 and 2024, 9 of 10 reported incidents
involving wrinkle bend failures occurred between November and March
when soil temperatures are at their seasonal lows, causing pipe to
be at its most brittle.
\142\ PHMSA, Pipeline Incident Files, Incident Rep. No.
20150040-17403 (Mar. 30, 2015) (noting operator was ``unable to
determine the source . . . of the tensile forces, but the tensile
overload does not appear to be a result of third-party damage or
observable land movement'').
\143\ PHMSA, Pipeline Incident Files, Incident Rep. No.
20230019-39287 (Feb. 22, 2023).
---------------------------------------------------------------------------
PHMSA finds that the wrinkle-bend-related geohazard concerns
identified by GPAC members are captured under the wrinkle bend
exclusion in the IM alternative. As several commenters noted, other
current regulations and PHMSA guidance pertain to managing geohazard
threats safely under the existing regulations. Section 192.917(a)(3)
requires operators to identify ``weather related and outside force
damage, to include consideration of seismicity, geology, and soil
stability of the area.'' Section 192.613(c)(2) requires operators to
assess their pipelines 72 hours after extreme weather events or natural
disasters deemed likely to damage pipeline facilities via scouring,
movement of the soil surrounding the pipeline, or movement of the
pipeline. These geohazard mitigations occur on an ongoing basis.\144\
Additional, specific
[[Page 1625]]
requirements for addressing geohazards near segments applying the IM
alternative are not necessary at this time.
---------------------------------------------------------------------------
\144\ In 2022, PHMSA issued an updated advisory bulletin
addressing geohazard identification and mitigation, and encouraged
operators to ``enhance their preparations and procedures beyond the
minimum Federal standards and to address the unique threats,
vulnerabilities, and challenges of each individual pipeline
facility.'' PHMSA, ADB-2022-01, Pipeline Safety: Potential for
Damage to Pipeline Facilities Caused by Earth Movement and Other
Geological Hazards, 87 FR 33576, 33579 (June 2, 2022).
---------------------------------------------------------------------------
Accordingly, PHMSA disagrees with the GPAC's two recommendations
regarding geohazards. While geohazards are a threat to the integrity of
pipelines nationwide, the wrinkle-bend-related geohazard concerns
identified by GPAC members are adequately addressed by the wrinkle bend
exclusion in the IM alternative.
viii. Vintage Seam Types
1. Summary of Proposal
The NPRM proposed to exclude from the IM alternative pipe with
seams manufactured by certain methods, including direct current (DC)
electric resistance welding (ERW), low-frequency (LF) ERW, electric
flash welding (EFW), or lap welding. PHMSA also proposed to exclude any
pipe with a listed longitudinal joint factor at Sec. 192.113 less than
1.0.
PHMSA has historically treated these vintage seam types as
requiring a ``substantial justification'' to obtain a class location
special permit.\145\ PHMSA has issued several special permits to
segments containing LF-ERW and EFW seams after completing
individualized technical reviews, subject to certain additional
integrity conditions. The additional conditions included a requirement
that the segment be subject to a pressure test of 100 percent SMYS or
replaced. Some special permits have been issued without requiring
replacement of the segment.
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\145\ PHMSA, 2004 Special Permit Criteria at 4.
---------------------------------------------------------------------------
2. Initial Comments
Accufacts expressed that IM assessments and repairs using ILI tools
are not sufficient to demonstrate that Class 1 design pipe with these
seam types are fit for service in Class 3 locations, and that such pipe
is, ``at this time, not appropriate for ILI assessment'' and the IM
alternative.\146\ The PST generally lauded all proposed eligibility
restrictions from the NPRM, including the seam type exclusion.\147\
---------------------------------------------------------------------------
\146\ Docket ID PHMSA-2017-0151-0058 at 3.
\147\ See Docket ID PHMSA-2017-0151-0063 at 4-5.
---------------------------------------------------------------------------
The Associations and TC Energy opposed PHMSA's proposal to exclude
all pipeline segments with the identified vintage seam types, arguing
that the integrity of such segments could be managed effectively
through an IM program because ``weld flaws are generally considered
stable if they have been successfully tested to 1.25 [times] MAOP.''
\148\ The Associations referenced PHMSA research for seam threat
management, including a 2013 Battelle report on longitudinal ERW seam
failures and a 2007 Kiefner and Associates report evaluating the
stability of manufacturing and construction defects in natural gas
pipelines. The Associations also cited PHMSA data indicating that
``manufacturing-related failures on onshore gas transmission pipelines
have declined precipitously over the past two decades--including . . .
a 75 [percent] decrease since the PG&E failure in San Bruno
[California] in 2010,'' and noted that incidents are rare on pipelines
managed under Subpart O's IM program.\149\
---------------------------------------------------------------------------
\148\ Docket ID PHMSA-2017-0151-0061 at 16; see TC Energy,
Docket ID PHMSA-2017-0151-0062 at 4.
\149\ Docket ID PHMSA-2017-0151-0061 at 16.
---------------------------------------------------------------------------
TC Energy stated that they have ``successfully managed risks
associated with EFW and LF-ERW [seams] through continuous improvement
utilizing [electromagnetic acoustic transducer ILI] inspections,
proprietary crack assessment tools, risk analysis, and additional
preventative and mitigative measures.'' \150\ The Associations noted
that the proposal in the NPRM would require operators to assess for the
threat of hard spots on a class change segment, and that operators
``could run a hard spot ILI tool or equivalent assessment method and
remediate hard spots that do not meet API 5L requirements.'' \151\ TC
Energy also noted that ``many existing class change special permits
cover EFW and LF-ERW pipe'' with no leaks or incidents reported ``on
these class change special permit segments[,] supporting that these
threats can be safely managed.'' \152\
---------------------------------------------------------------------------
\150\ Docket ID PHMSA-2017-0151-0062 at 4.
\151\ Docket ID PHMSA-2017-0151-0061 at 16.
\152\ Docket ID PHMSA-2017-0151-0062 at 4.
---------------------------------------------------------------------------
In addition, both the Associations and TC Energy noted the lack of
cyclic fatigue failures on natural gas transmission lines and, while
``cyclic fatigue has caused failures of LF-ERW pipe,'' such failures
``generally [occur] on liquid pipelines.'' \153\ Given the analysis
required in accordance with Sec. 192.917(e)(2), the Associations
stated that they would support excluding any pipeline segments with the
identified seam types where the threat of significant cyclic fatigue is
also present.
---------------------------------------------------------------------------
\153\ Docket ID PHMSA-2017-0151-0061 at 16; see TC Energy,
Docket ID PHMSA-2017-0151-0062 at 4.
---------------------------------------------------------------------------
3. GPAC Consideration
Industry GPAC members argued that the vintage seam type exclusion
in the NPRM swept too broadly and that pipe manufactured with ERW and
EFW seams should be eligible for the IM alternative.\154\ Specifically,
Mr. Zamarin discussed how LF-ERW and EFW seams are considered a
``stable threat'' under the B31.8S standard.\155\ Unlike corrosion, Mr.
Zamarin explained, a seam defect will not deteriorate over time and can
be treated as stable following a 1.25 times MAOP pressure test. Noting
that the IM alternative requires such a test, Mr. Zamarin argued that
the safety of pipe with ERW and EFW pipe can be established at the
outset of the program, and that seam integrity can be maintained over
time by complying with the provisions in Subpart O. Mr. Drake noted
that improved testing methods have decreased seam failure rates to a
level consistent with other pipe failure mechanisms, and that seams
which pass a 1.25 times MAOP pressure test can be managed consistent
with other pipeline characteristics. Mr. Drake also recommended that
PHMSA capitalize on the recent improvements to Subpart O in managing
seam integrity under the IM alternative, given the ``overlap in the
regulatory development of this rule and Subpart O.'' \156\ Mr. Weisker,
another industry GPAC member, added that the IM requirements in Subpart
O clearly recognize the principle that seam integrity can be
established with a 1.25 times MAOP pressure test.
---------------------------------------------------------------------------
\154\ Industry GPAC members endorsed the continued exclusion
from the IM alternative of lap welded seams or any seam with a
longitudinal joint factor below 1.0. See GPAC, Class Location
Requirements Transcript March 29, 2024, Docket ID PHMSA-2024-0005-
0308, at 148 (Apr. 11, 2024).
\155\ ASME, American Standard Code for Pressure Piping,
Supplement to ASME B31.8, ASME B31.8S-2018, Managing System
Integrity of Gas Pipelines (2018).
\156\ GPAC, Class Location Requirements Transcript March 29,
2024, Docket ID PHMSA-2024-0005-0308, at 203.
---------------------------------------------------------------------------
Ms. Murphy, a public member, acknowledged the point about seam
stability following a 1.25 times MAOP pressure test, but recommended
deferring to PHMSA's expertise as to whether these seam types present a
sufficient concern to require continuing review under special permits.
Ms. Gosman, another public member, also deferred to PHMSA's expertise
while noting that a more protective approach may be appropriate because
the IM alternative applies to thinner walled pipe that is non-
commensurate with its
[[Page 1626]]
current class location. Another public member asked PHMSA to review
incident data. Mr. Danner, the Committee chair and a member
representing government entities, preferred that PHMSA explore whether
adequate testing procedures can be implemented to maintain safety and
allow these seam types into the IM alternative.\157\
---------------------------------------------------------------------------
\157\ See GPAC, Class Location Requirements Transcript March 29,
2024, Docket ID PHMSA-2024-0005-0308, at 134-208.
---------------------------------------------------------------------------
In an 11-1 vote, the GPAC recommended that the seam eligibility
restriction was technically feasible, reasonable, cost-effective, and
practicable, if PHMSA considered alternatives, including the potential
removal of the exclusion for LF-ERW and EFW pipe segments (1) while
maintaining an equivalent or greater level of pipeline safety and (2)
if it can be shown that operators are effectively managing these
segments through the IM alternative.
4. Post-GPAC comments
Enbridge added its opposition to the proposed seam eligibility
restriction, as did Mr. Drake.\158\ The Associations expanded on their
opposition, questioning the lack of ``a specific rationale'' from PHMSA
``supporting this proposed exclusion.'' The Associations argued that
the identified seam features would be mitigated through the IM program
by the crack repair criteria finalized in the 2022 Safety of Gas
Transmission Rule, ``especially the crack depth threshold of 50 percent
[which] will help conservatively identify cracks before they result in
an incident,'' and Sec. 192.917(e)(3)(i), which ``provides an
additional level of safety protection by requiring an integrity
assessment if an incident occurs on selected vintage seam pipes.''
\159\
---------------------------------------------------------------------------
\158\ See Docket ID PHMSA-2024-0005-0418 at 2; Andy Drake,
Comments, Docket ID PHMSA-2024-0005-0419 at 3.
\159\ Docket ID PHMSA-2024-0005-0423 at 13-14.
---------------------------------------------------------------------------
The Associations also pointed to PHMSA's incident data as evidence
that pipe with these seam types can be managed safely. The Associations
identified 12 reported incidents over 15 years attributed to LF-ERW
pipe seam failures out of 1,531 reportable incidents on about 298,000
miles of gas transmission lines, with none occurring in HCAs. In
contrast, they cited 109 external corrosion and 90 internal corrosion
incidents over that same period and stated that ``[t]he comparison with
corrosion is important because there are long-established practices of
managing external and internal corrosion that integrity management
enhances. If you apply the same logic to selected vintage seam pipe,
then an equal or greater level of safety will be achieved by'' placing
these LF-ERW seams into the IM program.\160\
---------------------------------------------------------------------------
\160\ Id. at 12.
---------------------------------------------------------------------------
The Associations noted DC-ERW pipe came from a single manufacturer,
Youngstown Steel and Tube, between 1930 to 1980 and, while ``PHMSA
proposed making all pipe from this mill ineligible,'' process
improvements at the mill in 1948 improved the quality of the pipe.\161\
EFW pipe similarly was made by a single manufacturer, AO Smith
Corporation, starting from about 1927 through 1969. The Associations
reviewed PHMSA's incident data, which indicated there were 6 incidents
on EFW pipe over the past 15 years, one of which was seam-related, with
five related to cracking in hard spots in the pipe body; the
Associations pointed to studies on how hard spots could safely be
managed by operators.
---------------------------------------------------------------------------
\161\ Id.
---------------------------------------------------------------------------
An anonymous comment urged PHMSA not to allow pipe with EFW seams
to be eligible for the IM alternative, noting that EFW pipe
manufactured by AO Smith from the 1950s through the mid-1960s had seam
weld failure issues and hard spot issues (cracking) in the pipe steel
for which ILI tools and IM programs ``have not been perfected or may
not have qualified personnel for identifying,'' unlike with other
anomalies. The anonymous commenter also pointed to an NTSB report ``on
an Enbridge 30-inch EFW pipeline hard spot failure in Kentucky'' that
caused one fatality, injured others, and burned down several homes. The
commenter rhetorically asked what has been done to remedy these types
of pipe body and weld seam issues for Class 1 EFW pipe operating in
Class 3 locations. Referencing a 2004 INGAA pipe seam report showing a
total of 276 incidents attributed to EFW pipe issues, with 242 of them
being seam failures and 34 pipe body failures, the anonymous commenter
concluded that ``PHMSA must review the manufacturing and inline
inspection results/records, pressure test, leak, and rupture history .
. . of all EFW pipe prior to it being considered for [the IM
alternative]. EFW pipe must not be allowed in this rulemaking, as noted
in the draft rule shown to the public for comments.'' \162\
---------------------------------------------------------------------------
\162\ Anonymous, Comments, Docket ID PHMSA-2024-0005-0414 at 1-2
(Aug. 16, 2024) (discussing E.B. Clark et al., Battelle, Integrity
Characteristics of Vintage Pipelines, tbls. E-3 & E-5 (INGAA Found.,
Oct. 2004), available at: https://ingaa.org/foundation/resources/integrity-characteristics-of-vintage-pipelines/).
---------------------------------------------------------------------------
5. PHMSA Response
PHMSA has conducted a comprehensive review and is removing the
exclusion for LF-ERW, DC-ERW, and EFW seams. The 1.25 times MAOP
pressure testing requirement and comprehensive integrity measures in
the IM alternative provide an adequate basis for confirming the MAOP of
eligible Class 3 segments with these vintage seam types. While PHMSA
previously required a substantial justification for operators to obtain
a class location special permit for pipe manufactured with LF-ERW, DC-
ERW, and EFW seams, subsequent research, advances in ILI technology,
and changes to the IM requirements, when combined with PHMSA's
experience managing these class location special permits, demonstrate
that such a justification is no longer needed. Accordingly, the final
rule allows operators to use the IM alternative to confirm the MAOP of
eligible Class 3 segments with LF-ERW, DC-ERW, and EFW seams.
Background
Historically, the manufacturing process for ERW and EFW pipe
required the skelp (i.e., metal before forming the pipe) to be cold
rolled with current introduced to heat and bond the edges of the metal
and weld the longitudinal seam--LF-ERW used low frequency alternating
current induced at a frequency of around 120 (up to 360) cycles per
second for that purpose, while DC-ERW and EFW used forms of direct
current. The electrical current used in these manufacturing methods had
a relatively wide heat affected zone, which coarsened more of the metal
grain surrounding the seam.\163\ Along with the quality of skelp used
and quality of the metal edges before welding, pipe formed by these
methods tends to fail from cold welds where the skelp edges do not
fully bond, hook cracks where a j-shaped imperfection is introduced in
layers of the skelp edges when welded together, and selective seam weld
corrosion where metal loss occurs in the heat-affected zone and
bondline and can advance more quickly.\164\
---------------------------------------------------------------------------
\163\ J.F. Kiefner & K.M. Kolovich, Battelle, Task 1.4 Final
Report No. 12-139, ERW and Flash Weld Seam Failure, in The
Comprehensive Study to Understand Longitudinal ERW Seam Failures, at
2>-6 (Sept. 24, 2012) (noting that direct current tended to create a
wider heat affected zone than low-frequency current). The
Comprehensive Study can be accessed at: https://primis.phmsa.dot.gov/rd/projects/390/.
\164\ See Kiefner & Kolovich, Task 1.4, at 13, 39, 63-65; B.N.
Leis et al., Battelle, Task 4.5, Final Summary Report &
Recommendations--Phase One, in The Comprehensive Study to Understand
Longitudinal ERW Seam Failures, at 15 (Oct. 23, 2013).
---------------------------------------------------------------------------
[[Page 1627]]
Commonly adopted in the 1970s, manufacturers began using higher
frequency currents of around 450 kilocycles per second to complete
welds more quickly and create a smaller heat-affected zone on the pipe,
leaving intact more of original steel's microstructure. The prevalence
of that high-frequency ERW method, along with improved quality control
and the use of ``fully-killed'' steels with lower carbon content that
are more resistant to brittle fracture transition temperature,
generally improved line pipe manufactured after 1980.\165\ While
prospective, these improvements did not affect pipe already
manufactured with LF-ERW, DC-ERW, and EFW seams, which tended to
experience failures at a disproportional rate.\166\
---------------------------------------------------------------------------
\165\ Kiefner & Kolovich, Task 1.4, at 2, 7; J.D. Fields, The
Evolution of High-Frequency Welded Line Pipe, (Feb. 20, 2025),
available at: https://www.jdfields.com/news-and-case-studies/the-evolution-of-high-frequency-welded-line-pipe.
\166\ See Michael Baker Jr., Inc, Kiefner & Assoc., TTO No. 5
Final Report, Low Frequency ERW and Lap Welded Longitudinal Seam
Evaluation, at 7 (Apr. 2004), available at: https://www.phmsa.dot.gov/sites/phmsa.dot.gov/files/docs/technical-resources/pipeline/gas-transmission-integrity-management/65266/tto05lowfrequencyerwfinalreportrev3april2004.pdf (``Recent ERW line
pipe manufactured by the better pipe mills is of high-quality and
offer one of the best choices of materials for pipeline
construction. The concern relevant to seam-integrity assessment
arises because this was not necessarily the case prior to about
1980. . . . Both good and poor-quality lots have been made by most
of the manufacturers in the time period of interest (roughly 1930
through 1980).''); Kiefner & Kolovich, Task 1.4, at 139 (``[T]he
track record of failures involving pipe of pre-1970 vintage is
clearly not as good as that of pipe manufactured after 1970.'').
---------------------------------------------------------------------------
Acknowledging that trend, PHMSA issued a pair of pipeline safety
alerts in the late 1980s advising operators of findings related to
several recent failures of pipelines manufactured with ERW seams prior
1970. These notices advised operators that ``hydrostatic testing of
some ERW pipelines [have] reduc[ed] the risk of seam failures,'' with
pre-1970 ERW pipelines that operators have hydrotested largely
operating safely since that test.\167\ PHMSA recommended all gas
transmission and hazardous liquid pipeline operators consider testing
to 1.25 times the MAOP pre-1970 ERW pipe for which they not yet done
so, or alternatively reduce the operating pressure by 20 percent.\168\
PHMSA also advised operators to avoid increasing a pipeline's long-
standing operating pressure, to assure effectiveness of the cathodic
protection system, and to conduct metallurgical exams in the event of
an ERW seam failure.
---------------------------------------------------------------------------
\167\ PHMSA, ALN-88-01, Recent findings relative to factors
contributing to operational failures of pipelines constructed with
ERW prior to 1970 (Jan. 28, 1988).
\168\ See PHMSA, ALN-89-01, Pipeline Safety Alert Notice (Mar.
8, 1989), available at: https://www.phmsa.dot.gov/regulations/title49/interp/pi-89-001.
---------------------------------------------------------------------------
Following the 2009 rupture of a hazardous liquid pipeline with an
LF-ERW seam in Carmichael, Mississippi, from which the NTSB found
inspection and testing programs inadequate to identify reliably
features associated with longitudinal seam failures of ERW pipe, PHMSA
commissioned research into the potential integrity risks associated
with vintage seamed pipe.\169\ The ``Comprehensive Study to
Understanding Longitudinal ERW Seam Failures'' featured over two-dozen
studies by leading engineering researchers from 2011 to 2017.\170\
Research conducted in the 2000s confirmed that a 1.25 times MAOP
pressure test could remove any critical defects on ERW or EFW pipe, or
prove none present.\171\ The Comprehensive Study in the 2010s found
that pressure tests and ILI could be used in combination for effective
integrity management, pending further anticipated ILI tool
improvements.\172\ ILI technology had continued to improve in the
2010s, with higher probability of detection and an ability to detect
smaller seam cracks, even compared to the decade prior, but ILI crack
tools required further development in their ability to recognize seam
anomalies and location.\173\
---------------------------------------------------------------------------
\169\ See NTSB, PAR-09-01, Rupture of Hazardous Liquid Pipeline
with Release and Ignition of Propane, Carmichael, MS, Nov. 1, 2007,
at 49-51 (Oct. 14, 2009), available at: https://www.ntsb.gov/investigations/AccidentReports/Reports/PAR0901.pdf (recommendation
P-09-01).
\170\ The complete research docket is available at: https://primis.phmsa.dot.gov/matrix/PrjHome.rdm?prj=390.
\171\ Baker, TTO No. 5, at 15; Kiefner, Evaluating the Stability
of Manufacturing and Construction Defects, at 18.
\172\ See Leis, Task 4.5, at 20; J.F. Kiefner, et al., Battelle,
Task 1.3 Final Report 12-180, Track Record of In-Line Inspection as
a Means of ERW Seam Integrity Assessment, in The Comprehensive Study
to Understand Longitudinal ERW Seam Failures, at 120 (Nov. 15, 2012)
(noting the combination may not be necessary upon expected
improvements in ILI crack detection).
\173\ See, e.g., Leis, Task 4.5, at 33. See also Baker, TTO No.
5, at 6, 47, 60 (finding ILI tools in 2004 unreliable to identify
longitudinal seam anomalies).
---------------------------------------------------------------------------
PHMSA amended the IM regulations in the 2019 and 2022 Safety of Gas
Transmission Rules to address the potential integrity risks associated
with older ERW pipe through two main additions. First, in 2019 PHMSA
amended the Sec. 192.917(e)(3) requirement that operators analyze pipe
with manufacturing defects to require that an operator could only
consider manufacturing defects (including seam defects) stable if an
operator subjected them to a hydrostatic pressure test of at least 1.25
times the MAOP, with no subsequent reported incidents attributable to
the defect. Second, for anomalies found to be preferentially affecting
a longitudinal seam, Sec. 192.933 as amended in 2022 accelerates the
repair of DC-ERW, LF-ERW, and EFW seamed pipe by using a higher safety
factor to more conservatively calculate the predicted failure pressure
for preferential metal loss.\174\
---------------------------------------------------------------------------
\174\ See Sec. 192.933(d)(1)(iv), (2)(vi). See also Sec.
192.714(d)(1)(iv), (2)(vi).
---------------------------------------------------------------------------
The GPAC discussed each of these amendments in providing PHMSA with
the recommendation to consider removing pipe with LF-ERW, DC-ERW, and
EFW seams from the vintage seam exclusion in the IM alternative.
Members discussed how a 1.25 times MAOP pressure test is an accepted
method of stabilizing seam defects, and that the recent amendments to
Subpart O should be considered in determining the appropriate means of
assessing and, if necessary, remediating LF-ERW, DC-ERW, or EFW
anomalies.\175\ All members agreed that PHMSA should apply its
technical expertise to review research evidence and incident data to
consider whether these seams could safely apply the IM alternative with
these safeguards in place.
---------------------------------------------------------------------------
\175\ See, e.g., GPAC, Class Location Requirements Transcript
March 29, 2024, at 168-69, 183, 203 (Andy Drake).
---------------------------------------------------------------------------
Analysis
PHMSA has conducted a comprehensive review consistent with the
GPAC's recommendation and concludes that the requirements in the IM
alternative provide an adequate basis for confirming the MAOP of
eligible Class 3 segments with LF-ERW, DC-ERW, and EFW seams. Any
manufacturing defects associated with these seams can be treated as
stable by virtue of the 1.25 times MAOP testing requirement in the IM
alternative.\176\ ``Hydrostatic testing of the [pipe]line either
removes any defects that have grown beyond critical size at the test
pressure since the last test, or it proves
[[Page 1628]]
that no defects of critical size exist''; \177\ the 1.25 times MAOP
test required to use the IM alternative is the same as what is required
under the IM program at Sec. 192.917(e)(3). Several other interacting
threats that might otherwise cause LF-ERW, DC-ERW, or EFW seam to
become unstable are excluded from the IM alternative, like pipe with
wrinkle bends or that is known to have stress corrosion cracking
(SCC).\178\ Ongoing seam integrity can be maintained by the regular
assessment using ILI tools appropriate for the threats as is required
by the IM alternative, with PHMSA's recent amendments to Subpart O
providing a comprehensive framework for capitalizing on modern ILI tool
capabilities for pipe with LF-ERW, DC-ERW, and EFW seams.\179\
---------------------------------------------------------------------------
\176\ See NTSB, Safety Recommendation, at 10 (Sept. 26, 2011),
available at: https://www.ntsb.gov/safety/safety-recs/recletters/P-11-008-020.pdf; Kiefner, Evaluating the Stability of Manufacturing
and Construction Defects, at 18 (``Any manufacturing defect or
imperfection that survives a pre-service hydrostatic test to 1.25
times the [MAOP] is stable immediately after the test. . . .
[E]xperience with gas pipelines tested to levels of 1.25 times their
operating pressures validates the effectiveness of a test-pressure-
to-operating-pressure ration of 1.25.''). See also ASME, B31.8S-
2018, Sec. 6.3.2.
\177\ Baker, TTO No. 5, at 15.
\178\ See Kiefner, Evaluating the Stability of Manufacturing and
Construction Defects, at 6-7.
