# Pipeline Safety: Repair Criteria for Hazardous Liquid and Gas Transmission Pipelines

> Briefs, arguments, decisions, and more.

URL: https://www.frixlaw.com/law-library/documents/fr%3A2026-13805

## Record

- **Collection:** Federal Register
- **Document type:** Proposed Rule
- **Published:** July 8, 2026
- **Citation:** 91 FR 42272

## Text

DEPARTMENT OF TRANSPORTATION
Pipeline and Hazardous Materials Safety Administration
49 CFR Parts 192 and 195
[Docket No. PHMSA-2025-0019]
RIN 2137-AF44
Pipeline Safety: Repair Criteria for Hazardous Liquid and Gas Transmission Pipelines

AGENCY:

Pipeline and Hazardous Materials Safety Administration (PHMSA), Department of Transportation (DOT).

ACTION:

Notice of proposed rulemaking (NPRM).

SUMMARY:

PHMSA proposes to modernize and to clarify the anomaly response criteria in the Federal pipeline safety regulations for gas transmission and hazardous liquid pipelines. Driven by twenty years of technological development, modern engineering concepts allow operators to identify, schedule, and remediate pipeline anomalies more effectively and in a less costly manner. PHMSA proposes incorporating these improved safety practices into its regulations by finalizing certain safety improvements advanced in recent rulemakings for gas transmission pipelines and extending those changes to hazardous liquid pipelines. In addition, PHMSA proposes certain non-substantive revisions to its gas and hazardous liquid repair regulations to improve compliance.

DATES:

Submit comments by September 8, 2026.

A public meeting of PHMSA's statutory advisory committees will be held on a date to be announced in the
Federal Register
.

ADDRESSES:

Submit comments by any of the following methods, identifying docket number PHMSA-2025-0019 at the top of the first page:

• On
https://www.regulations.gov,
follow instructions to “submit a comment.”

• By mail or hand delivery to Docket Management System, U.S. Department of Transportation, 1200 New Jersey Avenue SE, West Building Ground Floor, Room W12-140, Washington, DC 20590-0001. Hand delivery is available to this address between 9:00 a.m. and 5:00 p.m., Monday through Friday (except Federal holidays). Include two copies if submitting by mail and include a self-addressed and stamped postcard to receive confirmation of receipt.

• By fax to Docket Management System at (202) 493-2251.

Comments may be viewed at
https://www.regulations.gov/docket/PHMSA-2025-0019.
Comments are posted without changes or edits, including any personal information provided. DOT's privacy statement can be reviewed at
https://www.dot.gov/privacy.
As required by the Administrative Procedure Act (5 U.S.C. 553(b)(4)), a plain language summary of the proposed rule is also available in section I.B, and this proposal will be available online on the rulemaking docket.

Confidential Business Information (CBI):
You may designate a comment as CBI if your comment contains commercial or financial information that is customarily treated as private and that you actually treat as private by sending to Sayler Palabrica, at the contact information listed below, the following: (1) the original document with each page containing CBI marked as “confidential;” (2) a redacted copy with the CBI deleted; and (3) an explanation of why the information you are submitting is CBI.
See
49 CFR 190.343. Any comment not specifically designated as CBI will be placed in the public docket.

FOR FURTHER INFORMATION CONTACT:

Sayler Palabrica, Standards and Rulemaking Division, by phone at (202) 744-0825 or by email at
sayler.palabrica@dot.gov.

SUPPLEMENTARY INFORMATION:

I. Executive Summary

A. Background

B. Summary of Proposal

C. Cost Benefit Summary

II. Background

A. Regulatory Origin

B. Technological Development

C. Modernization in PHMSA Regulations

III. Advanced Notice of Proposed Rulemaking

IV. Discussion of the Proposal

A. Response Schedules

B. Response Criteria

i. Gas Transmission Response Criteria

ii. Hazardous Liquid Response Criteria

C. Anomaly Evaluation

i. Anomaly Evaluation for Dents by the Dent ECA

ii. Anomaly Evaluation for Metal Loss

iii. Anomaly Evaluation for Cracks

iv. Generally Applicable Components of Anomaly Evaluation

D. Material Properties and Records

i. Toughness and Material Property Values

ii. Material Properties for Hazardous Liquid Pipelines

iii. Recordkeeping for Hazardous Liquid Pipelines

E. Response, Repair, and Remediation Requirements

i. Discovery

ii. Non-HCA Hazardous Liquid Response Requirements

iii. Temporary Pressure Reduction

iv. General Repair Requirements

V. Section-by-Section Analysis

VI. Legal Authority

A. Pipeline Safety Laws

B. Section 60102(b) Practicability Factors

VII. Regulatory Analysis

VIII. List of Subjects

I. Executive Summary

A. Background

In the early 2000s, PHMSA created integrity management (IM) programs for gas transmission and hazardous liquid pipelines. Both IM programs included criteria for responding to anomalies.
1

These requirements—which today apply approximately to 41 percent of hazardous liquid and less than 18 percent of gas mileage in high consequence areas (HCAs) and other higher risk locations—used generic depth measurements that did not account for the specific anomaly or the operating parameters of the pipeline.
2

That approach has forced costly repair of pipelines in good serviceable condition, interrupting service for consumers and disrupting other proactive operational activities.

1

Pipeline Safety: Pipeline Integrity Management in High Consequence Areas,
68 FR 69778 (Dec. 15, 2003);
Pipeline Safety: Pipeline Integrity Management in High Consequence Areas (Repair Criteria),
67 FR 1650 (Jan. 14, 2002).

2
Though a smaller portion of gas transmission pipelines are in an HCA than hazardous liquid pipelines, the gas response schedule also applies to Class 3, Class 4, and other moderate consequence areas with a high operating stress level. 49 CFR 192.710(a). The IM program for hazardous liquid pipelines applies to pipelines in, or that could affect, an HCA. § 195.452(a).

Technology has dramatically advanced in the quarter of a century since the adoption of the IM program. In-line inspection (ILI) tools can now detect more pipeline anomalies with a higher degree of certainty, even interacting threats and previously unreliably detected threats.
3

Models can depict an entire pipeline with the impact of the anomaly and calculate the critical strain. All of this can be used to determine a pipeline's predicted failure pressure or fatigue life.

3
Rosen USA (Rosen), Comment, Docket ID PHMSA-2017-0151-0025, at 1 (Sept. 28, 2018);
see supra
section II.B.

In 2022, PHMSA amended its gas pipeline response criteria to incorporate some of these modern, engineering-based concepts.
4

In this proceeding, PHMSA proposes to complete that work

and to extend the same concepts to hazardous liquid pipelines.

4

Pipeline Safety: 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).

B. Summary of Proposal

Element
Proposal

Response schedule—gas
The anomaly response tiers in 49 CFR § 192.714(d) are denoted as immediate, near-term, and other conditions. Near-term is one year under IM and two years otherwise. The duplicative schedule at § 192.933 is removed to allow one central location for the gas response schedule.

Response schedule—hazardous liquid
The same three anomaly response tiers apply for hazardous liquid IM pipelines. Near-term response is one-year. The hazardous liquid response schedule is placed in its own section at § 195.453 as part of the IM program.

Response criteria—gas
Editorial revisions are proposed to improve the clarity of the § 192.714 response requirements. Criteria use a failure pressure ratio (FPR) rather than spelling out `predicted failure pressure times the maximum allowable operating pressure.' Substantively, for gas response: (1) a modern engineering-based criterion is added for the immediate response of cracks at an FPR of 1.1 and below; (2) the immediate crack depth criterion is revised to 70 percent or more; (3) immediate response to preferential seam corrosion is revised to an FPR of 1.1 and below; and (4) the dent interacting threat immediate criterion adds an exception for non-mechanical metal loss under 10 percent.

Response criteria—hazardous liquid
Modern engineering-based metrics are added alongside the existing depth-based measurements for hazardous liquid response criteria. A consistent FPR of 1.1 and below is used for the immediate response of metal loss and cracks, with near-term response required at FPRs of 1.39 and below. On depth measurements, immediate response is added at 70 percent depth for cracks, with near-term response of cracks at 50 percent depth and higher. For dents, immediate response is required for interacting threats from mechanical damage (mechanical corrosion, cracking, gouging, and a stress riser) at any orientation, near-term response is required for all dents that were previously listed as 180-day conditions, while the seam corrosion provision is targeted to preferential metal loss. A dent ECA can be used to calculate an alternative timeline for all dent criteria. Finally, hazardous liquid pipelines not subject to IM should respond following API RP 1160.

Anomaly evaluation
Update § 192.712 and create a similar provision at § 195.415:

(a) Anomaly evaluation must be conducted by a subject matter expert and include uncertainties, like tool tolerance.

(b) Metal loss analysis can use API 579 and Psqr, in addition to ASME B31G, R-STRENG, and other models demonstrated to provide comparable results.

(c) A dent ECA is proposed with a reassessment safety factor of two for gas pipelines and five for hazardous liquid pipelines.

(d) Crack analysis may use technically accepted fracture mechanic methods, including API 579 Level II or III, Modified Ln-Sec, and Raju-Newman equations. The
in-situ
crack exam provision is relocated to this paragraph.

(e) Toughness can be derived by Charpy v-notch or other valid testing methods. The default toughness values are updated and the methods to obtain toughness and other material properties for the analysis are extended to part 195, including adding § 195.407 to allow collection of material property records.

Discovery
A consistent anomaly discovery definition continues to apply from an operator having adequate information within an 180-day period. Expedited response to immediate conditions is required from preliminary ILI results, with discovery otherwise following the final ILI results.

Temporary pressure reduction
Two consistent options for temporary pressure reductions taken until gas and hazardous liquid pipelines are permanently repaired: a 20 percent reduction or reduction to a pressure below the predicted failure pressure times a design factor.

General repair requirements
The disperse general repair requirements are editorially revised and centralized at §§ 192.711 and 195.422 to encourage compliance.

C. Cost-Benefit Summary

PHMSA estimates that the proposed rule would generate substantial cost savings of approximately $390 million each year. Gas transmission pipeline operators are expected to experience between $214.6 and $241.7 million in cost savings each year, with hazardous liquid and carbon dioxide pipeline operators expected to experience cost savings of approximately $148.5 million in cost savings each year (both at a three percent discount rate). By accelerating responses to critical threats while eliminating unnecessary excavations, the proposal is also expected to enhance pipeline safety, to benefit worker safety, to minimize detrimental environmental impacts, to alleviate economic costs associated with congestion caused by work-zones from excavations, and to improve regulatory certainty and clarity for operators. The Preliminary Regulatory Impact Analysis (PRIA) provided in the rulemaking docket includes additional information regarding the costs, cost-savings, and benefits of the proposed rule.

II. Background

A. Regulatory Origin

As originally adopted, the Federal Pipeline Safety Regulations generally required gas
5

and hazardous liquid
6

pipeline operators to repair safety impediments within a reasonable time.
7

In the early 2000s, PHMSA established more detailed anomaly response schedules in adopting the IM program requirements for hazardous liquid and gas transmission pipelines.
8

The IM rules required operators to assess the integrity of higher-risk pipelines in HCAs at certain intervals,
i.e.,
at least once every five years for hazardous liquid and at least once every seven years for gas transmission pipelines. The IM rules also included response criteria in §§ 192.933 and 195.452(h) that applied to anomalies detected during these assessments. This led to specific response requirements for anomalies discovered in HCAs

compared with longstanding generic requirements to make repairs as needed.

5
“Gas” pipeline is used throughout this document to refer to pipelines regulated under part 192, which can be natural gas and any “flammable gas, or gas which is toxic or corrosive.” 49 CFR 192.3 (definition of “gas”).

6
“Hazardous liquid” pipeline is used throughout this document to refer to pipelines regulated under part 195, which includes hazardous liquid and carbon dioxide pipelines. § 195.2 (definition of “pipeline”). In addition to carbon dioxide, “hazardous liquid” includes “petroleum, petroleum products, anhydrous ammonia, and ethanol or other non-petroleum fuel, including biofuel, which is flammable, toxic, or would be harmful to the environment if released in significant quantities.” § 195.2 (definition of “hazardous liquid”).

7

Establishment of Minimum Standards,
35 FR 13248, 13274 (Aug. 19, 1970) (codifying §§ 192.711 and 192.713);
Transportation of Liquids by Pipeline—Requirements for the Design, Construction, Operation, and Maintenance,
34 FR 15473, 38369 (Oct. 4, 1969);
Transportation of Liquids by Pipeline,
46 FR 38357, 38369 (July 27, 1981) (recodifying § 195.401 and the part 195 regulations to reflect the enactment of the Hazardous Liquid Pipeline Safety Act of 1979 (Pub. L. 96-129)).

8

Pipeline Safety: Pipeline Integrity Management in High Consequence Areas,
68 FR 69778 (Dec. 15, 2003);
Pipeline Safety: Pipeline Integrity Management in High Consequence Areas (Repair Criteria),
67 FR 1650 (Jan. 14, 2002).
See also Pipeline Safety: Pipeline Integrity Management in High Consequence Areas (Hazardous Liquid Operators With 500 or More Miles of Pipeline),
65 FR 75378 (Dec. 1, 2000) (promulgating rest of hazardous liquid IM).

