Document ID: s3://data.kl3m.ai/documents/govinfo/USCOURTS/USCOURTS-caDC-23-01173/USCOURTS-caDC-23-01173-0/pdf.json

Parties Involved:
Interstate Natural Gas Association of America
Petitioner
Pipeline Safety Trust
Amicus Curiae for Respondent
Pipeline and Hazardous Materials Safety Administration
Respondent
United States Department of Transportation
Respondent

Document Text:

United States Court of Appeals 

FOR THE DISTRICT OF COLUMBIA CIRCUIT

Argued May 16, 2024 Decided August 16, 2024 

No. 23-1173 

INTERSTATE NATURAL GAS ASSOCIATION OF AMERICA, 

PETITIONER

v. 

PIPELINE AND HAZARDOUS MATERIALS 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. 

USCA Case #23-1173 Document #2070403 Filed: 08/16/2024 Page 1 of 20
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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, WALKER 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/4E9EGZWG (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 highfrequency 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 lowfrequency 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 highfrequency-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 highfrequency 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 crackMAOP 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 dentrepair 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 dentsafety-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 corrosiveconstituent 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 crackMAOP standard); and 49 C.F.R. § 192.478 (the corrosiveconstituent standard). We also vacate 49 C.F.R. 

§§ 192.714(d)(1)(iv) and 192.933(d)(1)(iv) (the highfrequency-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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