Interstate Natural Gas Association of America v. Pipeline

United States Court of Appeals
FOR THE DISTRICT OF COLUMBIA CIRCUIT
Argued May 16, 2024 Decided August 16, 2024
No. 23-1173
I NTERSTATE NATURAL GAS ASSOCIATION OF AMERICA ,
PETITIONER
v.
PIPELINE AND HAZARDOUS M ATERIALS SAFETY
ADMINISTRATION AND UNITED STATES DEPARTMENT OF
TRANSPORTATION ,
RESPONDENTS
On Petition for Review of a Final Rule
of the Department of Transportation
Sean Marotta argued the cause for petitioner. With him
on the briefs were Catherine E. Stetson, Matthew J. Higgins,
and Keenan Roarty.
Brian J. Springer, Attorney, U.S. Department of Justice,
argued the cause for respondents. With him on the brief were
Brian M. Boynton, Principal Deputy Assistant Attorney
General, Abby C. Wright, Attorney, Paula Lee, Senior Trial
Attorney, U.S. Department of Transportation, and Jeremy T.
Henowitz, Attorney, Pipeline and Hazardous Materials Safety
Administration.

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Adrienne Y. Lee and Hana Vizcarra were on the brief for
amicus curiae Pipeline Safety Trust in support of
respondents.
Before: WILKINS , W ALKER and PAN, Circuit Judges.
Opinion for the Court filed by Circuit Judge PAN.
PAN, Circuit Judge: The Pipeline and Hazardous
Materials Safety Administration (“PHMSA”) regulates the
safety of pipelines that transport natural gas and other
potentially dangerous materials. In 2022, PHMSA
promulgated a long list of new and revised safety standards.
A trade group that represents pipeline companies — the
Interstate Natural Gas Association of America (“INGAA”) —
challenges five of those standards, alleging flaws in the
rulemaking process and inadequacies in PHMSA’s final
justifications. With respect to four of the standards at issue,
we agree with INGAA that the agency failed to adequately
explain why the benefits of the final standards outweigh their
costs, as required by 49 U.S.C. § 60102(b)(5). But we
conclude that the agency properly promulgated the last
challenged standard. We therefore grant the petition in part
and deny it in part.
I.
A.
The Secretary of Transportation is required by statute to
“prescribe minimum safety standards for pipeline
transportation and for pipeline facilities.” 49 U.S.C.
§ 60102(a)(2). The Secretary has delegated that authority to
PHMSA. Id. § 108(f); 49 C.F.R. § 1.97(a)(1).

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When prescribing pipeline-safety standards, PHMSA
must follow certain procedures that are mandated by statute.
The procedures “are more specific and still more demanding”
than those required by the Administrative Procedure Act
(“APA”), which PHMSA also must follow. GPA Midstream
Ass’n v. Dep’t of Transp., 67 F.4th 1188, 1196–97 (D.C. Cir.
2023).
To impose a new standard, PHMSA must publish two
cost-benefit analyses: one when it first proposes the standard,
and another when it finalizes the rule. See GPA Midstream,
67 F.4th at 1197–98, 1200–01. The first cost-benefit analysis
is part of the required “risk assessment,” 49 U.S.C.
§ 60102(b)(3), which the agency submits to “an advisory
committee of experts for peer review, and to the public for
comment.”1 GPA Midstream, 67 F.4th at 1192 (citing 49
U.S.C. § 60102(b)(4)). The advisory committee then
provides a report on the proposed standard, which
recommends adopting, rejecting, or changing it. See 49
U.S.C. § 60115(c)(2). Before finalizing the rule, PHMSA
must consider the advisory committee’s recommendation;
“comments and information received from the public”; and
other factors, such as the “reasonableness of the standard.”
Id. § 60102(b)(2). In addition, PHMSA must again explicitly
consider costs and benefits when issuing the final standard.
Id. § 60102(b)(5) (“[T]he Secretary shall . . . issue a standard
. . . only upon a reasoned determination that the benefits,
1 There are two advisory committees: the Technical Pipeline
Safety Standards Committee (also known as the Gas Pipeline
Advisory Committee, or GPAC) and the Technical Hazardous
Liquid Pipeline Safety Standards Committee. See 49 U.S.C.
§ 60102(b)(4)(A)(i); Pipeline Advisory Committees, PHMSA,
https://perma.cc/4NNP-4Q3E (Nov. 7, 2023). GPAC is the
relevant committee for the standards challenged here.