The original response criteria in the IM rules reflected the limited assessment technology and evaluation methods available at the time. Relying on traditional measurements, the criteria defined anomalies by location (
e.g.,
top- vs. bottom-side dents) or depth (
e.g.,
a crack at 50 percent depth). The response times for these criteria largely were not based on the anomaly's remaining safe life.
9

Though ILI tools could reliably measure the maximum depth of certain anomaly types, tool technologies and analytical methods were not sufficiently mature to produce high-resolution anomaly profiles reliably, to detect and classify interacting threats (such as selective seam weld corrosion and dents with interacting features), or to predict the remaining life of cracks and dents.

9
Consistent with the technology of the time, remaining strength calculation criteria were limited to metal loss.

By looking solely at measured anomaly size, the first IM response criteria overlooked the interaction between an anomaly and the specific characteristics of the pipeline (
e.g.,
size, material, and operating conditions), both of which must be considered to understand the likely impact on integrity and serviceability. As a result, the response margins in the original IM rules required remediation of anomalies in advance of what would otherwise be necessary to maintain pipeline integrity in many cases.

B. Technological Development

Pipeline technology has improved dramatically since the adoption of the anomaly response criteria in the original IM rules. Modern ILI tools can detect a wider range of defects with greater accuracy, particularly when compared to the technology available in the early 2000s. Today, commercially available ILI tools can detect pipe body crack sizing with 90 percent certainty to one millimeter via an Electromagnetic Acoustic Transducer (EMAT) tool,
10

and axial Magnetic Flux Leakage (MFL-A) tools can size corrosion depth with 80 percent certainty to 0.1 times the wall thickness.
11

Much of this technological improvement can be attributed to an increase in the number of sensors on modern ILI tools, which has improved both accuracy and probability of detection.
12

For example, sensors on crack ILI tools have increased from 480 in 2000 to over 1000 on today's tools, while MFL ILI corrosion tools have increased from 240 sensors in 2000 to about 1250 today. This corresponds to an improvement from +/− 10 percent wall thickness depth accuracy and 80 percent probability of detection in tools used in 2000 to +/− 0.03 inch and 90 percent probability of detection in tools used today.
13

Further, with dents, ILI tools now can detect a dent as small as 0.2 percent of wall thickness on large diameter pipelines.
14

Together, these advances have increased the probability of detection, probability of identification, and accuracy of sizing of pipeline anomalies.

10
Lacking precision when introduced in the mid-2000s, EMAT tools can now reliably detect smaller cracks with greater accuracy due to innovation in tool sizing and sensor count. Kinder Morgan,
Technical Justification for Use of EMAT as an Alternative Technology for Integrity Assessment of SCC in HCAs,
Docket ID PHMSA-2011-0023-0773 at 7-9 (Aug. 2019) (describing operator's development of EMAT ILI assessment and continued advancement of the technology over the 2010s). Previously, cracking was indicated by ILI run and not sized. Jeff Aron et al.,
Development of an EMAT In-Line Inspection System For Detection, Discrimination, and Grading of Stress Corrosion Cracking in Pipelines
(Feb. 2005),
https://www.netl.doe.gov/sites/default/files/2018-03/FG013105.PDF
(“Cracks of 30 [percent] or greater of the wall thickness in depth were imaged. Their depths and lengths could be estimated from the data.”).

11

See, e.g.,
Rosen,
RoCorr MFL-A Service: In-line Ultra-High-Resolution Metal Loss Detection and Sizing
(2024),
https://contenthub.rosen-group.com/api/public/content/729e05931aca4953ac0a47dbdf2c6566?v=f9378e13;
Rosen,
RoCD EMAT-C Service: In-line High-Resolution Detection and Sizing of Axial Cracks
(2024),
https://contenthub.rosen-group.com/api/public/content/7e9f40578f924917a4403fa7fc5ba41e?v=0071d845.

12
Colonial Pipeline Co. (Colonial), Comment, Docket ID PHMSA-2025-0019-0013, at 7 (July 21, 2025).

13
Colonial, Comment, Docket ID PHMSA-2025-0019-0013, at 7.

14

See
Rosen,
In-line Inspection Services for Deformation, Geometry and Mapping,
available at:
https://www.rosen-group.com/en/expertise/product-and-service-finder/in-line-inspection-services-for-deformation-geometry-and-mapping#ro-geo-xt-service
(noting how sensors improve accuracy and data quality, with more accurate tools “[m]inimiz[ing] conservatism of integrity assessments based on exceptionally detailed anomaly profiles”).

The experience gained by deploying ILI to more pipelines has led to further advancements in the detection and modelling of increasingly complex defect types.
15

New ILI tools are being designed and developed to assess anomalies with increasing accuracy and to address threats that could not previously be detected on a reliable basis. For example, to address hard to detect defects on double submerged arc welded pipe, Colonial Pipeline and NDT Global collaborated to create a multi-diameter and multi-threat tool that can be adjusted in the field for the size and threat to the pipeline.
16

Preferential metal loss, once thought not capable of reliable detection by ILI,
17

can now be assessed using a tool train that combines MFL-C corrosion and EMAT crack tools. Inertial Mapping Units have been updated to sub-meter accuracy with speed control, offering accurate measurement of bending strain caused by geohazards or construction activity through comparison to past tool runs.
18

15
Rosen, Comment, Docket ID PHMSA-2017-0151-0025, at 1 (Sept. 28, 2018); The Williams Companies, Inc., Comment, Docket ID PHMSA-2024-0005-0421, at 3, 5 (Aug. 27, 2024) (noting how study and application “drives the vendors to constantly improve and refine their tools,” and today “[o]perators . . . who regularly deploy [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” with “the data provided by the current generation of [ILI] tools giv[ing] [an operator] certainty and clarity around the risk assessment decisions . . . regarding potential threats”).

16
Nathan Leslie
et al., Compact 36” Ultrasonic ILI Tool for Enhanced Pipeline Integrity Management,
NDT Global, available at:
https://www.ndt-global.com/resources/white-paper/compact-36-ultrasonic-ili-tool-for-enhanced-pipeline-integrity-management/.

17
S
ee, e.g.,
Michael Baker Jr., Inc, Kiefner & Assoc., TTO No. 5,
Low Frequency ERW and Lap Welded Longitudinal Seam Evaluation,
at 6, 47, 60 (Apr. 2004), available at:
https://www.phmsa.dot.gov/sites/phmsa.dot.gov/files/docs/technical-resources/pipeline/gas-transmission-integrity-management/65266/tto05lowfrequencyerwfinalreportrev3april2004.pdf
(finding ILI tools in 2004 unreliable to identify longitudinal seam anomalies).

18
Rosen,
RoGeo XYZ Service: In-line High-Resolution Pipeline Route Mapping, Curvature Measurement and Strain Assessment,
available at:
https://contenthub.rosen-group.com/api/public/content/cc5d8df35a384c0a95e69d30122e31f8?v=9790a90c.

As ILI tools and modeling have advanced, critical strain levels and predicted failure pressure have become the preeminent, technically based option for evaluating anomalies to ensure pipeline safety. Until the 1970s, operators relied on burst tests, manufacture specifications, and Barlow's formula to predict potential failures. From the 1980s through the 2000s, operators began to use metal loss analysis to assess corrosion, starting with B31G and then Effective Area Method computer software like Remaining Strength (RSTRENG), which allows for more accurate representation to calculate predicted failure pressure.
19

Analytical methods have continued to

advance over time, becoming more precise and expanding to other types of anomalies, such as cracking and dents, allowing operators to engage in increasingly complex analysis and assessment of a pipeline's fitness for service.

19
Am. Soc. of Mech. Eng'rs (ASME), Supplement to ASME B31 Code for Pressure Piping, ASME B31G-1991,
Manual for Determining the Remaining Strength of Corroded Pipelines
(1991) (first edition as its own standard); Kiefner & Assocs. Inc.,
Validity of Standard Defect Assessment Methods for the Alliance Pipeline Operating at 80% of SMYS,
at 3-4 (Sept. 6, 2018), available at:
https://www.phmsa.dot.gov/sites/phmsa.dot.gov/files/docs/technical-resources/pipeline/gas-transmission-integrity-management/65316/validityofcorrosionassessmentsr1.pdf
(noting ASME B31G was first introduced as a supplement to B31.8 in 1984).

Today, with enhanced accuracy and data quality, computational algorithms can provide fracture mechanics, critical strain analysis, and remaining strength calculations to better predict when a defect might fail. API 579 contains three different levels of engineering calculations and analysis for each anomaly type, scalable based on the amount of data available.
20

Models are capable of overlaying multiple data inputs from different threats to provide a clearer understanding of the pipeline and potential anomalies.
21

Innovations in data processing and machine learning enable real-time algorithmic analysis of tool results, better interpreting complex signals and deformation shapes, and expediting decision-making.
22

20
American Petroleum Institute (API) & ASME, API 579-1/ASME FFS-1,
Fitness-for-Service
(4th ed., Dec. 2021) (“API 579”);
see
INGAA Integrity Management Continuous Improvement Group,
Definition and Application of Fitness for Service to Gas Pipelines
(May 31, 2012), available at:
https://ingaa.org/wp-content/uploads/2013/04/20024.pdf.

21

E.g.,
Creaform,
Pipeline Integrity Assessment Software for NFT Pipeline Inspection,
available at:
https://www.creaform3d.com/en/products/software/creaform-integrity-suite/pipeline
(discussing use of 3D analysis to show full coverage of pipeline surfaces and damages, feeding assessment calculation models).

22

See
NDT Global,
Evolving from a Leading ILI Company to a Preferred Provider of Integrity Management Solutions,
available at:
https://www.ndt-global.com/resources/news/evolving-from-a-leading-ili-company-to-a-preferred-provider-of-integrity/
(“We are leveraging machine learning and artificial intelligence techniques and use our big data platforms to improve the accuracy and reliability of the results from our inspection tools continuously. This is the key to delivering the greatest value in integrity assessments to enable proactive pipeline integrity management.”); Rosen, Comment, Docket ID PHMSA-2011-0151-0025, at 1; T.D. Williamson, Comment, Docket ID PHMSA-2017-0151-0024, at 2.

Use of 3D modelling of ILI data, including through the use of models like Plausible Profiles (Psqr), has allowed for “a data driven and more accurate probabilistic representation of corrosion features in pipelines that was not operationally feasible before the data revolution.”
23

Fracture mechanics analysis provides an avenue to consider all variables in the predicted failure of a crack or crack-like anomaly by quantifying the relationship between material properties, stresses, and crack propagation. This demonstrates that the propensity for crack failures is not based on depth alone, and depth-based crack response metrics must be overly conservative as a result.
24

Dent analysis has also undergone significant recent study and advancement. Contrary to historical practice and understanding, the latest research has shown that “dent depth alone is not a great predictor of the effect a dent can have on the fatigue life of a pipeline.”
25

API developed and released RP 1183 in 2020 to provide guidance using engineering critical assessment (ECA) to evaluate a dent's fitness for service.
26

Finite element analysis, which would not be possible without the more precise data derived from advanced ILI tools, provides the ability to simulate full-scale testing with numerical modeling.
27

23
TC Energy,
TC Energy wins Global Pipeline Award
(Nov. 17, 2021), available at:
https://www.tcenergy.com/stories/2021/2021-11-17-tc-energy-wins-global-pipeline-award/.

24

See
Vlad Semiga, BMT Fleet Technology,
Fatigue Considerations for Natural Gas Transmission Pipelines,
at 10 (June 30, 2016), available at:
https://ingaa.org/wp-content/uploads/2016/07/29846.pdf
(noting how the geometry factor is built into the equation, providing growth rate constraints that include material properties).

25
Semiga,
Fatigue Considerations for Natural Gas Transmission Pipelines,
at 65.

26
API, Recommended Practice (RP) 1183,
Assessment and Management of Pipeline Dents
(1st Ed. Nov. 2020).

27
“Due to the complexity and variability of dent shapes, dimensions, and the potential for coincident features, full-scale testing and numerical modeling (FEA) have been the two essential tools that have been deployed by the industry to assess the fundamental behavior of dents.” Aaron Dinovitzer et al., PR214-203804-R01,
Systematize 20 Years of Mechanical Damage Research,
sec. 3.4.2.6 (May 31, 2022), available at:
https://primis.phmsa.dot.gov/rd/FileGet/17097/Systematize_20_Years_of_Mechanical_Damage_Research_V2.pdf.

C. Modernization in PHMSA Regulations

PHMSA has modernized its regulations in recent years to account for many of these technological advancements. In 2019, for example, PHMSA revised its assessment requirements for gas transmission pipelines to apply to certain non-HCA locations and made similar revisions to its assessment requirements for hazardous liquid pipelines.
28

In 2022, PHMSA revised its anomaly response and evaluation requirements for gas transmission pipelines, adding detailed scheduling requirements at §§ 192.714 and 192.933 that incorporate predicted failure pressure- and strain-based criteria “to assure that anomalies are repaired before they become an immediate condition and are at or near failure.”
29

PHMSA also added analysis calculation criteria to § 192.712.
30

As explained below, PHMSA proposes to apply these concepts to the response and evaluation criteria for hazardous liquid pipelines.

28

Pipeline Safety: 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);
Pipeline Safety: Safety of Hazardous Liquid Pipelines,
84 FR 52260 (Oct. 1, 2019).

29

2022 Safety of Gas Transmission Rule,
87 FR at 52245. These modern criteria were added alongside the traditional depth-based measurements for operators who so prefer.

30
Section 192.712(c) was remanded without vacatur by the court in
INGAA
v.
PHMSA,
114 F.4d 744 (D.C. Cir. 2024) for PHMSA to reconsider the dent ECA process. Order on Pet. for Panel Reh'g,
INGAA
v.
PHMSA,
114 F.4th 744 (D.C. Cir. Dec. 10, 2024) (No. 23-1173). Section 192.712(b) and (d) for corrosion and cracks were created in the 2019 Safety of Gas Transmission Rule.