\179\ See Leis, Task 4.5, at 18 (noting ``it is important to
have the ILI option for seam-integrity assessment . . . via a
reliable ILI tool'' to ``find and eliminate injurious defects on a
scheduled basis'' after a pressure test).
---------------------------------------------------------------------------
Improvements in tool probability of detection and sizing accuracy
discussed in section II.C have been demonstrated in ILI tools on ERW
and EFW seams, a marked development compared with a 2004 PHMSA study
that previously questioned the use of ILI as an effective technology
for managing pipe with these seam types.\180\ Advanced ILI tools can
now detect even the smaller anomalies that may have gone undetected in
an initial pressure test, as shown by research as recent as 2017.\181\
Though there are limits to current tools' ability to identify a seam
crack's precise location and distinguish the type of anomaly feature as
between, e.g., cold welds, hook cracks, selective seam weld corrosion,
this is mitigated by the heightened safety factor applied in the
remediation criteria for these seam types in Sec. 192.933(d).\182\
Applying an IM program to LF-ERW, DC-ERW, and EFW seams in HCA
locations, there have been no reported incidents due to material
failure of pipe or weld since 2010.\183\
---------------------------------------------------------------------------
\180\ Compare Leis, Task 4.5, at 33 (Oct. 23, 2013) (``ILI done
using SMFL and EMAT tools focused in part on crack-like features
associated with stress-corrosion cracking (SCC) over almost 1500
miles of liquid, highly volatile liquid, and natural gas pipelines
made using low as well as high frequency ERW processes showed the
technology to detect cracking has recently improved
significantly.''), with Baker, TTO No. 5, at 6, 60 (finding in 2004
that ``the probability of detecting seam problems varied among the
types of ILI tools used,'' and recommending to not use it to
evaluate the failure pressures of specific defects affecting pipe
with these seam types).
\181\ Jennifer M. O'Brien & Bruce Young, Battelle, Phase II Task
2--Pipe Inventory, Inspection by In-The-Ditch Methods and In-Line
Inspection, and Hydrostatic Tests--a Continuation of Phase 1, Task
2, in The Comprehensive Study to Understand Longitudinal ERW Seam
Failures, at 57 (Aug. 2017).
\182\ Kiefner, Task 1.3, at 121 (advising added conservativism
in the repair criteria and calculating predicted failure pressure in
light of these deficiencies). ILI tools are expected to improve in
this regard with further innovation and application. See id. at 120;
Leis, Task 4.5, at 20 (``[T]he fact that the tools find some defects
is encouraging, and further use of the tools will undoubtedly lead
to better understanding of the capabilities.''); O'Brien & Young,
Pipe Inventory, Inspection by In-The-Ditch Methods and ILI, and
Hydrostatic Tests, at 41.
\183\ Conversely, 31 reported incidents by this mechanism
occurred outside of HCAs during the same period.
---------------------------------------------------------------------------
Review of the decades of study and incident history indicate that,
in PHMSA's expert judgment, LF-ERW, DC-ERW, and EFW seams can be safely
managed under the IM alternative. Gas transmission lines are generally
not subject to the heightened cyclic fatigue risk that applies to
hazardous liquid pipelines.\184\ The IM alternative also requires gas
transmission operators to follow more stringent IM requirements when
conducting the initial 24-month assessment on pipe with ERW or EFW
seams. Specifically, an operator must select an assessment technology
or technologies with a proven application capable of assessing seam
integrity and seam corrosion anomalies regardless of whether the
additional criteria in Sec. 192.917(e)(4) are met. The TVC records
requirement in the IM alternative provides an additional margin of
safety for pipe with ERW or EFW seams. Operators lacking TVC seam type
records must obtain that information before conducting the initial ILI
assessment, as failing to do so could lead to the selection of improper
ILI tool for pipe with an ERW or EFW seam and invalidate the results of
the assessment.
---------------------------------------------------------------------------
\184\ See Leis, Task 4.5, at 15. While the 1988 and 1989
advisories called to alarm 20 hazardous liquid pipeline failures
(with 12 announced in January 1988, and an addition 8 in the March
1989 advisory) involving pipe seams manufactured by ERW, they noted
but one such failure on a gas transmission pipeline. See ALN-89-01.
---------------------------------------------------------------------------
PHMSA concludes that the MAOP restoration provision in the IM
alternative can be safely applied to LF-ERW, DC-ERW, and EFW seams as
well. Studies indicate that pressure tests are not always effective to
prevent failure where operating pressure surges, and that changes in
operating pressure can destabilize a threat. To address these concerns,
PHMSA is requiring operators to treat an MAOP restoration under Sec.
192.611(d) as an MAOP increase under Subpart O, including for purposes
of the seam susceptibility analysis and, more likely than not,
prioritization of the ERW or EFW segment for reassessment under Sec.
192.917(e)(3) and (4). These provisions ensure that the LF-ERW, DC-ERW,
and EFW seams are properly assessed and remediated as part of an MAOP
restoration.
In summary, PHMSA is removing LF-ERW, DC-ERW, and EFW seams from
the vintage seam type exclusion. Having conducted a comprehensive
review in response to the GPAC's recommendation, PHMSA concludes that
the 1.25 times MAOP pressure testing requirement and other
comprehensive integrity measures in the IM alternative provide an
adequate basis for confirming or restoring the MAOP of eligible Class 3
segments with these seam types. As previously discussed, recent
advances in ILI technology, particularly with respect to probability of
detection and sizing accuracy, and changes to the IM requirements in
Subpart O demonstrate that operators can safely manage the integrity of
LF-ERW, DC-ERW, and EFW seams under the IM alternative. PHMSA has also
included provisions in the IM alternative that exceed the IM
requirements in Subpart O, such as for the selection of technologies
capable of assessing seam integrity and seam corrosion anomalies during
the initial 24-month assessment and the treatment of MAOP restorations
as MAOP increases, which provide an additional margin of safety for LF-
ERW, DC-ERW, and EFW seams.
The final rule retains the vintage seam type exclusion for lap
welded pipe and pipe with a joint factor below 1.0.\185\ Operators must
confirm or revise the MAOP of pipe manufactured with these vintage seam
types using the other methods authorized in Sec. 192.611 in the event
of a class location change. Operators may also replace the pipe or
apply for a class location special permit to maintain the current MAOP.
---------------------------------------------------------------------------
\185\ See Sec. 192.113; PHMSA, Fact Sheet: Pipe Manufacturing
Process (Dec. 01, 2011), available at: https://primis.phmsa.dot.gov/comm/FactSheets/FSPipeManufacturingProcess.htm.
---------------------------------------------------------------------------
ix. Pipe Coating for Cathodic Protection
1. Summary of Proposal
The NPRM proposed to exclude bare pipe and pipe with poor external
coating. Inadequate coating increases the risk of external corrosion,
and a compromised protective barrier impairs the effectiveness of
cathodic protection (CP). To address these concerns, the NPRM specified
the IM alternative could not be used where CP was maintained by linear
anodes spaced along the pipe, use of a minimum cathodic polarization
shift of -100
[[Page 1629]]
millivolts (mV), or segments containing tape wraps or shrink sleeves.
PHMSA has historically disfavored bare pipe in class location
special permits, as described in the 2004 Federal Register notice on
class location special permit eligibility criteria.\186\ Class location
special permits have also typically required additional measures, such
as inspecting the condition of pipe coatings on excavated facilities
and examining for SCC, on any pipe found to be suffering from poor
coating.
---------------------------------------------------------------------------
\186\ PHMSA, 2004 Special Permit Criteria at 3.
---------------------------------------------------------------------------
2. Initial Comments
The Associations agreed with the need to ensure effective CP but
questioned the appropriateness of the various mechanisms specified in
the proposed eligibility criteria. Regarding the -100 mV polarization
shift, the Associations noted that the Third Edition of A.W. Peabody's
Control of Pipeline Corrosion ``classif[ies] the cracking-related
concern with potentials below -0.850 mV as a `caution,' instead of the
`should not be used' recommendation from the Second Edition.'' \187\
The relationship to cracking, they argued, could be assessed and
managed using the ``robust crack anomaly response requirements'' in the
IM alternative, along with the requirements to inspect exposed pipe for
cracking and survey for and mitigate interference currents. As for
linear anodes, the Associations noted that placing them ``may be the
most effective way to cathodically protect a segment or portion of a
segment'' where ``good coating'' is present but cautioned that ``deep
ground beds are impracticable because of bedrock'' and that ``right-of-
way acquisition for conventional ground beds is impracticable because
of permitting or congestion.'' The Associations stated that operators
use linear anodes to mitigate ``significant alternating current (AC)
interference from high voltage power lines.'' \188\
---------------------------------------------------------------------------
\187\ Docket ID PHMSA-2017-0151-0061 at 17-19. Compare NPRM, 85
FR at 65158 n.89 (citing A.W. Peabody, Control of Pipeline Corrosion
(Ronald L. Bianchetti ed., 2d. ed., 2001)), with A.W. Peabody,
Control of Pipeline Corrosion 47 (Ronald L. Bianchetti ed., 3d ed.,
2018).
\188\ Docket ID PHMSA-2017-0151-0061 at 17-19.
---------------------------------------------------------------------------
The Associations recommended narrowing the exclusion to locations
where there is a specific indication of inadequate CP, using
``ineffective coating'' per the standard in Sec. 192.457, or a tape
coating or shrink sleeve used by an operator that has experienced a
history of coating disbondment or shielding. Disbondment, the
Associations continued, ``is less likely to occur with more modern
applications, so a broad disqualification of tape coating and shrink
sleeves is inappropriate.'' The Associations further argued that
shielding of CP can be managed under the IM alternative through the
``proposed conservative metal loss response criteria, especially at
girth welds, which will ensure that any disbondment/shielding-driven
metal loss is addressed quickly.'' \189\
---------------------------------------------------------------------------
\189\ Id.
---------------------------------------------------------------------------
3. GPAC Consideration
Industry GPAC members suggested that ILI could be used to manage
these types of pipe coatings along with the enhanced corrosion anomaly
remediation requirements established at Subpart O. Public GPAC members
generally supported excluding pipe with ineffective CP but were open to
PHMSA clarifying that operators could remain eligible if ILI
assessments and subsequent data confirmed effective CP.
The GPAC voted 10-2 that the pipe coating eligibility restriction
was technically feasible, reasonable, cost-effective, and practical,
provided that PHMSA considered alternatives for ineffectively coated
pipeline that would maintain an equivalent or greater level of pipeline
safety and if an ILI program could demonstrate that operators are
effectively managing corrosion. On a 7-5 vote, the Committee also
recommended that PHMSA consider alternatives, such as the use of ILI
data in conjunction with other measures, to ensure that ineffectively
coated pipeline is not eligible for the IM alternative.
4. Post-GPAC Comments
The PST stated that PHMSA should ensure that poorly coated pipe is
excluded from the IM alternative. The PST also disfavored using ILI as
a tool for managing poor coating, stating that the seven-year
assessment intervals is not frequent enough to take advantage of the
advances in ILI technology to detect corrosion because environmental
corrosion could quickly develop.\190\
---------------------------------------------------------------------------
\190\ See Docket ID PHMSA-2024-0005-0417 at 3.
---------------------------------------------------------------------------
The Associations supported the GPAC recommendations for PHMSA to
consider alternatives, such as ILI assessments, to demonstrate that an
operator can evaluate and manage corrosion effectively. The
Associations noted that ``Subpart O already requires operators to
collect and integrate relevant data into their integrity management
programs,'' including information collected and integrated including
information on the CP installed, coating type and condition, close
interval survey results, and ILI results. The Associations reiterated
that excluding pipe with tape coating or shrink sleeves would be
``overly broad and arbitrary.'' \191\ As evidence that IM can manage
corrosion risks associated with tape coatings or shrink sleeves, the
Associations pointed to PHMSA's 2016 Advisory Bulletin covering
protection of poorly coated pipe, which recommended operators conduct
additional assessments, coordinate data from appropriate ILI
technologies, and apply more stringent repair criteria targeted at
corrosion under disbonded coatings.\192\
---------------------------------------------------------------------------
\191\ Docket ID PHMSA-2024-0005-0423 at 8.
\192\ See PHMSA, ADB-2016-04, Pipeline Safety: Ineffective
Protection, Detection, and Mitigation of Corrosion Resulting from
Insulated Coatings on Buried Pipelines, 81 FR 40398, 40400 (June 21,
2016).
---------------------------------------------------------------------------
5. PHMSA Response
PHMSA is retaining a modified version of the exclusion for bare
pipe and pipe with poor external coating structured as an initial
compliance obligation. Application of the IM alternative remains
prohibited on pipe with external coating that is not adequate to
provide necessary CP, but PHMSA is allowing operators to conduct a
survey to confirm the presence of ineffective coating as suggested by
commenters. This approach strikes a better balance than did the
proposal, which unreasonably excluded all pipe with features that have
tended to correlate with pipe that has poor coating regardless of
whether the pipe itself has inadequate CP.\193\ Cathodic 100 mV
polarization shift (or -100 mV shift), linear anodes, tape wrap, and
shrink sleeves have been correlated with coating and corrosion issues
in the past, and may be difficult to predict reliably with ILI alone,
but do not universally indicate poor CP. PHMSA's review of technical
evidence, its experience administering class location change special
permits, and review of the comments confirms that the NPRM swept too
broadly in proposing to exclude pipe with adequate CP.
---------------------------------------------------------------------------
\193\ While they can be used to mitigate against inadequate
coating, see Sec. 192.463 and 49 CFR part 192, App'x D, that is not
their universal cause. The decision to use these corrosion control
tools may have nothing to do with coating effectiveness. For
example, use of these tools could be driven by soil characteristics
or to reduce CP interference on foreign pipelines, etc. As evidence
of that point, operators currently use both -100mV polarization
shifts and linear anodes with new, FBE-coated pipe.
---------------------------------------------------------------------------
If an eligible Class 3 segment uses the -100 mV shift, linear
anodes, tape wrap, or shrink sleeves, operators may conduct a survey in
accordance with Sec. 192.461(f) through (h) to determine the condition
of the coating. The IM alternative may be used if the results of
[[Page 1630]]
that survey confirm that the coating is in good condition. Should the
survey indicate remediation is required, the IM alternative may also be
used if the coating is restored to good condition. The coating survey
and any necessary remediation must be completed within the initial 24-
month compliance period. This will permit pipe with coating and CP in
good condition but prevent pipelines with coating, corrosion, and SCC
issues from being eligible for the new compliance option.
PHMSA has determined that a coating survey is appropriate for pipe
using the -100 mV polarization shift, linear anodes, tape wrap, or
shrink sleeves. Bare pipe lacks any coating to provide CP and remains
categorically excluded from the IM alternative due to its
susceptibility for corrosion. Tape wrap and shrink sleeves are common
types of shielding coatings, meaning they can ``shield'' (or prevent)
CP currents from working effectively, raising the risk of corrosion
incidents.\194\ PHMSA has not issued class location special permits on
segments that use tape wrap or shrink sleeves. Linear anodes provide a
path for current to get off at, and corrode, the anode instead of the
pipe metal itself (i.e., through coating holidays), and might be
indicative of a CP issue.
---------------------------------------------------------------------------
\194\ See, e.g., PHMSA, Pipeline Incident Files, Incident Rep.
No. 20220135-38004 (Dec. 27, 2022) (rupture on 16'' steel pipeline
``result[ing] in an approx[imately] 40 [foot] length of pipe opening
circumferentially and longitudinally (not seam oriented) [with] both
ends folding up and coming out of the ground,'' causing $635,000 in
property damage, which metallurgical analysis ``determined . . . the
apparent cause of the failure'' was ``external corrosion where
disbonded polyethylene coating was shielding'').
PHMSA defined a ``non-shielding'' coating in the Alternative
MAOP rule as a coating that allows CP currents to pass through the
coating and along the outside surface of pipe and which is an oxygen
barrier, even if the coating has disbonded from the pipe surface.
See Pipeline Safety: Standards for Increasing the Maximum Allowable
Operating Pressure for Gas Transmission Pipelines, 73 FR 62148,
62156-57 (Oct. 17, 2008) (Alternative MAOP Rule) (codifying Sec.
192.112(f)(1)).
---------------------------------------------------------------------------
While a valid compliance method, the -100 mV shift is commonly used
on poorly coated or bare structures when the -0.850 mV criterion cannot
be reached due to the need to mitigate some other threat (e.g., hard
spots). PHMSA's experience administering class location special permits
supports that conclusion as segments have been withdrawn from
consideration for containing widespread, systemic external corrosion on
pipe being managed with the -100 mV minimum shift or linear
anodes.\195\ Yet many modern pipelines either meet 850 mV polarized
potential or can safely operate below that level using the -100 mV
shift, as discussed by the Associations.\196\
---------------------------------------------------------------------------
\195\ The limited instances of class location special permits
issued to segments using the -100 mV shift have historically only
for a limited time until the pipe can be recoated or another class
location change compliance option is adopted (replacement or
pressure reduction).
\196\ See 49 CFR part 192, App'x D.
---------------------------------------------------------------------------
Adding the coating survey requirement to the IM alternative is
consistent with the GPAC's recommendation and comments, including from
the PST who advocated to exclude pipe that is poorly coated. The
requirement addresses concerns with CP management methods that
correlate with increased risk, without excluding segments that are
being effectively managed through the use of the -100 mV shift, linear
anodes, tape wrap, or shrink sleeves. Conducting a coating survey under
Sec. 192.461 is an appropriate, reasonable, and effective means of
ensuring that pipe enters the IM alternative with adequate CP. Section
192.461(f) requires the assessment for any coating damage using direct
current voltage gradient (DCVG), alternating current voltage gradient
(ACVG), or other technology which provides information about the
coating integrity. Section 192.461(h) requires the repair of any severe
coating damage using NACE SP0502 within six months of completing that
assessment. The initial survey and remediation requirement, when
combined the ongoing obligation to comply with the IM requirements in
Subpart O, provides a sufficient margin of safety to mitigate the risk
of external corrosion on eligible Class 3 segments.
x. Cracking
1. Summary of Proposal
The NPRM proposed to exclude segments with (1) cracking that
exceeds 20 percent of the pipe wall thickness; (2) a crack with a
predicted failure pressure of less than 100 percent of SMYS, or 1.50
times the MAOP; (3) a history of a leak or rupture caused by pipe
cracking; or (4) where analysis indicates that the pipe could fail in
brittle mode. These cracking concerns could not be located on the pipe
body, seam, or girth weld of the segment or on a segment within five
miles of the class change segment. Cracking for these purposes included
SCC and selective seam weld corrosion, which are crack or crack-like
defects in the pipe body or weld seam.
The NPRM also proposed that discovery of the above crack defects
while a segment is managed under this new IM alternative would render
the segment no longer eligible. The operator would need to comply with
the requirements of Sec. 192.611 within 24 months from the date the
operator discovered the cracking.
PHMSA has not historically required a total absence of unremediated
cracks or crack-like anomalies in class location special permit
applications. Instead, PHMSA has analyzed applications to ensure
successful crack monitoring and management, and that the operator was
aware of the presence and risk profiles of any cracks or crack-like
anomalies on the proposed special permit segment. That allowed an
operator under a typical special permit to remediate cracks as
necessary using a similar schedule to the one proposed in the NPRM.
2. Initial Comments
Industry commenters criticized the proposed cracking eligibility
criteria as overly conservative, noting a disconnect between excluding
the majority of cracks from the IM alternative and Subpart O's
provisions for repairing cracks and maintaining safe operation. The
Associations recommended that PHMSA allow for safe management and
remediation of cracks by aligning the eligibility criteria with the
scheduled response criteria for cracks as proposed in this NPRM and
adopted for Subpart O in the 2022 Safety of Gas Transmission Rule. The
Associations noted that Electromagnetic Acoustic Transducer (EMAT) ILI
tools can be used for ``segments susceptible to the threat of
cracking'' to ensure that ``any identified cracks'' are ``remediated in
accordance with conservative crack response criteria,'' and that
excluding so many cracks from the IM alternative was ``unnecessary for
safety.'' \197\
---------------------------------------------------------------------------
\197\ Docket ID PHMSA-2017-0151-0061 at 19. See also Enbridge,
Docket ID PHMSA-2024-0005-0418 at 2.
---------------------------------------------------------------------------
Regarding the proposed applicability to cracking on pipe within
five miles of the class change segment, the Associations found this
``particularly problematic because the upstream/downstream pipe could
be different pipe, with different coating, in a different environment,
and cracking is often an isolated, environment-specific phenomenon.''
\198\ The NTSB urged PHMSA to ``thoroughly analyze the [five-mile]
distance specified . . . to determine if it is appropriate or should be
extended,'' noting that the NPRM is unclear in its justification for
that distance.\199\
---------------------------------------------------------------------------
\198\ Docket ID PHMSA-2017-0151-0061 at 19.
\199\ Docket ID PHMSA-2017-0151-0055 at 4.
---------------------------------------------------------------------------
The commenters were split on the proposal to exclude pipe based on
[[Page 1631]]
subsequently discovered cracking defects. The Associations found it
unreasonable, noting that the exclusion would disregard the number of
years that the operator successfully managed the segment under the IM
alternative, and remove the ability of operators to invest in the
program with certainty, particularly given the low threshold to exclude
many cracks. The Associations recommended that, if an operator
discovers a crack, the operator should notify PHMSA and propose a crack
remediation and management plan.\200\ NAPSR stated that PHMSA should
require operators to assess for and manage cracking threats.\201\
---------------------------------------------------------------------------
\200\ Docket ID PHMSA-2017-0151-0061 at 19.
\201\ See Docket ID PHMSA-2017-0151-0059 at 6.
---------------------------------------------------------------------------
On the other hand, the PST urged PHMSA to require compliance with
Sec. 192.611(a)(1)-(3) if an operator discovers a cracking feature on
a pipeline segment while using the IM alternative. The PST expressed
concern with continuing to allow an operator to use the IM alternative
in those circumstances, noting that ``if pipes with crack features are
high enough risk to not be eligible for [the IM alternative], shouldn't
they also be eliminated from [the IM alternative] once cracking
features are found?'' \202\ The PST also encouraged PHMSA to provide an
exclusion from the IM alternative for any segment that experiences an
``IM-related significant incident.'' The PST argued that effective
application of the IM program should prevent such an incident, so an
incident would indicate that operator is unable to safely
continue.\203\
---------------------------------------------------------------------------
\202\ Docket ID PHMSA-2017-0151-0063 at 7.
\203\ See id. at 9.
---------------------------------------------------------------------------
3. GPAC Consideration
An industry GPAC member noted operators currently inspect and
manage cracks under Subpart O and other industry GPAC members noted
that PHMSA has allowed operators to manage and remediate cracks under
class location special permits using a process similar to Sec.
192.933. Public GPAC members suggested that a higher standard of care
should be maintained for crack threats on eligible Class 3 segments,
given that significant populations would be living near these
pipelines. Because PHMSA initially determined the presence of cracking
on segments would be disqualifying, the public GPAC members felt
subsequent cracking should be disqualifying from the IM alternative as
well. Multiple GPAC members, representing both the industry and
government, felt that the five-mile radius in which operators would
need to check for cracking was too broad and not reflective of how
cracks manifest in pipe. The GPAC also discussed ongoing eligibility
more broadly. The GPAC generally agreed that PHMSA could consider
restricting eligibility for operators who experience failures due to IM
violations.
The GPAC voted 10-2 to recommend that the crack eligibility
requirement would be technically feasible, reasonable, cost-effective,
and practicable if PHMSA considered allowing operators to inspect for
and remediate cracks in accordance with Subpart O, rather than broadly
excluding all pipe segments with cracks from eligibility. Similarly,
the GPAC voted 8-4 to recommend that PHMSA allow an operator to
continue to use the IM alternative after discovery a cracking defect.
Finally, the GPAC voted 12-0 to recommend that PHMSA consider
restricting eligibility for the IM alternative if an operator has a
significant incident following the effective date of the rule, and
PHMSA determines there has been a violation of a provision of Subpart O
in an enforcement action brought as a result of the incident.
4. Post-GPAC Comments
The PST suggested that cracks which are easily remediated and non-
recurring may be admissible, but that cracking based on certain causes,
for example, pipes experiencing environmentally assisted cracking,
should be excluded, while permitting pipes experiencing only mechanical
cracking.\204\ Operators and industry representatives, including
Williams, Enbridge, and the Associations, sought to use Subpart O to
assess for and remediate cracks in lieu of a broad exclusion. Mr. Drake
noted the ``well-established methods for identifying, categorizing,
mitigating, and monitoring cracking threats,'' particularly in light of
the significant advancements in EMAT ILI technology, should be utilized
rather than having pipe entirely excluded.\205\ Williams recommended
that PHMSA leverage recent amendments to the Subpart O remediation
schedule to permit operators to assess cracks and apply the IM
alternative.\206\ Echoing this, the Associations added that
``[o]perators have demonstrated that they can successfully use Subpart
O to manage cracking threats,'' with but ``one stress corrosion
cracking-related incident in an HCA over the past 15 years.'' Allowing
remediation of cracks within the IM alternative program, the
Associations argued, would encourage more assessment and remediation of
cracks to increase pipeline safety, while adding mileage and data
toward an operator's IM plan.\207\ The Associations also repeated their
critique of the five-mile upstream and downstream range for these
cracks as ``a vestige from the special permit process without a clear
technical basis,'' noting that such pipe ``may not share the same
characteristics or materials as the [class change] segment'' and they
``may have different soil conditions, manufacturers, seam types, and
external loads.'' \208\
---------------------------------------------------------------------------
\204\ See Docket ID PHMSA-2024-0005-0417 at 4.
\205\ Docket ID PHMSA-2024-0005-0419 at 3.
\206\ Docket ID PHMSA-2024-0005-0421 at 6-7.