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including safety and environmental benefits, of the intended
standard justify its costs.”); see also id. § 60102(b)(2)(D), (E).
B.
In August 2011, PHMSA issued an Advance Notice of
Proposed Rulemaking to announce that the agency was
“considering whether changes are needed to the regulations
governing the safety of gas transmission pipelines.” J.A. 1–3.
Nearly five years later, in April 2016, PHMSA published a
Notice of Proposed Rulemaking (“NPRM”) that included a
long list of proposed modifications to pipeline standards. In
conjunction with its proposal, PHMSA published a report
entitled “Preliminary Regulatory Impact Assessment,” id. at
139, which in relevant part outlined the expected costs and
benefits of the proposed standards. Members of the public —
including petitioner INGAA — offered comments, and the
advisory committee considered the standards and proposed
some alterations.
In August 2022, PHMSA published its final rule and a
report entitled “Final Regulatory Impact Analysis” (“RIA”),
J.A. 619, which analyzed the costs and benefits of the final
standards. INGAA petitioned for reconsideration, noting its
support for the final rule generally, but asking that PHMSA
“reconsider several provisions.” Id. at 677. PHMSA largely
denied that petition, with a few exceptions not relevant here.
INGAA now petitions this court for review, challenging
five specific standards that were included in the final rule.
The challenged standards and PHMSA’s justifications for
adopting them are highly technical. We thus address each
standard individually and in detail infra, in Section III of this
opinion.

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II.
We have jurisdiction under 49 U.S.C. § 60119(a) to
review final regulations prescribed by PHMSA. We review
de novo whether the agency followed the procedural
mandates of the APA, as well as those of the pipeline-specific
statute, § 60102. See Sorenson Commc’ns Inc. v. FCC, 755
F.3d 702, 706 (D.C. Cir. 2014); 49 U.S.C. § 60119(a)(3). On
the merits of the final rule, we apply the familiar APA
standard that requires us to determine whether the rule is
“arbitrary, capricious, an abuse of discretion, or otherwise not
in accordance with law.” 5 U.S.C. § 706(2)(A). But in this
context, we defer to the agency’s decision only if it is
“informed,” GPA Midstream, 67 F.4th at 1199, and PHMSA
must make a “reasoned determination” that the benefits of the
final standard justify the costs, 49 U.S.C. § 60102(b)(5)
(emphasis added). Finally, the APA requires the agency to
show that it “reasonably considered the relevant issues and
reasonably explained the decision.” China Telecom (Ams.)
Corp. v. FCC, 57 F.4th 256, 264 (D.C. Cir. 2022) (cleaned
up).
III.
A.
We grant INGAA’s petition for review as to four
standards for which PHMSA failed to make “a reasoned
determination that the benefits . . . justify [the] costs.” 49
U.S.C. § 60102(b)(5). We refer to these standards as the
high-frequency-ERW standard, the crack-MAOP standard,
the dent-safety-factor standard, and the corrosive-constituent