III. Advanced Notice of Proposed Rulemaking

In a May 2025 advanced notice of proposed rulemaking (ANPRM), PHMSA solicited public feedback on improving anomaly response requirements for gas and hazardous liquid pipelines.
31

Public response overwhelmingly favored modernizing these requirements to incorporate a performance-based, engineering-focused approach—one that prioritizes anomalies based on calculated predicted failure pressure, strain, and remaining life rather than one dimensional thresholds. Comments submitted by the Liquid Associations—API, the Liquid Energy Pipeline Association (LEPA), GPA Midstream Association, and the American Fuel & Petrochemical Manufacturers—note that the existing hazardous liquid anomaly response requirements are obsolete and fail to leverage over twenty years of advancement in ILI technology and data analytics.
32

Comments by the Gas Associations—the Interstate Natural Gas Association of America (INGAA), American Gas Association (AGA), and GPA Midstream Association—supported using modern anomaly evaluation, as did individual gas and hazardous liquid pipeline operators.
33

Representatives of smaller operators requested that in any modernization effort PHMSA retain the existing depth-based options, stating that engineering-based analyses can be costly and resource-intensive up-front, before reaping substantial cost-savings.
34

The Pipeline Safety Trust (PST) supported improving the clarity of response requirements but cautioned

against reducing the safety level for gas transmission IM regulations or making deregulatory changes without considering safety benefits, environmental impact, and public participation.
35

The National Association of Pipeline Safety Representatives (NAPSR) similarly cautioned not to reduce the standard of care in IM regulations, which NAPSR credited with the declining rate of incidents and accidents.
36

31

Pipeline Safety: Repair Criteria for Hazardous Liquid and Gas Transmission Pipelines,
90 FR 21715 (adv. notice May 21, 2025).

32
Liquid Associations, Comment, Docket ID PHMSA-2025-0019-0021, at 2-4 (July 21, 2025).

33
Gas Associations, Comment, Docket ID PHMSA-2025-0019-0017, at 4-5 (July 21, 2025).

34
Air Liquide Large Indus. US, L.P., Comment, Docket ID PHMSA-2025-0019-0012, at 3 (July 21, 2025); Compressed Gas Ass'n, Comment, Docket ID PHMSA-2025-0019-0009, at 5 (July 18, 2025).

35
PST, Comment, Docket ID PHMSA-2025-0019-0016, at 2 (July 21, 2025).

36
NAPSR, Comment, Docket ID PHMSA-2025-0019-0025, at 4 (Aug. 1, 2025).

The Liquid Associations and operators like Colonial Pipeline Co. (Colonial) and Marathon Pipe Line (Marathon) commented that incorporating improved evaluation methods for hazardous liquid pipelines would enable the consolidation of near-term response timelines.
37

Hazardous liquid operators also requested that PHMSA allow an ECA to respond to dents based on a detailed calculation of strain and fatigue life.
38

Commenters suggested certain changes to the criteria and evaluation methods adopted in a recent rulemaking for gas transmission lines to provide greater flexibility and to reflect modern technologies and practices, though PST cited the need to maintain the safety margins established in these new regulations.
39

37
Colonial, Comment, Docket ID PHMSA-2025-0019-0013, at 2, 7; Liquid Associations, Comment, Docket ID PHMSA-2025-0019-0021, at 49-50; Marathon, Comment, Docket ID PHMSA-2025-0019-0018, at 4-5 (July 21, 2025).

38

See, e.g.,
Liquid Associations, Comment, Docket ID PHMSA-2025-0019-0021, at 5; Colonial, Comment, Docket ID PHMSA-2025-0019-0013, at 3; Enterprise Prods. Operating LLC (Enterprise), Comment, Docket ID PHMSA-2025-0019-0015 at 4 (July 21, 2025).

39
Gas Associations, Comment, Docket ID PHMSA-2025-0019-0022, at 7; PST, Comment, Docket ID PHMSA-2025-0019-0016, at 2.

As engineering-based criteria depend on an evaluation of the anomaly, commenters suggested revisions to anomaly evaluation methods for gas transmission and that these revisions be adopted for hazardous liquid pipelines. Suggestions included explicitly approving additional metal loss and crack evaluation methods;
40

revising default toughness values based on recent research;
41

and allowing a process in part 195 to determine material properties by extending the procedures in § 192.607.
42

40
Gas Associations, Comment, Docket ID PHMSA-2025-0019-0022, at 20; Liquid Associations, Comment, Docket ID PHMSA-2025-0019-0021, at 19.

41
Gas Associations, Comment, Docket ID PHMSA-2025-0019-0022, at 10; TC Energy, Comment, Docket ID PHMSA-2025-0019-0019, at 5 (July 21, 2025).

42
Energy Transfer LP, Comment, Docket ID PHMSA-2025-0019-0020, at 18 (July 21, 2025).

IV. Discussion of the Proposal

To address concerns with the use of inconsistent or imprecise terminology in the existing regulations, PHMSA proposes to use the terms “anomaly” and “response criteria” throughout the regulations.
43

The use of these terms is consistent with ASME B31.8S and other industry sources. An anomaly is an unexamined deviation from the norm in pipeline material, coatings, or welds, which includes defects and imperfections identified upon further examination.
44

Sections 192.714 and 195.453 list “response criteria” that require response in a set time for an anomaly that meets those levels, though PHMSA has previously used the term “repair criteria” interchangeably.
45

Response refers to the action an operator takes on an identified anomaly, including remediation, to ensure safety such as a repair or temporary pressure reduction.
46

Response is completed by permanent repair, which means replacing the pipe cylinder containing the defect, removing the anomaly, or taking other actions permanently to restore pipeline serviceability.

43

See
Gas Associations, Comment, Docket ID PHMSA-2025-0019-0017, at 4-5 (noting that current requirements usage of interchangeable terminology is confusing); PST, Comment, Docket ID PHMSA 2025-0019-0016, at 1. As each are consistent terms, PHMSA does not propose defining these terms in §§ 192.3 and 195.2.

44

See
ASME, Code for Pressure Piping Supplement to ASME B31.8, B31.8S-2018,
Managing System Integrity of Gas Pipelines,
sec. 13 (2018).

45

See
PST, Comment, Docket ID PHMSA 2025-0019-0016, at 1.

46

See
ASME, B31.8S-18, sec. 7.

A. Response Schedules

Existing requirement:
Anomaly response schedules set timelines to respond to criteria based on severity. The gas response criteria are broken out by immediate, scheduled (one-year in HCAs, two-years otherwise), monitored, and “other” conditions. A schedule is repeated at § 192.933(d) for HCAs and § 192.714(d) outside of HCAs. Existing hazardous liquid response criteria at § 195.452(h) are designated as immediate, 60-day, 180-day, and “other” conditions.

Proposal:
PHMSA proposes three anomaly response categories to be used consistently between gas and hazardous liquid pipelines: (1) immediate, (2) near-term, and (3) other conditions. The time for immediate response is unchanged. PHMSA proposes to consolidate the repetitive response schedule at § 192.933 into § 192.714 to eliminate unnecessary duplication.

Discussion:
PHMSA proposes three clear and consistent anomaly response categories for parts 192 and 195: immediate, near-term, and other conditions. The deadline for responding to near-term conditions is one year in HCAs, two years otherwise. The proposed framework allows for necessary deviations based on location and commodity. It also better prioritizes remediation timelines for hazardous liquid pipelines and provides editorial clarity for gas transmission pipelines. Establishing clear benchmarks promotes public safety and compliance. The proposed revisions to the gas transmission response schedule are purely editorial and the response timelines remain unchanged. Additional information about the proposals is provided below.

PHMSA proposes to create three response categories for gas transmission and hazardous liquid pipelines. The first category, immediate response conditions, would continue to apply to anomalies that require remediation immediately upon discovery. The second category, near-term conditions, would replace the existing provisions in part 192 for one-year conditions (§ 192.933(d)) and two-year conditions (§ 192.714(d)) and in part 195 for 60-day and 180-day conditions (§ 195.452(h)). The third category, other conditions, would apply to anomalies scheduled for response prior to the next reassessment or for monitoring during the next scheduled reassessment.

Consolidating the response category for near-term conditions will eliminate unnecessary complexity and improve the efficiency of PHMSA's regulations. Currently, the regulations in part 192 and part 195 recognize four different types of comparable conditions that require a response within either 60 days, 180 days, one year, or two years. This four-tiered framework introduces unnecessary inconsistency and complexity into the regulations without producing a meaningful safety benefit. Consistent with the approach used in industry standards, PHMSA proposes to group these conditions into a single near-term category denoted as “near-term” conditions, a term which provides consistency and avoids confusion inherent in the term “scheduled conditions.”
47

47
API, RP 1160,
Managing System Integrity for Hazardous Liquid Pipelines,
sec. 9.2.3.4 (3rd ed. 2019, reaff'd Mar. 2024) (also denoting this category as “near-term”).

For near-term conditions on gas transmission lines, PHMSA proposes to

require response within one year of discovery for segments in higher risk locations (
i.e.,
HCAs) or two years of discovery for segments in lower risk locations. PHMSA proposes to create an analogous near-term category for hazardous liquid pipelines and to require a response within one year of discovery for all covered segments. PHMSA notes that industry commenters expressed strong support for consolidating the response timelines for hazardous liquid pipelines, which they characterized as unnecessarily complex.
48

PHMSA further notes that two decades of experience applying IM and progress in assessment tools indicate that operators can schedule repairs safely on a one-year basis for many anomalies.
49

A one-year response deadline strikes an appropriate balance between the need to remediate anomalies before they grow to critical dimensions, aligning with industry standards like API RP 1160 and API RP 1176,
50

and allowing operators to engage in the coordination and planning required to complete that remediation without causing unnecessary adverse impacts to customers, communities, and the environment.
51

As discussed in more detail in section IV.B.ii below, PHMSA proposes to address the risk of fatigue-related, time-dependent threats on hazardous liquid pipelines by prioritizing specific response criteria for certain immediate or near-term conditions.
52

For example, as Colonial notes, PHMSA's proposal to respond immediately to metal loss at or below a 1.1 FPR captures slightly more metal loss, while allowing operators to manage the remainder safely under the new near-term response category.
53

Adopting more stringent immediate repair criteria for metal loss, cracking, and dents, but longer timelines and engineering-based criteria for less injurious anomalies, allocates resources more efficiently on high-risk threats.

48
Liquid Associations, Comment, Docket ID PHMSA-2025-0019-0021, at 11, 49-50; Colonial, Comment, Docket ID PHMSA-2025-0019-0013, at 2; Marathon, Comment, Docket ID PHMSA-2025-0019-0018, at 4-5 (recommending consolidating the two into a single 180-day criteria).

49
Colonial, Comment, Docket ID PHMSA-2025-0019-0013, at 2 (noting that updating “response timelines for `near term' conditions is possible without impacting safety because the advances in understanding anomaly growth and failure mechanisms that have occurred since the 2001 [IM] rule allow for better prediction of pipeline failures.”).

50
API RP 1160 (recommending 270-day response of near-term conditions in “critical locations” (
i.e.,
HCAs)); API, RP 1176,
Recommended Practice for Assessment and Management of Cracking in Pipelines,
sec. 11.7.3 (1st ed. July 16, 2021, reaff'd Mar. 2024, incl. Errata 1 (Feb. 2021)) (specifying 365-day response for certain cracks).

51

See
Liquid Associations, Comment, Docket ID PHMSA-2025-0019-0021, at 11, 49-50.

52

See Pipeline Safety: Pipeline Integrity Management in High Consequence Areas,
68 FR 69778 (Dec. 15, 2003).

53
Colonial, Comment, Docket ID PHMSA-2025-0019-0013, at 8.

The third response category for other conditions applies to anomalies that can be scheduled safely for response prior to the next reassessment or that can be monitored for change during that reassessment. Currently, gas regulations contain two similar requirements at § 192.714(d)(3) and (f) designated as “monitored” and “other” conditions. Splitting these requirements has caused confusion and inconsistency. PHMSA proposes to retain the substantive requirement in a single category termed “other” conditions to be applied to both gas and hazardous liquid pipelines, located at paragraph (d)(3). This revision would require that other conditions in (d)(3) must be addressed as required by ASME B31.8S Figure 7.2.2.1, the dent reassessment interval established under the ECA, or monitored no later than the next scheduled reassessment. As PHMSA recently explained in another rulemaking proceeding, Figure 7.2.2.1 provides a sliding scale to determine response timelines based on specified minimum yield strength (SMYS) and predicted failure pressure.
54

“Other” conditions under part 195 accounts for some operational differences by directing operators to evaluate any condition not listed for immediate or near-term response that could impair pipeline integrity and schedule remediation as appropriate. API RP 1160 Section 9.2.3.6—a recognized industry practice operators must follow under § 195.452(b)—describes conditions that operators should record and monitor during the next integrity assessment, including stable manufacturing and construction conditions (provided operating conditions have not changed since the last pressure test) or conditions that do not impair pipeline integrity.
55

In both gas transmission and hazardous liquid response, monitoring at the next regular reassessment is the floor, even if the dent ECA, ASME B31.8S, or API RP 1160 imply a longer period. This is consistent with current requirements.