\207\ Docket ID PHMSA-2024-0005-0423 at 7; see Enbridge, Docket
ID PHMSA-2024-0005-0418 at 2.
\208\ Docket ID PHMSA-2024-0005-0423 at 17.
---------------------------------------------------------------------------
While Williams supported the GPAC's recommendation to restrict
continuing eligibility upon finding of a significant incident,\209\ the
Associations disagreed. The Associations felt that a violation of
Subpart O should not preclude subsequent use of Subpart O. The
Associations noted there is no provision of similar breadth in the
Pipeline Safety Regulations, and that the public lacked adequate prior
notice of the proposal, which was introduced by the GPAC for the first
time during the meeting.\210\ An anonymous commenter concurred that an
eligibility restriction based on a significant incident should be
noticed for public comment given how central the IM measures are in
this rulemaking.\211\
---------------------------------------------------------------------------
\209\ Docket ID PHMSA-2024-0005-0421 at 10.
\210\ Docket ID PHMSA-2024-0005-0423 at 8-9.
\211\ See Docket ID PHMSA-2024-0005-0422 at 1.
---------------------------------------------------------------------------
5. PHMSA Response
The IM alternative retains an exclusion for in service-leaks or
ruptures due to cracking on the pipe or pipe with similar
characteristics within five miles but allows operators to manage other
cracks under Subpart O as recommended by the GPAC and numerous
commenters. Cracks and crack-like anomalies present a significant risk
to pipeline safety and PHMSA has prescribed detailed criteria in Sec.
192.933(d) for remediating these anomalies.\212\ PHMSA adopted the
criteria in the 2022 Safety of Gas Transmission Rule after completing
an extensive, 10-year rulemaking process and is confident that
requiring operators of eligible Class 3 segments to comply with the
requirements in Sec. 192.933(d)--which are comparable to the
conditions that PHMSA has typically included in
[[Page 1632]]
class location special permits, and proposed in the NPRM for this
rulemaking--will generally provide an adequate margin of safety for the
management of cracks and crack-like anomalies.
---------------------------------------------------------------------------
\212\ See, e.g., Michael Baker Jr., Inc, TTO No. 8 Final Report,
Stress Corrosion Cracking Study (Jan. 2005), available at: https://www.phmsa.dot.gov/sites/phmsa.dot.gov/files/docs/technical-resources/pipeline/hazardous-liquid-integrity-management/62746/sccreport-finalreportwithdatabase.pdf.
---------------------------------------------------------------------------
Many commenters agreed with this basic point, and even those who
were more skeptical acknowledged that the requirements in Subpart O can
be used to effectively manage certain cracks. The PST observed, for
example, that the IM alternative could be safely applied to cracks
caused by mechanical damage, which can be remediated without concern of
a systemic or ongoing issue. The IM alternative includes other
provisions that address the detection and prevention of cracks too, for
example, the requirement to conduct girth weld cracking inspections
(see discussion below in section IV.E.i).
Stress corrosion cracking, however, remains a concern. The point at
which SCC coalesces together before rapid deterioration cannot be
reliably predicted using ILI tools. SCC ``growth rates should not be
used to estimate remaining life up to a time point of failure, but to
some point before failure where rapid mechanical growth . . . of the
anomalies is not occurring.'' \213\ SCC ``remains a significant issue
largely because the industry's understanding of this phenomenon is
still evolving and practical methods of addressing SCC are not as
mature as methods for addressing other failure causes.'' \214\ These
concerns are addressed in the IM alternative by excluding segments that
have experienced an in-service leak or rupture due to cracking in the
pipe body, seam, or girth weld on the segment or pipe within five
miles.\215\
---------------------------------------------------------------------------
\213\ ADV Integrity, Inc., Technical Guidance: Integrity
Assessment for Stress Corrosion Cracking (SCC) Using Electromagnetic
Acoustic Transducer (EMAT) In-Line Inspection, 21 (INGAA Found. ed.,
May 2023), available at: https://www.ingaa.org/wp-content/uploads/2023/11/Integrity_Assessment_for_SCC_using_EMAT_Final.pdf. Stress
corrosion cracking is understood to behave according to a ``bathtub
model'' in four stages: Stage 1 ``Condition for SCC have not yet
occurred;'' Stage 2 ``SCC initiates. Initially high SCC velocity
decreases. Few coalesced cracks;'' Stage 3 ``Initiation continues.
SCC grows through an environmental mechanism. Coalescence
continues;'' and Stage 4 ``Large cracks coalesce. Transition to
mechanical growth.'' Id. at 21, fig. 8.
\214\ Mohammed Al-Rabeeah et al., Saudi Arabian Oil Co., Stress
Corrosion Cracking (SCC) Susceptibility Screening Enhancement, 2020
Pipeline Tech. J. 42, 44 (Nov. 2020), available at: https://www.pipeline-journal.net/ejournal/ptj-5-2020/epaper/ptj-05-2020.pdf.
\215\ This restriction should be primarily limited to older
vintages of pipe, as SCC is generally limited to pipe vintages
``with years of installation between 1947 and 1968,'' before
pipeline manufacturers accounted for gas-discharge-temperature in
manufacturing methods. John Kiefner & Michael Rosenfield, Final
Report No. 2012.04, The Role of Pipeline Age in Pipeline Safety at
22-23 (INGAA Found. Nov. 8, 2012), available at: https://ingaa.org/wp-content/uploads/2012/11/19307.pdf. Kiefner and Rosenfield found
that 18 percent of reported SCC incidents occurred in the
approximately 12 percent of pipe in the Nation's gas transmission
pipeline network installed prior to 1950, another 18 percent
occurred in the approximately 25 percent of pipe installed between
1950 and 1959, and the remaining 64 percent occurred in the
approximately 23 percent of pipe installed between 1960 and 1969.
Ibid.
---------------------------------------------------------------------------
As SCC consists of small cracks which become problematic when they
coalesce, and is shown to correlate to pipe vintage, cracking near the
class change segment can indicate a serious risk to the segment. The
same is true with other causes of cracking. PHMSA's experience shows
that cracking is not an isolated defect and is generally found in pipe
with similar material properties, coating type, age, operation and
maintenance history, and environmental conditions. That cracking can
affect or correlate with pipe of similar characteristics is well-
recognized in Subpart O--Sec. 192.917(e)(5) and (6) require the
evaluation of corrosion and cracking threats for segments with similar
characteristics. To address this concern, the IM alternative places a
five-mile limit on the evaluation required under Sec. 192.917(e)(5) &
(6). Five miles is an appropriate range within which it is likely if a
crack occurs, similar conditions within the segment seeking management
under the IM alternative will soon (or already have) lead to cracking.
A five-mile radius has been used successfully for years in class
location special permits, and no one offered a specific or reasonable
alternative limit to use in this rulemaking proceeding.
Focusing the exclusion in the crack eligibility criteria on in-
service leaks or ruptures strikes the proper balance that considers the
recommendations by industry, the public, and the GPAC. An in-service
leak or rupture of the pipe--which includes pipe body, seams, girth
welds, and pipe to pipe connections, but does not include
appurtenances--appropriately targets significant incidents caused by
operational failures. The occurrence of such an incident on a segment
subject to the IM alternative indicates that the operator has failed to
properly implement the applicable program requirements and provides a
reasonable basis for revoking eligibility. Accordingly, if an in-
service leak or rupture due to cracking or any other cause occurs on an
eligible Class 3 segment, the operator is no longer allowed to use the
IM alternative and must either confirm or revise the MAOP in accordance
with the requirements in Sec. 192.611(a)(1) through (3) or replace the
pipe within 24 months.
PHMSA does not agree that violations of Subpart O should be used as
a basis for determining or revoking program eligibility. No other
regulation in part 192 relies on the presence or absence of a violation
in establishing the safety standards that apply to a particular
pipeline facility, and there are no special circumstances that warrant
the use of that criterion in the IM alternative. The decision as to
whether to initiate an enforcement action against an operator for
failing to comply with Subpart O is inherently discretionary, and the
sanction that should be imposed for violating a specific regulation
requires the careful consideration of various factors. Mandating that
an operator be prohibited from using the IM alternative on a Class 3
segment if any violation of Subpart O is found in an enforcement
proceeding is inconsistent with these basic principles. While that
sanction may be appropriate in specific cases, PHMSA does not agree
that a violation of Subpart O, even if established in an enforcement
action resulting from an incident, should provide a per se basis for
determining or revoking an operator's eligibility to use the IM
alternative. The in-service leak or rupture adopted to exclude ongoing
program eligibility discussed above more appropriately excludes program
management failure with regard to cracking, meeting the aim of the
Committee and commenters.
xi. Class Location Change Date--Special Permits
1. Summary of Proposal
The NPRM proposed that the IM alternative would only apply to pipe
segments changing class location after the final rule effective date.
The NPRM did not address whether the IM alternative should be applied
to class change segments subject to active special permits.
2. Initial Comments
The PST agreed that the IM alternative should be limited to
segments that have a class location change following the effective date
of the final rule.\216\ The Associations disagreed, noting that the
limitation artificially restricts the benefits of the IM alternative
without a safety rationale having been provided in the NPRM.\217\ TC
Energy recommended PHMSA allow class changes 24 months before the
effective date to apply the IM
[[Page 1633]]
alternative, because ``restrict[ing] the applicability of [the IM
alternative] to class changes after the effective date of the final
rule would be capricious'' and not add to pipeline safety. An arbitrary
deadline ``would require two class change segments with identical
characteristics to be operated and maintained differently for no reason
other than [class change] date,'' TC Energy added.\218\
---------------------------------------------------------------------------
\216\ See Docket ID PHMSA-2017-0151-0063 at 6.
\217\ See Docket ID PHMSA-2017-0151-0061 at 13-14.
\218\ Docket ID PHMSA-2017-0151-0062 at 3-4.
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The Associations further commented that existing special permits
which are otherwise eligible should be incorporated into the IM
alternative, allowing any previous special permits to be withdrawn. The
Associations argued this was consistent with PHMSA projections since
the 2003 Gas IM rulemaking, and stated that ``[r]equiring similarly-
situated pipelines to comply with different operations and maintenance
requirements based solely on when a class change occurred is
arbitrary.'' \219\ Requiring special permits to be maintained in
perpetuity would create unnecessary administrative burdens for both
PHMSA and operators, according to the Associations and TC Energy.
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\219\ Docket ID PHMSA-2017-0151-0061 at 14.
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3. GPAC Consideration
The GPAC did not offer a specific recommendation as to this issue,
though it is related to the discussion below in section IV.C.xii.
4. Post-GPAC Comments
No significant additional comments on this issue were submitted
after the GPAC.
5. PHMSA Response
PHMSA is expanding the availability of the IM alternative to
eligible Class 3 segments that experienced class location changes prior
to the effective date of the final rule. Limiting the IM alternative to
class location changes that occurred on or after that date would
introduce unnecessary complexity into the regulations and draw
unreasonable distinctions between similarly situated pipeline segments
without providing a meaningful benefit to pipeline safety. Two adjacent
segments originally installed in a Class 1 location on the same date
should not be subject to different MAOP confirmation requirements
simply because, for example, one became a Class 3 location in 2023,
before the effective date of the rule, and the other became a Class 3
location in fall 2026, after the effective date of the rule.\220\ With
the eligibility criteria and initial and recurring programmatic
requirements in the IM alternative creating a comprehensive framework
for ensuring the integrity of eligible Class 3 segments, PHMSA is
allowing operators to apply the IM alternative regardless of when the
class location change occurred.
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\220\ The risk profile of both segments should be the same, and
each of the methods for confirming or revising MAOP under Sec.
192.619(a) is designed to provide a comparable level of safety, so
long as the operator complies with the applicable requirements.
---------------------------------------------------------------------------
Expanding the availability of the IM alternative to pre-effective
date class location changes should only affect a relatively small
number of pipelines. Section 192.611(a) obliges operators to confirm or
to revise the MAOP of a class change segment within 24 months.
Operators who elected to pressure test or replace their pipe--which
PHMSA estimates in the associated RIA as 89 percent of Class 1 to Class
3 and 93.1 percent of Class 2 to Class 3 changes in past practice--have
already complied with Sec. 192.611(a) and should have no reason to use
the IM alternative. However, operators who addressed a prior class
change by reducing MAOP or obtaining a special permit may elect to use
the IM alternative. In the case of the former, operators who
implemented a pressure reduction may be able to restore a previously
established MAOP by following the provisions in Sec. 192.611(d), a
topic discussed in greater detail in the ensuing section. As to the
latter, operators who obtained a special permit have already been
complying with conditions that are comparable to the requirements in
the IM alternative. There is no reason in either scenario to deem these
segments ineligible for the IM alternative solely on the basis of the
date of the class location change.
Operators of eligible Class 3 segments who wish to terminate
existing class location special permits and use the IM alternative
should file a request with PHMSA. PHMSA encourages operators to submit
such requests within one year of the publication of the final rule to
avoid any unnecessary processing delays.
xii. Class Location Change Date--Prior Pressure Reductions
1. Summary of Proposal
Section 192.611(c) currently provides that an operator who confirms
or revises the MAOP of a segment by relying on a prior 8-hour test,
reducing the MAOP, or conducting a new test in accordance with Subpart
J may increase the MAOP of the segment at a later date by complying
with the uprating requirements in Sec. Sec. 192.553 and 192.555.
Section 192.611(d) similarly provides that an operator who reduces the
MAOP of a segment may establish a new MAOP at a later date by
conducting a test in accordance with Subpart J.
The NPRM proposed adding a reference in Sec. 192.611(d) to
acknowledge that an operator who previously reduced the MAOP of a
segment could restore that MAOP at a later date by using the IM
alternative. PHMSA noted that ``an operator would need to implement
[the IM alternative program] prior to any future increases of MAOP.''
Though the text of the proposed amendments to Sec. 192.611(d) would
apply to any pressure reduction, the preamble text at one point noted
that ``operators will not be allowed to use pressure reduction taken
prior to the effective date of the rule'' because the NPRM proposed
applying to future class changes.\221\
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\221\ NPRM, 85 FR at 65168.
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The NPRM also proposed that a pipe segment which had been
previously uprated could apply the IM alternative with a new, Subpart J
pressure test for a minimum of 8-hour pressure test at a minimum test
pressure of 1.39 times MAOP within 24 months after the class change and
prior to raising the MAOP. PHMSA mentioned that allowing MAOP increases
without additional requirements for pipeline segments that have
previously operated at a lower pressure would present undue risk.
2. Initial Comments
The Associations and TC Energy urged PHMSA to allow operators to
use the IM alternative to restore a previously established MAOP, which
``would safely unlock[ ] capacity on an existing pipeline without the
requirement for any new construction,'' benefit customers, and add more
mileage into the IM program. The Associations noted that implementing
the ``rigorous requirements of [the IM alternative] and Subpart K to
restore the original MAOP'' would create ``no new safety risk,'' and
asked PHMSA to clarify that an operator could restore a previously
established MAOP at any time, not only within 24 months of a class
location change.
The Associations supported the proposal to require an additional
1.39 times MAOP pressure test requirement in conjunction with the
existing Subpart K uprating requirements, stating that doing so
``provides a high bar that will ensure safety of class change segments
at their original MAOP.'' \222\ TC Energy agreed with the comments from
the Associations, suggesting that ``operators should be allowed to
utilize [the IM alternative] to return previously de-
[[Page 1634]]
rated pipeline segments to [their] prior MAOP,'' as doing so ``would be
a benefit to consumers and operators to expand capacity on existing
pipelines,'' with safety assured by the ``implementation of [the IM
alternative program] in conjunction with the requirements of [S]ubpart
K.'' \223\
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\222\ Docket ID PHMSA-2017-0151-0061 at 13-14.
\223\ Docket ID PHMSA-2017-0151-0062 at 3.
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The PST did not comment specifically on the concept of MAOP
restoration but asked PHMSA to limit the IM alternative to segments
that undergo class location changes following the effective date of the
final rule.\224\
---------------------------------------------------------------------------
\224\ See Docket ID PHMSA-2017-0151-0063 at 6.
---------------------------------------------------------------------------
3. GPAC Consideration
Industry GPAC members suggested that allowing MAOP restorations as
part of the IM alternative would help to improve pipeline system
capacity and reliability without compromising safety. Meanwhile, GPAC
members representing the public and government expressed support for
the expansion of pipeline infrastructure--noting that the installation
of new pipelines has become increasingly difficult in many States--but
voiced reluctance with reducing the safeguards proposed in the NPRM.
In a 10-2 vote, the GPAC recommended that PHMSA consider allowing
operators who previously managed a class change by a pressure reduction
to use the IM alternative and restore the original operating pressure
of a pipeline segment. The recommendation specified that this would be
technically feasible, reasonable, cost-effective, and practicable, so
long as it (1) maintained an equivalent or greater level of pipeline
safety and (2) operators are effectively managing these segments under
the IM alternative. Specifically, the Committee recommended allowing
the restoration of pressure up to the original MAOP, subject to the
0.72 design factor and 1.25 times MAOP pressure testing limitations in
the IM alternative.
4. Post-GPAC Comments
The Associations agreed with the GPAC's recommendation and urged
PHMSA to allow operators to ``restore the previous pressure up to a
0.72 design factor, if the segments can meet the requirements of'' the
IM alternative. The Associations stated that with a sufficient pressure
test, ``there is not a risk-based or engineering reason to treat these
segments differently than the lines that will undergo class changes
after [the IM alternative] becomes available.'' The Associations also
observed that allowing operators to use the IM alternative for prior
and future pressure reductions is ``a safe and efficient way to
increase [pipeline] capacity without new construction, alleviating the
environmental and landowner concerns that can accompany new gas
infrastructure construction.'' \225\
---------------------------------------------------------------------------
\225\ Docket ID PHMSA-2024-0005-0423 at 10-11.
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Williams similarly ``struggle[d] to find a compelling reason why
PHMSA should'' limit the pathway restoring capacity on pipelines that
underwent a pressure reduction to only those class changes that occur
following the effective date of the rule. Williams noted ``that many of
these pipe segments that [previously] underwent a voluntary, prior
pressure reduction did so because executing a pressure test or
replacing the pipe was impractical or not feasible at the time of the
prior change in class location.'' Williams also stated that allowing
pipe segments which previously underwent pressure reductions to
participate in the IM alternative will allow operators to meet
continuing domestic energy demand ``without having to put new pipe in
the ground.'' Williams emphasized the reasonableness of their proposal
and encouraged PHMSA to ``provide for this option utilizing the
stringent requirements of pressure restoration in Subpart K as part of
the Final Rule.'' Williams stated that such a path would provide ``an
adequate level of safety'' as ``[t]he rigors of the integrity
management standards can provide confirmation and validation of the
pipe material and its condition, and the pressure test provide[s]
confidence in a safe operating pressure for prior class location change
segments.'' \226\
---------------------------------------------------------------------------
\226\ Docket ID PHMSA-2024-0005-0421 at 8-9.
---------------------------------------------------------------------------
An anonymous commenter argued that ``PHMSA must not allow pipeline
operators to raise the MAOP of the Class 1 [design] pipe that is
located in a Class 3 location [as] [e]xisting Class 1 [design] pipe
does not have the strength and integrity of new[,] modern Class 3
[design] pipe.'' The anonymous commenter further noted that ``raising
the pipe MAOP for a Class 1 location to a Class 3 location [] may raise
a 500 psig MAOP . . . to 720 psig MAOP[,] an increase of 44 [percent]
in pressure. This would raise the [potential impact radius] in a highly
populated area.'' \227\
---------------------------------------------------------------------------
\227\ Docket ID PHMSA-2024-0005-0415 at 2.
---------------------------------------------------------------------------
5. PHMSA Response
PHMSA agrees that MAOP restorations should be allowed under the IM
alternative. Section 192.611(c) has long recognized that an operator
may use the process in Subpart K to increase the MAOP of a segment or
conduct a new test in accordance with Subpart J to establish a new MAOP
and Sec. 192.611(d) has permitted an operator to restore the MAOP upon
electing a different compliance method. Consistent with these
provisions and the GPAC's recommendation, PHMSA has determined that the
IM alternative may be used to restore the previously established MAOP
of an eligible Class 3 segment, provided the operator undertakes
certain additional safety measures. These measures are drawn from the
uprating requirements in Subpart K, which have been used for decades to
safely increase the MAOP of pipeline segments.\228\
---------------------------------------------------------------------------
\228\ NPRM, 85 FR at 65157. While several uprating requirements
can also provide safety when restoring MAOP, PHMSA has been clear
that returning pressure previously reduced in response to a class
location change is not considered an ``uprate,'' which the NPRM
disclaimed for the IM alternative as it raises pressure to a new
level not previously qualified. See Transportation of Natural and
Other Gas by Pipeline; Period for Confirmation or Revision of
Maximum Allowable Operating Pressure, 51 FR 34987, 34988 (Oct. 1,
1986).
---------------------------------------------------------------------------
Before restoring a previously established MAOP, the operator must
review the design, operating, and maintenance history of the segment to
determine that the proposed increase in pressure is safe in accordance
with Sec. 192.555(b)(2). An operator must also complete each of the
initial programmatic requirements in the IM alternative before
restoring the previously established MAOP: the pipeline must be
assessed, all anomalies remediated, and the Sec. 192.611(a)(4)(i)
initial programmatic requirements completed. Compliance with the threat
identification and remedial action requirements in Sec. 192.917(e)(3)-
(4) is needed as well, and the final rule requires an operator to
manage a restoration as an MAOP increase under Subpart O. With these
steps complete, the operator may raise the pressure of a segment in the
increments provided at Sec. 192.555(e), i.e., 10 percent of the
pressure, or 25 percent of the total pressure increase, whichever
produces the fewer number of increments. While an operator may restore
the pressure of an eligible Class 3 segment to a previously established
MAOP, no pressure may be restored to greater than 72 percent SMYS for
Class 1 design pipe, or 60 percent SMYS for Class 2 design pipe, as
required by the IM alternative program itself.
These requirements provide the safeguards necessary to restore the
previously MAOP of eligible Class 3 segments. The 1.25 times MAOP test
pressure requirement, when combined with the prior history of
successful operation at the previously established
[[Page 1635]]
MAOP, provides sufficient assurance that the segment can be safely
operated at the increased pressure.\229\ The IM alternative also
requires compliance with a series of additional requirements to ensure
the ongoing integrity of the segment, including the provision in Sec.
192.917(e)(3)(ii) and (4) that requires the prioritization of segments
that undergo MAOP increases for integrity assessments.
---------------------------------------------------------------------------
\229\ On the other hand, to ``uprate'' pressure above a
previously established MAOP may require a 1.5 times MAOP pressure
test under Subpart K.
---------------------------------------------------------------------------
PHMSA is adopting the IM alternative because the methods
traditionally authorized for confirming or revising the MAOP of class
change segments--MAOP reductions, pressure testing, and pipe
replacement--do not account for modern risk management principles and
impose unnecessary burdens on the regulated community and consumers.
The MAOP restoration requirements in the final rule provide a safe,
efficient, and practicable approach for eliminating those burdens and
increasing pipeline capacity.
xiii. Previously Denied Special Permits
1. Summary of Proposal
The NPRM proposed to exclude segments if PHMSA had previously
denied a special permit application for another segment located between
the nearest upstream ILI launcher and downstream ILI receiver.
2. Initial Comments
The Associations and TC Energy commented that a pipe segment should
be eligible or ineligible for the IM alternative on its own right. The
Association also noted that prior applications involved ``inspection
areas often span[ning] tens of miles upstream and downstream of special
permit segments and could have [pipe] attributes and histories
completely different than'' the specific segment previously denied a
special permit.\230\ TC Energy added that the ``[r]ejection [or]
revocation of a special permit may be based on a number of factors that
should not factor into the application of'' the IM alternative, noting,
for example, that PHMSA broadly halted the issuance of special permits
from 2008 to 2010.\231\
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\230\ Docket ID PHMSA-2017-0151-0061 at 14-15.
\231\ Docket ID PHMSA-2017-0151-0062 at 5.
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3. GPAC Consideration
The GPAC did not offer a specific recommendation as to this
proposed eligibility restriction.
4. Post-GPAC Comments
No significant additional comments on this issue were submitted
after the GPAC.
5. PHMSA Response
PHMSA is not finalizing a restriction for previously denied special
permits. As discussed above, the definition of eligible Class 3 segment
excludes segments with pipeline operating characteristics that are not
appropriate for MAOP confirmation under the IM alternative, for
example, severe cracking. The IM alternative also includes requirements
for pressure testing and verification of material property records and
imposes a 72 percent of SMYS limitation on MAOP confirmation. Segments
with these characteristics overlap with those that PHMSA likely did, or
would have, denied in prior special permit proceedings, making an
additional exclusion predicated on that denial unnecessary. With these
eligibility restrictions on use of the IM alternative program, it is
unnecessary to further exclude a segment where its neighbor was
previously denied a special permit.
In addition, it is likely that at least some operators previously
decided not to apply for special permits for segments that PHMSA would
have denied based on the eligibility criteria established in the 2004
policy. Those operators may now be able to use the IM alternative to
confirm, revise, or restore the previously established MAOP of the
segment. An operator who chose to apply for a special permit and
received a denial for a segment with the same characteristics would
not. Today, there is no reason to treat these two segments differently.
Accordingly, PHMSA is not including the proposed eligibility
restriction for previously denied special permits in the final rule.
D. IM Program Requirements
i. Subpart O Incorporation
1. Summary of Proposal
The NPRM proposed requiring operators treat the class change
segment as an HCA subject to the IM requirements in part 192, subpart
O. The proposal also set out specific assessment and remediation
requirements from subpart O, as discussed in sections IV.D.ii through v
below. Subpart O compliance has been a central feature of PHMSA's class
location special permits.