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standard. We vacate each of these standards based on
PHMSA’s inadequate final cost-benefit analyses.2
1. High-Frequency-ERW Standard
Some pipes are manufactured through a process known
as electric resistance welding (“ERW”). ERW involves
forming a pipe by using an electric current to weld the edges
of a piece of steel together to form a cylinder. See Fact
Sheet: Pipe Manufacturing Process, PHMSA,
https://perma.cc/JYD5-URFB (Dec. 1, 2011). Prior to 1970,
this welding was achieved through the use of low-frequency
currents. Id. But for the last several decades, the process has
instead used high-frequency currents, which “produce[] a
higher quality weld.” Id.
Corrosion can lead to the thinning of pipe walls, known
as “metal loss,” which can cause some pipes, including those
formed by ERW, to split open at the seam (that is, the point
where the steel is welded together). See Fact Sheet: Pipe
Defects and Anomalies, PHMSA, https://perma.cc/4E9E-
GZWG (Dec. 1, 2011). Prior to the instant rulemaking, the
regulations addressed this concern by incorporating an
industry standard known as ASME/ANSI B31.8S. See 49
C.F.R. § 192.7(c)(6). That industry standard requires pipeline
2 We thus need not opine on INGAA’s other challenges to these
four standards, including that PHMSA failed to offer an adequate
preliminary cost-benefit analysis under 49 U.S.C.
§ 60102(b)(3)(B); violated the APA’s logical-outgrowth doctrine;
and failed to consider recommendations from the advisory
committee as required by § 60102(b)(2)(G). Cf. United States v.
Philip Morris USA Inc., 566 F.3d 1095, 1118 (D.C. Cir. 2009)
(“Because these challenges have no impact on the outcome of this
appeal, we decline to address them.”).

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operators to immediately repair a pipe upon discovering metal
loss along longitudinal seams formed by low-frequency ERW
— but the standard does not mention pipes formed by high-
frequency ERW. See ASME/ANSI B31.8S at § 7.2.1
(available at https://perma.cc/P66V-3C5K). By contrast, the
final rule requires immediate repair where there is metal loss
along a seam created by either high-frequency or low-
frequency ERW, if the pipe is expected to fail at a certain
pressure. See 49 C.F.R. §§ 192.714(d)(1)(iv),
192.933(d)(1)(iv).3
In justifying the final standard, PHMSA claimed that the
standard “will not impose an additional cost burden on
pipeline operators” because the regulations already required
immediate repairs through their incorporation of
ASME/ANSI B31.8S. J.A. 658–59. INGAA noted in its
motion for reconsideration that the agency’s reliance on
ASME/ANSI B31.8S did not justify immediate repair of
pipes formed by high-frequency ERW. INGAA therefore
asked PHMSA to exclude from the rule’s repair requirements
any pipes formed by high-frequency ERW. But PHMSA
denied the request. INGAA now challenges this standard as
applied to pipes formed by high-frequency ERW.
We vacate the high-frequency-ERW standard because
PHMSA’s analysis of its costs is unsupported by the record.
See 49 U.S.C. § 60102(b)(5) (requiring “a reasoned
determination that the benefits . . . justify [the] costs”). The
agency concluded that this standard simply “adopt[ed]
requirements . . . referenced in ASME/ANSI B31.8S” and
claimed that the standard therefore “will not impose an
3 The regulation also applies to seams formed by other methods
— known as direct current and electric flash welding — which are
not at issue here.

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additional cost burden on pipeline operators since [the
mandated repairs] are already required.” J.A. 658–59; see 49
C.F.R. § 192.7(c)(6) (incorporating ASME/ANSI B31.8S by
reference). But, as discussed, the pre-existing industry
standard addressed seams formed by low-frequency ERW, but
not those formed by high-frequency ERW. See ASME/ANSI
B31.8S at § 7.2.1 (available at https://perma.cc/P66V-3C5K).
Contrary to the agency’s assurances, the challenged standard
imposes a new repair requirement with respect to high-
frequency-ERW pipes. PHMSA did not recognize this
requirement as new and therefore did not consider the costs it
imposed. Thus, the agency’s cost-benefit analysis is
unsupported by the record and fails to demonstrate “a
reasoned determination.” 49 U.S.C. § 60102(b)(5); cf. Motor
Vehicle Mfrs. Ass’n of U.S., Inc. v. State Farm, 463 U.S. 29,
43 (1983) (requiring a “rational connection between the facts
found and the choice made” (cleaned up)).
On appeal, the agency argues that seams formed through
high-frequency ERW face a high risk of failure. But that
argument pertains only to the standard’s benefits — it
supports the conclusion that the standard would reduce the
risk of an accident. Without properly identifying the costs of
the new standard, “it is not apparent just how the agency went
about weighing the benefits against the costs.” GPA
Midstream, 67 F.4th at 1200. We find unconvincing
PHMSA’s contention that its discussion of ASME/ANSI
B31.8S was “beside the point” because the agency just
“‘clarif[ied] existing regulatory expectations.’” PHMSA Br.
55–56 (alteration in original) (quoting J.A. 659). According
to the agency’s contemporaneous explanation, the existing
regulatory expectations were the requirements of
ASME/ANSI B31.8S, which do not support the agency’s
claim that no new costs will be incurred by pipeline operators
under the high-frequency-ERW standard. See Dep’t of Com.