54

See 2022 Safety of Gas Transmission Rule,
87 FR at 52252 (discussion when Figure 7.2.2.1 was named Figure 4 in ASME B31.8S-2004).

55
API RP 1160, sec. 9.2.3.6 & fig. 6. An anomaly with a scheduled response under API RP 1160 sec. 9.2.3.6 that extends beyond the date of the next reassessment is essentially an “other” condition.

Finally, PHMSA proposes to create a single, consolidated response schedule for gas transmission pipelines at § 192.714. The intent of the proposed revision is to eliminate the duplicative requirements that are currently codified at § 192.714 (for non-HCA segments) and § 192.933 (for HCA segments) without affecting the applicable response deadlines. In other words, a one-year response deadline would continue to apply to near-term conditions on HCA segments, and a two-year response deadline would continue to apply to near-term conditions on non-HCA segments under the consolidated schedule. This revision would maintain current levels of safety as the proposed requirements are equivalent to the current response criteria. When the proposed response schedule in § 192.714 applies to covered segments in HCAs, the rigorous subpart O requirements would still apply.

B. Response Criteria

PHMSA proposes a modern, engineering-analysis-based anomaly response schedule. The modern criteria will go alongside traditional measures, accommodating smaller operators as requested.
56

PHMSA largely implemented these criteria for gas transmission lines in a 2022 final rule and proposes to complete that work and modernize the anomaly response schedule for hazardous liquid pipelines, too. The proposed rule uses calculations, including predicted failure pressure and fatigue life, to determine the proper schedule for responding to anomalies. Using these advanced analyses, operators can better “characterize the risks associated with specific” anomalies, tailor safety responses “to the characteristics and operating conditions of specific pipelines,” and make “more informed decisions about what needs to be repaired and when,” avoiding costly response to non-threats.
57

56
Air Liquide Large Indus., Comment, Docket ID PHMSA-2025-0019-0012 at 3; Compressed Gas Ass'n, Comment, Docket ID PHMSA-2025-0019-0009 at 5.

57
Liquid Associations, Comment, Docket ID PHMSA-2025-0019-0021, at 7.

Predicted failure pressure (PFP) describes the calculated maximum pressure a pipeline can withstand before a specific anomaly fails. PFP can be calculated using a remaining strength equation for metal loss or a fracture mechanics model for cracks.
58

Pipeline operation is based on the maximum pressure—maximum allowable operating pressure (MAOP) for gas or maximum operating pressure (MOP) for hazardous liquids—that is safe for operation. Response is designed to ensure predicted failure pressure cannot

fall below the maximum safe operating pressure using the failure pressure ratio (FPR). FPR is calculated as the PFP divided by the MAOP or MOP of the pipeline.
59

The result of that calculation determines how quickly an operator must repair the anomaly under PHMSA's response criteria. Risk and time-sensitivity increase as the ratio lowers approaching 1.0.

58
Modern dents are evaluated based on strain and fatigue, as discussed in section IV.C.i.

59
API 579 refers to this as “remaining strength factor,” defined as “ratio of the collapse pressure of a damaged component to the collapse pressure of the undamaged component.” API 579, sec. 1A.87.

At an FPR of 1.0, the pipeline is predicted to fail at any moment when operated at or above the MAOP or MOP (though the MAOP and MOP have built-in safety factors). An additional margin is necessary to respond before predicted failure pressure reaches MAOP or MOP (
i.e.,
FPR is 1.0) for several reasons. That margin accounts for any potential error between the operating pressure and point of failure and for any permissible temporary pressure surges.
60

It also accounts for further degradation that may occur depending on how soon an anomaly is detected after reaching the point of failure, given the variation that occurs in detecting anomalies within the reassessment cycle.
61

60

See, e.g.,
§§ 192.201(a)(2) (minimum performance standards for pressure relieving and limiting stations pegged to 110 percent of MAOP or 75 percent of SMYS, whichever is lower), 192.739(b) (inspection and test requirements for pressure limiting and regulating stations pegged to 104 percent of MAOP), and 195.406 (allowing a pipeline to operate at up to 110 percent of MOP during surges and other variations from normal operations).

61
The reassessment interval is up to five years in hazardous liquid HCAs, seven years in gas transmission HCAs, and 10 years on other gas transmission pipelines requiring assessment.

Immediate response criteria are generally set at a 1.1 FPR. At this point, the anomaly's burst pressure is within 10 percent of the maximum operating pressure, requiring immediate attention. Near-term response criteria are generally derived from the design factors in §§ 192.611 and 195.406, which results in a 1.39 FPR for Class 1 gas transmission pipelines and most hazardous liquid pipelines. To show the importance of these safety margins, consider a pipeline with a MAOP of 1,000 psig where an operator calculates a PFP of 1,390 psig for a metal loss anomaly. With a 10 percent range for tool inaccuracy, the actual burst pressure could range from 1,251 psig to 1,529 psig. Because corrosion is a time-dependent threat, the PFP will continue to decrease, which means that remediation must be scheduled before the next inspection cycle to prevent failure. This example is representative of other near-term response criteria. If an anomaly does not meet an immediate response condition but meets one of these criteria, it is operating below its intended safety margin, necessitating a scheduled response.

For gas transmission pipelines under part 192, PHMSA created a modern, engineering-based response schedule in § 192.714 in the 2022 Safety of Gas Transmission Rule. An engineering-based response schedule is supported by anomaly evaluation calculations, which PHMSA promulgated for gas transmission pipelines in § 192.712 through the 2019 and 2022 Safety of Gas Transmission Rules. In this rulemaking, PHMSA proposes completing the modern response schedule for gas and creating one to improve public safety and efficiency on hazardous liquid pipelines.

i. Gas Transmission Response Criteria

Existing requirement:
After the 2022 Safety of Gas Transmission Rule, § 192.714(d) contains an engineering-based and traditional measurement-based schedule for responding to almost every anomaly; however, there is no engineering-based immediate response criterion for cracks. Currently, immediate response is required for cracks at 50 percent wall thickness, § 192.714(d)(1)(v); preferential seam corrosion with an FPR below 1.25 in seams formed by direct current (DC) electric resistance welding (ERW), low-frequency (LF) ERW, electric flash welding (EFW), or with a longitudinal joint factor less than 1.0, § 192.714(d)(1)(iv); top-side dents with metal loss, cracking, or a stress riser, § 192.714(d)(1)(ii); and metal loss with an FPR of 1.1 and below or greater than 80 percent wall thickness, § 192.714(d)(1)(i)&(iii).
62

62
The same criteria exist as the same provisions within § 192.933(d).

Proposal:
PHMSA proposes (1) to add an immediate response criterion for cracks with an FPR of 1.1 and below, (2) to raise the immediate crack depth threshold to 70 percent wall thickness, (3) to revise the immediate response of preferential seam corrosion to an FPR of 1.1 and below, and (4) to refine the interacting dent immediate response criterion to include gouging, but to exclude non-mechanical metal loss up to 10 percent depth, focusing the criterion on excavation damage. PHMSA proposes no change to metal loss criteria.

Discussion:
To complete the gas engineering-based response schedule, PHMSA proposes slight amendments in the criteria to reflect improvements in tool technology and capability.

Crack criteria.
First, PHMSA proposes adding an immediate response criterion for cracks (or crack-like anomalies) at 1.1 FPR.
63

This provides a PFP-based immediate and near-term response criterion for each crack and metal loss anomaly on gas systems where there is currently not one for immediate crack response. PHMSA sought to adopt a similar PFP-based immediate criterion for cracks in the 2022 Safety of Gas Transmission Rule, but that provision was vacated on judicial review in
INGAA
v.
PHMSA,
114 F.4th 744 (D.C. Cir. 2024). The U.S. Court of Appeals for the District of Columbia Circuit found that PHMSA had not performed a reasoned cost-benefit analysis for the measure it selected in that final rule—immediate response of cracks with an FPR less than or equal to 1.25.
64

INGAA asserted throughout that rulemaking and ensuing litigation that a 1.1 FPR level was sufficient.
65

INGAA continues to do so, citing API RP 1176, which recommends immediate response of likely cracks with an FPR less than 1.1, with a predicted depth greater than 70 percent of nominal wall thickness, or where maximum depth exceeds the tool's sizing capabilities.
66

63
The crack criteria capture stress corrosion cracking and other cracking or crack-like anomalies.

64

See INGAA
v.
PHMSA,
115 F.4th at 752.

65
Gas Associations, Comment, Docket ID PHMSA-2025-0019-0022, at 8; AGA, API, APGA, & INGAA,
Comments on Pipeline Safety: Repair Criteria, Integrity Management Improvements, Cathodic Protection, Management of Change, And Other Related Amendments Final Rule,
Docket ID PHMSA-2011-0023-0451 at 4-5, 42-43 (June 6, 2018); API & INGAA,
Petition for Reconsideration of Gas Transmission Final Rule (RIN 2),
Docket ID PHMSA-2011-0023-0641 at 7-10 (Sept. 23, 2022).

66
API RP 1176, sec. 11.7.2; Gas Associations, Comment, Docket ID PHMSA-2025-0019-0022, at 8.

PHMSA finds that a 1.1 FPR level is appropriate for immediate response when using advanced engineering calculations. In formulating this proposal, PHMSA reviewed pipeline safety consensus standards, recommendations, and research; received nearly a decade of public comment on the topic; and benefited from extensive advice from the Gas Pipeline Advisory Committee (GPAC) in public fora. Increased ILI data accuracy, paired with using traceable, verified, and complete records, gives PHMSA confidence setting a 1.1 FPR level for immediate crack response. In the past, PHMSA was concerned that tool tolerances could swallow a 1.1 FPR safety factor, leading the Agency to offer a 1.25 FPR with tool tolerance built in.

67

However, for all other anomalies, operators must add tool tolerance to the FPR. This approach incentivizes operators to deploy more precise tools.
68

Proposed § 192.712(a) addresses this concern by requiring that a qualified subject matter expert perform the analysis, providing additional assurance that the analyses will be performed correctly to include tool tolerance and other uncertainties.

67

See 2022 Safety of Gas Transmission Rule,
87 FR at 52248; GPAC,
All GT Voting Slides,
Docket ID PHMSA-2011-0023-0656 at 49 (GPAC vote of Mar. 28, 2018) (vote recommending that for crack

anomalies PHMSA “consider 1.1 x MAOP for immediate conditions after tool tolerance has been field verified and applied”).
See also
INGAA & API,
Petition for Reconsideration,
Docket ID PHMSA-2011-0023-0644 at 10 (Sept. 23, 2022) (requesting that PHMSA “amend the language modify the threshold for requiring immediate repair of a crack or crack-like anomaly to be 1.1 times MAOP after tool tolerance is verified”).

68

See GPAC Transcript March 28, 2018,
Docket ID PHMSA-2016-0136-0040 at 72-73 (2018) (Andy Drake) (noting that too high of an immediate response level would discourage proactive safety behavior and result in “a gamesmanship thing going on where people don't look at tool tolerance, they don't look at colony length, they're not doing the things you want them to do so that they don't have to dig up half of the earth”).

An FPR of 1.1 “is an appropriate level if [an operator is] doing this correctly with tool tolerances, colony length considerations, and” other considerations accounted for, and “[t]hat's actually better engineering.”
69

The technical advisors on the GPAC previously recommended that PHMSA “consider 1.1” as the immediate crack level.
70

API RP 1176 for assessing cracks recommends this immediate response level, too.
71

EMAT tools for cracks have advanced significantly through additional deployment and improvement in recent years, increasing the reliability of ILI-based assessment and reducing concerns expressed about over-conservatism.
72

Cracks with slightly higher FPRs (
e.g.,
1.25) will fall under the existing near-term response condition, providing sufficient margin for operators to respond before an integrity threat arises.

69

GPAC Transcript March 28, 2018,
Docket ID PHMSA-2016-0136-0040 at 73 (2018) (Andy Drake).

70
Gas Associations, Comment, Docket ID PHMSA-2025-0019-0022, at 8 (recommending that an FPR of 1.1 “was a sufficient and a technically supported standard” for the immediate response to cracks); GPAC,
All GT Voting Slides,
Docket ID PHMSA-2011-0023-0656 at 49. Liquid Associations and operators made similar arguments in the hazardous liquid context, as discussed there.

71
API RP 1176, sec. 11.7.2. Though the FPR and depth criteria are consistent with those in API RP 1176, PHMSA does not propose to incorporate that standard by reference for these purposes. Specifically, the likelihood factors for cracking and time-dependence in 11.6.3 and 11.6.4 are highly subjective as written.

72

See
Rosen,
RoCD EMAT-C Service: In-line High-Resolution Detection and Sizing of Axial Cracks
(2024),
https://contenthub.rosen-group.com/api/public/content/7e9f40578f924917a4403fa7fc5ba41e?v=0071d845
(EMAT tool detecting pipe body crack sizing with 90 percent certainty to one millimeter); Colonial, Comment, Docket ID PHMSA-2025-0019-0013, at 7 (noting that they observed crack tools with 480 sensors in 2000, which has increased to 1028 on today's tool).

Second, PHMSA proposes complementary depth-based immediate response criterion for cracks at depths greater than 70 percent of pipe wall thickness. The existing 50 percent crack depth threshold does not reflect current technical understandings and should align with established industry standards and recent research.
73

API RP 1176 treats cracks deeper than 70 percent of nominal wall as immediate conditions, while those between 50 and 70 percent require a 365-day response.
74

The study
Fatigue Considerations for Natural Gas Transmission Pipelines
found that some cracks between 50 and 70 percent depth could remain in a typical gas transmission pipeline for at least 100 years before failing.
75

This shows that operators can manage cracks safely with modifications to operating characteristics depending on the crack properties. Requiring more cracks to be treated as immediate response conditions than is necessary results in unnecessary costs and leads to “adverse environmental, landowner, and pipeline operational impacts that outweigh the resulting safety benefit.”
76

73

See
Gas Associations, Comment, Docket ID PHMSA-2025-0019-0022, at 6.

