Rule2026-00566
Pipeline Safety: Class Location Change Requirements
Primary source
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Published
January 14, 2026
Effective
March 16, 2026
Issuing agencies
Transportation DepartmentPipeline and Hazardous Materials Safety Administration
Abstract
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.
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[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 [<a href="http://www.gpo.gov">www.gpo.gov</a>]
[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 <a href="/cdn-cgi/l/email-protection#c3b1aca1a6b1b7eda9a2a4a4a6b183a7acb7eda4acb5"><span class="__cf_email__" data-cfemail="70021f121502045e1a111717150230141f045e171f06">[email protected]</span></a>.
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., <a href="https://amerpipe.com/reference/charts-calculators/barlows-formula/">https://amerpipe.com/reference/charts-calculators/barlows-formula/</a> (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: <a href="https://www.applus.com/dam/Energy-and-Industry/GLOBAL/userfiles/file/Pressure-Testing-and-Recordkeeping-Reconciling-Historic-Pipeline-Practic.pdf">https://www.applus.com/dam/Energy-and-Industry/GLOBAL/userfiles/file/Pressure-Testing-and-Recordkeeping-Reconciling-Historic-Pipeline-Practic.pdf</a>.
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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: <a href="https://www.phmsa.dot.gov/regulations/title49/interp/pi-81-001">https://www.phmsa.dot.gov/regulations/title49/interp/pi-81-001</a>.
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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: <a href="https://ingaa.org/wp-content/uploads/2013/01/19697.pdf">https://ingaa.org/wp-content/uploads/2013/01/19697.pdf</a>; 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: <a href="https://www.researchgate.net/publication/307583466_Introduction_to_Pigging_a_Case_Study_on_Pigging_of_an_Onshore_Crude_Oil_Trunkline">https://www.researchgate.net/publication/307583466_Introduction_to_Pigging_a_Case_Study_on_Pigging_of_an_Onshore_Crude_Oil_Trunkline</a>.
\28\ See, e.g., Rosen Swiss AG, RoCorr MFL-A Service: In-line
Ultra-High-Resolution Metal Loss Detection and Sizing (2024),
available at: <a href="https://contenthub.rosen-group.com/api/public/content/729e05931aca4953ac0a47dbdf2c6566?v=f9378e13">https://contenthub.rosen-group.com/api/public/content/729e05931aca4953ac0a47dbdf2c6566?v=f9378e13</a>; Rosen Swiss AG, RoCD
EMAT-C Service: In-line High-Resolution Detection and Sizing of
Axial Cracks (2024), available at: <a href="https://contenthub.rosen-group.com/api/public/content/7e9f40578f924917a4403fa7fc5ba41e?v=0071d845">https://contenthub.rosen-group.com/api/public/content/7e9f40578f924917a4403fa7fc5ba41e?v=0071d845</a>.
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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\
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\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:
<a href="https://www.argusinnovates.com/public/download/files/244219">https://www.argusinnovates.com/public/download/files/244219</a>.
\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: <a href="https://www.ntsb.gov/safety/safety-studies/documents/ss1501.pdf">https://www.ntsb.gov/safety/safety-studies/documents/ss1501.pdf</a> (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).
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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:
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\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\
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\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.
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\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: <a href="https://www.phmsa.dot.gov/sites/phmsa.dot.gov/files/docs/technical-resources/pipeline/class-location-special-permits/64091/classchangewaivercriteria.pdf">https://www.phmsa.dot.gov/sites/phmsa.dot.gov/files/docs/technical-resources/pipeline/class-location-special-permits/64091/classchangewaivercriteria.pdf</a> (PHMSA, 2004 Special Permit
Criteria).
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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.
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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\
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\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: <a href="https://www.phmsa.dot.gov/sites/phmsa.dot.gov/files/docs/news/55521/report-congress-evaluation-expanding-pipeline-imp-hcas-full.pdf">https://www.phmsa.dot.gov/sites/phmsa.dot.gov/files/docs/news/55521/report-congress-evaluation-expanding-pipeline-imp-hcas-full.pdf</a>.
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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.
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\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\
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\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 <a href="http://regulations.gov">regulations.gov</a>. 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).
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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 <a href="http://regulations.gov">regulations.gov</a>.
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\
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\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).
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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\
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\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).
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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\
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\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).
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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\
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\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\
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\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).
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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.
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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\
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\65\ NTSB, Comments, Docket ID PHMSA-2017-0151-0055 at 3-4 (Dec.
10, 2020).
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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\
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\66\ Docket ID PHMSA-2017-0151-0063 at 2.
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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\
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\67\ Docket ID PHMSA-2017-0151-0061 at 11.
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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.
---------------------------------------------------------------------------
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:
<bullet> First, the final rule defines under eligibility those
pipeline characteristics that can safely be managed by the program.
<bullet> 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.
<bullet> Third, the final rule includes supplemental O&M measures
based on historical special permit conditions.
<bullet> 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.
---------------------------------------------------------------------------
\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).
---------------------------------------------------------------------------
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\
---------------------------------------------------------------------------
\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.
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\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: <a href="https://www.phmsa.dot.gov/sites/phmsa.dot.gov/files/2023-06/Batch-1-FAQs-PHMSA-2019-0225-9-15-20.pdf">https://www.phmsa.dot.gov/sites/phmsa.dot.gov/files/2023-06/Batch-1-FAQs-PHMSA-2019-0225-9-15-20.pdf</a>.