2. Initial Comments
Commenters generally agreed that segments whose class change is
managed under the IM alternative should be subject to the requirements
in Subpart O. The NTSB commented that PHMSA should expand the Subpart O
mileage to include such segments,\232\ and NAPSR and the PST each
supported PHMSA requiring operators designate these as HCAs, while also
providing that further safety requirements are needed.\233\
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\232\ See Docket ID PHMSA-2017-0151-0055 at 4.
\233\ See Docket ID PHMSA-2017-0151-0059 at 7; Docket ID PHMSA-
2017-0151-0063 at 6.
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The Associations, Sander Resources, the GPTC, and NAPSR asked PHMSA
to clarify whether the IM requirements are one-time actions performed
when the class change occurs, and if any subsequent assessments,
remediation, monitoring, and P&MMs would be subject to Subpart O.\234\
Rather than cross-reference Subpart O, the GPTC and Sander Resources
recommended explicitly reiterating all applicable requirements of
Subpart O. Sander Resources also requested that PHMSA clarify the
proposed wording of this requirement, as the phrase ``If the following
[criteria] are met:'' might imply that an operator could have an HCA in
its IM program that the operator does not have to assess.
---------------------------------------------------------------------------
\234\ See Docket ID PHMSA-2017-0151-0061 at 26-27; Docket ID
PHMSA-2017-0151-0064 at 4; Docket ID PHMSA-2017-0151-0065 at 3;
Docket ID PHMSA-2017-0151-0059 at 7.
---------------------------------------------------------------------------
3. GPAC Consideration
The GPAC supported PHMSA's proposal to apply the Subpart O
requirements to class change segments, and voted on individual
implementation details discussed in sections IV.D.ii through v below.
At the meeting, PHMSA explained that the requirements proposed in the
NPRM had been subsequently incorporated into Subpart O by parallel
rulemakings, and that those amendments could now be directly cross-
referenced in this final rule.\235\
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\235\ GPAC, Class Location Requirements Transcript March 28,
2024, Docket ID PHMSA-2024-0005-0309, at 128 (Apr. 11, 2024) (Mary
McDaniel, PHMSA) (``[S]ome of these provisions in here may have been
included since we've adopted those other regulations. But still we
are saying that Subpart O requirements do apply.'').
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4. Post-GPAC Comments
Williams and Mr. Drake each characterized Subpart O as the ``best
standard of care . . . available for operators.'' \236\ The
Associations highlighted Subpart O's strong track record, and noted how
adding more mileage into IM assessment will provide better data for
risk assessment and encourage the use of modern
[[Page 1636]]
technology.\237\ The Associations, Williams, Enbridge, Mr. Drake, and
Mr. Zamarin asked PHMSA to incorporate the amendments to Subpart O
adopted in the 2019 and 2022 Safety of Gas Transmission Rules into the
IM alternative, noting that the new provisions are similar to those
referenced in the NPRM.\238\
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\236\ Docket ID PHMSA-2024-0005-0421 at 5; see Docket ID PHMSA-
2024-0005-0419 at 2.
\237\ See Docket ID PHMSA-2024-0005-0423 at 6, 8-9, 15.
\238\ See Docket ID PHMSA-2024-0005-0418 at 2; Docket ID PHMSA-
2024-0005-0420 at 4-5.
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5. PHMSA Response
The IM alternative applies the requirements in Subpart O to
eligible Class 3 segments. Section 192.611(a)(4) includes explicit
language to that effect and amended Sec. 192.903 includes these
segments as HCAs. These provisions make clear that Subpart O compliance
is required for each eligible Class 3 segment that uses the IM
alternative.
Subpart O requirements--which include anomaly assessment and
remediation, as well as risk assessment procedures--provide an
appropriate foundation for the IM alternative. PHMSA has seen a
significant decrease in failures and ruptures on transmission lines
since Subpart O went into full effect.\239\ Before integrity management
was in effect, yearly reported incidents on gas transmission lines were
consistent or increasing from 2000 to 2012. Regression analysis
projects that without intervention yearly incident counts would have
continued increasing by a rate of 2.98 incidents per year. But after
implementation of integrity management with the first round of baseline
assessments, the trendline reversed, even just from applying IM to a
relatively small portion of all gas transmission lines. In 2013, 107
gas transmission incidents were reported, while in 2024 only 94 such
incidents were reported, with a consistent downward trend in this
period. Using this time period under IM, a regression analysis predicts
each subsequent year to experience 2.64 fewer incidents than the year
before it. As assessments become more advanced, PHMSA expects this
trend will continue and result in further declines in the frequency of
incidents.
---------------------------------------------------------------------------
\239\ Plotting a trendline on incidents from 2000 to 2012
produces an equation of y = 2.9835x + 84.962, while the trendline
for 2013 to 2024 produces an equation of y = -2.6364x + 127.47. This
shows a significant change in the linear relationship of incidents
per year under Subpart O's influence.
---------------------------------------------------------------------------
PHMSA's recent amendments to Subpart O are incorporated by
reference into the IM alternative. Rather than restating existing
regulatory requirements as suggested by some commenters, Sec.
192.611(a)(4) simply refers directly to Subpart O. That approach
eliminates a significant amount of duplicative text, avoids any
uncertainty that might result from having parallel provisions
addressing the same topic, and improves the clarity and concision of
the regulation. These changes will not have any impact on the covered
segments that are otherwise subject (i.e., not under the IM
alternative) to the IM requirements in Subpart O.
PHMSA expects that the IM alternative will add only an estimated
0.64 percent to the total HCA mileage nationwide.\240\ The addition of
this mileage will not dilute the important data that PHMSA receives on
total HCA mileage, and PHMSA sees no reason to omit these segments from
the other IM data collection requirements, such as annual reports and
IM performance measures at Sec. 192.945, that apply to other covered
segments under to Subpart O.
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\240\ In 2023, operators reported approximately 21,381 miles of
onshore transmission HCAs. The RIA estimates that 120 miles of gas
transmission pipeline would take advantage of the IM alternative to
manage class changes.
---------------------------------------------------------------------------
The final rule also applies certain Subpart O requirements,
including the provisions for periodic assessment and remediation, from
the nearest upstream launcher to downstream receiver surrounding the
eligible Class 3 segment. This span of pipe is defined as the eligible
Class 3 inspection area, and the measures taken there are important for
providing safety to the eligible Class 3 segment. These requirements
are discussed in the ensuing subsections.
ii. Assessment Methods
1. Summary of Proposal
The NPRM proposed that operators regularly assess and reassess
eligible Class 3 segments, as well as the portion of pipe extending
from the nearest upstream launcher to downstream receiver, using ILI as
the primary integrity assessment method. Alternative assessment
methods--such as pressure testing or other technology, excluding direct
assessment--could be used by notifying PHMSA 90 days in advance in
accordance with Sec. 192.18. Operators could also notify PHMSA if it
chose not to conduct the ILI as required on a pipeline segment with a
history of pipe body or weld cracking or pipe movement.
Historically, class location special permits have required
assessment using ILI tools tailored to all integrity threats identified
on the pipeline. That requirement has applied to the entire ``special
permit inspection area,'' which extends to the area between the
upstream ILI launcher and downstream ILI receiver, or compressor
stations, or 25 miles on either side of the segment, whichever is less,
to ensure the class change segment is adequately protected.
2. Initial Comments
The Associations encouraged the use of ILI as the primary integrity
assessment method for eligible Class 3 segments, noting that these
assessments will encourage the development of more modern inspection
technology, apply ILI to greater mileage, and provide operators with
more information and data to integrate into their IM program. The
Associations also requested PHMSA clarify that the ILI assessments
should address only the threats to which the eligible Class 3 segment
is susceptible.\241\
---------------------------------------------------------------------------
\241\ See Docket ID PHMSA-2017-0151-0061 at 13.
---------------------------------------------------------------------------
Regarding other integrity assessment methods, the GPTC recommended
that PHMSA not require notification when assessing using a pressure
test as that is allowed under Subpart O.\242\
---------------------------------------------------------------------------
\242\ See Docket ID PHMSA-2017-0151-0065 at 3.
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3. GPAC Consideration
Two GPAC recommendations generally endorsed requiring assessment to
use the IM alternative. By 10-2 and 12-0 votes, respectively, the GPAC
recommended that it was technically feasible, reasonable, cost-
effective, and practicable to require operators perform an initial
assessment within 24 months of the class change, and that operators
could use an assessment from the previous 24 months.
4. Post-GPAC Comments
While in their initial comments the Associations had suggested that
direct assessment should be permitted so long as operators follow the
90-day-prior-notice-and-no-objection process prescribed in Sec.
192.18, in their post-GPAC comments, the Associations offered draft
regulatory text with the direct assessment exclusion reinstated. The
Associations recommended PHMSA otherwise cross-reference assessment
methods under Sec. 192.921(a)(1).\243\
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\243\ See Docket ID PHMSA-2024-0005-0423 at 25.
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5. PHMSA Response
PHMSA agrees that ILI tools should be the primary integrity
assessment for eligible Class 3 segments under the IM alternative. When
compared to other integrity assessment methods, ILI tools provide
operators with the most useful information and data about the current
[[Page 1637]]
state of a pipeline, so long as the operator selects a tool that is
appropriate for completing the assessment of a given threat. The IM
alternative continues to incentivize the use of ILI tools as the
primary integrity assessment method, which is consistent with PHMSA's
historical practice of requirements for the selection and use of ILI
tools for assessment and remediation in class location special permits,
as well as NTSB Recommendation P-15-20.\244\
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\244\ NTSB, Safety Recommendation P-15-20 (Feb. 10, 2015),
available at: https://www.ntsb.gov/safety/safety-recs/recletters/P-15-001-022.pdf (``Identify all operational complications that limit
the use of in-line inspection tools in piggable pipelines, develop
methods to eliminate the operational complications, and require
operators to use these methods to increase the use of in-line
inspection tools.'').
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While Subpart O presents several viable assessment methods, direct
assessment is not authorized under the IM alternative. Direct
assessment identifies the most likely locations where external
corrosion, internal corrosion, or SCC exist on an assessed pipeline
segment. With in situ examinations limited to specific locations,
direct examination is unable to identify and measure anomalies along
the full length of the eligible Class 3 inspection area to provide
assurance with non-commensurate pipe under the IM alternative. PHMSA
has also not allowed operators to use direct assessment as an integrity
assessment method in class location special permits. Allowing operators
to use direct assessment in the IM alternative would be inconsistent
with this historical practice.
The IM alternative otherwise incorporates the requirements for
integrity assessment methods in Subpart O, including the provisions in
Sec. Sec. 192.921(a) and 192.937(c) for conducting baseline
assessments and reassessments, respectively. Incorporating the approved
assessment methods (other than direct assessment) in Sec. Sec.
192.921(a) and 192.937(c) eliminates the need to relist the specific
assessment methods in the IM alternative. This allows for the use of
pressure testing, which has long been recognized as an appropriate
assessment method. However, pressure testing rarely provides
information about specific anomalies, and the result of a pressure test
is generally a binary pass or fail result. As a result, PHMSA expects
operators will likely find pressure testing is a less practicable
integrity assessment method than ILI tools.
Incorporating Sec. Sec. 192.921(a) and 192.937(c) obviates the
need for notification when using an approved assessment method. Such a
notification is not necessary for an assessment method that is already
authorized under Subpart O. An operator intending to use an alternative
method or ``other technology'' for conducting an integrity assessment
is still required to comply with notification requirements at
Sec. Sec. 192.710(c)(7) or 192.921(a)(7), as applicable.
iii. ILI Validation
1. Summary of Proposal
The NPRM proposed requiring operators to validate the results of
ILI assessments under the IM alternative to the Level 3 standard
defined in the second edition of API Standard 1163, In-line Inspection
Systems Qualification Standard, Second edition, April 2013, Reaffirmed
August 2018 (API STD 1163), which PHMSA proposed to incorporate by
reference. API STD 1163 defines Level 3 validation as being supported
by ``extensive validation measurements . . . that allow stating the as-
run tool performance.'' The proposal also included several
specifications, such as conducting four validation digs.
2. Initial Comments
The NTSB supported PHMSA's proposal and was ``hopeful the
implementation of the more detailed requirements of API [STD] 1163 will
lead to a greater level of validation of ILI data,'' noting its
research which shows the quality of such data currently varies from
operator to operator. The NTSB encouraged PHMSA to consider applying
this requirement to the entirety of the Federal Pipeline Safety
Regulations. The NTSB agreed that validation digs were necessary to
show the efficacy of the ILI tools but urged PHMSA to further
scrutinize the ``sufficient'' number of digs ``for data validation.''
\245\
---------------------------------------------------------------------------
\245\ Docket ID PHMSA-2017-0151-0055 at 4. See also NTSB, SS-15-
01, Safety Study: Integrity Management of Gas Transmission Pipelines
in High Consequence Areas (Jan. 27, 2015), available at: https://
www.ntsb.gov/safety/safety-studies/Documents/SS1501.pdf.
---------------------------------------------------------------------------
The PST also strongly supported PHMSA's proposal for tool
validation as critical to confirm ILI tools are operating within
specification, thus providing operators with the ``meaningful data that
is necessary to make . . . decisions about the remaining serviceability
of a pipeline segment.'' \246\ Observing that Level 2 validation does
not ensure a given tool performance is within specification, the PST
endorsed Level 3 validation. Accufacts echoed this last point and noted
that ILI tool validation is necessary to close loopholes in Subpart O
that have led to ineffective application of ILI.\247\
---------------------------------------------------------------------------
\246\ Docket ID PHMSA-2017-0151-0063 at 4-5.
\247\ See Docket ID PHMSA-2017-0151-0058 at 4.
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The Associations agreed with the value of ILI validation but
questioned the need to require it to Level 3, which they stated is not
practicable, unnecessary to ensure safety, and intended for use by ILI
tool vendors. The Associations noted that Level 3 requires ``extensive
measurements'' which are ``often not possible'' for segments in the
best condition, i.e., the best candidates for the IM alternative. This,
the Associations argued, would inhibit ILI of segments not previously
inspected and where few anomalies have been identified. Emphasizing
that API STD 1163 ``Level 1 and Level 2 validation . . . prove with a
high degree of confidence that the tool performed in accordance with
the tool vendor's specifications,'' the Associations argued there is no
reason to depart from Subpart O, which requires validation under API
STD 1163 but does not specify a required level of validation.\248\ In
addition, the Associations stated that the proposed four dig
requirement is ``not necessary to validate tool performance,'' with
``no technical basis for selecting four digs'' provided in the
proposal.
---------------------------------------------------------------------------
\248\ Docket ID PHMSA-2017-0151-0061 at 21-22. Sanders Resources
questioned whether this rulemaking vehicle was the proper one in
which to incorporate by reference API STD 1163. See Docket ID PHMSA-
2017-0151-0064 at 3. However, API STD 1163 was originally
incorporated by reference, for Sec. 192.493, in the 2019 Safety of
Gas Transmission Rule. See 84 FR at 52210, 52243. This rulemaking
merely extends it to Sec. 192.611(a)(4).
---------------------------------------------------------------------------
3. GPAC Consideration
Public comments from industry members similarly expressed that
Level 3 validation was overly intensive when Levels 1 and 2 provided
high confidence to validate tools. The GPAC offered no specific
recommendation as to the level of validation.
4. Post-GPAC Comments
No significant additional comments on this issue were submitted
after the GPAC.
5. PHMSA Response
The IM alternative requires validation of ILI assessments to at
least Level 2, rather than Level 3 as proposed in the NPRM. Confirming
that ILI measurements accurately reflect tool performance and anomaly
characterization is essential for an operator to effectively use ILI
data. Though Subpart O generally allows any appropriate level to be
used to validate
[[Page 1638]]
tools, Level 1 validation is for ILI tool use on pipelines ``that
represent low levels of risk in consideration of either consequence or
probability of failure.'' \249\ Level 1 validation is not appropriate
for eligible Class 3 segments under the IM alternative, which relies
heavily on the results of ILI assessments to provide the margin of
safety that would otherwise be afforded by the class-based design and
test factors in part 192.
---------------------------------------------------------------------------
\249\ API, API Standard 1163, In-line Inspection Systems
Qualification, sec. 8.1.3 & C.1.1 (2nd Ed. Rev. 2018) (API STD
1163).
---------------------------------------------------------------------------
Based on the comments submitted and PHMSA's subsequent technical
review of the standard, the IM alternative requires validation of ILI
results to at least Level 2 in accordance with API STD 1163, rather
than Level 3 as proposed.\250\ Whereas Level 1 relies only on
historical data, Level 2 validation provides appropriate validation and
confidence level to verify that ILI tools are performing within stated
specifications and have adequately indicated potential areas of the
specified threat. By using field measurements to check tool performance
against its specification, Level 2 establishes a minimum confidence
level for assessments while avoiding unnecessary excavations and
analyses that may be required in Level 3 where a tool is not performing
according to specification.\251\ Use of Level 2 is bolstered with
PHMSA's requirement to conduct anomaly digs necessary to achieve 80
percent confidence.
---------------------------------------------------------------------------
\250\ Under API STD 1163, Level 2 validation may require an
operator to conduct Level 3 validation in certain situations
requiring additional measurements. For example, if a Level 2
validation indicates that ILI tool performance is worse than
specified, API STD 1163 provides that the operator should consider
performing more field measurements, rejecting the ILI tool, or
confirming the as-run performance of the ILI assessment with a Level
3 validation. See, e.g., API STD 163, Fig. 6. API STD 1163 provides
that operators or equipment manufacturers should also consider
performing Level 3 validation when evaluating new technologies or
new applications of technologies.
\251\ See API STD 1163, Sec. 8.2.6.
---------------------------------------------------------------------------
API STD 1163 also provides for the appropriate number of validation
measurements (i.e., digs) to establish confidence that the ILI is
performing within specification.\252\ Having considered the various
comments regarding the proposed validation measurements, PHMSA agrees
it is not well-suited to a one-size-fits-all codified requirement.
Instead, PHMSA is requiring operators to perform sufficient in-situ
anomaly validation measurements to achieve an 80 percent confidence
level for the tool run in accordance with API STD 1163. This may
require more or less validation measurements to successfully validate
the ILI tool performance than did the proposal, and is more technically
based for the tool and pipeline, as the NTSB suggested PHMSA consider.
As the third edition of API STD 1163 addresses validation measurement
and validation levels in greater detail compared with the second
edition, PHMSA will consider in a future rulemaking updating the
incorporation by reference of newer editions of API STD 1163, which may
allow for more tailored validation dig requirements.
---------------------------------------------------------------------------
\252\ PHMSA notes that the IM alternative uses the term
``validation measurement,'' rather than ``validation dig,'' to
minimize ambiguity. The term validation measurement is defined
separately from calibration dig in API STD 1163, since multiple
anomalies can be measured in a single dig, referring to measurements
is more accurate.
---------------------------------------------------------------------------
iv. Baseline Assessment
1. Summary of Proposal
The NPRM proposed requiring a baseline integrity assessment within
24 months following a change in class location. This baseline
assessment, similar to the reassessment mandated at least every seven
years, would cover the class change segment and the surrounding area
extending from the nearest upstream launcher to the downstream
receiver.
2. Initial Comments
The Associations commented that PHMSA should allow assessments from
a few years prior to satisfy as the baseline assessment requirement,
provided the operator complete any outstanding remediation within 24
months of the class change.\253\ TC Energy also supported allowing
assessments recently completed before the class change to count towards
the initial assessment.\254\
---------------------------------------------------------------------------
\253\ See Docket ID PHMSA-2017-0151-0061 at 22.
\254\ See Docket ID PHMSA-2017-0151-0062 at 7.
---------------------------------------------------------------------------
The PST recommended that PHMSA accelerate the proposed baseline
assessment requirement to require operators to both conduct a baseline
assessment and to complete remediation of any identified anomalies
within 24 months. Permitting operators to conduct only an initial
assessment, the PST argued, ``pretty much guarantees there will be
segments that have changed classes . . . and are still subject to the
higher risks of an older, weaker pipe, requiring additional time to
plan for its replacement or to apply for a special permit.'' \255\
Conversely, TC Energy sought more time, recommending 36 months from the
class change to complete the baseline assessment to allow adequate time
for proper assessment, giving sufficient time for an operator to
identify and document susceptible threats; contract, schedule, and
coordinate tool services; and integrate the data from multiple ILI
tools.\256\
---------------------------------------------------------------------------
\255\ Docket ID PHMSA-2017-0151-0063 at 6-7.
\256\ Docket ID PHMSA-2017-0151-0062 at 7.
---------------------------------------------------------------------------
3. GPAC Consideration
GPAC members representing the government and the industry supported
the use of prior assessments to satisfy the baseline assessment
requirement. These members noted that data from a tool run could be
valid for several years and that prohibiting operators from using prior
assessments would create an arbitrary and artificial deadline centered
around the date of the class location change.
In a 12-0 vote, the GPAC recommended that the timing of the
baseline assessment was technically feasible, reasonable, cost-
effective, and practicable, if PHMSA permitted a valid previous
assessment performed within 24 months of the class location change to
serve as the baseline assessment, so long as remediation is completed
and the reassessment interval is maintained as detailed in the rule.
4. Post-GPAC Comments
The Associations reiterated their support for using prior
assessments because ``[m]odern technology permits operators to predict
developments over time periods that far exceed 24 months'' and provide
``good data that is actionable for years.'' \257\ The Associations also
echoed the concerns of the GPAC members that requiring a new assessment
within 24 months of a class change soon after having run a prior tool
could be considered arbitrary and result in the deployment of
unnecessary resources.
---------------------------------------------------------------------------
\257\ Docket ID PHMSA-2024-0005-0423 at 16.
---------------------------------------------------------------------------
5. PHMSA Response
The IM alternative requires an operator to conduct a baseline
assessment and complete any necessary remediation within 24 months of
the class location change or effective date of the final rule. PHMSA
agrees with the commenters and unanimous GPAC recommendation that
operators should be allowed to use recently conducted integrity
assessments to satisfy the baseline assessment requirement. A prior
integrity assessment meeting the parameters required by IM alternative,
conducted within 24 months of the class location change or effective
date of the final rule, contains data that remains valid and is
comparable to a new
[[Page 1639]]
integrity assessment conducted in the 24-month period following these
dates. Either can be used to satisfy the initial integrity assessment
requirement in the IM alternative, an approach that PHMSA has applied
in class location special permits.
PHMSA agrees with the PST that the timeline for remediating
conditions discovered during an initial integrity assessment should be
modified--PHMSA is requiring all repairs of immediate and scheduled
conditions to be completed within a 24-month period. That time period,
which runs either from the effective date of the final rule or the date
of the class location change, aligns with the 24-month deadline that
applies under Sec. 192.611(d) for confirming or revising the MAOP of a
non-commensurate segment. Requiring remediation of immediate and
scheduled conditions within the 24-month period ensures that a segment
will be of optimal condition to administer the IM alternative program
from the outset. The 24-month period also provides operators with
enough flexibility to complete the baseline assessment and scheduled
remediation, while providing for pipeline safety with prompt
remediation of time-sensitive conditions.\258\
---------------------------------------------------------------------------
\258\ This deadline does not supersede (or extend) remediation
timelines in Sec. 192.933. Anomalies discovered during a baseline
assessment must be remediated in accordance with the requirements of
that section or within 24 months of the change in class location,
whichever is earlier.
---------------------------------------------------------------------------
v. Remediation Schedule
1. Summary of Proposal
The NPRM proposed an extensive remediation schedule for managing
anomalies discovered during an integrity assessment. The proposed
schedule identified the following three tiers of remediation timelines
based on threat potential:
1. PHMSA proposed immediate repair of anomalies at or near the
point of failure, including metal loss with a predicted failure
pressure less than or equal to 1.1 times the MAOP, crack-like defects
with a predicted failure pressure less than 1.25 times the MAOP, and
additional specified criteria dependent on anomaly type and size.
2. PHMSA proposed requiring repair within one year for metal loss,
denting, cracking, and other anomalies that are not an immediate threat
to integrity but which require timely repair before they devolve into a
more significant threat. Many of these criteria used engineering
analysis, such as predicted failure pressure (PFP) using a safety
factor based on the class location and dent repair criteria on an
engineering critical assessment (ECA) using anomaly size and location.
3. Other less severe anomalies would require monitoring during
subsequent integrity assessments.
PHMSA proposed to apply this remediation schedule to anomalies
found throughout the eligible Class 3 inspection area (i.e., the
eligible Class 3 segment and the span of pipe from its nearest upstream
launcher to downstream receiver). Within the eligible Class 3 segment
specifically, PHMSA proposed an additional one-year remediation
requirement for anomalies exhibiting crack depth or pipe wall thickness
loss greater than 40 percent. PHMSA also proposed a two-year
remediation requirement for anomalies throughout the eligible Class 3
inspection area exhibiting cracks with 40 percent or greater wall depth
and a PFP greater than or equal to 1.39 times MAOP.
2. Initial Comments
The comments on this topic generally expressed (1) support for the
expanded remediation schedule, (2) divergence on the timeline for
remediation of various anomalies outside the segment, and (3)
opposition to the two additional prescriptive crack remediation
criteria as superfluous.
The PST and Accufacts appreciated PHMSA's proposed updated
remediation criteria.\259\ The historical Subpart O remediation
schedule provided too much ``room for error,'' according to Accufacts,
while the proposal incorporated prudent ILI tool tolerances into
predicted failure pressures to prevent anomalies with actual failure
pressures below MAOP, which has caused some ruptures below MAOP.