74
API RP 1176;
see
Gas Associations, Comment, Docket ID PHMSA-2025-0019-0022, at 7 (noting that API RP 1176 supports a near-term response for cracks between 50 and 70 percent wall thickness).

75
Semiga,
Fatigue Considerations for Natural Gas Transmission Pipelines,
at 53 (“Operating at less severe cyclic severities (
i.e.,
lower SSIs) allows for deeper and longer flaws to exist in the pipeline while still meeting the 100-year fatigue life criterion.”);
see
Gas Associations, Comment, Docket ID PHMSA-2025-0019-0022, at 7.

76
Gas Associations, Comment, Docket ID PHMSA-2025-0019-0022, at 5.

PHMSA proposes to shift the 50 percent crack depth level to a near-term condition. This ensures that 50 percent through-wall cracks receive near-term response in one to two years. Immediate response at 70 percent, with near-term response above 50 percent, strikes the proper balance for safety by ensuring that operators address more imminent threats while retaining a degree of planning for near-term cracks.

ERW immediate criterion.
Third, PHMSA proposes revising from an FPR of 1.25 to an FPR of 1.1 the immediate response criterion for metal loss preferentially affecting a detected longitudinal seam weld formed by DC-ERW, LF-ERW, EFW, or with a joint factor less than 1.0.
77

This criterion addresses selective seam weld corrosion, which can behave like a crack defect. PHMSA proposes to revise the FPR criterion to align with those adopted for cracks. Because these seam types are particularly susceptible to selective seam weld corrosion, several existing provisions address the assessments for pipe with these seams. Section 192.712(d) specifies that analysis must be analyzed using a fracture mechanics model proven appropriate to the pipe and seam weld properties, while § 192.917(e)(4) in IM further requires assessments on these types of pipes use tools proven capable of assessing seam threats. The proposed clarifying of the requirement for a subject matter expert to perform any analysis under § 192.712 further strengthens the analysis and assures it considers all variables. Operators must also prioritize assessing pipe with these seams under § 192.917(e)(4) to ensure the prompt detection of potential anomalies, reducing the risk that an anomaly may have existed at threatened levels for some time.
78

The obligation to prioritize assessments using analysis models proven appropriate to the seam properties provide an adequate margin of safety for vintage seam types, making an additional safety factor in the response criterion unnecessary.

77

See
Gas Associations, Comment, Docket ID PHMSA-2025-0019-0022, attach. 2 at 8 (recommending this change).

78
In addition, § 192.917(e)(3) requires that an operator can 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.

Dents.
Fourth, PHMSA proposes to clarify the immediate response criterion in § 192.714(d)(1)(ii) for top-side dents that have interacting threats of metal loss, cracking, or a stress riser.
79

This criterion for top-side dents is intended to guard against excavation and unrestrained mechanical damage. Top-side dents are more likely to be caused by excavation damage and be unrestrained, while bottom-side dents are more likely to be caused by an object, like a rock, that remains in place and keeps the dent from shifting under fatigue.
80

But the existing criterion does not reflect this concern precisely as it also requires response to dents with interacting metal loss caused by ordinary corrosion, which is a less

pressing threat.
81

That is not the intended effect, as an accelerated response is justified for mechanical damage, not ordinary corrosion.

79

See
§ 192.933(d)(1)(ii).

80
Unrestrained dents can be at higher risk from increased fatigue and strain because the dent size later can “re-round” and re-form upon fluctuations in pressure, and unrestrained dent shapes at pressure can be underpredicted. Arnav Rana et al., BMT Canada Ltd
., Improve Dent/Cracking Assessment Methods,
at 55 (PRCI May 30, 2022),
https://primis.phmsa.dot.gov/rd/FileGet/17090/Improve_Dent_Cracking_Assessment_Methods.pdf.

81
Gas Associations, Comment, Docket ID PHMSA-2025-0019-0022, at 38 (noting that the existing criterion requires remediation of many dents with non-injurious metal loss).

To focus the criterion on mechanical damage and other higher risk threats, PHMSA proposes to exclude corrosion-related metal loss that does not exceed 10 percent depth. PHMSA preliminarily finds that a 10 percent threshold is appropriate—though some operators recommended applying a 20 percent threshold—because of the variability in distinguishing between gouging and other mechanical damage from corrosion.
82

A 10 percent threshold ensures that operators will not invest unnecessary resources in addressing dents with superficial corrosion, while minimizing the risks of misclassifying interacting gouges or mechanical damage.

82

See
Liquid Associations, Comment, Docket ID PHMSA-2025-0019-0021, at 16, 22-25 (citing Matt Romney et al.,
The Power to Know More About Third Party Gouging,
(Pipeline Tech. Conf. 2022)). One report found that ILI vendors had an average gouge probability of detection of 0.81 and a probability of identification of 0.61. Sanjay Tiku et al., BMT Canada Ltd., PR-214-203805,
Performance Evaluation of ILI Systems for Dents and Coincident Features,
at 55 (PRCI Mar. 6, 2024), available at:
https://primis.phmsa.dot.gov/rd/FileGet/19308/693JK31910014POTA-_Validate_In-Line_Inspection_(ILI)_Capabilities_to_Detect_Characterize_Mechanical_Damage-_FR.pdf.

Consistent with the focus on mechanical and excavation damage, PHMSA proposes to add gouging as a specified interacting threat.
83

“Gouging” is a mechanical form of metal loss (as opposed to corrosion) that removes metal mechanically.
84

83

See
Gery Wilkowski et al., Stress Eng'g Servs., Inc., PRCI L51705,
Cyclic Pressure Fatigue Life of Pipelines with Plain Dents, Dents with Gouges, and Dents with Welds,
(June 1, 1994) (concluding that “gouge depth has a significant impact on fatigue life. Unground gouges whose depth is more than 10[ percent] of the wall cannot be counted on to have any fatigue life.”).

84
Gouging in a dent is itself a stress riser and significantly raises the risk of cracking, these factors decrease the fatigue life of a dent with a gouge.

General.
Throughout § 192.714(d)(2), the near-term response FPRs are tied to the design factor and involve the class location of the pipeline where the anomaly is located. In the recently issued Class Location Change Final Rule, PHMSA provided an FPR for operators to use as part of the IM alternative for eligible Class 3 segments.
85

PHMSA added that FPR because PFP is based on the original design of the pipe, which varies for eligible Class 3 segments depending on the class location at the time of installation. To create a unified response schedule for all gas transmission lines, PHMSA proposes moving the FPR for eligible Class 3 segments from § 192.611(a)(4)(iii)(C) to § 192.714.

85
Section 192.611(a)(4)(iii)(C);
Pipeline Safety: Class Location Change Requirements,
91 FR 1608, 1640 (Jan. 14, 2026).

PHMSA also proposes certain editorial revisions to the gas response section. PHMSA has restructured the section to avoid duplication in revisions that are not intended to impart substantive changes. For example, PHMSA proposes centralizing FPR criteria and references to ECA provisions, rather than repeating the same FPR for each anomaly. These changes should provide additional clarity to the regulations and increase operator compliance.

ii. Hazardous Liquid Response Criteria

Section 195.452 contains a response schedule for hazardous liquid pipelines that has not been amended since the adoption of the IM regulations in the early 2000s. PHMSA proposes to create a more modern response schedule that combines engineering-based metrics with existing depth-based measurements. Though largely modeled on the response schedule for gas transmission lines, the proposal accounts for the unique characteristics of hazardous liquids where necessary.

PHMSA proposes locating the updated hazardous liquid response schedule in a new section, § 195.453, within the IM regulations. Proposed § 195.453 would incorporate many of the editorial revisions discussed above for gas transmission lines to provide consistency in the response schedule for hazardous liquid pipelines under the IM program. That consistency should aid operators, regulators, and other interested stakeholders in evaluating, monitoring, and making decisions about pipeline repairs.
86

86

See
Gas Associations, Comment, Docket ID PHMSA-2025-0019-0022, at 26-27.

1. Cracks

Existing requirement:
The IM regulations treat “[a] potential crack indication that when excavated is determined to be a crack” as a 180-day condition, § 195.452(h)(iii)(G).

Proposal:
PHMSA proposes to treat cracks with an FPR of 1.1 and below or that are through more than 70 percent of the remaining wall thickness as immediate response conditions. PHMSA proposes to treat cracks with an FPR of 1.39 and below or with a depth above 50 percent as near-term response conditions.

Discussion:
The response schedule in the existing IM regulations does not include any explicit criteria for cracks that require an immediate response. As the Liquid Associations note, “[i]n recent years, operators have deployed advanced ultrasonic crack detection tools to find cracks in the pipe body and longitudinal seam, created calculation methods for cracks, and learned which crack-like features warrant immediate repair.”
87

Drawing on that experience, PHMSA proposes to categorize cracks at levels of 1.1 FPR and 70 percent depth as immediate response conditions. These two criteria align with API RP 1176, a recommended practice on the
Assessment and Management of Cracking in Pipelines,
and industry comments submitted in response to the ANPRM.
88

Moreover, as Enterprise explains in its comments, EMAT tools have good sensitivity and resolution for identifying and sizing cracks up to 70 percent wall thickness. Adding the proposed crack criteria to the list of immediate response conditions will capitalize on the latest EMAT technology and improve pipeline safety by providing a “necessary safety margin to ensure” safe repair.
89

Several other operators expressed support for including these crack thresholds in the immediate response category.
90

87
Liquid Associations, Comment, Docket ID PHMSA-2025-0019-0021, at 10.

88
API RP 1176, sec. 11.7.2 (recommending these levels as providing a “necessary safety margin to ensure” safe repair and also recommending immediate response of cracks predicted to interact with a dent, which are addressed by PHMSA in a dent criterion);
see
Enterprise, Comment, Docket ID PHMSA-2025-0019-0015 at 10-11 (encouraging adoption of 1.1 FPR and a 70 percent wall thickness immediate response conditions to provide necessary safety margin on cracks and align with API RP 1176).

89
Enterprise, Comment, Docket ID PHMSA-2025-0019-0015 at 10-11;
see
API RP 1176.

90

See
Liquid Associations, Comment, Docket ID PHMSA-2025-0019-0021, at 49 (noting these measures match operator data and evidence outlined in API TR 1190); Colonial, Comment, Docket ID PHMSA-2025-0019-0013, at 22; Marathon, Comment, Docket ID PHMSA-2025-0019-0018, at 5 (recommending incorporating API RP 1176 by reference). Though consistent with criteria in API RP 1176, PHMSA does not propose to incorporate that standard by reference for these purposes as the likelihood factors for cracking and time-dependence are subjective.

PHMSA proposes to use a 1.39 FPR level in the near-term response category for cracks. This threshold is consistent with the design factor in § 195.106 for most pipe and the approach used in the 2022 final rule for gas transmission lines. Though some hazardous liquid operators suggested that pipelines with an FPR of 1.25 or less are unlikely to fail within one year based on research published by the Pipeline Research Council International (PRCI), the

commenters did not provide that research to PHMSA for review.
91

API RP 1160 recommends near-term response within 270 days for anomalies with an FPR below 1.25, and the proposed 1.39 FPR level accounts for the additional quarter of a year provided for its near-term response.
92

PHMSA recognizes that API RP 1176 recommends response within 365-days for cracks below a 1.25 FPR or exceeding 50 percent depth
93

and will consider further publicly submitted information on the appropriate FPR measure for near-term response of cracks and metal loss.

91
Liquid Associations, Comment, Docket ID PHMSA-2025-0019-0021, at 20.

92
API RP 1160, sec. 9.2.3.4.

93
API RP 1176, sec. 11.7.3.

As a corollary depth measurement, PHMSA proposes near-term response for cracks at 50 percent or more of wall thickness.
94

The
Study on Reliability of In-ditch NDE for SCC Anomalies
illustrates declining
in situ
examination accuracy when depth exceeds 50 percent, supporting the need for near-term response.
95

94

See
API RP 1176, sec. 11.7.3.

95
Jason Van Velsor & Scott Riccardella, Structural Integrity Assocs., Inc., PR-335-143705-R01,
Study on Reliability of In-ditch NDE for SCC Anomalies,
at 35 (PRCI June 11, 2018);
see
API RP 1176, sec. 11.7.3.

2. Metal Loss

Existing requirements:
The IM regulations for hazardous liquid pipelines require immediate response for metal loss greater than 80 percent of nominal wall thickness, § 195.452(h)(4)(i)(A), or where the remaining strength shows the predicted burst pressure is less than the MOP (
i.e.,
FPR below 1.0), § 195.452(h)(4)(i)(B). In addition, the IM regulations prescribe an 180-day deadline for responding to the following metal loss conditions, § 195.452(h)(4)(iii):

• a calculation of the remaining strength of the pipe shows operating pressure is less than the established maximum operating pressure at the anomaly location,

• predicted metal loss greater than 50 percent wall thickness in an area of general corrosion,

• predicted metal loss greater than 50 percent wall thickness at a pipeline crossing, or in areas of widespread circumferential corrosion or that could affect a girth weld,

• any indication of corrosion of or along a longitudinal seam weld, and

• a gouge or groove greater than 12.5 percent of the nominal wall.