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v. New York, 588 U.S. 752, 780 (2019) (“[I]n reviewing
agency action, a court is ordinarily limited to evaluating the
agency’s contemporaneous explanation in light of the existing
administrative record.” (citations omitted)). Because the
agency imposed a new safety requirement without properly
addressing the costs of doing so, the standard cannot stand.4
2. Crack-MAOP Standard
Another type of anomaly in a pipeline that can potentially
cause failures is a crack — i.e., an opening or separation in
the pipe wall. See Pipeline Glossary: Cracks, PHMSA,
https://perma.cc/V7L8-VWKA (last visited July 31, 2024). In
the NPRM, PHMSA proposed requiring immediate repair of
“cracks or crack-like flaws” in certain circumstances,
depending on the location of the crack, its depth, and its
interaction with other cracks.
Separately, PHMSA proposed requiring operators to
immediately repair any anomaly — crack, corrosion, dent,
etc. — based on the pipeline’s “predicted failure pressure”
4 As for remedy, the high-frequency-ERW standard is contained
within a provision that also applies to longitudinal seams formed by
other methods — “direct current, low-frequency . . . electric
resistance welding, [or] electric flash welding.” 49 C.F.R.
§§ 192.714(d)(1)(iv), 192.933(d)(1)(iv). INGAA does not
challenge the standard as applied to pipes formed by those other
methods, and PHMSA’s reasoning is valid as to those methods
because ASME/ANSI B31.8S did require repairs to those types of
pipes prior to the present rulemaking. See ASME/ANSI B31.8S at
§ 7.2.1 (available at https://perma.cc/P66V-3C5K). Thus, as
INGAA requests, we vacate 49 C.F.R. §§ 192.714(d)(1)(iv) and
192.933(d)(1)(iv) only as applied to pipes formed by high-
frequency electric resistance welding. See GPA Midstream, 67
F.4th at 1201–02.

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(that is, the gas pressure at which the anomaly would cause
the pipeline to burst or otherwise fail). J.A. 121. The
proposed rule set the limit for the predicted failure pressure in
relation to the maximum allowable operating pressure
(“MAOP”). The MAOP is the maximum gas pressure at
which an operator may lawfully operate a segment of a
pipeline based on its material, design, and location. See 49
C.F.R. §§ 192.3, 192.619. The proposed standard required
operators to immediately repair any anomaly when the
predicted failure pressure was less than or equal to 1.1-times
the MAOP — in other words, when the pipe was expected to
fail if faced with a gas pressure of 110% or less of the MAOP.
PHMSA noted that the proposed standard was consistent with
the pre-existing standard, stating that “PHMSA is not
proposing to change this criterion.” J.A. 38.
But PHMSA adjusted its approach to cracks during the
comment period. The final rule requires operators to
immediately repair any crack or crack-like anomaly when its
predicted failure pressure is less than 1.25-times the MAOP.
49 C.F.R. §§ 192.714(d)(1)(v)(C), 192.933(d)(1)(v)(C).
Thus, the threshold for repairing cracks was changed and
operators must repair more cracks under the final rule than
they would have repaired under the proposed rule: Under the
final rule, operators must repair a crack when the expected
failure pressure falls below 125% of the maximum allowed
pressure, rather than below 110% of the maximum. This
increases the burden on operators because, for example, under
the final rule operators need to repair a cracked pipe that is
expected to fail if the pressure reaches 115% of the MAOP,
but operators would not have been required to make that
repair under either the proposed or the pre-existing standard.
To justify this change, PHMSA explained that, for
cracks, it believed that the proposed 1.1-times-MAOP