\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: <a href="https://doi.org/10.55274/R0012046">https://doi.org/10.55274/R0012046</a> (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: <a href="https://www.structint.com/wp-content/uploads/2022/08/APTITUDE-Crack-Evaluation-for-Pressurized-Cylinders.pdf">https://www.structint.com/wp-content/uploads/2022/08/APTITUDE-Crack-Evaluation-for-Pressurized-Cylinders.pdf</a>
(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: <a href="https://www.phmsa.dot.gov/sites/phmsa.dot.gov/files/2023-05/Batch-2-RIN-1-FAQs.pdf">https://www.phmsa.dot.gov/sites/phmsa.dot.gov/files/2023-05/Batch-2-RIN-1-FAQs.pdf</a>.
\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: <a href="https://www.phmsa.dot.gov/sites/phmsa.dot.gov/files/docs/technical-resources/pipeline/gas-transmission-integrity-management/65316/validityofcorrosionassessmentsr1.pdf">https://www.phmsa.dot.gov/sites/phmsa.dot.gov/files/docs/technical-resources/pipeline/gas-transmission-integrity-management/65316/validityofcorrosionassessmentsr1.pdf</a>.
\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: <a href="https://info.ornl.gov/sites/publications/Files/Pub126720.pdf">https://info.ornl.gov/sites/publications/Files/Pub126720.pdf</a>.
---------------------------------------------------------------------------
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: <a href="https://www.usgs.gov/programs/landslide-hazards/landslide-basics">https://www.usgs.gov/programs/landslide-hazards/landslide-basics</a> (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\
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\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: <a href="https://www.phmsa.dot.gov/sites/phmsa.dot.gov/files/docs/technical-resources/pipeline/gas-transmission-integrity-management/65321/evaluatingstabilityofdefects.pdf">https://www.phmsa.dot.gov/sites/phmsa.dot.gov/files/docs/technical-resources/pipeline/gas-transmission-integrity-management/65321/evaluatingstabilityofdefects.pdf</a>.
---------------------------------------------------------------------------
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: <a href="https://www.phmsa.dot.gov/sites/phmsa.dot.gov/files/docs/technical-resources/pipeline/gas-transmission-integrity-management/65286/tto11pipewrinklestudyfinalreportoct2004.pdf">https://www.phmsa.dot.gov/sites/phmsa.dot.gov/files/docs/technical-resources/pipeline/gas-transmission-integrity-management/65286/tto11pipewrinklestudyfinalreportoct2004.pdf</a>. 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:
<a href="https://primis.phmsa.dot.gov/enforcement-documents/22024009CAO/22024009CAO_Corrective%20Action%20Order%20">https://primis.phmsa.dot.gov/enforcement-documents/22024009CAO/22024009CAO_Corrective%20Action%20Order%20</a>(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.
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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: <a href="https://ingaa.org/foundation/resources/integrity-characteristics-of-vintage-pipelines/">https://ingaa.org/foundation/resources/integrity-characteristics-of-vintage-pipelines/</a>).
---------------------------------------------------------------------------
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: <a href="https://primis.phmsa.dot.gov/rd/projects/390/">https://primis.phmsa.dot.gov/rd/projects/390/</a>.
\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: <a href="https://www.jdfields.com/news-and-case-studies/the-evolution-of-high-frequency-welded-line-pipe">https://www.jdfields.com/news-and-case-studies/the-evolution-of-high-frequency-welded-line-pipe</a>.
\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: <a href="https://www.phmsa.dot.gov/sites/phmsa.dot.gov/files/docs/technical-resources/pipeline/gas-transmission-integrity-management/65266/tto05lowfrequencyerwfinalreportrev3april2004.pdf">https://www.phmsa.dot.gov/sites/phmsa.dot.gov/files/docs/technical-resources/pipeline/gas-transmission-integrity-management/65266/tto05lowfrequencyerwfinalreportrev3april2004.pdf</a> (``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: <a href="https://www.phmsa.dot.gov/regulations/title49/interp/pi-89-001">https://www.phmsa.dot.gov/regulations/title49/interp/pi-89-001</a>.
---------------------------------------------------------------------------
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: <a href="https://www.ntsb.gov/investigations/AccidentReports/Reports/PAR0901.pdf">https://www.ntsb.gov/investigations/AccidentReports/Reports/PAR0901.pdf</a> (recommendation
P-09-01).
\170\ The complete research docket is available at: <a href="https://primis.phmsa.dot.gov/matrix/PrjHome.rdm?prj=390">https://primis.phmsa.dot.gov/matrix/PrjHome.rdm?prj=390</a>.
\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).
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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\
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\176\ See NTSB, Safety Recommendation, at 10 (Sept. 26, 2011),
available at: <a href="https://www.ntsb.gov/safety/safety-recs/recletters/P-11-008-020.pdf">https://www.ntsb.gov/safety/safety-recs/recletters/P-11-008-020.pdf</a>; 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).
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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\
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\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.
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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.
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\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.
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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.
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\185\ See Sec. 192.113; PHMSA, Fact Sheet: Pipe Manufacturing
Process (Dec. 01, 2011), available at: <a href="https://primis.phmsa.dot.gov/comm/FactSheets/FSPipeManufacturingProcess.htm">https://primis.phmsa.dot.gov/comm/FactSheets/FSPipeManufacturingProcess.htm</a>.
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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.
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\186\ PHMSA, 2004 Special Permit Criteria at 3.
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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\
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\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.
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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\
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\189\ Id.
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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\
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\190\ See Docket ID PHMSA-2024-0005-0417 at 3.
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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\
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\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).
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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.
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\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.
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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.
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\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)).
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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\
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\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.
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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''
[…truncated; see source link]Indexed from Federal Register on January 14, 2026.
This is legal information, not legal advice. Laws vary by jurisdiction and change frequently. Always verify current law with official sources and consult a licensed attorney in your jurisdiction for advice on your specific situation.