Proposal:
PHMSA proposes to make metal loss with an FPR of 1.1 and below an immediate response condition, while retaining the 80 percent depth criterion. For near-term response, PHMSA proposes to include general metal loss with an FPR of 1.39 and below, to limit the 50 percent depth criterion to localized pitting, and to focus the longitudinal seam criterion on preferential metal loss. PHMSA proposes no change to the gouge or grove criterion.

Discussion:
PHMSA proposes to include corrosion at 1.1 FPR and below as an immediate response condition. The current threshold at MOP is outdated and introduces unnecessary risk, particularly for time-dependent anomalies like metal loss, by deferring response until the remaining strength of the pipeline coincides with the highest allowable operating pressure. PHMSA adopted the MOP threshold before the use of engineering analysis in determining anomaly response became standard practice. Modern, strain-based response criteria incorporate a safety factor, both to ensure that an operator responds before PFP reaches MOP and to account for temporary surges above MOP that are permitted under § 195.406. Adding a safety factor is particularly appropriate given the longer time being permitted for near-term response to metal loss anomalies at less critical dimensions, as Colonial notes, and the cost-savings and other benefits from the longer near-term response timeline outweighs the addition of a slightly more immediate response.
96

96
Colonial, Comment, Docket ID PHMSA-2025-0019-0013, at 8.

A 1.1 FPR is reasonable for immediate response to metal loss on hazardous liquid pipelines. API RP 1160 treats metal loss with an FPR below 1.1 as requiring immediate response,
97

and at least one operator, Colonial, applies the same immediate response threshold for metal loss on its hazardous liquid system.
98

Gas regulations also require immediate response to metal loss at a 1.1 FPR, and there is no technical reason for hazardous liquid response requirements to be less protective.

97
API RP 1160, sec. 9.2.3.3. This excludes tool tolerance, which PHMSA will require.

98
Colonial, Comment, Docket ID PHMSA-2025-0019-0013, at 8 (noting that there is conservatism built-in to the remaining strength models but it would require “aggressive” defect growth rates “identified through multiple ILI run results comparisons and other data integration”).

Next, PHMSA proposes to retain the immediate response requirement for metal loss greater than 80 percent of nominal wall thickness. No comments from the May 2025 ANPRM recommended changing that criterion, and the reliability of inspection tools and remaining life models diminishes at such high levels of wall loss. The 80 percent threshold is consistent with industry standards, such as API RP 1160 and ASME B31G-2023, which cautions that “due consideration shall be given to the accuracy of measurements and effective corrosion rates when the depth of metal loss exceeds 80 percent of the actual pipe wall dimension.”
99

99
API, RP 1160 sec. 9.2.3.3; ASME, Supplement to ASME B31 Code for Pressure Piping, B31G-2023,
Manual for Determining the Remaining Strength of Corroded Pipelines,
at 1, 19 (2023).
See also
ASME, Supplement to ASME B31 Code for Pressure Piping, B31G-1991,
Manual for Determining the Remaining Strength of Corroded Pipelines,
Fig. 1-2 (1991) (requiring repair above 80 percent depth).

PHMSA proposes three changes in the near-term response category. First, PHMSA proposes a general 1.39 FPR threshold for metal loss, consistent with the level for cracks and for reasons explained in section IV.B.ii.1 above. The 1.39 FPR threshold is appropriate considering the additional time afforded to respond compared with the existing 180-day criterion, though PHMSA welcomes comments with technical study or data on the appropriateness of near-term response at 1.25 FPR.

Second, PHMSA proposes narrowing the general 50 percent criterion to apply only to localized pitting. The 1.39 FPR criterion addresses the failure risk for most metal loss anomalies. But, as Marathon notes, aggressive pitting with complex corrosion can cause pinhole leaks that pass an FPR criterion.
100

The proposal addresses that threat by focusing the existing 50 percent wall thickness criterion on localized corrosion pitting.

100
Marathon, Comment, Docket ID PHMSA-2025-0019-0018, at 4 (recommending retaining the existing 50 percent depth criterion as it applies to localized pitting).

Third, PHMSA proposes to limit the near-term response criteria to corrosion that preferentially affects a susceptible longitudinal seam, including the heat-affected zone. This proposal aligns with the gas transmission response criteria. It received broad support in the comments submitted in response to the ANPRM, with commenters noting that the existing criterion is overly broad by requiring remediation of any corrosion that coincides with a longitudinal seam.
101

Preferential seam weld corrosion is different than ordinary corrosion coinciding with a seam, and

modern ILI tools are capable of recognizing that distinction.
102

By focusing on preferential longitudinal seam weld corrosion, the proposed amendment will avoid unnecessary excavations and response to superficial indications of corrosion that operators know are non-injurious.
103

Indeed, Energy Transfer estimates that it repairs two to three hundred non-critical seams annually due to this overbreadth.
104

PHMSA's proposal allows operators to treat coincidental seam weld corrosion the same as any other metal loss anomaly, ensuring safety while avoiding unnecessary excavation. PHMSA notes that the proposal does not include an FPR threshold and requires near-term response for all anomalies preferentially affecting longitudinal seams. The absence of an FPR threshold, which is included in the comparable provision for gas transmission lines, is necessary to account for the accelerated fatigue rates that are generally experienced on hazardous liquid pipelines.

101
API & LEPA, Comment, Docket ID DOT-OST-0025-0026-0874 at 10 (May 5, 2025) (recommending to focusing the criteria on seams known to be potentially injurious, consistent with the gas requirement); Energy Transfer, Comment, Docket ID PHMSA-2025-0019-0020, at 8 (July 21, 2025) (recommending adopting the seam criterion similar to gas); Colonial, Comment, Docket ID PHMSA-2025-0019-0013, at 9-10 (similar, though suggested a selective seam weld corrosion criterion separate from general PFP criterion, as on gas).

102
Colonial, Comment, Docket ID PHMSA-2025-0019-0013, at 8 (noting that new ILI tools are better able to find these seam defects).

103

See
API & LEPA, economic comment, Docket ID PHMSA-2025-0019-0027, at table 1 (Dec. 3, 2025) (supplemental comments representing nearly half of industry estimated quantified cost savings and suggesting substantial cost savings by focusing this requirement on injurious seams); GPA Midstream Ass'n, Comment, Docket ID PHMSA-2025-0019-0029 (Dec. 8, 2025) (supporting API & LEPA economic comment).

104
Energy Transfer, Comment, Docket ID PHMSA-2025-0019-0020, at 8.

PHMSA is not proposing any change to the 12.5 percent gouge or groove criteria. Though the Liquid Associations omitted the term “groove” from their recommended regulatory text, they provided no reasoning to support that change in approach.
105

105
Liquid Associations, Comment, Docket ID PHMSA-2025-0019-0021, at 17.

3. Dents

Existing requirement:
Immediate response is required under the IM regulations for top-side dents (a) with any indication of metal loss, cracking, or a stress riser or (b) that exceed 6 percent depth, § 195.452(h)(4)(i). The IM regulations require a 60-day response for bottom-side dents with any indication of metal loss, cracking, or a stress riser, or top-side dents exceeding 3 percent depth, § 195.452(h)(4)(ii). The IM regulations require an 180-day response for dents (a) greater than 2 percent depth that affect pipe curvature at a girth weld or longitudinal seam weld, (b) on the top-side that are greater than 2 percent depth, or (c) on the bottom-side that are more than 6 percent depth, § 195.452(h)(4)(iii).

Proposal:
PHMSA proposes to require an immediate response for dents interacting with metal loss, or for dents with cracking, gouging, or a stress riser regardless of orientation, except non-mechanical metal loss that does not exceed 10 percent depth. PHMSA proposes to require a near-term response for each of the existing 180-day dent conditions. Consistent with the requirements for gas transmission lines, PHMSA proposes to allow an operator to use an ECA process as an alternative for managing each of these dent conditions.

Discussion:
First, PHMSA proposes to require an immediate response for dents with interacting features related to mechanical damage regardless of orientation. This proposal combines the existing immediate response requirements for top-side interacting dents and accelerates the existing 60-day criterion for bottom-side interacting dents. PHMSA intended the top- and bottom-side distinction to capture where excavation or mechanical damage is likely to occur, but operators can now distinguish mechanical damage and gouging features with dents from less injurious features. Delaying repair of a bottom-side dent known to interact with injurious gouging or mechanical damage is not justified on a hazardous liquid pipeline subject to fatigue-related threats.
106

These interacting threats requiring immediate response are cracking, mechanical metal loss, gouging, and stress riser. PHMSA explains the threat of excavation and mechanical damage from interacting features in section IV.B.i above. The exclusion for metal loss not caused by mechanical damage (that is still below 10 percent) applies equally to hazardous liquid pipelines.

106

See
Liquid Associations, Comment, Docket ID PHMSA-2025-0019-0021, at 24 (citing Matt Romney et al.,
The Power to Know More About Third Party Gouging,
(Pipeline Tech. Conf. 2022)).

Second, PHMSA proposes to retain top-side dents exceeding six percent depth in the immediate response category and to include bottom-side dents exceeding six percent depth in the near-term response category. Despite one commenter recommending immediate response for all six percent dents, the risk of a new dent indication, though serious, is not universal.
107

A new bottom-side dent discovered during a baseline assessment is likely construction-related, a risk addressed by the interacting dent criterion.

107
Colonial, Comment, Docket ID PHMSA-2025-0019-0013, at 10.

Third, PHMSA proposes to retain each of the existing criteria listed for 180-day response in the near-term response category. The top- and bottom-side dent distinction remains relevant as the location affects the likelihood of whether the dent is restrained or unrestrained. The top-side two percent depth criterion adequately captures, and subsumes, the existing three percent dent requirement in the 60-day response category. Operators can respond to three percent dents safely in one year as a near-term condition. Finally, PHMSA proposes adding helical seams to the criterion for two percent dents that affect a girth weld or longitudinal seam weld, as they share identical risks.
108

108

See
API RP 1183, sec. 6.5.1.3.

These are minor changes for dent response. All existing 180-day dent conditions would remain in the proposed near-term response category. Commenters did not generally suggest significant changes to the near-term criteria for dents.
109

The proposal effectively takes two of the current 60-day dent criteria and, based on severity, assigns one (bottom-side interacting dent) as an immediate condition and the other (three percent dents) as a near-term condition. The proposal also allows operators to use an ECA process to set an alternative response schedule for all dents.
110

109

See
Gas Associations, Comment, Docket ID PHMSA-2025-0019-0022, attach. 2 at 13.

110

See
Liquid Associations, Comment, Docket ID PHMSA-2025-0019-0021, at 5; Colonial, Comment, Docket ID PHMSA-2025-0019-0013, at 3; Enterprise, Comment, Docket ID PHMSA-2025-0019-0015 at 4.

C. Anomaly Evaluation

Section 192.712 contains anomaly evaluation methods for metal loss, dents, and cracks. These methods require operators to conduct engineering-based calculations in determining a modern response schedule. PHMSA proposes to make select revisions to § 192.712, to add a dent ECA provision at § 192.712(c), and to promulgate a similar regulation for hazardous liquid pipelines at § 195.415.

i. Anomaly Evaluation for Dents by the Dent ECA

Existing Requirement:
In 2022, PHMSA issued requirements at § 192.712(c) establishing procedures for gas operators to determine alternative dent response timelines using an ECA. INGAA filed a petition for judicial review challenging that regulation, and the U.S. Court of Appeals for the District of Columbia Circuit (D.C. Circuit) subsequently remanded § 192.712(c) to PHMSA for further consideration to address certain deficiencies in the rulemaking process.
111

No dent ECA

process is yet included in the part 195 regulations for hazardous liquid pipelines.

111

See
Order on Pet. for Panel Reh'g,
INGAA
v.
PHMSA,
114 F.4th 744 (D.C. Cir. Dec. 10, 2024) (No.

23-1173);
id.
at 753.
See also Pipeline Safety: Safety of Gas Transmission Pipelines: Repair Criteria, Integrity Management Improvements, Cathodic Protection, Management of Change, and Other Related Amendments: Corrections to Conform to Judicial Review,
90 FR 3713, 3714 (Jan. 15, 2025).

Proposal:
PHMSA proposes to add a dent ECA process at §§ 192.712(c) and 195.415(c) to allow operators to establish alternative response timelines for dent criteria under §§ 192.714 and 195.453.

Discussion:
As a result of the significant advancements in pipeline technology that have occurred in recent years, operators can use ECA to model the characteristics of a dent with greater accuracy, producing strain and fatigue analyses that can be used to calculate the remaining life of a dent.
112

The traditional criteria for responding to dents only account for general characteristics such as depth, size, and location. Fatigue is not considered, which makes the traditional criteria overly conservative from an anomaly response perspective, particularly when an operator is willing to conduct an ECA.
113

112
These include profile, geometry, strain sharpness and curvature, potential interacting threats, and whether a dent is restrained or unrestrained.

113

See
Janine Woo,
Integrity Assessment of Dents in Pipelines Using Finite Element Analysis and Artificial Neural Networks,
at 2 (2019), available at:
https://ualberta.scholaris.ca/items/2e902116-cadb-4e17-a4c2-9a81ae81bde8
(noting several situations where dent criteria failed to screen injurious dents); Jian Zhao et al.,
Standards and Methods for Dent Assessment and Failure Prediction of Pipelines,
Petroleum Sci. Vol. 19, 3029, at 3035 (Oct. 10, 2022).