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standard “would not provide an adequate safety margin.” J.A.
587; see also id. (“PHMSA has determined that this safety
margin for immediate crack conditions is inadequate . . . .”).
In denying INGAA’s petition for reconsideration as to this
standard, PHMSA elaborated that the “more conservative
MAOP-based threshold for immediate repair is appropriate to
ensure adequate protection against crack anomaly failure for a
number of reasons.” Id. at 708–09 (footnote omitted).
We conclude that PHMSA failed to provide a reasoned
final cost-benefit analysis for this standard, as required by 49
U.S.C. § 60102(b)(5). This time, the agency’s reasoning fails
because it neglected to analyze the costs altogether. The
agency should have considered the costs of changing the
predicted failure pressure at which operators would be
required to repair cracks and crack-like anomalies. The
change was significant — 1.1-times the MAOP was the
standard for all anomalies prior to this rulemaking and was
included in the proposed rule, but the agency adopted a new
threshold of 1.25-times the MAOP for cracks and crack-like
anomalies. Without evaluating the costs of the change, the
agency could not make “a reasoned determination that the
benefits . . . justify [the] costs.” 49 U.S.C. § 60102(b)(5); see
GPA Midstream, 67 F.4th at 1200.
PHMSA points to its statement in the RIA that “the final
changes to § 192.933(d) addressing metal loss, stress
corrosion cracking, and metal-loss affecting a detected
longitudinal seam, and selective seam corrosion will not
impose an additional cost burden on pipeline operators since
they are already required.” J.A. 658–59. But the pipe
anomalies discussed in that statement include only one type
of crack (stress corrosion cracking) — the statement does not
address the costs of the entire crack-MAOP standard, which
applies to all cracks and crack-like anomalies. See 49 C.F.R.

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§§ 192.714(d)(1)(v)(C), 192.933(d)(1)(v)(C). In any event, to
the extent the quoted statement from the RIA purports to
apply to the crack-MAOP standard, it is inaccurate because
the crack-MAOP standard did not adopt a mandate that was
“already required,” J.A. 659 — rather, it increased the
standard from 1.1-times MAOP to 1.25-times MAOP.
PHMSA falls back on an argument that it “was not
obligated to consider the impact of the [crack-MAOP
standard] separate from other elements of this rulemaking.”
PHMSA Br. 51 (cleaned up). Elsewhere, it similarly argues
that the statute “allows PHMSA to evaluate the aggregate
effects of similar, mutually reinforcing regulatory
provisions.” Id. at 35. We need not decide today the precise
extent to which the agency must particularize its cost-benefit
analyses, or the extent to which it can calculate the costs and
benefits of related provisions together: Here, as explained,
the agency did not calculate the costs of the final crack-
MAOP standard at all. To the extent it did address the costs,
the agency claimed the standard had none because it
reiterated already existing requirements, which is contrary to
the record. We therefore vacate 49 C.F.R.
§§ 192.714(d)(1)(v)(C) and 192.933(d)(1)(v)(C).
3. Dent-Safety-Factor Standard
The dent-safety-factor standard is one part of the
agency’s approach to addressing dents in pipe walls.
Depending on factors such as their location and depth, dents
are subject to certain repair or monitoring requirements. For
example, some dents require immediate repair, 49 C.F.R.
§ 192.933(d)(1)(ii), and others require repair within one year,
id. § 192.933(d)(2)(i)–(iii). But operators can avoid or delay
these repair requirements under the final rule based on an
exception: If the operator performs an engineering analysis