Accufacts lauded PHMSA's proposal and noted that the approach responded
to early ruptures under Subpart O and would ensure ``consistency across
the industry.'' \260\ TC Energy advocated for a risk-based remediation
schedule, allowing operators to select the appropriate time to repair,
rather than apply a fixed schedule. TC Energy also noted that ``a
repair is not always required to maintain pipeline safety. Often,
remediation, such as a recoating, adequately address[es] a condition.''
\261\ The Associations agreed that the remediation schedule should be
updated and harmonized with the improved Subpart O remediation schedule
in the then-in-progress 2022 Safety of Gas Transmission Rule.\262\
---------------------------------------------------------------------------
\259\ Docket ID PHMSA-2017-0151-0058 at 4-5.
\260\ Docket ID PHMSA-2017-0151-0058 at 4; see Docket ID PHMSA-
2017-0151-0063 at 6-7.
\261\ Docket ID PHMSA-2017-0151-0062 at 6.
\262\ See Docket ID PHMSA-2017-0151-0061 at 22-23.
---------------------------------------------------------------------------
The GPTC also highlighted how the proposed remediation schedule was
more stringent than the then-codified remediation schedule in Subpart
O. The GPTC asked PHMSA to clarify that the additional requirements
were applicable in particular to the eligible Class 3 segment and not
all pipelines subject to Subpart O.\263\
---------------------------------------------------------------------------
\263\ See Docket ID PHMSA-2017-0151-0065 at 2-3.
---------------------------------------------------------------------------
As for the timing of scheduled remediation, TC Energy commented
that pipelines in the eligible Class 3 inspection area should be
treated the same as any other non-HCA segment, with two years to
schedule repairs.\264\ The Associations agreed, offering that the
broader inspection area was ``no different than any other non-HCA'' and
should be treated to a two-year response for scheduled anomalies, while
one year was appropriate for the eligible Class 3 segment given its HCA
designation. The Associations commissioned a study from Blade Energy
Partners to demonstrate how extending the remediation period for
scheduled anomalies in the eligible Class 3 inspection area from a one-
year timeline to a two-year timeline would still provide sufficient
safety for the external corrosion and SCC threats.\265\
---------------------------------------------------------------------------
\264\ See Docket ID PHMSA-2017-0151-0062 at 6.
\265\ Docket ID PHMSA-2017-0151-0061 at 23, submitting Blade
Energy Partners, Reliability Based Assessment of Pipeline Class
Changes (Dec. 4, 2020).
---------------------------------------------------------------------------
Given their support for using the then-proposed Subpart O
remediation schedule from the 2022 Safety of Gas Transmission Rule, the
Associations argued against the two additional crack related
conditions, which were not contained in those in-progress amendments to
Subpart O. Citing the Blade Report, the Associations suggested that
equivalent safety would be provided regardless of whether the 40
percent crack or metal loss depth criteria were adopted. The
Associations observed that ``wall loss in and of itself is an
incomplete measure of risk'' while ``PFP is a much more informed basis
for categorizing anomalies, because PFP calculations consider anomaly
depth, length, and pipe material properties to directly evaluate the
extent to which an anomaly is impairing the pipeline's ability to
safely operate at its MAOP.'' The Associations argued that, because
PHMSA's other proposed remediation criteria already ensure that
anomalies which reduce the PFP of the class change segment below 1.39
times
[[Page 1640]]
MAOP will be remediated within one year, ``the additional depth-based
criterion is unnecessary.'' In addition, the Associations suggested
removing the requirement in monitored conditions to consider anomaly
growth because they found it ``confusing and contradictory.'' \266\
---------------------------------------------------------------------------
\266\ Id. at 22-24.
---------------------------------------------------------------------------
TC Energy also found this added criteria lacking in technical
justification, even if consistent with some class location change
special permit conditions. TC Energy echoed the Associations'
observations about the insufficiency of wall loss as a measure of risk
when compared to PFP and noted the improved quality of ILI tool
accuracy.\267\
---------------------------------------------------------------------------
\267\ Docket ID PHMSA-2017-0151-0062 at 6.
---------------------------------------------------------------------------
3. GPAC Consideration
PHMSA amended the Subpart O remediation schedule in the 2022 Safety
of Gas Transmission Rule, which published prior to the GPAC meeting on
the NPRM. Given the consistency between the two, PHMSA explained at the
GPAC meeting that the final rule in this proceeding could simply cross-
reference the new Subpart O remediation schedule.\268\ The GPAC members
discussed the proposed remediation schedule, ultimately recommending,
by a vote of 10-2, that PHMSA use the same assessment and repair
criteria now in place under Subpart O. As discussed in section IV.C.x,
the GPAC also voted 10-2 recommending for the remediation of crack
anomalies in accordance with Subpart O.
---------------------------------------------------------------------------
\268\ GPAC, Class Location Requirements Transcript March 28,
2024, Docket ID PHMSA-2024-0005-0309, at 128 (Apr. 11, 2024) (Mary
McDaniel, PHMSA) (``[S]ome of these provisions in here may have been
included since we've adopted those other regulations. But still we
are saying that Subpart O requirements do apply.'').
---------------------------------------------------------------------------
4. Post-GPAC Comments
The Associations stated that using the newly updated Subpart O
repair criteria ``ensures that operators are repairing the highest risk
pipe at the earliest time versus the use of an arbitrary repair
timeline that would require an operator to repair a lower risk pipe
earlier than pipe at a greater risk.'' The Associations continued that
there is ``no clear reason why'' separate remediation schedules are
necessary for HCAs and the IM alternative.\269\ Williams added its
support for the amended Subpart O standards, which ``are backed up by
years of research, scientific data analysis, and peer-reviewed,
technical debate by numerous industry experts.'' Williams offered that
``buil[ding] upon these principles enhance[s] the level of certainty
for operators'' and that ``operators and PHMSA have confidence in the
ability of the ILI tools to correctly grade anomalies.'' \270\
---------------------------------------------------------------------------
\269\ Docket ID PHMSA-2024-0005-0423 at 15.
\270\ Docket ID PHMSA-2024-0005-0421 at 10.
---------------------------------------------------------------------------
5. PHMSA Response
The IM alternative applies the recently amended Subpart O
remediation schedule to protect pipeline integrity and provide for
safety across the eligible Class 3 inspection area, consistent with the
intent of the proposal, the suggestion of many commenters, and the
recommendation of the GPAC. Since publication of the NPRM, PHMSA has
enacted a modern, detailed remediation schedule for anomalies in
Subpart O at Sec. 192.933.\271\ The IM alternative applies that
remediation schedule, which is analogous to the schedule proposed in
the NPRM, to anomalies detected in the eligible Class 3 segment and
eligible Class 3 inspection area. Applying the Sec. 192.933
remediation schedule provides a more detailed, specific response
schedule, as the PST and Accufacts advocated, and it provides a single
remediation schedule operators are already becoming familiar with, as
the Associations and operators like Williams sought.
---------------------------------------------------------------------------
\271\ See 2022 Safety of Gas Transmission Rule, 87 FR at 52224.
---------------------------------------------------------------------------
Rather than prescribing a rigid or one-size-fits-all approach,
Sec. 192.933 uses calculations of remaining fatigue life and predicted
failure pressure to determine the remediation schedule for anomalies.
Each criterion grounded in a predicted failure pressure also includes a
safety factor based on class design. Where the NPRM originally proposed
to add to each individual criterion a 1.39 times MAOP factor for Class
1 design pipe in Class 3 location, the IM alternative provides at Sec.
192.611(a)(4)(iii)(C) that same safety factor to use across Sec.
192.933(d). A similar variance is not needed for Class 2 pipe, which
has the same 1.5 times MAOP factor as Class 3 pipe for most criteria
under Sec. 192.933(d).
To facilitate fatigue life and predicted failure pressure, Sec.
192.933 references the engineering calculations in Sec. 192.712. That
includes the dent ECA process in Sec. 192.712(c), which PHMSA
similarly proposed in this NPRM and adopted in the parallel 2022 Safety
of Gas Transmission Rule. In response to a petition for judicial review
filed by the Interstate Natural Gas Association of America, the U.S.
Court of Appeals for the D.C. Circuit issued an order remanding Sec.
192.712(c) to PHMSA for further consideration without vacating it.\272\
PHMSA intends to address the order on remand in the rulemaking
``Pipeline Safety: Repair Criteria for Hazardous Liquid and Gas
Transmission Pipelines'' (RIN 2137-AF44), which focuses on the repair
criteria for gas transmission lines, including anomaly thresholds for
cracks, dents, and certain seam types. Section 192.712(c) remains in
effect until that time.
---------------------------------------------------------------------------
\272\ Order on Pet'r's Pet. for Panel Reh'g at 1, INGAA v.
PHMSA, No. 23-1173 (D.C. Cir. Dec. 10, 2024); see Pipeline Safety:
Safety of Gas Transmission Pipelines: Repair Criteria, Integrity
Management Improvements, Cathodic Protection, Management of Change,
and Other Related Amendments: Corrections to Conform to Judicial
Review, 90 FR 3713, 3714 (Jan. 15, 2025).
---------------------------------------------------------------------------
The NPRM proposed two conditions not found in Sec. 192.933 that
PHMSA is omitting from the IM alternative. First, the NPRM proposed to
require the repair within one year of metal loss or cracking exceeding
40 percent of the wall thickness found in the class change segment.
Second, the NPRM proposed to require the repair within two years of a
detected crack through 40 percent or more of the pipe wall thickness,
which produces a predicted failure pressure of 1.39 times MAOP or more,
in the eligible Class 3 inspection area. As the GPTC noted, both
proposals conflicted with the HCA remediation requirements at Sec.
192.933. And, as several commenters observed, supported by technical
study, the anomaly response measures centered on predicted failure
pressure contained in Sec. 192.933 are more accurate measures of a
pipeline safety threat than a default requirement to repair the
proposed 40 percent anomalies. For example, a 40 percent wall thickness
crack is not perceived as a safety threat warranting scheduled repair
in all cases. The predicted failure pressure can more accurately
calibrate anomaly response to threats, allowing operators to focus on
risks to pipeline safety.
Finally, a one-year timeline for remediating scheduled conditions
under Sec. 192.933 applies to the eligible Class inspection area,
consistent with the NPRM and as historically required under special
permits. While some operators advocated applying the two-year
remediation timeline for areas outside of the eligible Class 3 segment,
similar to locations outside of HCAs in Sec. 192.714, PHMSA concludes
that applying a consistent assessment and remediation requirement
across the entire inspection area is appropriate. Adopting consistent
criteria and timelines simplifies the implementation and enforcement of
integrity
[[Page 1641]]
assessments and remediation, given that the entire eligible Class 3
inspection area will be assessed at the same time. Ensuring anomaly
response between the nearest launcher and receiver of the segment also
provides an additional margin of safety for the eligible Class 3
segment itself. Incorporating the remediation requirements of Subpart O
is consistent with the various interests provided in comments to the
NPRM and was emphasized repeatedly over the course of the GPAC meeting,
including by members representing gas transmission operators.\273\
Since these pipelines are in areas experiencing population growth,
extending the IM remediation criteria to the entire eligible Class 3
inspection area ensures the continued integrity of pipelines that
become Class 3 segments in the future.
---------------------------------------------------------------------------
\273\ See, e.g., GPAC, Class Location Requirements Transcript
March 27, 2024, Docket ID PHMSA-2024-0005-0307, at 105-06 (comment
of Member Andy Drake) (summarizing a discussion of class location
and IM).
---------------------------------------------------------------------------
E. Additional Programmatic Requirements--One-Time and Recurring
Obligations
i. General Programmatic Requirements
1. Summary of Proposal
PHMSA proposed in the NPRM that operators be required to perform
preventative and mitigative measures (P&MM) that address threats not
assessed or manageable by ILI. These included prescribed close interval
surveys (CIS), interference surveys, and CP pipe-to-soil test station
locations; the installation of line-of-sight markers; additional right-
of-way patrols and leakage surveys; clarified depth-of-cover
requirements to specify lowering pipe or adding cover where depth was
too low; and rectifying shorted casings. In addition, as an eligibility
provision, the NPRM proposed that a segment using the IM alternative
must not transport gas whose composition is not suitable for sale. The
NPRM also proposed to require pipe weld inspections for cracking on
uncovered segments of pipe.
2. Initial Comments
This proposal garnered widespread approval. The Associations
generally supported the proposal,\274\ while the PST and Accufacts
applauded how PHMSA adequately maintained pipeline safety by combining
these P&MMs with the IM requirements. The PST noted that these
additional requirements are ``necessary to assure the integrity of
Class 1 [design] pipe'' operating in Class 3 locations without
replacement.\275\ Accufacts concurred that the additional activities
proposed in the NPRM were necessary for pipeline safety and provided a
level of safety consistent with the current MAOP confirmation options.
Accufacts commended how these proposed requirements focused on
``preventing the introduction or growth of injurious anomalies.'' \276\
The Associations requested PHMSA ``clarify that [the P&MM] requirements
qualify as `additional measures' to meet the requirements of Sec.
192.935(a),'' which requires operators to implement additional measures
beyond those already required by part 192.\277\ The Associations also
recommended PHMSA allow an operator to use the results of CIS and
interference surveys performed prior to the change in class location to
meet the requirements.
---------------------------------------------------------------------------
\274\ See Docket ID PHMSA-2017-0151-0061 at 26.
\275\ Docket ID PHMSA-2017-0151-0063 at 7.
\276\ Docket ID PHMSA-2017-0151-0058 at 5.
\277\ Docket ID PHMSA-2017-0151-0061 at 26.
---------------------------------------------------------------------------
Regarding depth-of-cover, the Associations commented that it could
be impracticable on short segments to restore construction cover depths
and suggested that lowering a short segment of pipe could introduce its
own safety risks, such as additional strain or liquid buildup, or
inhibit the ability to accommodate ILI tools. Both the Associations and
NAPSR recommended that operators should be permitted to use all
effective measures to mitigate the consequences of loss of cover, such
as installing above-ground safety barriers or adding concrete over the
pipe.\278\
---------------------------------------------------------------------------
\278\ See id. at 27; Docket ID PHMSA-2017-0151-0059 at 6.
---------------------------------------------------------------------------
3. GPAC Consideration
With a unanimous 12-0 vote the GPAC endorsed these measures as
``necessary to maintain pipeline safety.'' The Committee also
recommended that PHMSA allow the P&MMs to count as ``additional
measures'' for the purposes of operators complying with Sec. 192.935.
4. Post-GPAC Comments
The Associations reiterated their general support for the P&MMs,
noting that ``many of the P&M[Ms] proposed under [the IM alternative]
are already in place for special permits and used on HCA segments in
accordance with [Sec. ] 192.935(a).'' \279\ The Associations
cautioned, however, that ``the P&M[Ms] required in Subpart O already
provide sufficient monitoring and risk reduction for pipeline safety,''
and noted that adding requirements may be burdensome without
commensurate benefit. Regarding depth-of-cover, the Associations
requested revision to increase flexibility, without any loss of safety
benefit, by ``allow[ing] operators the option to install concrete pads
over pipe with depth of cover less than 24 inches . . . similar to the
protections allowed in [Sec. ] 192.327(c).'' \280\
---------------------------------------------------------------------------
\279\ Docket ID PHMSA-2024-0005-0423 at 17.
\280\ Id.
---------------------------------------------------------------------------
5. PHMSA Response
The IM alternative requires operators to comply with a series of
additional O&M measures in addition to the IM provisions. These
measures are intended to protect the pipe from threats of corrosion and
excavation damage, and are consistent with conditions PHMSA has
typically included in class location special permits and received broad
support from commenters and the GPAC. While the IM program in Subpart O
is foundational to the IM alternative, equally important for pipeline
safety to further account for the pipe being not commensurate with
class design--as commented by the NTSB, the PST, and others--are the
other program management requirements proposed in the NPRM.
For regulatory clarity, PHMSA has broken the requirements into a
list at Sec. 192.611(a)(4)(i) for those that are initial, one-time
requirements to be completed within 24 months of the class location
change, and a second list at Sec. 192.611(a)(4)(ii) for the ongoing,
or recurring, requirements to be maintained. In response to comments
from the Associations and the GPAC recommendations, PHMSA confirms that
the P&MMs in the IM alternative can qualify as ``additional measures''
necessary for an operator to comply with Subpart O requirements. These
programmatic requirements supplement an operator's determination to
take additional P&MMs for each segment. PHMSA expects operators to
evaluate the merits of additional P&MMs, above and beyond what is
required by Sec. 192.611(a)(4), for each segment as necessary and
consistent with their IM program.
Corrosion and excavation damage are two leading causes of gas
transmission incidents. While modern technology allows an operator to
mitigate the risk of corrosion and other time-dependent threats through
application of IM and use of ILI tools, additional provisions are
necessary to ensure the safety of eligible Class 3 segments to account
for the design factor reduction. The risk of excavation damage is not
fully captured by preventative ILI assessment and is a particular issue
in more densely populated Class 3 locations, warranting supplemental
requirements under the IM alternative. While there are modest
[[Page 1642]]
costs for operators to perform these activities, those costs are
justified by safety benefits from managing corrosion and the potential
cost savings for identifying coating or CP deficiencies before they
result in corrosion anomalies that require remediation, as well as from
avoided excavation damage.
The IM alternative provides a consistent level of safety over the
life of the pipeline through more stringent corrosion requirements for
performing CIS, spacing cathodic protection test stations, and ensuring
that the concentration of certain corrosive materials in the gas stream
is kept below specified levels.\281\ Close interval surveys assess the
adequacy of CP on the pipeline and help to identify areas where current
may be leaving the pipeline, which may cause corrosion. Monitoring and
evaluating the effectiveness of CP, and identifying and remediating
coating anomalies, are key components of preventing corrosion and
predicting the growth rate of corrosion that has been discovered. Test
stations assist in corrosion control as they are a direct connection to
the pipe that check the adequacy of CP during annual inspections; these
inspections ensure that operators catch issues with a pipeline's
corrosion control system in a timely manner. Limiting the gas stream
transported to gas quality reflected in FERC tariffs and ordinary
operating conditions restricts excess constituents to ensure that
pipelines transport gas that does not itself pose a pipeline safety
risk from internal corrosion.
---------------------------------------------------------------------------
\281\ The proposed requirement for operators to perform
interference surveys has been adopted at Sec. 192.473(c) and is no
longer necessary as part of this final rule. See 2022 Safety of Gas
Transmission Rule, 87 FR at 52269-70.
---------------------------------------------------------------------------
The IM alternative also includes damage prevention requirements
(patrols, leakage surveys, line markers, and maintaining adequate depth
of cover) that are an effective risk mitigation measure as shown
through class location special permits. Patrols are a cost-effective
way for operators to identify excavation or construction activity,
along with other potential integrity threats such as earth movement.
Leakage surveys can identify relatively minor gas releases that occur
between integrity assessments, or on components that operators cannot
evaluate with ILI tools, before they deteriorate into more significant
problems. Line markers visible along the pipeline right of way provide
a final reminder for excavators that there are gas pipelines in the
vicinity, and the contact information on the markers can be useful for
first responders or other members of the public in the case of an
emergency.
In addition, adequate depth of cover can reduce the strain on the
pipeline from surface earth movement and, to some extent, can reduce
the risk that excavation activity results in damage to a pipeline.
PHMSA's class location special permits have historically required a
depth of cover survey within the first six months, along with
appropriate remedial measures. PHMSA agrees with commenters that the
risks addressed by depth of cover can be remediated through various
engineered means, and the IM alternative allows operators to select the
appropriate means of remediation, which may include markers, lowering
pipe, adding cover, or adding safety barriers. This is similar in
principle to existing exceptions to the depth of cover requirements at
Sec. 192.327(c). By preventing excavation damage, each of these
measures prevents costly pipeline repairs and serious risk to life and
property from pipeline punctures.
Further, the IM alternative requires operators to examine the
pipeline and its welds whenever a pipeline is exposed and the coating
is removed. This is a non-destructive opportunity for operators to
verify they are mitigating cracks effectively. It is not a free-
standing obligation and only occurs when the pipe is otherwise exposed,
excluding for the purposes of Sec. 192.614(c), and is capable of easy
inspection.
Additional supplemental measure as discussed in the ensuing
subsections.
ii. Clear Shorted Casings
1. Summary of Proposal
The NPRM proposed requiring operators to clear shorted casings
within 1 year of discovery. Casings are typically installed at road and
railway crossings. The pipeline carrying gas is surrounded by a casing
pipe to protect it from outside forces. These pipes are electrically
isolated from each other to prevent corrosion and ensure the
effectiveness of CP. When the carrier pipe and casing come into
metallic or electrolytic contact, a short can occur. Shorted casings
increase the risk of active corrosion. PHMSA has historically included
conditions aimed at detecting and remediating shorted casings in class
location special permits, including requirements to clear a shorted
casing within one year of discovery.
2. Initial Comments
The Associations and TC Energy argued that shorted casings could be
managed with IM.\282\ Each noted that PHMSA issued an interpretation to
Enstar in March 2019 allowing the operator to monitor and perform ILI
inspections of shorted casings that were impractical or unsafe to
clear.\283\ Similarly, TC Energy claimed that in certain class location
change special permits PHMSA allows the management of shorted casings
that are impractical to clear.\284\
---------------------------------------------------------------------------
\282\ See Docket ID PHMSA-2017-0151-0061 at 17; Docket ID PHMSA-
2017-0151-0062 at 8.
\283\ See PHMSA, PI-18-0003, Letter of Interpretation to Mr.
Steve Cooper (Mar. 11, 2019), available at: https://www.phmsa.dot.gov/regulations/title49/interp/pi-18-0003. See also
PHMSA, PI-19-0006, Letter of Interpretation to Mr. Steve Cooper
(Oct. 22, 2019), available at: https://www.phmsa.dot.gov/regulations/title49/interp/pi-19-0006.
\284\ See Docket ID PHMSA-2017-0151-0062 at 8.
---------------------------------------------------------------------------
3. GPAC Consideration
The GPAC briefly discussed the management of shorted casings, with
members representing the industry referencing the 2019 Enstar
interpretation and highlighting how operators could manage shorted
casings that are impractical to clear using a monitoring approach with
ILI tools. As part of the unanimous vote in favor of the P&MMs
referenced in the preceding section, the Committee suggested that PHMSA
consider allowing operators flexibility in managing shorted casings
with approval from the appropriate PHMSA regional director.
4. Post-GPAC Comments
The Associations noted that removing a shorted casing is sometimes
impractical and that the threat can be managed using other IM tools,
such as ILI. They urged PHMSA to eliminate the requirement to clear a
shorted casing or allow operators to demonstrate that the risk can be
effectively managed through alternative methods.\285\
---------------------------------------------------------------------------
\285\ See Docket ID PHMSA-2024-0005-0423 at 17.
---------------------------------------------------------------------------
5. PHMSA Response
The final rule retains the requirement to clear shorted casings in
the IM alternative but allows other measures to be implemented in
certain circumstances. Clearing the shorted casings is a common-sense
measure to eliminate an active threat and prevent what would otherwise
lead to failure. Consistent with the GPAC recommendation, the IM
alternative does not require operators to physically clear shorted
casings in instances where that effort may be impractical or unsafe. As
commenters suggested, the IM alternative allows an operator to ``take
equivalent preventive and mitigative corrosion control measures'' with
[[Page 1643]]
appropriate documentation. Recent improvements in ILI tools allow
operators to adopt alternatives like an IM assessment of the short, if
documented that clearing a given short is impractical or unsafe.\286\
PHMSA considered this recommendation and agrees that equivalent
measures to manage a shorted casing in these circumstances are
appropriate for pipeline safety. Because it is appropriate in cases
where clearing a shorted casing may be impractical or unsafe,
individual approval is not necessary for an operator to implement such
measures.
---------------------------------------------------------------------------
\286\ As examples of earlier difficulty with ILI tools and this
threat, see, e.g., NPRM, 85 FR at 65164; PHMSA, CPF 4-2009-1005,
Notice of Probable Violation and Proposed Civil Penalty, at 3 (Feb.
12, 2009), available at: https://primis.phmsa.dot.gov/enforcement-documents/420091005/420091005_NOPVPCP_02122009_text.pdf.
---------------------------------------------------------------------------
iii. Valve Requirements
1. Summary of Proposal
The NPRM proposed requiring mainline valves on both sides of the
class change segment, plus any isolation valves for any crossover or
lateral pipe, be capable of remote control or automatic-shutoff valves.
In the event of a rupture, these valves would need to be closed as soon
as practicable but within 30 minutes after the rupture. The NPRM also
proposed requiring these valves to be operational at all times,
controlled by a supervisory control and data acquisition (SCADA)
system, and monitored in accordance with Sec. 192.631.
2. Initial Comments
The PST supported the proposal as ``an important way to reduce the
consequences of a failure,'' while encouraging PHMSA to look at
shortening the 30-minute maximum valve closure time.\287\ The NTSB
noted that the proposed requirements for operators to install automatic
shut off or remote control valves on both sides of pipe segments that
use the IM alternative would be only partially responsive to Safety
Recommendation P-11-11 as its recommendation extended to all Class 3,
Class 4, and HCA locations.\288\ The NTSB also noted that the maximum
valve spacing intervals and maximum valve closure time PHMSA provided
may not be sufficient to mitigate the consequences of a pipeline
failure.\289\
---------------------------------------------------------------------------
\287\ Docket ID PHMSA-2017-0151-0063 at 7.
\288\ This final rule is not intended to apply to all pipelines,
only the limited subset of pipe which a) experiences a change to a
Class 3 location and b) meets the eligibility requirements. PHMSA
did not include this rulemaking among its planned responses to P-11-
11 in its January 14, 2022 response to the NTSB.
\289\ See Docket ID PHMSA-2017-0151-0055 at 2, 5.