For these reasons, PHMSA proposes to allow operators to perform an ECA to establish an alternative response schedule for dents that would otherwise fall into the immediate or near-term response category.
114

Commenters expressed overwhelming support for this concept. “The ability for operators to use an ECA to set an alternate timeline for responding to dents, which does not increase safety risk, can have great benefit to operators.”
115

114

See
TC Energy, Comment, Docket ID PHMSA-2025-0019-0019, at 18 (“ECAs are a technically sound and appropriate method for evaluating dents in many scenarios” and “allow for a more detailed, physics-based understanding of strain behavior, material response, and potential crack presence”).

115
Colonial, Comment, Docket ID PHMSA-2025-0019-0013, at 15;
see
AGA & API,
Letter,
Docket ID PHMSA-2011-0023-0781 (Sept. 20, 2024) (noting that PHMSA's ECA allows gas operators to “prioritize repairs and maintain gas deliverability” without impairing public safety or requiring that “operators expend additional resources to making repairs on piping that can be showing (through engineering analysis) to not be a threat”); Energy Transfer, Comment, Docket ID PHMSA-2025-0019-0020, at 6 (“Repair criteria for hazardous liquid pipelines that could affect HCAs should be updated to allow dent-strain engineering analysis to evaluate dents and determine whether the pipe is at risk of failure.”); Liquid Associations, Comment, PHMSA-2025-0019-0021, at 6 (requesting that PHMSA amend the hazardous liquid response criteria “to also allow operators the option to apply modern [ECA] methods to determine if dents are a threat to pipeline integrity”); TC Energy, Comment, Docket ID PHMSA-2025-0019-0019, at 18 (supporting § 192.712(c) as “a solid foundation for evaluating dents and mechanical damage anomalies on gas transmission pipelines”).

More accurate results and information can be obtained by following an approved ECA process, allowing operators to focus scarce resources on responding to dents that present a true integrity threat and avoiding unnecessary operations and maintenance activities and service disruptions. The ECA process also provides a level of safety that meets or exceeds the general depth measurements used in the traditional approach and results in significant cost savings (even considering upfront costs).
116

For example, one operator found that 29 of 31 dents analyzed with level 3 FEA had a remaining life of 25 years or more, proving them safe.
117

Another expects that more than half of the 251 dents excavated over the past decade under the response criteria did not present an integrity threat, so the ECA would allow them over $10 million in cost savings.
118

In its analysis of § 192.712(c), INGAA stated that a dent ECA process would reduce around 572 unnecessary excavations per year, saving even just a sampling of its gas transmission member-operators about $85.8 million in repair costs.
119

116
AGA & API,
Letter,
Docket ID PHMSA-2011-0023-0781 at 2 (noting that these engineering analyses “allow operators to be precise in how repairs are identified and prioritized, leading to more thoughtful and sophisticated approaches to pipeline safety, not only in [HCAs] but across [ ] pipeline systems more broadly”).

117
API & LEPA, economic comment, Docket ID PHMSA-2025-0019-0027 at 13.

118
Colonial, Comment, Docket ID PHMSA-2025-0019-0013, at 15.

119
Pet'r's Unopposed Pet. for Panel Reh'g at 53,
INGAA
v.
PHMSA,
114 F.4th 744 (D.C. Cir. Oct. 15, 2024) (No. 23-1173).

PHMSA proposes a dent ECA process at §§ 192.712(c) and 195.415(c) for gas and hazardous liquid pipelines that is substantially similar to the approach used in the 2022 Safety of Gas Transmission Rule.
120

With slight differences accounting for the commodities, PHMSA expects that the proposal similarly is appropriate for hazardous liquid pipelines. Edits provide clarity regarding acceptable procedures and improve structure without substantive difference intended.
121

The ECA is available for dents less than 10 percent deep, which is consistent with an original requirement within § 192.712(c)(8) (2022), as depths exceeding this level introduce too much uncertainty.
122

Conversely, “[t]esting has shown that plain dents (regardless of shape) with depths up to 10 percent of the pipe diameter (without coincidental metal loss, weld, or crack features) have the same failure pressure as plain line pipe,” making them well-suited for the ECA.
123

120

2022 Safety of Gas Transmission Rule,
87 FR at 52249-50, 52271. The Gas Pipeline Advisory Committee unanimously endorsed that approach during the rulemaking process. GPAC,
All GT Voting Slides,
Docket ID PHMSA-2011-0023-0656 at 47; PHMSA,
GPAC Meeting Slides March 26 to 28, 2018,
Docket ID PHMSA-2011-0023-0657 attach. 2 at 147-50.

121

See
Gas Associations, Comment, Docket ID PHMSA-2025-0019-0022, at 3 (expressing uncertainty and concern with PHMSA's review and no-objection of these ECA procedures).

122

See., e.g.,
Brian Leis et al.,
Dent Strain and Stress Analyses and Implications Concerning API RP 1183—Part II: Examples of Dent Geometry and Strain Analyses During Contact and Re‐Rounding,
J. of Pipeline Sci. & Eng'g, Vol. 4, Iss. 1, at 15 (Mar. 2024), available at:
https://www.sciencedirect.com/science/article/pii/S2667143324000015?via%3Dihub.

123
API RP 1183, sec. 5.2.5;
see
ASME, B31 Code for Pressure Piping, B31.8-2018,
Gas Transmission and Distribution Piping Systems,
sec. 851.4.2 (2018) (marking a distinction for dents at 10 percent depth by permitting griding to a depth of 10 percent regardless of length). Though the consensus ASME B31.8 industry standard advises repair of dents at depths above 6 percent, PHMSA finds that using its proposed version of ECA can permit dents to remain in service somewhat larger than this, up to 10 percent.

To address the concerns identified by the D.C. Circuit, PHMSA provides additional explanation in support of the dent ECA process below, with information about the estimated cost-savings provided in the preliminary regulatory impact analysis. As a threshold matter, PHMSA notes that the first edition of API RP 1183,
Assessment and Management of Pipeline Dents,
published in 2020, provides useful guidance on elements of an ECA on gas and hazardous liquid pipelines. PHMSA considered the provisions in the first edition of API RP 1183 in developing the proposed ECA requirements and will consider any updates in the forthcoming second edition in developing the final rule in this proceeding.
124

With that said, the steps of the proposed ECA process for

hazardous liquid pipelines are generally as follows.
125

124
API RP 1183, at 8. PHMSA does not propose generally incorporating the recommended practice but proposes the ECA must be consistent with that recommended practice and incorporating it at paragraph (c)(6). PHMSA will consider broader incorporation pending possible improvements in future editions of API RP 1183.

125
The numerals correspond to the subparagraph under paragraph (c).

First, an operator must identify any potential interacting threats or features. Interacting threats and coincidental features are critical to modeling and to assessing dents and may impact fitness-for-service.
126

Some key interacting threats include ground movement, external loading, fatigue, cracking, and corrosion that could affect the dent.
127

The extent of area within which to consider threats to the dent may vary depending on the threat.

126
API RP 1183, sec. 6.5.

127

See
API RP 1183, sec. 4.2.3.

Second, an operator must review the available ILI data to create a dent profile to model the dent. The shape parameter involves human judgment that can result in variance, which step six later helps to specify and to remove subjectivity.
128

Third, the profile of a dent that has been identified previously must be compared against any prior profiles. Fourth, loads acting on the dent, both present and any previous loads, must be identified as even past strain can impact dent fatigue.

128

See
Rhett Dotson et al.,
Practical Challenges of Using the RP 1183 Shape Parameter Methods,
at 8 (Pipeline Pigging & Integrity Mgmt. Conf., Houston, Tx., Jan. 2025), available at:
https://ppimconference.com/wp-content/uploads/proceedings/167.pdf
(“the shape parameter approach has significant repeatability challenges based solely on the subjectivity in setting the baselines”).

Fifth, an operator must conduct a curvature-based strain analysis. For these purposes, strain is “assessed from ILI data using the shape and curvature of the dent as the basis for the strain estimation.”
129

This provides a quick and valuable computational analysis to ensure a dent does not exceed 10 percent strain level. Curvature-based strain analysis is based solely on the measured geometric dimensions of deformation and is limited in that it assumes the dent is a symmetrical plain dent and does not account for residual stress, interactions, loadings, or fatigue.
130

This assessment is a “precursor to fatigue life analysis” in a later step.
131

129
API RP 1183, sec. 5.2.4.

130
Curvature-based strain analysis will use a formula such as ASME B31.8, Appendix R, which does not take shear strain, circumferential extensional strain, and the pressure at the time of dent formation into account, all of which can have significant effects on dent strain.

131
API RP 1183, sec. 5.2.4.

Sixth, an operator must account for interacting conditions and loading by performing a finite element analysis (FEA) under API RP 1183.
132

API RP 1183 sets out three levels of strain analysis depending on the type of dent and information available. Level 1 and 2 are screening analyses and apply to single-peak plain dents and assume the dent is free from cracking. Level 3 is a more rigorous analysis that applies to all dents, including interacting defects.
133

PHMSA proposes that a level 3 FEA be required for all dents for the following reasons.

132
PHMSA proposes to incorporate API RP 1183 by reference for purposes of this step in the analysis.

133
API RP 1183, sec. 8.3.5.

Recent research casts doubt on the reliability of the other less rigorous level 1 or 2 screening tools in API RP 1183. The Canadian Energy Regulator (CER) found that the screening methods for estimating the strain of dents in API RP 1183 Table 6 “can lead to an underestimation of dent severity, potentially misclassifying injurious dents as non-injurious” with “the pipeline's actual integrity below what is projected by API RP 1183.”
134

Based on these concerns, API issued an addendum removing table 6 and alerting operators that the “various screening tools included in RP 1183, Table 6 . . . is not the most conservative dent screening method in all cases” and recommending that dents assessed under its methods may require reevaluation.
135

134
CER, SA 2025-01,
Evaluation of Dents in Pipe
(June 19, 2025), available at:
https://www.cer-rec.gc.ca/en/safety-environment/industry-performance/information-safety-advisories/safety-advisory/2025/safety-advisory-sa-2025-01-evaluation-dents-pipe.html.

135
API,
Addendum to API RP 1183 for Improved Dent Screening
(June 9, 2025), available at:
https://www.api.org/products-and-services/standards/important-standards-announcements/addendum-1-rp-1183; see
Brian Leis et al.,
Dent Strain and Stress Analyses and Implications Concerning API RP 1183—Part I: Background for Dent Geometry and Strain Analyses During Contact and Re-Rounding,
J. Pipeline Sci. & Eng'g, Vol. 3, Iss. 3, at 2 (Sept. 2023), available at:
https://doi.org/10.1016/j.jpse.2023.100143
(“It becomes evident that significant disparities can arise when results from Level 3 methods are compared to those of the simpler lower-level methods—even for smooth profile single-peak dents.”).

Leading pipeline researchers have also found that “the screening criteria and the fatigue assessment methods at level 2 and below frequently lead to unconservative errors well in excess of 100 [percent]” with “the worst unconservative prediction approached -2500 [percent].”
136

By making assumptions about maximum strain and curvature forms—rather than taking the actual measurements, as these can migrate from the apex of the dent during its lifecycle due to formation, rebounding, and subsequent cycling—the less rigorous strain analyses are found to result in erroneous, often unconservative strain calculations, which negatively impacts the fatigue assessments.
137

Even with smooth, symmetrical dents, this strain analysis risks error, and that is more pronounced for asymmetric, kinked, and skewed dents.
138

FEA is inherently more accurate and requires fewer assumptions, allowing PHMSA to propose the reassessment safety factors discussed below, while higher safety factors may have been necessary with alternative screening analyses.
139

136
Brian Leis et al.,
Dent Strain and Stress Analyses and Implications for API RP 1183—Part IIB: Fatigue-Life Prediction for Dented Pipes, J. of Pipeline Sci & Eng'g, Vol. abst & secs. 9-10 (forthcoming May 14, 2026), https://doi.org/10.1016/j.jpse.2026.100531.

137
Brian Leis et al.,
Dent Strain and Stress Analyses and Implications Concerning API RP 1183—Part II: Examples of Dent Geometry and Strain Analyses During Contact and Re‐Rounding,
J. of Pipeline Sci. & Eng'g, Vol. 4, Iss. 1, at 20 (Mar. 2024), available at:
https://www.sciencedirect.com/science/article/pii/S2667143324000015?via%3Dihub.

138
Leis,
Dent Strain and Stress Analyses and Implications Concerning API RP 1183—Part II,
at 32 (noting that the error permitted by the first edition of API RP 1183 is too large as a “±20[ percent] error bound is large relative to the safety margin for cross-country pipelines, such that errors the order of 60[ percent] become untenable.”).

139

See
API RP 1183, sec. 8.3.

PHMSA's proposal includes specific language addressing ECA procedures that would generally be viewed as unobjectionable. That language should address the concerns raised by operators, though some sought greater flexibility to use lower-level screening tools than PHMSA is comfortable codifying based on the current data and edition of API RP 1183.
140

Data collected from evaluations of dents analyzed by level 3 FEA should lead to the development of more reliable level 1 and 2 procedures in the future.
141

PHMSA will revisit the requirements for dent ECA procedures, including potential adoption of screening methods as alternatives to level 3 FEA, following

its review of the expected forthcoming second edition of API RP 1183. In the meantime, operators are permitted to use the § 192.18(c) and § 195.18(c) process to submit procedures with alternative technology or approaches, including screening tools or simplified strain procedures demonstrated to produce safe results reliably under defined circumstances.