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and ensures the pipe is not at risk of failure based on a
measure known as “critical strain levels,” the normal dent-
repair requirements do not apply. Id.
Section 192.712(c), which was not included in the
proposed rule but was added to the final rule, spells out
procedures that an operator must use as part of its engineering
analysis when evaluating dents if the operator seeks to utilize
the exception to the normal repair requirements. The dent-
safety-factor standard is one part of these procedures and is
used to measure “reassessment intervals.” 49 C.F.R.
§ 192.712(c)(9). If the engineering analysis relieves an
operator of the duty to repair a dent at a particular time, the
reassessment interval dictates when an operator must
reexamine that dent to see if the condition has worsened. The
dent-safety-factor standard requires operators to calculate the
reassessment interval using two inputs. Operators start by
estimating the “fatigue life,” i.e., how long it would take the
dent to cause the pipeline to fail. See id. Then, the operators
divide the fatigue life by a “safety factor” — a number set to
provide a margin of error to ensure that the dent is reassessed
prior to failure. See id. The final rule requires a safety factor
of five or greater, meaning that, for example, a dent with a
fatigue life of ten years would need to be reassessed within a
maximum of two years: ten years (fatigue life) divided by five
(safety factor). See id.
In the comment process, INGAA supported the adoption
of a fatigue-life to safety-factor ratio, like the one adopted in
the final rule; but INGAA proposed a safety factor of two
rather than five. That would have resulted in reassessment
intervals 2.5 times greater than that required by the final rule.
In other words, if the fatigue life of a dent were ten years,
INGAA supported a proposal that would have required
reassessment after five years, instead of the final rule’s two

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years. After promulgating the final rule, PHMSA denied
INGAA’s reconsideration petition as to this standard.
We must vacate the dent-safety-factor standard because
the agency failed to analyze its costs: There is simply no
discussion of the costs of this standard in the final rule or
RIA. Thus, “it is not apparent just how the agency went
about weighing the benefits against the costs,” and the
standard cannot stand. See GPA Midstream, 67 F.4th at 1200.
The agency cites only its statement in the final rule that
this standard provided “an adequate safety margin” and a
footnote in the final rule referencing an industry publication
that recommended a safety factor between two and five. J.A.
588. That does little to explain why the agency adopted the
top end of the range and, more importantly, does nothing to
identify the costs of the standard.
Because we have determined that the dent-safety-factor
standard, contained in 49 C.F.R. § 192.712(c)(9), is
inadequately justified, we must address the parties’ further
dispute over the appropriate remedy. INGAA asks us to
vacate only that sub-provision, while leaving the remainder of
§ 192.712(c) intact. PHMSA, on the other hand, argues that
if we vacate subsection (c)(9), we must vacate all of
§ 192.712(c).
We agree with PHMSA. “We will sever . . . a portion of
an administrative regulation only when we can say without
any substantial doubt that the agency would have adopted the
severed portion on its own,” such as when the provisions
“operate[] entirely independently of one another.” Am.
Petrol. Inst. v. EPA, 862 F.3d 50, 71 (D.C. Cir. 2017)
(cleaned up). Here, § 192.712(c) establishes a cohesive
scheme under which an operator must “evaluate dents and
other mechanical damage,” and its application allows an

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exception in circumstances where an operator otherwise
would be required to more immediately repair the dent, see 49
C.F.R. § 192.933(d)(1)–(3). If we vacate only
§ 192.712(c)(9), an operator could avail itself of the exception
without having to comply with the provision that “details
when the next dent reassessment must take place.”5 Reply Br.
14 (emphasis in original). Because we have “substantial
doubt that the agency would have adopted” the exception
without the reassessment-interval requirement in subsection
(c)(9), we conclude that it is not severable from the remainder
of the provision. Am. Petrol. Inst., 862 F.3d at 71 (cleaned
up). We therefore vacate 49 C.F.R. § 192.712(c) in its
entirety.
4. Corrosive-Constituent Standard
The corrosive-constituent standard is designed to require
operators to monitor and prevent internal corrosion of
pipeline walls. Prior to the present rulemaking, regulations
focused on corrosive gas: They provided that pipeline
operators must monitor and minimize internal corrosion “[i]f
corrosive gas is being transported.” 49 C.F.R. § 192.477.
Corrosive gas can cause the pipeline’s walls to corrode or
thin, risking dangerous incidents such as ruptures. See
Pipeline Safety: Internal Corrosion in Gas Transmission
Pipelines, 65 Fed. Reg. 53,803, 53,803 (Sept. 5, 2000).
Concerned that those requirements were not specific
enough, PHMSA proposed adding a new standard that would
5 In such a circumstance, reassessment would instead be
required in either seven or ten years, depending on the geographic
location of the dent, as established by 49 C.F.R. § 192.712(h). But
those timelines act as backstops and may be significantly longer
than the reassessment interval calculated under § 192.712(c)(9).