---------------------------------------------------------------------------
Multiple commenters, including the GPTC, requested PHMSA clarify
that pipelines without a SCADA control room could use the IM
alternative.\290\ The Associations noted how automatic shut-off or
remote-control valves do not necessarily require a control room as
activating these valves on local sensors can be a suitable
alternative.\291\
---------------------------------------------------------------------------
\290\ See, e.g., Docket ID PHMSA-2017-0151-0065 at 1-2.
\291\ See Docket ID PHMSA-2017-0151-0061 at 25.
---------------------------------------------------------------------------
3. GPAC Consideration
The GPAC voted 12-0 that the valve requirements proposed were
technically feasible, reasonable, cost-effective, and practicable.
4. Post-GPAC Comments
The Associations agreed with the GPAC recommendation, supporting
the valve requirements and encouraging PHMSA to align them with the
provisions codified by the April 2022 Valve Rule.\292\
---------------------------------------------------------------------------
\292\ See Docket ID PHMSA-2024-0005-0423 at 17.
---------------------------------------------------------------------------
5. PHMSA Response
The IM alternative requires rupture-mitigation valves (RMVs) spaced
at the original class design in accordance with recently codified
provisions. Since the publication of the NPRM, PHMSA issued the April
2022 Valve Rule, which addressed the design, construction, initial
inspection, testing, and maintenance of RMVs.\293\ The term RMV is
defined at Sec. 192.3 to include both automatic shutoff and remote-
controlled valves. By referring to the modern valve standard now
codified in Sec. 192.634, the IM alternative retains the principle of
operators installing (or automating) RMVs capable of isolating the
class change segment. The proposal in the NPRM provided similar
substantive requirements. Incorporating Sec. 192.634, as recommended
by commenters, addresses several of the comments: a SCADA system is not
strictly required by the April 2022 Valve Rule so nor is it here.
---------------------------------------------------------------------------
\293\ Requirement of Valve Installation and Minimum Rupture
Detection Standards, 87 FR 20940 (Apr. 8, 2022).
---------------------------------------------------------------------------
RMVs and related rupture-response requirements mitigate the
consequences of ruptures by reducing the duration and volume of gas
escaping the pipeline. Reducing the duration of the release can reduce
the extreme heat exposure to nearby structures and their occupants and
result in benefits to firefighting and rescue operation, according to a
PHMSA-commissioned study by the Oak Ridge National Laboratories.\294\
The protection against rupture provided by RMVs affords an additional
margin of safety for eligible Class 3 segments.
---------------------------------------------------------------------------
\294\ See C.B. Oland et al., Oak Ridge Nat'l Lab., Studies for
the Requirements of Automatic and Remotely Controlled Shutoff Valves
on Hazardous Liquids and Natural Gas Pipelines with Respect to
Public and Environmental Safety (Oct. 31, 2012), available at:
https://www.phmsa.dot.gov/sites/phmsa.dot.gov/files/docs/technical-resources/pipeline/16701/finalvalvestudy.pdf. Table 5.1 details
$8.230M in avoided damage costs from RMVs in Class 3 locations.
---------------------------------------------------------------------------
While facilitating the upgrading of valves to modern RMV technology
on either side of the class change segment, this final rule allows an
operator to retain the original valve spacing requirement based on the
pipeline's original class location. This corresponds to 20 miles for
Class 1 and 15 miles for Class 2 locations. This means that any
pipeline previously designed in accordance with the valve spacing
design standards in Sec. 192.179(a) will not be expected to install
new valves to meet the RMV spacing requirement, as an operator could
automate or install actuators on existing valves to meet the
requirements of this rule. This is important for the IM alternative to
be appropriate for Class 1 or Class 2 to Class 3 change segments which
do not replace their pipelines, because changing valve spacing without
pipeline replacement would not be practicable. In these cases,
upgrading the valve to modern RMVs to protect the segment provides
valuable pipeline safety benefit.
iv. Notification Upon Use of the Program
1. Summary of Proposal
The NPRM proposed that operators notify PHMSA within 60 days of
choosing to use the IM alternative to manage a class location change in
accordance with Sec. 191.22(c)(2). This notification would include
details of the specific pipeline segments for which operators intend to
apply the IM alternative. Notification pursuant to Sec. 192.18 was
also required for use of certain assessment methods.
2. Initial Comments
The majority of NAPSR representatives and the PST agreed that
operators should be required to notify PHMSA if implementing the IM
alternative to manage a class change. Multiple commenters--including
the Associations, the GPTC, NAPSR, and Sander Resources--requested
PHMSA consolidate the notification
[[Page 1644]]
requirements into a single provision, rather than spreading them
between Sec. Sec. 191.22(c) and 192.18, to simplify operators'
compliance.\295\ NAPSR also recommended requiring operators to notify
PHMSA of any changes to MAOP, including those resulting from class
location changes.
---------------------------------------------------------------------------
\295\ See Docket ID PHMSA-2017-0151-0061 at 28; Docket ID PHMSA-
2017-0151-0065 at 2-3; Docket ID PHMSA-2017-0151-0059 at 3; Docket
ID PHMSA-2017-0151-0064 at 5.
---------------------------------------------------------------------------
The PST and Accufacts noted how the special permit process invites
public comment prior to approval and recommended a similar public
notification process in this rule, stressing the importance of making
the public aware of segments using the IM alternative.\296\ The PST
urged PHMSA to consider ``making access to the National registry and
information filed there available to the public on the PHMSA website.''
\297\ The PST also suggested requiring operators to report use of the
IM alternative as a safety related condition ``for at least a decade
after the rule goes into effect, providing both PHMSA and the public
more information.'' \298\
---------------------------------------------------------------------------
\296\ See Docket ID PHMSA-2017-0151-0063 at 5; Docket ID PHMSA-
2017-0151-0058 at 7.
\297\ Docket ID PHMSA-2017-0151-0063 at 5.
\298\ Id. at 9.
---------------------------------------------------------------------------
3. GPAC Consideration
GPAC members representing the public advocated for a robust public
notification process as a part of this rulemaking, emphasizing the
importance of the existing public notification and comment process for
class location change special permits. These members also acknowledged
the challenges operators face in producing and providing valuable,
actionable information to the public. GPAC members representing the
industry and other government agencies debated whether requiring
operators to provide notification of intent to use the IM alternative
to nearby residents would be an appropriate or meaningful requirement.
Members representing the industry and other government entities noted
that operators are typically not required to notify the public when
following other parts of the Federal Pipeline Safety Regulations and
questioned why operators should be required to do so here. Members
representing the industry also referenced the existing public awareness
and engagement standards incorporated into PHMSA's regulations, such as
API RPs 1162 and 1185, plus other part 192 public notifications
requirements like the alternate MAOP regulations. PHMSA staff clarified
during the meeting that only one recent special permit had a specific
public notification condition as a part of its requirements.
The GPAC voted 10-3 recommending that PHMSA consider incorporating
a public notification process to people within the segment's potential
impact radius (PIR) \299\ when implementing the proposed IM
alternative.
---------------------------------------------------------------------------
\299\ The potential impact radius, or ``PIR,'' is defined in
Sec. 192.903 as ``the radius of a circle within which the potential
failure of a pipeline could have significant impact on people or
property. PIR is determined by the formula r = 0.69* (square root of
(p*d2)), where `r' is the radius of a circular area in feet
surrounding the point of failure, `p' is the [MAOP] in the pipeline
segment in pounds per square inch and `d' is the nominal diameter of
the pipeline in inches.''
---------------------------------------------------------------------------
4. Post-GPAC Comments
The Associations stated that a notification to individuals located
within the PIR of a segment would be ``unnecessary and overly
burdensome'' as ``PHMSA already requires operators to develop and
implement a public awareness program alerting the affected public of
the existence of the pipeline, the commodity the pipeline transports,
the possible hazards associated with an unintended release from the
pipeline, and the steps to report a possible release.'' Because
``[o]perators are not required now to notify individual landowners when
they are complying with the pipeline safety regulations,'' they
suggested this addition may require an additional information
collection request under the Paperwork Reduction Act.\300\
---------------------------------------------------------------------------
\300\ Docket ID PHMSA-2024-0005-0423 at 4.
---------------------------------------------------------------------------
The Associations further noted that ``[p]ublic notice and comment
is appropriate'' in situations where, as with a special permit, the
agency is ``waiving compliance with certain specified regulations.''
But, they argued, requiring the same here ``would amount to operators
notifying the affected public that they intend to follow the law.''
\301\ Williams similarly disagreed with a direct notification and
comment period to use this final rule, noting such a change would not
be a logical outgrowth of the NPRM. Williams noted how ``pipeline
operators routinely notify the landowners around its pipe when there is
a potential increase in risk based on'' operator activity or if it
planned to work near the property. But a notification to landowners
should not be required, it argued, where ``the operator successfully
completes the rigors of the [IM alternative program] and the pipe is
deemed safe and approved for Class 3 location operation at MAOP [as]
the risk to the public is no greater than it would otherwise be at
Class 1 operating conditions.'' \302\
---------------------------------------------------------------------------
\301\ Id. The Associations also disagreed with PHMSA's proposal
to create a notification requirement to PHMSA for operators planning
to use the IM alternative.
\302\ Docket ID PHMSA-2024-0005-0421 at 7-8.
---------------------------------------------------------------------------
An anonymous commenter provided that ``PHMSA must require . . .
that operators notify landowners within the PIR of usage of the'' IM
alternative. This commenter further suggested that PHMSA make an
operator's enforcement actions and integrity management activities
publicly available, and solicit public comment, before permitting use
of the IM alternative.\303\
---------------------------------------------------------------------------
\303\ Docket ID PHMSA-2024-0005-0415 at 1.
---------------------------------------------------------------------------
5. PHMSA Response
Consistent with recommendations from commenters, the final rule
consolidates the notification provisions into Sec. 192.18. The Safety
Related Condition report is not appropriate for this purpose, as
compliance with Sec. 192.611 does not meet its criteria, while Sec.
192.18 is the notification process for part 192 compliance obligations.
Under this final rule, an operator deciding to use this IM alternative
must notify PHMSA and the appropriate State regulator under Sec.
192.18(a) and (b) within the initial 24-month compliance period. This
notification is for PHMSA's awareness, knowledge, and data-tracking
purposes; it is not a review process before an operator can use the
codified compliance method in part 192.
Some commenters representing the industry asked that PHMSA include
in the list of provisions within Sec. 192.18(c) those IM alternative
requirements which reference Sec. 192.18 for its notification process.
However, Sec. 192.18 itself provides the notification process, and the
no-objection process contained in subordinate Sec. 192.18(c) applies
only in limited circumstances where specified, and not here. Section
192.18 provides the simple procedure by which an operator can notify
Federal (paragraph (a)) and State (paragraph (b)) regulators for the
variety of notifications called for throughout part 192. Where Sec.
192.18 is referenced without further specification, it is this passive
notification that an operator must follow. Paragraph (c) then provides
for specifically incorporated provisions that require notification of
plans and procedures that must obtain PHMSA's no-objection before the
operator may continue with some alternative approach. In this
rulemaking, PHMSA did not intend this no-objection review process for
any of the notifications proposed and intentionally did (and does) not
propose adding them into the incorporated
[[Page 1645]]
references in Sec. 192.18(c). For clarity however, in light of these
comments, PHMSA has specified in the text of the IM alternative that
the notifications must be submitted to PHMSA and the applicable State
regulator as set out in Sec. 192.18(a) and (b).
PHMSA considered the GPAC's recommendation to incorporate a process
for operators to notify people within the PIR of each segment using the
IM alternative but is not including such a provision in the final rule.
PHMSA agrees with the commenters who said that it would be unusual--and
in this case inappropriate--to require specific notification to
individual residents each time an operator follows a codified
regulation. Applications for special permits involve waivers to the
requirements in the Pipeline Safety Regulations and must be publicly
docketed; with the IM alternative being codified, it is now itself a
regulatory compliance option and the procedures for an exception are
not appropriate. The NPRM proposed one notification to the agency when
an operator opted to use the IM alternative. Sending direct
notifications to each person in the PIR is a materially different
burden and one not foreseeable from the proposal. Individualized public
notification is more onerous even than the public docketing conducted
under the special permit process when operators seek exceptions to the
class change requirements--special permit applications are individually
docketed and available to be seen by interested members of the public,
but not affirmatively sent to each person in the affected community.
Turning that single notification to PHMSA into upwards of dozens of
notifications to individual homes or businesses could not have been
contemplated by commenters to the proposal.
While the GPAC recommended PHMSA consider setting up such a regime,
no proposal--even skeletal--was discussed at the committee meeting to
provide commenters insight into how this provision may develop. Absent
that, no sufficiently concrete proposal was offered on which the public
could comment during the period after the GPAC meeting. For similar
reasons, PHMSA has not adopted recommendations from NAPSR to require
notifications for other changes to MAOP that were not included in the
proposal.
v. Class Location Study
1. Summary of Proposal
The NPRM proposed requiring operators to conduct an annual class
location study in accordance with Sec. 192.609 as part of the IM
alternative option. PHMSA historically required annual class location
studies as part of class location change special permits.
2. Initial Comments
As a one-time fitness for service assessment, the Associations
suggested a class location study should not be required ``until a class
change has actually occurred.'' \304\
---------------------------------------------------------------------------
\304\ Docket ID PHMSA-2017-0151-0061 at 26.
---------------------------------------------------------------------------
3. GPAC Consideration
There was no GPAC recommendation provided on this specific
provision.
4. Post-GPAC Comments
No significant additional comments on this issue were submitted in
the docket for this rulemaking after the GPAC. But, in a May 2025
comment to a DOT request for information on reducing regulation, INGAA
stated that ``the Agency should update section 192.609 to codify an
annual process to determine if changes in population density have
occurred,'' as the existing phrasing requiring ``a class study
`whenever an increase in population density indicates a change in class
location' '' is ``fairly subjective and has been interpreted
differently over the decades since it was first codified.'' \305\
---------------------------------------------------------------------------
\305\ INGAA, Comments, Docket ID DOT-OST-2025-0026-0872, 5 (May
5, 2025), regarding Ensuring Lawful Regulation; Reducing Regulation
and Controlling Regulatory Costs, 90 FR 14593 (April 4, 2025).
---------------------------------------------------------------------------
5. PHMSA Response
The IM alternative requires annual class location studies in
eligible Class 3 inspection areas. This ensures operators promptly find
new Class 3 locations. Once a segment becomes Class 3, as has a segment
applying this final rule, it is likely that population growth will
continue among adjoining segments. Identifying the new class is
important for appropriate class management. This is crucial for IM
assessments, as baseline assessments on new HCAs must be prioritized
and scheduled, with discovered anomalies remediated in a timely manner
to address potential threats in a populated area. While commenters note
that the standing requirement of Sec. 192.609 prescribes no set
interval to conduct such a study, this final rule requires an operator
using the IM alternative to do so annually, same as the proposal.
Annual class location studies are standard practice in class location
special permits, where they have been successfully applied. By
referencing an existing procedural requirement, it can be easily
applied on a yearly basis, which INGAA recommends in their May 2025
comment.
PHMSA acknowledges that specific portions of the class location
study generally do not change year-to-year, specifically concerning
reviews of initial design, construction, and testing procedures in
Sec. 192.609(b) and the MAOP and operating stress level in Sec.
192.609(e). PHMSA does not expect an operator will need to update these
evaluations each year for its class location study, unless justified by
a change in class location, change in MAOP, or replacement of the
pipeline. Yet other important factors in Sec. 192.609 may change over
time and must be evaluated annually under this requirement: the current
class location (Sec. 192.609(a)), the physical condition of the
pipeline segment based on available records (Sec. 192.609(c)), the
operating and maintenance history of the segment (Sec. 192.609(d)),
and population density increases (Sec. 192.609(f)). In this way, the
class location study feeds into the IM program by updating data on the
segment, verifying continued operational safety of the eligible Class 3
segment (and other HCAs) as well as the rest of the eligible Class 3
inspection area, and directly informing an operator's risk-based
procedures under its IM program.
F. Adjustments to Class Locations Through Clustering
Section 192.5(c) allows operators to adjust the endpoints of Class
2, 3, or 4 locations through a process commonly known as
``clustering.'' While not mentioned directly in the NPRM, several
stakeholders discussed clustering in their comments and the topic also
came up during the GPAC's public meeting on the NPRM.
Specifically, the Associations advocated for PHMSA to allow
operators to continue their practices applying a variety of reasonable
definitions currently used across industry, and encouraged a subsequent
meeting to reevaluate class determination methodology in a new
proceeding.\306\ TC Energy agreed that operators should continue to be
allowed to use established practices which use reasonable, risk-based
approaches to clustering.\307\ Mr. Zamarin sought the modernization of
class location methodologies to newer analytical technologies,\308\ and
the GPAC voted 12-1 recommending that PHMSA
[[Page 1646]]
continue to review the class location change requirements for possible
future rulemaking action and hold a subsequent GPAC meeting.
---------------------------------------------------------------------------
\306\ PHMSA-2017-0151-0061, at 28-29; Docket ID PHMSA-2024-0005-
0423, at 5-6.
\307\ Docket ID PHMSA-2017-0062, at 9.
\308\ Docket ID PHMSA-2024-0005-0423, at 2.
---------------------------------------------------------------------------
While the final rule does not amend the clustering requirements in
Sec. 192.5(c), PHMSA recognizes that it has given conflicting and
inconsistent guidance in applying these requirements over time.\309\
PHMSA intends to take action regarding these conflicts and
inconsistencies in the near future. Until that occurs, PHMSA encourages
operators to continue applying reasonable programs in adjusting the
endpoints of class locations under the cluster rule.
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\309\ In a 2003 notice of proposed rulemaking, for example,
PHMSA stated that it did ``not believe that . . . isolated buildings
are commonly included as Class 3 clusters,'' and that it did ``not
intend this proposed rule to result in a change of existing practice
in this regard.'' Pipeline Safety: Pipeline Integrity Management in
High Consequence Areas (Gas Transmission Pipelines), 68 FR 4278,
4283-84 (proposed Jan. 28, 2003). Yet PHMSA offered an entirely
different view of the clustering requirements in 2018, stating
``that even a single house could form the basis of a . . . cluster
under this requirement, as all buildings within a specified class
location unit must be protected by the maximum class location level
that was determined for the entire class location unit.'' ANPRM, 83
FR at 36862-63.
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V. Section-by-Section Analysis
Sec. 192.3 Definitions
Section 192.3 provides definitions for various terms that are used
in part 192. The final rule adds two new definitions to Sec. 192.3:
``Eligible Class 3 segment'' and ``Eligible Class 3 inspection area.''
Both terms are used in the new integrity management alternative (IM
alternative) method for addressing class location changes in Sec.
192.611(a)(4).
Eligible Class 3 Segment
The final rule defines the term ``Eligible Class 3 segment'' in
Sec. 192.3 as a segment of a transmission line in a Class 3 location
that is capable of being assessed with an instrumented in-line
inspection tool which does not contain: bare pipe; wrinkle bends; pipe
with a seam formed by lap welding; a seam with a longitudinal joint
factor below 1.0; or a segment which has experienced an in-service leak
or rupture due to cracking in the pipe body, seam, or girth weld on the
segment or segments of similar characteristics in or within five miles.
PHMSA is adding this definition to Sec. 192.3 to prescribe the types
of pipeline segments that are eligible to use the new IM alternative
method in Sec. 192.611(a)(4). The definition incorporates the
requirements in Sec. 192.5 for determining if a pipeline segment is in
a Class 3 location, including the cluster rule in Sec. 192.5(c), and
provides exclusions for pipe and segments with certain characteristics.
These exclusions are consistent with PHMSA's two decades of experience
administering class location special permits.
Eligible Class 3 Inspection Area
The final rule defines the term ``Eligible Class 3 inspection
area'' in Sec. 192.3 as an eligible Class 3 segment and the upstream
and downstream portion of the transmission line that is capable of
being assessed with an ILI tool extending from the nearest upstream ILI
tool launcher to the nearest downstream ILI tool receiver. The purpose
of this definition is to delineate the boundaries of the inspection
area that must be used in satisfying several of the new integrity
management provisions in Sec. 192.611(a)(4). These provisions include
the initial programmatic requirements for conducting baseline
assessments and remediating immediate and one-year conditions in Sec.
192.611(a)(4)(i), the recurring programmatic requirements for
conducting class location surveys and performing reassessments and
remediation in Sec. 192.611(a)(4)(ii), and the general requirements
for validating ILI results and prohibiting the use of direct
assessments in Sec. 192.611(a)(4)(iii).
Sec. 192.7 What documents are incorporated by reference partly or
wholly in this part?
Section 192.7 lists documents that are incorporated by reference in
part 192. Section 192.7(b)(12) currently incorporates the second
edition of API STD 1163 by reference into Sec. 192.493, which
prescribes the requirements for conducting ILI of gas pipelines. API
STD 1163 is a comprehensive document that provides performance-based
requirements for ILI systems, including procedures, personnel,
equipment, and associated software, for both existing and developing
technologies.
API STD 1163 is available from the following website: https://publications.api.org/Default.aspx. The material can also reasonably be
obtained by interested parties through the applicable publisher contact
information listed in Sec. 192.7. Additional information regarding
standards availability can be found at https://www.phmsa.dot.gov/standards-rulemaking/pipeline/standards-incorporated-reference.
The final rule amends Sec. 192.7(b)(12) by adding a new reference
to Sec. 192.611(a)(4) for addressing class location changes under the
IM alternative. Specifically, Sec. 192.611(a)(4)(iii)(A) requires
operators to validate the results of any ILI conducted in an eligible
Class 3 inspection area to Level 2 in accordance with API Standard
1163. Under API STD 1163, a Level 2 validation is one where ``it is
possible to state with a high degree of confidence whether the tool
performance is worse than the specification.''
Sec. 192.611 Change in Class Location: Confirmation or Revision of
Maximum Allowable Operating Pressure
Section 192.611 prescribes certain requirements that apply to
pipeline segments that experience class location changes. If a change
in class location occurs and the established MAOP of a segment produces
a hoop stress that is not commensurate with the new class location,
Sec. 192.611(a) requires the operator to confirm or to revise the MAOP
of that segment using certain methods. Three of those methods have been
authorized under Sec. 192.611(a)(1)-(3) since the adoption of the
original Federal Pipeline Safety Regulations in 1970. The final rule
adds a fourth method to Sec. 192.611(a)(4) to allow operators to
confirm the MAOP of certain eligible segments in Class 3 locations
using a new IM alternative.
Operators may only use Sec. 192.611(a)(4) to confirm the MAOP of
an eligible Class 3 segment as defined in Sec. 192.3. Operators must
use one of the three other methods authorized in Sec. 192.611(a)(1)-
(3) to confirm or to revise the MAOP of a pipe or segment with an
excluded characteristic. Operators may also replace the pipe or segment
to establish an MAOP that is commensurate with the present class
location.
Operators must comply with the integrity management requirements in
Subpart O to confirm the MAOP of an eligible Class 3 segment under
Sec. 192.611(a)(4). That obligation is codified in the text of Sec.
192.611(a)(4) and in a corresponding revision to the definition of
``high consequence area'' in Sec. 192.903 of the integrity management
regulations. In addition, operators must comply with the initial
programmatic requirements in Sec. 192.611(a)(4)(i), recurring
programmatic requirements in Sec. 192.611(a)(4)(ii), and general
programmatic requirements in Sec. 192.611(a)(4)(iii) to confirm the
MAOP of an eligible Class 3 segment. Compliance with these
requirements, which are largely based on PHMSA's two decades of
experience administering class location special permits, will protect
the public, property, and the environment without requiring the
implementation of unnecessary or unduly burdensome
[[Page 1647]]
remedial measures. Finally, operators must follow the remaining
requirements in Sec. 192.611(a)(4)(iv)-(vi), including provisions for
in-service leaks or ruptures, lifetime recordkeeping, and limiting the
confirmed MAOP based on the corresponding hoop stress and design factor
of the pipe.
Initial Programmatic Requirements
Operators must comply with the initial programmatic requirements in
Sec. 192.611(a)(4)(i) to confirm the MAOP of an eligible Class 3
segment. These requirements are subject to a 24-month compliance
deadline that runs from the effective date of the final rule or the
date of the class location change, whichever is later. Depending on the
provision, the initial programmatic requirements either apply to the
eligible Class 3 inspection area or the eligible Class 3 segment as
defined in Sec. 192.3. Each of the initial programmatic requirements
incorporates another provision in part 192 and imposes an additional or
more stringent compliance obligation.
Operators must conduct a baseline integrity assessment of the
eligible Class 3 inspection area and remediate all immediate and one-
year repair conditions in accordance with the remediation schedules in
Subpart O. Prior integrity assessments conducted within 24 months of
the effective date of the final rule or the date of the class location
change, whichever is later, may be used to satisfy this obligation.
Moreover, if an eligible Class 3 segment contains pipe with a seam
formed by direct current electric resistance welding, low-frequency
electric resistance welding, or electric flash welding, the operator
must select an assessment technology or technologies with a proven
application capable of assessing seam integrity and seam corrosion
anomalies.
Operators must also comply with other initial programmatic
requirements that apply to the eligible Class 3 segment. Those
requirements include provisions for pressure testing to a minimum of
1.25 times MAOP; installing rupture mitigation valves; confirming or
obtaining traceable, verifiable, and complete materials property
records; installing cathodic protection test stations and line markers;
performing depth of cover and coating surveys; and providing
notification to PHMSA.
Recurring Programmatic Requirements
Operators must comply with the recurring programmatic requirements
in Sec. 192.611(a)(4)(ii) to confirm the MAOP of an eligible Class 3
segment, beginning no later than 24 months after the effective date of
the final rule or the date of the class location change, whichever is
later. The recurring programmatic requirements include provisions for
limiting the amount of carbon dioxide, water, and hydrogen sulfide that
can be present in the gas stream in an eligible Class 3 segment;
conducting close interval surveys, right-of-way patrols, and leakage
surveys of the eligible Class 3 segment; clearing shorted casings in
the eligible Class 3 segment; performing annual class location studies
of the eligible Class 3 inspection area; examining and remediating
exposed pipe in the eligible Class 3 segment; and conducting
reassessments and remediation of the Class 3 inspection area in
accordance with the integrity management requirements in Subpart O.
General Programmatic Requirements
Section 192.611(a)(4)(iii) prescribes three general requirements
that operators must follow in conducting the initial and recurring
programmatic requirements to confirm the MAOP of an eligible Class 3
segment. First, Sec. 192.611(a)(4)(iii)(A) requires operators to
validate the results of any ILI conducted in an eligible Class 3
inspection area to Level 2 in accordance with API Standard 1163.
Second, Sec. 192.611(a)(4)(iii)(B) prohibits operators from using
direct assessments as an integrity method for an eligible Class 3
inspection area. Third, Sec. 192.611(a)(4)(iii)(C) requires operators
to use a factor of less than 1.39 times the MAOP when determining the
predicted failure pressure for one-year conditions in accordance with
Sec. 192.933(d)(2)(iv) through (vii) and monitored conditions in
accordance with Sec. 192.933(d)(3)(v) through (vi) for any Class 1
design pipe in an eligible Class 3 segment.
Other Requirements
Operators must comply with three additional requirements in Sec.
192.611(a)(4)(iv)-(vi). First, if an eligible Class 3 segment
experiences an in-service leak or rupture, the MAOP of that segment may
no longer be confirmed under Sec. 192.611(a)(4). The operator must
confirm or revise the MAOP of the segment using one of the other
methods authorized in Sec. 192.619(a)(1)-(3) within 24 months of the
leak or rupture. The operator may also replace the pipe in the segment.
Second, the operator of an eligible Class 3 segment must maintain a
record of any action taken to comply with Sec. 192.611(a)(4) for the
life of the pipeline. Third, the MAOP of an eligible Class 3 segment
confirmed under Sec. 192.619(a)(4) may not produce a corresponding
hoop stress that exceeds 72 percent of SMYS for pipe with a Class 1
design factor or 60 percent SMYS for pipe with a Class 2 design factor.
Finally, Sec. 192.611(a)(4)(vii) clarifies that the IM alternative is
not authorized for gathering lines or distribution lines.
MAOP Restoration
The final rule amends Sec. 192.611(d) to clarify that a prior
pressure reduction taken to comply with a change in class location does
not preclude an operator from restoring the previously established MAOP
of an eligible Class 3 segment under Sec. 192.611(a)(4). The final
rule also adds new requirements to Sec. 192.619(d)(1)-(3) that an
operator must satisfy before restoring the MAOP of an eligible Class 3
segment. First, the operator must review the design, operating and
maintenance history of the segment to determine if restoring the MAOP
is safe, and make any repairs, replacements, or alterations necessary
for safe operation at the previously established MAOP. Second, the
operator must comply with the existing requirements in Subpart O
applicable to MAOP increases. These measures are consistent with the
uprating requirements in PHMSA's current regulations and can be used to
facilitate the safe restoration of previously established MAOPs for
eligible Class 3 segments. Finally, the operator must complete all
baseline assessments, repairs, and initial programmatic requirements
under this final rule before restoring the MAOP of the segment.
Sec. 192.903 What definitions apply to this subpart?
Section 192.903 provides definitions for terms used throughout part
192, subpart O. In this final rule, PHMSA is amending the definition of
``high consequence area'' to include any area containing an eligible
Class 3 segment with an MAOP being confirmed in accordance with Sec.
192.611(a)(4), as well as any area within a potential impact circle
containing any portion of an eligible Class 3 segment with an MAOP
being confirmed in accordance with Sec. 192.611(a)(4). The purpose of
the amendments is to ensure that operators incorporate any eligible
Class 3 segments subject to the MAOP confirmation under Sec.
192.611(a)(4) into their integrity management programs as HCAs.
VI. Statutory Authority
Pipeline Safety Laws
PHMSA is authorized to administer the Federal Pipeline Safety Laws
(49 U.S.C. 60101 et seq.) pursuant to a
[[Page 1648]]
delegation of authority from the Secretary of Transportation. 49 CFR
1.97. Section 60102 authorizes PHMSA to prescribe minimum safety
standards for the design, installation, inspection, emergency plans and
procedures, testing, construction, extension, operation, replacement,
and maintenance of pipeline facilities. Section 60109 further
authorizes PHMSA to establish an integrity management program
applicable to each gas pipeline facility located in high-density
population areas and to require operators of these pipeline facilities
to have and follow a written IM program.\310\
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\310\ In addition, section 5 of the Pipeline Safety, Regulatory
Certainty, and Job Creation Act of 2011 required PHMSA to evaluate
applying IM principles to mitigate the need for class location
requirements on gas transmission lines. Public Law 112-90, 5(a)(2),
125 Stat. 1904, 1907 (Jan. 3, 2012). PHMSA did so in a 2016 Report
to Congress. See PHMSA, Report to Congress: Evaluation of Expanding
Pipeline Integrity Management beyond High-Consequence Areas and
Whether Such expansion Would Mitigate the Need for Gas Pipeline
Class Location Requirements (June 6, 2016), available at: https://www.phmsa.dot.gov/sites/phmsa.dot.gov/files/docs/news/55521/report-congress-evaluation-expanding-pipeline-imp-hcas-full.pdf.
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Section 60102(b) Practicability Factors
Section 60102(a) and (b)(2) require PHMSA to find that a safety
standard prescribed pursuant to sections 60102 and 60109 is practicable
and designed to meet the needs for gas pipeline safety and protecting
the environment based on consideration of its appropriateness for the
type of transportation, reasonableness, and upon a risk assessment of
the costs and benefits. A gas pipeline safety standard proposed under
sections 60102 and 60109 must also be submitted to the GPAC for review
of its technical feasibility, reasonableness, cost-effectiveness, and
practicability. 49 U.S.C. 60102(b)(2), (b)(4), 60115(c). The GPAC
reviewed and provided recommendations on this rule in a public meeting
held March 27-29, 2024, and issued a report \311\ which PHMSA reviewed
and to which it provided a written response.\312\ PHMSA considered the
GPAC's report throughout this final rule.
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\311\ GPAC, Class Location NPRM Voting Slides, Docket ID PHMSA-
2017-0151-0068 (Mar. 28-29, 2024).
\312\ PHMSA, Response to the GPAC's Report on the `Class
Location Change Requirements' Proposed Rule, Docket ID PHMSA-2024-
0005-0424 (Dec. 11, 2024).
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PHMSA has determined that the IM alternative adopted in this final
rule is practicable, reasonable, cost-effective, technically feasible,
and appropriate for gas transmission pipelines. IM programs are widely
used by gas transmission operators and are the subject of mature
consensus industry standards.\313\ IM programs have been applied by
regulation to gas transmission pipelines in high consequence areas
since 2003 and this now makes up more than half of all Class 3 mileage
(approximately 52%), demonstrating widespread application of integrity
management to pipe in such circumstances and operating conditions. With
industry consolidation, the overwhelming majority of gas transmission
operators, or their corporate affiliates, have in place an IM program
and are familiar with the requirements being extended by the IM
alternative to pipe experiencing a class change. More recently, the
integrity management elements of assessment, data analysis, and repair
have been extended to all Class 3 (and Class 4 and MCA) pipe pursuant
to Sec. Sec. 192.710 and 192.714; each segment that may qualify for
this IM alternative is in a Class 3. For assessments under this final
rule, PHMSA encourages operators to use ILI tools that operators have
championed--including at the GPAC meetings--as robust improvements in
technology, with at least Level 2 tool validation confirming these
evolutions in technology are suitable.
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\313\ See generally ASME B31.8S-2018.
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In addition to integrity management requirements, the IM
alternative requires the implementation of supplemental O&M practices.
Patrols, leakage surveys, and line markers are each familiar to
pipeline operators as they are longstanding PHMSA regulatory
requirements and the subject of consensus industry standards.\314\ The
final rule requires these activities to occur more regularly in the IM
alternative program, a practice which PHMSA understands many operators
already do on their pipeline systems for business and operational
reasons in ordinary course.\315\ The IM alternative also includes
provisions for material record verification, upgraded valves, and close
interval surveys. While the IM alternative can only be used if
operators have their records verified no later than two years after the
change in class location, knowing the material in your pipeline system
is a first-principle obligation for any reasonably prudent operator
transporting a hazardous commodity under high pressure within a gas
transmission pipeline, and all transmission lines are required by
regulation to have or opportunistically obtain material record
verifications. See 49 CFR 192.607. Upgraded rupture mitigation valves
are now required for any substantially replaced pipe, see 49 CFR
192.179, 192.610, 192.634; that is what most qualifying pipe for this
final rule may have to do but for the new IM alternative option. Under
the IM alternative, close interval surveys are performed on a regular
seven-year interval rather than on an `as needed' basis, which already
exists for other transmission pipelines when annual test station
readings indicate inadequate cathodic protection. 49 CFR 192.465(f)(2).
This recitation is non-exhaustive, but as section IV shows in more
detail, each compliance requirement should be well known by prudent
operators who have been complying with PHMSA regulation.
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\314\ See ASME B31.8-2018 Sec. Sec. 851.2, 851.3.
\315\ See, e.g., Pac. Gas & Elec. Co., 2019 Gas Safety Plan at
36, available at: https://www.pge.com/assets/pge/docs/about/pge-systems/2019-gas-safety-report.pdf (noting monthly gas transmission
patrols).
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By ``piloting'' through special permits over 20 years what PHMSA
now codifies as the IM alternative option, PHMSA and operators have
validated the program to reasonably provide for safety, to
appropriately manage the safety risks on gas transmission lines, and to
apply to operators in a practicable fashion. Those special permits have
involved both Class 1 and Class 2 designed transmission segments
changing into Class 3 locations for which the IM alternative is
specifically designed, demonstrating that this amended standard for
managing a gas transmission pipeline segment which changes class is
``appropriate[ ] for the pipeline facilities''--gas transmission
pipelines. PHMSA did not extend the amended standard to Class 4
locations because the current IM alternative program would not be
appropriate for those facilities, based on current engineering
understanding and a lack of experience and data. The combination of
proven pipeline safety techniques in the IM alternative program, along
with eligibility exclusions, use modern pipeline safety technology to
reasonably provide for pipeline safety, as demonstrated by the record
of those special permit segments and further shown by analysis in the
RIA.\316\
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\316\ See 113 Cong. Reg. 32041, 32043 (Nov. 9, 1967) (Senate)
(``In determining reasonableness, safety, which is the purpose of
this act, shall be the overriding consideration.'').
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In addition, at the proposed and final rule stage, PHMSA has
conducted a risk assessment considering the costs and benefits of the
rule. This final rule provides substantial cost-savings of
approximately $461 million per year. The quantified and non-quantified
safety benefits and quantified cost-savings of this rule justify its
costs to codify the IM alternative option, as
[[Page 1649]]
further discussed below and in the associated RIA available in the
docket for this rulemaking.
Pursuant to section 60102(g), PHMSA has good cause to provide a 60-
day effective date for this final rule as reasonably necessary for
operators to comply. Given that the rule will begin applying as an
option for all forthcoming class changes, upon which time an operator
will have a limited window to implement compliance procedures, a 60-day
effective date allows operators to familiarize themselves and develop
IM alternative programs. As it also applies to some previous class
changes, more than 30 days is reasonably necessary for operators to
prepare orderly to process and convert past class changes, as well as
for PHMSA to terminate existing special permits. This additional time
is necessary due to resource constraints and to allow care in reviewing
current pipeline inventory and procedures. At the same time, 60 days is
the appropriate duration for an extended effective date because it does
not deprive for too long the ability of operators to elect this new
option for managing class changes, and operators are not required to
select this option.
VII. Regulatory Analysis and Notices
A. Executive Orders 12866, 14192, and 14219; Regulatory Planning and
Review
Executive Order (E.O.) 12866 (Regulatory Planning and Review; 58 FR
51735 (Oct. 4, 1993)), as implemented by DOT Order 2100.6B (Policies
and Procedures for Rulemaking), 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 also requires that ``agencies should assess all costs and
benefits of available regulatory alternatives, including the
alternative of not regulating.'' DOT Order 2100.6B specifies that
regulations should generally ``not be issued unless their benefits are
expected to exceed their costs'' except where required by law or
compelling safety need.
E.O. 12866 and DOT Order 2100.6B also require that PHMSA submit
``significant regulatory actions'' to the Office of Information and
Regulatory Affairs (OIRA) within the Executive Office of the
President's Office of Management and Budget (OMB) for review. OIRA has
determined that this final rule is a significant regulatory action
pursuant to E.O. 12866. OMB has also determined that this is a ``major
rule'' as defined by the Congressional Review Act (5 U.S.C.
804(2)).\317\
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\317\ This final rule does not implicate any of the factors
identified in section 2(a) of E.O. 14219 (``Ensuring Lawful
Governance and Implementing the President's `Department of
Government Efficiency' Deregulatory Initiative;'' 90 FR 10583 (Feb.
25, 2025)) indicative that a regulation is ``unlawful'' or ``. . .
undermine[s] the national interest.''
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This final rule is a deregulatory action under E.O. 14192
(Unleashing Prosperity Through Deregulation; 90 FR 9065 (Feb. 6, 2025))
and OMB guidance, including M-25-20.\318\ PHMSA expects this final rule
will result in significant cost savings by reducing regulatory burdens
and regulatory uncertainty for gas transmission pipeline operators by
enabling an additional, generally available, non-invasive method to
manage class location changes. At a 7 percent discount rate, PHMSA
estimates that avoided pipe replacement under the final rule will save
approximately $593.2 annually, while an additional $13.3 million
annually is saved by reduced applications for special permits. Offset
by the modest cost of applying the IM alternative program, PHMSA
estimates total cost savings of approximately $461 million per year,
based on its analysis at a 7 percent discount rate. PHMSA expects these
cost savings will also result in reduced costs for the public to whom
gas transmission pipeline operators generally transfer a portion of
their compliance costs. Those reduced costs to pipeline operators and
the public are consistent with E.O. 14192, which establishes a Federal
policy of alleviating ``unnecessary regulatory burdens'' by reducing
compliance costs and reducing the risks from non-compliance with
burdensome regulations.
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\318\ See OMB, M-24-20, Guidance Implementing Section 3 of E.O.
14192 (Mar. 26, 2025), available at: https://www.whitehouse.gov/wp-content/uploads/2025/02/M-25-20-Guidance-Implementing-Section-3-of-Executive-Order-14192-Titled-Unleashing-Prosperity-Through-Deregulation.pdf.
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In addition to the quantified cost savings described above, PHMSA
expects this final rule will have non-quantified benefits to public
safety and the environment arising from reduced need for blowdowns and
excavation activity, as well as to public safety and commercial and
industrial operations due to reduced potential for class location
change-related interruptions of gas transmission supply. The costs and
benefits of the final rule are described in detail within the RIA
available in the rulemaking docket. PHMSA has determined, as discussed
in the immediately preceding section and the associated RIA, that the
benefits of each of the final rule elements justifies any associated
costs notwithstanding the uncertainties identified.
E.O. 12866 and DOT Order 2100.6B also require PHMSA to provide a
meaningful opportunity for public participation, which reinforces
requirements for notice and comment in the Administrative Procedure Act
(APA, 5 U.S.C. 551 et seq.). PHMSA's NPRM sought public comment on its
proposed revisions to the Federal Pipeline Safety Regulations and the
cost and benefit analyses in the preliminary RIA, as well as any
information that could assist in quantifying the costs and benefits of
this rulemaking. PHMSA again sought public comment in connection with
the March 2024 meeting of the GPAC discussing this rulemaking. Those
comments are addressed in this final rule.
B. Energy-Related Executive Orders 13211, 14154, and 14156
The President has declared in E.O. 14156 (Declaring a National
Energy Emergency; 90 FR 8353 (Jan. 29, 2025)) a National emergency to
address the United States's inadequate energy development production,
transportation, refining, and generation capacity. Similarly, E.O.
14154 (Unleashing American Energy; 90 FR 8353 (Jan. 29, 2025)) asserts
a Federal policy to unleash American energy by ensuing access to
abundant supplies of reliable, affordable energy from (inter alia) the
removal of ``undue burden[s]'' on the identification, development, or
use of domestic energy resources such as natural gas. PHMSA finds this
final rule is consistent with each of E.O. 14156 and E.O. 14154. The
final rule will give gas transmission pipeline operators regulatory
flexibility in responding to class location changes, thereby avoiding
constraints on their facilities' transportation capacity--including
pressure reductions, interruptions of service, or onerous special
permit conditions--contemplated by existing regulations. That increased
regulatory flexibility will in turn increase natural gas transportation
capacity Nation-wide and improve gas transmission pipeline operators'
ability to provide abundant, reliable, affordable natural gas in
response to residential, commercial, and industrial demand.
However, this final rule is not a ``significant energy action''
under E.O. 13211 (Actions Concerning Regulations That Significantly
Affect Energy Supply, Distribution, or Use; 66 FR 28355 (May 22,
2001)), which requires Federal agencies to prepare a Statement of
Energy Effects for any ``significant
[[Page 1650]]
energy action.'' While this final rule is a significant action under
E.O. 12866, it will not have a significant adverse effect on supply,
distribution, or energy use, as further discussed in the RIA.
C. Executive Order 13132: Federalism
PHMSA analyzed this final rule in accordance with the principles
and criteria contained in E.O. 13132 (Federalism; 64 FR 43255 (Aug. 10,
1999)) and the Presidential Memorandum (Preemption; 74 FR 24693 (May
22, 2009)). E.O. 13132 requires agencies to ensure 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.''
While the final rule may operate to preempt some State
requirements, it would not impose any regulation that has substantial
direct effects 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. Section
60104(c) of Federal Pipeline Safety Laws prohibits certain State safety
regulation of interstate pipelines. Under Federal Pipeline Safety Laws,
States that have submitted a current certification under section
60105(a) can augment Federal pipeline safety requirements for
intrastate pipelines regulated by PHMSA but may not approve safety
requirements less stringent than those required by Federal law. A State
may also regulate an intrastate pipeline facility that PHMSA does not
regulate. This final rule pertains to gas transmission pipelines and
the preemptive effect of the regulatory amendments in this final rule
is limited to the minimum level necessary to achieve the objectives of
the Federal Pipeline Safety Laws. Therefore, the consultation and
funding requirements of E.O. 13132 do not apply.
D. Regulatory Flexibility Act
The Regulatory Flexibility Act (5 U.S.C. 604) requires Federal
agencies to conduct a Final Regulatory Flexibility Analysis for a final
rule subject to notice-and-comment rulemaking under the APA unless the
agency head certifies that the proposed rule will not have a
significant economic impact on a substantial number of small entities.
DOT's implementing guidance--established consistent with E.O. 13272
(Proper Consideration of Small Entities in Agency Rulemaking; 67 FR
53461 (Aug. 16, 2002))--is available online at https://www.transportation.gov/regulations/rulemaking-requirements-concerning-small-entities. This final rule was developed in accordance with E.O.
13272 and DOT implementing guidance.
After conducting an Initial Regulatory Flexibility Analysis along
with the proposed rule, PHMSA has further analyzed the final rule
impact on small entities and prepared a Final Regulatory Flexibility
Analysis contained in the RIA. The final rule will relieve regulatory
burdens, resulting in cost-savings for small entities. The objectives
of, and legal basis for, the final rule is described earlier this final
rule preamble. No comments were raised regarding the Initial Regulatory
Flexibility Analysis issued along with the proposed rule, nor did the
Chief Counsel for Advocacy of the Small Business Administration (SBA)
file any comments.
Description and Estimate of the Number of Small Entities to Which the
Rule Will Apply
PHMSA analyzed privately owned entities (inclusive of investor-
owned entities) that could be impacted by the final rule, which are gas
transmission operators of current Class 1 and Class 2 pipelines that
later experience a class location change.\319\ Based on SBA size
standards under the North American Industry Classification System
(NAICS) in effect as of March 17, 2023, small privately owned entities
for companies in the pipeline transportation of natural gas sector are
those with less than $41.5 million in annual revenue.\320\ Using
operator Annual Report data, U.S. Energy Information Administration
Operations Data, and Dun & Bradstreet databases, PHMSA identified small
entities operating Class 1 and Class 2 pipelines under the applicable
SBA threshold.
---------------------------------------------------------------------------
\319\ PHMSA, Gas Transmission & Gathering Annual Data--2010 to
present (Nov. 7, 2025), available at: https://www.phmsa.dot.gov/data-and-statistics/pipeline/gas-distribution-gas-gathering-gas-transmission-hazardous-liquids; Dun & Bradstreet, Hoovers Data
Services (2025); Dun & Bradstreet, Hoovers Data Services (2024);
EIA, Annual Energy Outlook 2018--Natural Gas Delivered Prices
Average (Case Reference case) (accessed December 28, 2018) available
at: https://www.eia.gov/outlooks/aeo/data/browser/#/?id=13-
AEO2018®ion=0-
0&cases=ref2018&start=2016&end=2050&f=A&linechart=~ref2018-
d121317a.40-13-AEO2018&map=&ctype=linechart&sourcekey=0. See also
ICF International, Gas Gathering, Gas Transmission, and Gas
Distribution Operators--Small Entity Designation Database (2023).
\320\ PHMSA does not estimate that publicly owned entities will
be affected by this rule.
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PHMSA estimated that approximately 11% of pipelines currently in
each of Class 1 and Class 2 locations are operated by small entities.
There are currently 878 Class 1 pipeline operators, which are owned by
634 parent entities. 449 of these are small entities. These small
entities operate approximately 25,896 miles of Class 1 pipeline, which
is about 11 percent of all Class 1 pipelines.
There are currently 502 operators of Class 2 pipelines, which are
owned by 344 parent entities. 213 of these are small entities. These
small entities operate approximately 3,256 miles of Class 2 pipelines,
which is about 11 percent of all Class 2 pipelines.
Description of Projected Reporting, Recordkeeping, and Other Compliance
Requirements of the Rule, Including an Estimate of the Classes of Small
Entities Which Will Be Subject to the Requirement and the Type of
Professional Skills Necessary for Preparation of the Report or Record
PHMSA analyzed the costs of compliance for the small gas
transmission operators that may elect to use the IM alternative to
manage a class change. For all class changes experienced across all
operators in a given year, PHMSA calculated annualized estimated
compliance costs with the IM alternative that ranged from $61.5 to
$62.9 million depending on the discount rate. Small entities equally
share in this. Offset by the significant cost savings compared with
existing compliance options, this results in an estimated $460 to $461
million in cost savings per year. Class 1 to Class 3 changes make up
$452.7 to $453.8 million in annual cost savings depending on discount
rate, and Class 2 to Class 3 changes make up $7.2 million in annual
cost savings.
PHMSA calculated cost savings by estimating the miles of Class 1 to
Class 3 and Class 2 to Class 3 changes per year. This is because in any
given year, only a subset of operators will encounter such a change in
class location, though PHMSA is not able to develop an annual forecast
describing specific pipeline segments changing classes or to what
extent those changes will be managed by small versus large operators.
PHMSA assumes that all Class 1 and Class 2 segments encounter a class
change at the same rate regardless of operator size. PHMSA allocated
annualized cost savings to small entities based on the proportion of
total Class 1 or Class 2 miles that are operated by large and small
entities. Applying the 11 percent of estimated Class 1 to Class 3
change mileage
[[Page 1651]]
operated by small entities yields small entity annual cost savings of
$50.2 to $50.3 million depending on discount rate. Applying the 11
percent of estimated Class 2 to Class 3 change mileage operated by
small entities yields annual small entity costs savings of $0.8
million. Per small entity, this equates to cost savings of
approximately $112,000 for each small operator of a Class 1 pipeline
segment that changes to Class 3 and $3,600 for each small operator of a
Class 2 pipeline segment that changes to Class 3.
PHMSA then calculated cost-to-revenue ratios using the calculated
compliance costs of each small parent entity. PHMSA estimated that 73
percent of Class 1 small entities and 28 percent of Class 2 small
operators may experience cost savings greater than 1 percent of their
annual revenue. PHMSA estimated that 61 percent of Class 1 small
entities and 19 percent of Class 2 small operators may experience cost
savings greater than three percent of their annual revenue.
As to the impact on small entities, PHMSA notes that its
calculations are for annual cost savings, however PHMSA expects that
most entities will not manage a Class 1 to Class 3 or Class 2 to Class
3 change in any given year. For example, if operators only manage one
segment per year, then roughly 40 small entities (or fewer if operators
manage multiple segments in one year) may manage a Class 1 to Class 3
change per year, out of 449 total Class 1 small entities.
Steps PHMSA Has Taken To Minimize the Significant Economic Impact on
Small Entities Consistent With the Stated Objectives
The impacts of the final rule are beneficial to small entities. The
final rule enables a lower cost way safely to manage segments that
transition from a lower class location to a Class 3 location, thereby
creating cost savings for affected entities, large or small. While
PHMSA analyzed a number of alternatives to the final rule, which are
described in Section 6 of the RIA, PHMSA determined that each were not
necessary for pipeline safety, would unnecessarily limit the benefit or
cost-savings of this final rule, or both. None would reduce the impact
on small entities. As costs savings of the final rule are beneficial
rather than adverse, minimizing impacts for small entities would tend
to disadvantage them in favor of larger entities, an outcome that is at
odds with the goal of the Regulatory Flexibility Act. PHMSA therefore
has not considered these alternatives.