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“require monitoring for deleterious gas stream constituents.”
J.A. 92 (emphasis added) (discussing proposed 49 C.F.R.
§ 192.478). “Corrosive constituents,” such as carbon dioxide
and water, may be harmless on their own but can create
corrosive gas when combined with other substances.
Commenters objected to the breadth of the proposed
standard and the advisory committee proposed limiting the
rule “to the transportation of corrosive gas,” rather than
corrosive constituents. J.A. 504 (emphasis added). In
response, PHMSA narrowed its approach in the final rule:
The final rule requires operators to “develop and implement a
monitoring and mitigation program to mitigate the corrosive
effects, as necessary”; it does not, like the proposed rule,
expressly require operators to “identify potentially corrosive
constituents in the gas being transported.” Compare 49
C.F.R. § 192.478(a) (emphasis added) with J.A. 112.6
In justifying the final standard, PHMSA claimed that
regulations promulgated by the Federal Energy Regulatory
Commission already require some operators to monitor
corrosive constituents, so the new standard “is not expected to
add any incremental compliance activities or costs, but rather
codifies existing practice into regulation.” J.A. 648. At the
same time, “PHMSA acknowledge[d] that while there may be
6 PHMSA asserts that the changes between the proposed and
final rules sufficed to fully implement the advisory committee’s
recommendation that the regulation only apply where corrosive gas
is present. INGAA reads the final rule differently and believes the
standard imposes obligations in some circumstances where
corrosive constituents, but not corrosive gas, are present. We need
not resolve this dispute over the precise meaning of the rule
because we vacate the standard based on PHMSA’s insufficient
final cost-benefit analysis.

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compliance costs,” it was difficult to precisely predict or
calculate those costs. Id. at 650. As for benefits, the agency
noted that there were nearly 150 incidents and $200 million in
damages over a 12-year span caused by corrosion-related
incidents. Id. at 652. Once again, PHMSA rejected
INGAA’s petition for reconsideration of this final standard.
The final cost-benefit analysis of the corrosive-
constituent standard was inadequate because PHMSA’s
description of the costs was internally inconsistent. The
agency stated first that the rule “is not expected to add any
incremental compliance activities or costs,” J.A. 648; and
then that “while there may be compliance costs, precisely
how much those compliance costs are is hard to determine,”
id. at 650. We thus cannot discern the agency’s reasoning:
Does the standard impose no costs at all or does it impose
some costs that cannot be calculated? The agency’s
explanation contradicts itself and thus fails to meet the
requirement of a reasoned cost-benefit analysis. See 49
U.S.C. § 60102(b)(5); cf. Nat. Res. Def. Council v. Nuclear
Regul. Comm’n, 879 F.3d 1202, 1214 (D.C. Cir. 2018) (“[I]t
would be arbitrary and capricious for the agency’s decision
making to be internally inconsistent.” (cleaned up)).
PHMSA does little to reconcile this inconsistency on
appeal. It restates its conflicting justifications, and claims
that the second statement “did not override” the first one.
PHMSA Br. 43 (quoting J.A. 648, 650). But we must rely on
the agency record, which does not explain PHMSA’s
reasoning, so this argument is unavailing. We thus vacate 49
C.F.R. § 192.478.
B.
We deny INGAA’s petition as to the last challenged
standard, which we refer to as the pipeline-segment standard.

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INGAA challenges both the preliminary and final cost-benefit
analyses of this standard based on a minor change in the
language between the proposed and final rules. But PHMSA
stated in the record that the revised wording does not
implement any substantive change, and INGAA provides no
reason to doubt the agency’s representations. Because the
language-change arguments are the only ones that INGAA
preserved and because those claims are unconvincing,
INGAA’s challenge to the pipeline-segment standard fails.
The pipeline-segment standard addresses monitoring for
“stress corrosion cracking” (“SCC”), which is a pipe anomaly
that occurs when corrosion and high pressure (i.e., stress) lead
to cracks. See Fact Sheet: Stress Corrosion Cracking,
PHMSA, https://perma.cc/QLP7-TPUX (July 23, 2014); see
also J.A. 63 (“SCC is cracking induced from the combined
influence of tensile stress and a corrosive medium.”). One
way to monitor pipelines for SCC is through “direct
assessment” — i.e., excavating areas around a pipeline to
directly examine sample portions of the pipe and surrounding
soil. The NPRM proposed requiring a minimum of three
excavations per “SCC segment” when operators conduct a
direct assessment. J.A. 127. The proposed rule did not define
“SCC segment.”
The final rule adopts the proposed standard with a minor
tweak: It requires at least three excavations per “covered
pipeline segment” — rather than per “SCC segment.” 49
C.F.R. § 192.929(b)(3). The regulations define “covered
pipeline segment” — as they did prior to the instant
rulemaking — to mean “a segment of gas transmission
pipeline located in a high consequence area,” id. § 192.903,
and a covered pipeline segment’s “boundaries are determined
by population density and other consequence factors,” J.A.
582. The agency explained that “the final rule invokes certain

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consensus industry standards” that “[m]ost operators already
successfully utilize,” so “the incremental cost . . . would be
negligible.” Id. at 642. As for benefits, PHMSA recognized
that the standard was not expected “to result, on [its] own, in
measurable changes in the risk of pipeline releases, incidents
or other quantifiable benefits,” but the agency pointed to the
benefits of clarifying its expectations. Id.
In its petition for reconsideration, INGAA asserted that
the change in terminology from “SCC segment” to “covered
pipeline segment” could require pipeline operators to perform
up to three times as many excavations. PHMSA disagreed
and stated that there was no “substantive difference between
the meaning of the proposed and final versions.” J.A. 720.
On appeal, INGAA persists in claiming that the change
in wording imposes a significant burden on pipeline
operators, and that PHMSA failed to evaluate the costs and
benefits of that burden in either its preliminary or final
analyses. It asserts that requiring three assessments per
“covered pipeline segment” instead of per “SCC segment”
“tripl[es] the number of excavations” that a pipeline operator
must conduct. INGAA Br. 39. But PHMSA has never
defined “SCC segment,” and INGAA provides no evidence
other than its own representations that a single “SCC
segment” could contain up to three “covered pipeline
segments.” To the contrary, PHMSA indicated in the record
that it viewed the two terms as interchangeable. At oral
argument, INGAA’s counsel accepted that, if “SCC segment”
and “covered pipeline segment” mean the same thing, it has
no disagreement with the agency or the final rule.
Accordingly, we take PHMSA at its word and interpret the
final rule as substantively the same as the proposed rule with
respect to the number of excavations required for a direct
assessment. As a result, the parties agree to the number of

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excavations that are mandated; and INGAA’s challenges to
both the preliminary and final cost-benefit analyses fall away.
To the extent INGAA mounts other attacks on the final
cost-benefit analysis, such arguments are forfeited: INGAA’s
petition for reconsideration focused only on the language
modification. Thus, INGAA cannot now argue, for example,
that PHMSA failed to conduct a cost-benefit analysis for
conducting a set number of excavations. See Nuclear Energy
Inst., Inc. v. EPA, 373 F.3d 1251, 1290 (D.C. Cir. 2004) (“As
a general rule, claims not presented to the agency may not be
made for the first time to a reviewing court.” (cleaned up));
49 U.S.C. § 60119(a)(3) (“A judicial review of agency action
under this section shall apply the standards of review
established in [the APA].”).
* * *
For the foregoing reasons, we grant the petition in part
and deny it in part. We vacate 49 C.F.R. § 192.712(c) (the
dent-safety-factor standard and related provisions); 49 C.F.R.
§§ 192.714(d)(1)(v)(C) and 192.933(d)(1)(v)(C) (the crack-
MAOP standard); and 49 C.F.R. § 192.478 (the corrosive-
constituent standard). We also vacate 49 C.F.R.
§§ 192.714(d)(1)(iv) and 192.933(d)(1)(iv) (the high-
frequency-ERW standard), but only as applied to seams
formed by high-frequency electric resistance welding. We
deny the petition as to 49 C.F.R. § 192.929(b)(3) (the
pipeline-segment standard).
So ordered.

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