E. Unfunded Mandates Reform Act of 1995
The Unfunded Mandates Reform Act (UMRA, 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 ($203 million in 2024
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.
This final rule does not impose unfunded mandates under UMRA. As
shown in the RIA located in the rulemaking docket, the final rule does
not result in costs of $100 million or more in 1996 dollars per year
for either State, local, or Tribal governments, or to the private
sector.
F. National Environmental Policy Act
The National Environmental Policy Act (NEPA, 42 U.S.C. 4321 et
seq.) requires that Federal agencies assess and consider the impacts of
major Federal Actions on the human and natural environment.
PHMSA analyzed this final rule in accordance with NEPA and prepared
a final Environmental Assessment (EA) and an accompanying Finding of No
Significant Impact (FONSI), determining that this action would not
adversely affect safety and will not significantly affect the quality
of the human and natural environment. A copy of the EA and FONSI for
this action is available in the rulemaking docket.
G. Executive Order 13175
PHMSA analyzed this final rule according to the principles and
criteria in E.O. 13175 (Consultation and Coordination with Indian
Tribal Governments; 65 FR 67249 (Nov. 9, 2000)) and DOT Order 5301.1A
(Department of Transportation Tribal Consultation Policies and
Procedures). 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 or
distribution of power between the Federal Government and Tribes.
PHMSA assessed the impact of the final rule and determined that it
will not significantly or uniquely affect Tribal communities or Indian
Tribal governments. The rulemaking's regulatory amendments have a
broad, national scope; therefore, this final rule will not
significantly or uniquely affect Tribal communities, much less impose
substantial compliance costs on Native American Tribal governments or
mandate Tribal action. Insofar as the rulemaking will improve safety
and reduce public safety and environmental risks associated with class
location changes on gas pipelines, it will not impose
disproportionately high adverse risks for Tribal communities. For these
reasons, PHMSA has concluded that the funding and consultation
requirements of E.O. 13175 and DOT Order 5301.1A do not apply.
H. Paperwork Reduction Act
The Paperwork Reduction Act (44 U.S.C. 3501 et seq.) and its
implementing regulations at 5 CFR 1320.8(d) requires that PHMSA provide
interested members of the public and affected agencies with an
opportunity to comment on information collection and recordkeeping
requests. Components of this rulemaking will trigger new notification
and recordkeeping requirements for operators of gas transmission
pipeline systems who experience a change in their class location. The
provisions in this final rule include the following Paperwork Reduction
Act impacts:
First, gas transmission pipeline operators are required to notify
PHMSA, in accordance with Sec. 192.18, within 24 months if they elect
to use the IM alternative's protocols to manage pipeline segments that
have changed to a Class 3 location. This prompt notification will
provide PHMSA an opportunity to oversee the operator's implementation
of the segment regulations. The notification for each segment is
generally expected to include information such as: when the class
location change occurred; the original class location; the current
class location; the hoop stress corresponding to the MAOP; each state
and county in which the segment operates; the length of the segment; a
certification that the segment meets the eligibility criteria and will
operate in accordance with the stipulated requirements; and, for those
segments requesting to use the IM alternative that are actively under
an active special permit, identification of the special permit and a
request to void the special permit for specified segments or in its
entirety.
Second, operators who elect to use the IM alternative must comply
with various recordkeeping requirements.
[[Page 1652]]
Operators must confirm that the pipe in the segment has been pressure
tested to a minimum test pressure of 1.25 times the MAOP, with
traceable, verifiable, and complete records. Operators must also
confirm that the pipe in the segment has traceable, verifiable, and
complete pipe material records for diameter, wall thickness, grade,
seam type, yield strength, and tensile strength, or use Sec. 192.607
to collect necessary material records. For these and the various other
requirements to comply with this new compliance options, operators must
maintain records of all actions implemented to meet the program for the
life of the pipeline.
PHMSA will submit information collection requests to OMB for
approval based on the requirements in this rule. The information
collection requests are contained in the Pipeline Safety Regulations,
49 CFR parts 190-199. The following information is provided for each
information collection request: (1) Title of the information
collection; (2) OMB control number; (3) Current expiration date; (4)
Type of request; (5) Abstract of the information collection activity;
(6) Description of affected public; (7) Estimate of total annual
reporting and recordkeeping burden; and (8) Frequency of collection.
The information collection burden is estimated as follows:
1. Title: Class Location Change Notification Requirements.
OMB Control Number: 2137-0639.
Current Expiration Date: TBD.
Abstract: This mandatory information collection covers notification
requirements for operators of gas transmission pipeline systems who
experience a change in the class location of their pipelines. Operators
are required to notify PHMSA if they elect to the IM alternative to
manage pipeline segments that have changed to a Class 3 location. All
notifications must be made in accordance with 49 CFR 192.18.
Affected Public: Owners and operators of gas transmission
pipelines.
Annual Reporting Burden:
Total Annual Responses: 364.
Total Annual Burden Hours: 719.
Frequency of Collection: Once, when electing the compliance option.
2. Title: Class Location Change Records.
OMB Control Number: Will Request from OMB.
Current Expiration Date: TBD.
Abstract: This mandatory information collection covers the
collection of data by owners and operators of gas transmission pipeline
systems in their compliance with the requirements of this rule. Gas
transmission pipeline operators are required to make and maintain
various records to comply with the Pipeline Safety Regulations
pertaining to class location change requirements.
Affected Public: Owners and operators of gas transmission pipeline
systems.
Annual Reporting Burden:
Total Annual Responses: 496.
Total Annual Burden Hours: 13,114.
Frequency of Collection: On occasion.
Requests for a copy of these information collection requests should
be directed to Angela Hill by email at [email protected].
This document serves as a 60-day notice to invite comments on this
second information collection pertaining to the recordkeeping an
operator may conduct to comply with this new compliance option.
Specifically, comment is sought regarding: (a) The need for the
proposed collection of information for the proper performance of the
functions of the agency, including whether the information will have
practical utility; (b) The accuracy of the agency's estimate of the
burden of the revised collection of information, including the validity
of the methodology and assumptions used; (c) Ways to enhance the
quality, utility, and clarity of the information to be collected; and
(d) Ways to minimize the burden of the collection of information on
those who are to respond, including the use of appropriate automated,
electronic, mechanical, or other technological collection techniques.
Comments may be submitted in the following ways:
E-Gov Website: http://www.regulations.gov. This site allows the
public to submit comments on any Federal Register notice issued by any
agency.
Fax: 1-202-493-2251.
Mail: Docket Management Facility; U.S. Department of Transportation
(DOT), 1200 New Jersey Avenue SE, West Building, Room W12-140,
Washington, DC 20590-0001. Alternatively, hand delivery is available to
this address between 9:00 a.m. and 5:00 p.m. ET, Monday through Friday,
except Federal holidays.
Instructions: Identify the docket number PHMSA-2017-0151 at the
beginning of your comments. Note that all comments received will be
posted without change to http://www.regulations.gov, including any
personal information provided. If you submit your comments by mail,
submit two copies and, if you wish to receive confirmation that PHMSA
received your comments, include a self-addressed stamped postcard.
Privacy Act Statement: DOT posts public comments, without edit,
including any personal information the commenter provides, to our
docket at regulations.gov. You may review DOT's complete Privacy Act
Statement by visiting dot.gov/privacy.
Confidential Business Information: Confidential Business
Information (CBI) is commercial or financial information that is both
customarily and actually treated as private by its owner. Under the
Freedom of Information Act (FOIA) (5 U.S.C. 552), CBI is exempt from
public disclosure. It is important that you clearly designate the
comments submitted as CBI if your comments responsive to this notice
contain commercial or financial information that is customarily treated
as private, that you actually treat as private, and is relevant or
responsive to this notice. Pursuant to 49 CFR 190.343, you may ask
PHMSA to give confidential treatment to information you give to the
Agency by taking the following steps: (1) mark each page of the
original document submission containing CBI as ``Confidential;'' (2)
send PHMSA, along with the original document, a second copy of the
original document with the CBI deleted; and (3) explain why the
information you are submitting is CBI. Unless you are notified
otherwise, PHMSA will treat such marked submissions as confidential
under the FOIA, and they will not be placed in the public docket of
this notice. Send submissions containing CBI to Angela Hill, DOT,
PHMSA, 1200 New Jersey Avenue SE, PHP-30, Washington, DC 20590-0001.
Any comment PHMSA receives that is not specifically designated as CBI
will be placed in the public docket for this matter unaltered.
I. Executive Order 13609 and International Trade Analysis
E.O. 13609 (Promoting International Regulatory Cooperation; 77 FR
26413 (May 4, 2012)) requires agencies consider whether the impacts
associated with significant variations between domestic and
international regulatory approaches are unnecessary or may impair the
ability of American business to export and compete internationally. In
meeting shared challenges involving health, safety, labor, security,
environmental, and other issues, international regulatory cooperation
can identify approaches that are at least as protective as those that
are or would be adopted in the absence of such cooperation.
International regulatory cooperation can also reduce, eliminate,
[[Page 1653]]
or prevent unnecessary differences in regulatory requirements.
Similarly, the Trade Agreements Act of 1979 (Pub. L. 96-39), as
amended by the Uruguay Round Agreements Act (Pub. L. 103-465),
prohibits Federal agencies from establishing any standards or engaging
in related activities that create unnecessary obstacles to the foreign
commerce of the United States. For purposes of these requirements,
Federal agencies may participate in the establishment of international
standards, so long as the standards have a legitimate domestic
objective, such as providing for safety, and do not operate to exclude
imports that meet this objective. The statute also requires
consideration of international standards and, where appropriate, that
they be the basis for U.S. standards.
While the Agency engages with international standards setting
bodies to protect the safety of the American public, PHMSA has assessed
the effects of the final rule and has determined that its regulatory
amendments will not cause unnecessary obstacles to foreign trade.
J. Cybersecurity and Executive Order 14028
E.O. 14028 (Improving the Nation's Cybersecurity; 86 FR 26633 (May
17, 2021)) directed the Federal Government to improve its efforts to
identify, deter, and respond to ``persistent and increasingly
sophisticated malicious cyber campaigns.'' PHMSA has considered the
effects of the final rule and has determined that its regulatory
amendments would not materially affect the cybersecurity risk profile
for pipeline facilities.
PHMSA's regulatory amendments would not require pipeline operators
to generate new security-sensitive records. This rule provides an
additional option pipeline operators may choose to manage a change in
class location, an option which utilizes existing, proven IM and O&M
provisions already used elsewhere in part 192. Ultimately operators can
choose to adopt or decline this option. It is highly likely that
operators electing it are already familiar with the IM and O&M
requirements, have plans for each, and have evaluated their
cybersecurity risks.
Operators affected by these requirements may also be subject to
cybersecurity requirements and guidance under Transportation Security
Administration (TSA) Security Directives, as well as any new
requirements resulting from ongoing TSA efforts to strengthen
cybersecurity and resiliency in the pipeline sector.\321\ The
Cybersecurity & Infrastructure Security Agency (CISA) and the Pipeline
Cybersecurity Initiative (PCI) of the U.S. Department of Homeland
Security also conduct ongoing activities to address cybersecurity risks
to U.S. pipeline infrastructure and may introduce other cybersecurity
requirements and guidance for gas pipeline operators. These are
available at https://www.cisa.gov/uscert/ncas/alerts.
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\321\ E.g., TSA, Ratification of Security Directive, 90 FR 5491
(Jan. 17, 2025) (ratifying TSA Security Directive Pipeline-2021-02E,
which requires certain pipeline owners and operators to conduct
actions to enhance pipeline cybersecurity).
---------------------------------------------------------------------------
K. Severability
This final rule represents a considered decision by PHMSA, based in
its pipeline safety expertise and upon review of the technical record,
amending the class location change standard to add the IM alternative
program as an additional option. The IM alternative may not operate as
intended if one of the eligibility restrictions in Sec. 192.3 or
program elements set forth in Sec. 192.611(a)(4) is severed. PHMSA has
crafted a comprehensive program, contained within Sec. 192.611(a)(4),
to suit the safety needs of pipe with eligible integrity
characteristics, as defined by Sec. 192.3, upon a class location
change. The programmatic requirements may need to be different should
any eligibility requirement be removed (which would operate to make
more pipelines eligible).\322\ Based on the administrative record in
this proceeding, PHMSA cannot say it would have promulgated this IM
alternative without each eligibility and programmatic element.
---------------------------------------------------------------------------
\322\ Adding additional eligibility restrictions to the final
rule, however, could still allow safe operation of the program.
---------------------------------------------------------------------------
However, PHMSA intends the IM alternative option to be severable as
applied to different classes and dates of class changes as these are
different situations to which the program as a whole may apply. For
example, the IM alternative as applied to Class 1 locations moving to
Class 3 locations is severable from its application to Class 2
locations moving to Class 3 locations. In addition, the program is
severable as applied to future class changes verse retrospective class
changes; the provision in amended Sec. 192.611(d) for MAOP restoration
of past class changes is severable from the main of the program in
Sec. 192.611(a)(4) too. For each of these individual scenarios, the IM
alternative option is practicable for pipeline safety and PHMSA has
assessed that the IM alternative option is separately warranted and
independently cost-justified for each category of pipeline facility. In
other words, PHMSA could have promulgated each set of requirements
independently. Yet, because each applies the same program as a whole,
it can be severed and not applied to those additional circumstances
while the IM alternative program can still function in the other
circumstances.
VIII. Regulatory Text
List of Subjects in 49 CFR Part 192
Incorporation by reference, Natural gas, Pipeline safety,
Pipelines.
In consideration of the foregoing, PHMSA amends 49 CFR part 192 as
follows:
PART 192--TRANSPORTATION OF NATURAL AND OTHER GAS BY PIPELINE:
MINIMUM FEDERAL SAFETY STANDARDS
0
1. The authority citation for part 192 continues to read as follows:
Authority: 30 U.S.C. 185(w)(3), 49 U.S.C. 5103, 60101 et seq.,
and 49 CFR 1.97.
0
2. Amend Sec. 192.3 by adding the definition of ``Eligible Class 3
inspection area'' and ``Eligible Class 3 segment'' in alphabetical
order to read as follows:
Sec. 192.3 Definitions.
* * * * *
Eligible Class 3 inspection area means an eligible Class 3 segment
and the upstream and downstream portion of the transmission line that
is capable of being assessed with an in-line inspection tool extending
from the nearest in-line inspection tool launcher to the nearest in-
line inspection tool receiver.
Eligible Class 3 segment means a segment of a transmission line in
a Class 3 location that is capable of being assessed with an
instrumented in-line inspection tool which does not contain: bare pipe;
wrinkle bends; pipe with a seam formed by lap welding; a seam with a
longitudinal joint factor below 1.0; or a segment which has experienced
an in-service leak or rupture due to cracking in the pipe body, seam,
or girth weld on the segment or segments of similar characteristics in
or within 5 miles.
* * * * *
0
3. Amend Sec. 192.7 by revising paragraph (b)(12) to read as follows:
Sec. 192.7 What documents are incorporated by reference partly or
wholly in this part?
* * * * *
(b) * * *
[[Page 1654]]
(12) API STANDARD 1163, In-Line Inspection Systems Qualification,
Second edition, April 2013, Reaffirmed August 2018 (API STD 1163); IBR
approved for Sec. Sec. 192.493; 192.611(a).
* * * * *
0
4. Amend Sec. 192.611 by adding paragraph (a)(4) and revising
paragraph (d) to read as follows:
Sec. 192.611 Change in class location: Confirmation or revision of
maximum allowable operating pressure.
(a) * * *
(4) The maximum allowable operating pressure of an eligible Class 3
segment may be confirmed by complying with the integrity management
requirements in subpart O of this part and the additional or more
stringent requirements in paragraphs (a)(4)(i) and (ii) of this
section:
(i) By no later than March 16, 2028, or within 24 months of the
date of the class location change, whichever is later, the operator
must complete the following initial programmatic requirements:
(A) Conduct a baseline assessment of the eligible Class 3
inspection area and remediate all immediate and one-year conditions in
accordance with this section and subpart O of this part. A prior
assessment conducted after March 16, 2024, or within 24 months of the
class location change, whichever is later, may be used as the baseline
assessment. In addition, if the eligible Class 3 segment contains pipe
with a seam formed by direct current electric resistance welding, low-
frequency electric resistance welding, or electric flash welding, the
assessment technology or technologies selected must have a proven
application capable of assessing seam integrity and seam corrosion
anomalies.
(B) Test the eligible Class 3 segment in accordance with the
requirements in subpart J of this part to a pressure of at least 1.25
times the maximum allowable operating pressure. The results of a prior
test, conducted for a duration consistent with the requirements in
subpart J to a pressure of at least 1.25 the maximum allowable
operating pressure, may be used to satisfy this requirement.
(C) Confirm that the eligible Class 3 segment has traceable,
verifiable, and complete records available for pipe diameter, wall
thickness, grade, seam type, yield strength, and tensile strength; or
obtain the necessary material records in accordance with Sec. 192.607.
(D) Install, or use existing, valves such that rupture-mitigation
valves are located on both sides of the eligible Class 3 segment.
Isolation valves on any crossover or lateral pipe designed to isolate a
leak or rupture within the eligible Class 3 segment consistent with the
requirements of Sec. 192.634(b)(3) and (4). Valves must be located at
their original class design per Sec. 192.179.
(E) Install, if not already present, at least one cathodic
protection pipe-to-soil test station on the eligible Class 3 segment in
accordance with Sec. 192.469, with a maximum spacing of \1/2\ mile
between test stations. Where prevented by obstructions or restricted
areas, the test station may be placed in the closest practical
location.
(F) Perform a depth of cover survey of the eligible Class 3 segment
and take appropriate action to remediate any locations that do not
conform to the requirements in Sec. 192.327 for the original class
design.
(G) Perform a coating survey of the eligible Class 3 segment and
remediate in accordance with the requirements in Sec. 192.461(f)
through (h) if any of the following in paragraphs (a)(4)(i)(1) through
(5) are present:
(1) Ineffective external coating, as defined in Sec. 192.457;
(2) Adequacy of cathodic protection is measured using a minimum
negative (cathodic) polarization voltage shift of 100 millivolts in
accordance with paragraph I.A.(3) of appendix D to this part;
(3) Linear anodes are required to maintain cathodic protection in
accordance with Sec. 192.463;
(4) Tape wraps or shrink sleeves; or
(5) A history of shielding pipe from cathodic protection.
(H) Notify PHMSA in accordance with Sec. 192.18(a) and (b) that
the maximum allowable operating pressure of the eligible Class 3
segment is being confirmed under paragraph (a)(4) of this section.
(ii) Beginning no later than March 16, 2028, or 24 months after the
date of the class location change, whichever is later, the operator
must comply with the following recurring programmatic requirements:
(A) Except during abnormal operations, the gas transported in the
eligible Class 3 segment must not contain:
(1) More than 3 percent carbon dioxide by volume;
(2) More than seven pounds of water per million cubic feet of gas
or any free water; and
(3) More than one grain of hydrogen sulfide (H2S) per
100 cubic feet of gas.
(B) Perform close interval surveys of the eligible Class 3 segment
using a maximum interval of 5 feet or less with the protected current
interrupted at least once every 7 calendar years, with intervals not to
exceed 90 months. Evaluate the close interval survey results in
accordance with Sec. 192.463 and complete any needed remedial actions
in accordance with Sec. 192.465 within 1 year of the survey.
(C) Perform right-of-way patrols of the eligible Class 3 segment in
accordance with Sec. 192.705(a) and (c) at least once per month, with
intervals not exceeding 45 days.
(D) Perform leakage surveys of the eligible Class 3 segment in
accordance with Sec. 192.706 at least four times each calendar year,
with intervals not exceeding 4\1/2\ months.
(E) Install, if not already present, line markers on the eligible
Class 3 segment in accordance with Sec. 192.707. Each line marker must
be visible from at least one other line marker. Replace any missing
line markers within 30 days of discovery.
(F) Clear shorted casings in the eligible Class 3 segment within 1
year of identifying any metallic or electrolytic short. If clearing the
short is impractical, take other measures to minimize corrosion inside
the casing.
(G) Conduct a class location study of the eligible Class 3
inspection area in accordance with Sec. 192.609 at least once each
calendar year, with intervals not to exceed 15 months.
(H) Whenever the eligible Class 3 segment is exposed and the
coating is removed, examine the pipe and weld surfaces for cracking
using non-destructive examination methods and procedures that are
appropriate for the pipe and integrity threat conditions. Analyze
predicted failure pressure and critical strain level of any cracking in
accordance with Sec. 192.712 and remediate in accordance with the
requirements in paragraph (a)(4) of this section.
(I) The eligible Class 3 inspection area must be reassessed and
remediated in accordance with the requirements of paragraph (a)(4) of
this section and subpart O of this part.
(iii) Whenever required to comply with the requirements in
paragraphs (a)(4)(i) and (ii) of this section, the operator must:
(A) Validate the results of any in-line inspection of an eligible
Class 3 inspection area in accordance with API Std 1163 (incorporated
by reference, see Sec. 192.7) to at least level 2 validation with
sufficient in-situ anomaly validation measurements to achieve an 80
percent confidence level or 100 percent of anomalies, whichever results
in fewer validation measurements.
(B) Not use direct assessment as an integrity assessment method for
an eligible Class 3 inspection area.
[[Page 1655]]
(C) Use a factor 1.39 times the maximum allowable operating
pressure when determining the predicted failure pressure on any Class 1
design pipe in an eligible Class 3 segment for one-year conditions in
accordance with Sec. 192.933(d)(2)(iv) through (vii) and monitored
conditions in accordance with Sec. 192.933(d)(3)(v) through (vi).
(iv) Within 24 months of experiencing an in-service leak from the
pipe (including pipe to pipe connections) or rupture, the operator must
confirm or revise the maximum allowable operating pressure of an
eligible Class 3 segment in accordance with the requirements in
paragraph (a)(1), (2), or (3) of this section.
(v) The operator must keep for the life of the pipeline a record of
any action taken to comply with the requirements in paragraph (a)(4) of
this section.
(vi) The maximum allowable operating pressure of an eligible Class
3 segment confirmed under this paragraph may not produce a
corresponding hoop stress that exceeds 72 percent of SMYS for pipe with
a Class 1 design factor or 60 percent of SMYS for pipe with a Class 2
design factor.
(vii) Confirmation of maximum allowable operating pressure pursuant
to Sec. 192.611(a)(4) is not authorized for gathering lines or
distribution lines.
* * * * *
(d) Confirmation or revision of maximum allowable operating
pressure required as a result of a study under Sec. 192.609 must be
completed within 24 months of the change in class location. Pressure
reduction under paragraph (a)(1) or (2) of this section within the 24-
month period does not preclude establishing the maximum allowable
operating pressure of a segment under paragraph (a)(3) of this section
or restoring the maximum allowable operating pressure of a segment
under paragraph (a)(4) of this section at a later date. Before
restoring the maximum allowable operating pressure of an eligible Class
3 segment pursuant to paragraph (a)(4) of this section, an operator
must:
(1) Comply with the requirements of Sec. 192.555(b)(1) and (2),
(e);
(2) Comply with the requirements in subpart O of this part for MAOP
increases; and
(3) Complete all requirements of paragraph (a)(4)(i) of this
section.
0
5. Amend Sec. 192.903 by revising the definition of ``High consequence
area'' to read as follows:
Sec. 192.903 What definitions apply to this subpart?
* * * * *
High consequence area means an area established by one of the
methods described in paragraph (1) or (2) of this definition as
follows:
(1) An area defined as--
(i) A Class 3 location under Sec. 192.5; or
(ii) A Class 4 location under Sec. 192.5; or
(iii) Any area in a Class 1 or Class 2 location where the potential
impact radius is greater than 660 feet (200 meters), and the area
within a potential impact circle contains 20 or more buildings intended
for human occupancy; or
(iv) Any area in a Class 1 or Class 2 location where the potential
impact circle contains an identified site; or
(v) Any area containing an eligible Class 3 segment with a maximum
allowable operating pressure confirmed in accordance with Sec.
192.611(a)(4).
(2) The area within a potential impact circle containing--
(i) 20 or more buildings intended for human occupancy, unless the
exception in paragraph (4) of this definition applies; or
(ii) An identified site; or
(iii) Any portion of an eligible Class 3 segment with a maximum
allowable operating pressure confirmed in accordance with Sec.
192.611(a)(4).
(3) Where a potential impact circle is calculated under either
method in paragraph (1) or (2) of this definition to establish a high
consequence area, the length of the high consequence area extends
axially along the length of the pipeline from the outermost edge of the
first potential impact circle that contains either an identified site
or 20 or more buildings intended for human occupancy to the outermost
edge of the last contiguous potential impact circle that contains
either an identified site or 20 or more buildings intended for human
occupancy. (See figure E.I.A. in appendix E.)
(4) If in identifying a high consequence area under paragraph
(1)(iii) of this definition or paragraph (2)(i) of this definition, the
radius of the potential impact circle is greater than 660 feet (200
meters), the operator may identify a high consequence area based on a
prorated number of buildings intended for human occupancy with a
distance of 660 feet (200 meters) from the centerline of the pipeline
until December 17, 2006. If an operator chooses this approach, the
operator must prorate the number of buildings intended for human
occupancy based on the ratio of an area with a radius of 660 feet (200
meters) to the area of the potential impact circle (i.e., the prorated
number of buildings intended for human occupancy is equal to 20 x (660
feet) [or 200 meters]/potential impact radius in feet [or meters]\2\).
* * * * *
Issued in Washington, DC, on January 12, 2026, under authority
delegated in 49 CFR 1.97.
Linda Daugherty,
Acting Associate Administrator for Pipeline Safety.
[FR Doc. 2026-00566 Filed 1-13-26; 8:45 am]
BILLING CODE 4910-60-P