140

See
Gas Associations, Comment, Docket ID PHMSA-2025-0019-0022, at 3 (expressing concern with delay in review of § 192.18(c) notifications for dent ECA procedures from conflict in PHMSA staff review as “PHMSA has been expecting operators to conduct [FEAs] for all dents even though, the language in § 192.712(c)(6) states `[FEA], or other technology' ” and requesting that “PHMSA should allow for us of `other technology' than FEA).
See also
Liquid Associations, Comment, Docket ID PHMSA-2025-0019-0021, at 33 (requesting use of a “valid fatigue life prediction model such as an analytical model or [FEA]”); Colonial, Comment, Docket ID PHMSA-2025-0019-0013, at 24 (similar).

141

See
Gas Associations, Comment, Docket ID PHMSA-2025-0019-0022, at 34-35 (noting that those operators who have applied an ECA in the last few years “have gained valuable experience about how the ECA process for dents should be improved to enhance its efficiency”).

At step seven, the operator estimates the fatigue life of the dent. Fatigue life computes as cycles the pipeline can withstand before failure and is converted to a predicted minimum fatigue life in years. The fatigue life determines whether an alternative timeline can be applied to a dent that would otherwise warrant an immediate or near-term response.
142

An “ideal 7-step analysis” for dents includes an “[a]ccurate estimate of remaining life using `reasonable' safety factors.”
143

A safety factor accounts for variability in cyclic life that PHMSA has observed between models in its review of the application of a dent ECA. The effect is that the remaining fatigue life is divided by the safety factor to provide the reassessment factor. With a predicted fatigue life of 500 years, a safety factor of two results in a 250-year reassessment factor, while a safety factor of five results in a 100-year reassessment factor; as both reassessment factors exceed the reassessment periods, the dent ECA in this example would permit delayed response in either scenario.
144

API RP 1183 recommends that reasonable safety factors “from 2 to 5 have traditionally been applied to the fatigue life” in ordinary circumstances, though it may be higher with interacting features.
145

A higher safety factor than this is not necessary because PHMSA's formulation does not permit an ECA in certain edge cases, like dents greater than 10 percent depth, and a separate response criteria without an ECA covers anomalies preferentially affecting susceptible welds.

142
A dent with a fatigue life, with safety factor applied, exceeding the immediate or near-term response interval is an “other condition” and, as proposed §§ 192.714(d)(3) and 195.453(d)(3) provide, must be reassessed at the next scheduled reassessment unless the calculated fatigue life provides a shorter interval.

143

API/PRCI Joint Workshop on Dent Assessment & Engineering Analysis Methods,
at 39 (PRCI Aug. 9, 2018), available at:
https://www.prci.org/NewsEvents/MeetingsEvents/138344.aspx; see
API RP 1183, sec. 8.4.

144
This example is representative of a typical ECA that PHMSA has observed in its analysis of data including through “other technology” requests even before it first offered a dent ECA in part 192.

145
API RP 1183, sec. 8.4.
See also id.
secs. 6.5.1.2, 6.5.1.3 (safety factor of 10 for dent with known longitudinal weld or spiral weld interacting threats)

For gas transmission pipelines, PHMSA proposes a reassessment safety factor of two. A safety factor of two is appropriate due to the reduced risk of cyclic fatigue. This was the minimum safety factor achieved to calculate a 90 percent probability of the calculations under the fatigue life assessment models of API RP 1183.
146

A safety factor of two effectively divides results in half, corresponding to the half-life concept common in fitness-for-service standards.
147

Data reviewed by PHMSA has not shown a meaningful difference from a higher safety factor on gas transmission pipelines as these factors do not make a difference in whether safe dents exceed the reassessment interval to qualify for use of the delayed response.

146

See
Rana,
Improve Dent/Cracking Assessment Methods,
at 46 (“Level 2 is the least conservative assessment model and cannot provide minimum factor of safety of 1 with high certainty when using mean curve and up to 0.8 with mean -1sd curve. For target minimum safety factors greater than 1, scaling factors are required across most certainty levels.”).

147

See, e.g.,
API 510,
Pressure Vessel Inspection Code: In-service Inspection, Rating, Repair, and Alteration,
sec. 6.5 (11th ed. 2022) (“Unless justified by an RBI assessment, the period between internal or on-stream inspections shall not exceed one-half the remaining life of the vessel. . .”); NACE, SP 0502-10,
Pipeline External Corrosion Direct Assessment Methodology,
sec. 6.6.1 (2010) (“[T]he maximum reassessment interval for each ECDA region shall be taken as one-half the calculated remaining life.”); API, Standard 653,
Tank Inspection, Repair, Alteration, and Reconstruction,
sec. 6.3.3.2(b) (5th ed. Nov. 2014) (similar).

For hazardous liquid pipelines, PHMSA proposes a reassessment safety factor of five. A higher safety factor is necessary for hazardous liquid pipelines to account for the effect of cyclic fatigue,
148

and a safety factor of five corresponds to the upper range recommended by API RP 1183.
149

The difference in the safety factor for gas (2) and hazardous liquids (5) reflects the fatigue calculation differences observed between the commodities. For example, a study found that service life for a repaired dent on a liquid pipeline is 10 years versus 100 years for a gas pipeline using composite wrap.
150

148

See
Aaron Dinovitzer
et al.,
PR214-203804-R01,
Systematize 20 Years of Mechanical Damage Research,
at 291 (May 31, 2022), available at:
https://primis.phmsa.dot.gov/rd/FileGet/17097/Systematize_20_Years_of_Mechanical_Damage_Research_V2.pdf.
(“As noted, the estimated design lives for the gas pipeline are significantly longer than those calculated for the liquid pipeline; this is typical as liquid pipelines are recognized for having more aggressive pressure cycling conditions than their gas transmission counterparts.”).

149

See
API RP 1183, sec. 8.4.

150
Dinovitzer,
Systematize 20 Years of Mechanical Damage Research,
at 293, fig. 3 & 4.

Finally, though PHMSA still proposes a notification and no-objection approach under §§ 192.18(c) and 195.18(c), PHMSA has revised the requirements of § 192.712(c) to express PHMSA's expectations more clearly for operator procedures, which should reduce review time significantly.
151

PHMSA continues to believe that dent ECA notifications are appropriate to ensure the effective administration of this unique and technically complex program, but invites comment on whether to modify the process. PHMSA may consider adopting a simple notification without requiring an advanced no-objection at the final rule stage. PHMSA also requests comment on whether a simple notification should be incorporated into annual reports instead, and, if so, what information should be collected there.

151

See
Gas Associations, Comment, Docket ID PHMSA-2025-0019-0022, at 3 (expressing concern with delay in review of § 192.18(c) notifications for no-objection of dent ECA procedures).

ii. Anomaly Evaluation for Metal Loss

Existing requirement:
Gas and hazardous liquid pipeline operators are required to calculate PFP of metal loss anomalies using ASME B31G or R-STRENG. §§ 192.712(b), 195.452(h)(4), and 195.587. For gas transmission pipelines, an alternative remaining strength calculation can be used subject to the notification and no-objection process.

Proposal:
PHMSA proposes to allow API 579 and Probable Profiles (Psqr), in addition to B31G and R-STRENG, to assess metal loss in §§ 192.714(b) and 195.415(b). Use of alternative technically accepted remaining strength models demonstrated to provide comparable results is also permitted. PHMSA proposes a 1.25 FPR to accommodate the use of Psqr in the immediate response criteria.

Discussion:
After further technical review, PHMSA proposes to expand the acceptable models for calculating metal loss. Specifically, PHMSA proposes to amend §§ 192.712(b) and 195.415(b) to allow the use of API 579 and Psqr.
152

As with R-STRENG and B31G, API 579 and Psqr could be used without further notification or approval from PHMSA.

See
§ 192.712(b)(2). API RP 579 has three levels of assessment for metal loss due to corrosion, which are equivalent to, or more rigorous than, a Modified B31G formula.
153

Leveraging the dramatic advancements in pipeline data, the Psqr model better represents corrosion features probabilistically in a pipeline by using a larger statistical distribution for more accurate and precise PFP calculation.
154

Peer-reviewed research indicates that Psqr classifies injurious defects reliably with fewer unnecessary excavations compared with other models.
155

152
API 579-1/ASME FFS-1,
Fitness-for-Service
(4th ed. Dec. 2021); John Kiefner et al., PR-218-183607-R01,
Peer Review of the Plausible Profile (Psqr) Corrosion Assessment Model,
Project Number EC-2-9 (PRCI Aug. 9, 2019).
See also
ASME, American Standard Code for Pressure Piping, B31G-2023,
Manual for Determining the Remaining Strength of Corroded Pipelines
(2023); J.F. Kiefner & P.H. Vieth, Pipeline Research Committee Project, PRCI PR-3-805,
A Modified Criterion for Evaluating the Remaining Strength of Corroded Pipe,
(Dec. 22, 1989)),
https://www.osti.gov/biblio/7181509
(RSTRENG).

153
Kiefner & Associates, Inc.,
Validity of Standard Defect Assessment Methods for the Alliance Pipeline Operating at 80% of SMYS,
at 6 (“The methods discussed above present trade-offs for the user between technical rigor and accuracy on the one hand, versus ease of use and reduced exactness on the other. In being modified from complex to simple, the exactness of the assessment decreases, but the simplifications were made so as to offset error with increased conservatism. So, one can say that more exact implies a less conservative computed result but not necessarily reduced safety because in using the more exact method the user is making a better quality estimate.”).

154
RSI Pipeline Solutions, presentation,
Peer Review of the Plausible Profile (Psqr) Corrosion Assessment Model,
at 20 (PRCI Nov. 2019), available at:
https://www.prci.org/File.aspx?id=171572
(“The Psqr Model is more accurate and exhibits less scatter than the existing models. The model avoids over conservatism without compromising safety.”); Shenwei Zhang et al., IPC2020-9448,
Plausible Profile (Psqr) Corrosion Assessment Model: Refinement, Validation and Operationalization
(Jan. 15, 2021), available at:
https://doi.org/10.1115/IPC2020-9448
(“Validation results show the Psqr model is safe, and more accurate and precise than RSTRENG.”). Though Psqr uses a statistical distribution of possible predicted failure pressures, RSTRENG is based on one worst-case (and overly conservative) profile. RSI Pipeline, at 7.

155
John Kiefner et al., PR 218-183607-R01,
Peer Review of the Plausible Profile (Psqr) Corrosion Assessment Model,
at 33 (PRCI Aug. 9, 2019).

To encourage further technological advancement, the proposed regulation will continue to permit operators to use other technically proven models (
i.e.,
those validated against the incorporated methods). However, PHMSA also proposes not to permit alternative methods that provide less conservative results. Since PHMSA proposes doubling the technically proven options specified in code, removing these less conservative options will reduce unnecessary notifications and improve safety.

The same models and methods are appropriate for both gas transmission and hazardous liquid pipelines. Currently, § 195.587 allows the same existing metal loss models for hazardous liquid pipelines. PHMSA proposes to centralize the existing models, along with the two additional models, in a § 195.415(b) that is similar to § 192.712(b). The current § 195.587 requirement will reference the proposed § 195.415(b) for the metal loss assessment methods and will be relocated to § 195.585(c) to provide one IM regulation on corrosion.

Use of Psqr requires a different FPR for the metal loss response criterion to maintain the intended level consistent with other models as its “calculated failure pressures are generally higher than those calculated using RSTRENG or B31G.”
156

That Psqr specific FPR is incorporated in the proposed §§ 192.714 and 195.453. Given the increased precision in Psqr, PHMSA requests comments with technical information on whether this separate FPR is necessary or appropriate for corrosion anomalies calculated using Psqr.

156
Kiefner,
Peer Review of the Psqr Corrosion Assessment Model,
at 9.

iii. Anomaly Evaluation for Cracks

Existing requirement:
Section 192.712(d) requires gas operators to analyze cracks by PFP using a technically proven fracture mechanics model appropriate to the failure mode, material properties, and boundary condition. Acceptable crack evaluation methods are not specified in § 192.712, though the regulation provides additional guidance. Fatigue analysis must be performed using an applicable fatigue crack growth law for a segment that is susceptible to cyclic fatigue or other loading. In addition, § 192.712(d)(3) provides for calculation based on pressure test assessments. Part 195 does not have a comparable provision, as PFP-based crack criteria for hazardous liquid pipelines are not yet codified by regulation.

Proposal:
PHMSA proposes to codify examples of technically accepted fracture mechanic methods to assess cracks, including API 579 Level II or III, Modified Ln-Sec, and Raju-Newman equations. PHMSA proposes editorial clarifications to the existing regulation for crack anomaly evaluation at § 192.712(d) and to apply the same approach to hazardous liquid pipelines in § 195.415(d).

Discussion:
Cracks must be evaluated by a model appropriate to a specific anomaly. PHMSA has issued guidance on accepted, technically proven crack evaluation models, such as the Newman-Raju Model, PipeAssess PI
TM
software, and PipeAssess PI
TM
software for brittle failure; and the Modified Log-Secant Model API RP 579-14—Level II or Level III, CorLas
TM
software PAFFC Model, and PipeAssess PI
TM
software for ductile failure.
157

157

See 2019 Safety of Gas Transmission Rule,
84 FR at 52236; PHMSA,
[Batch One of] Frequently Asked Questions for the [2019 Safety of Gas Transmission Rule]: MAOP Establishment and Reconfirmation FAQs,
FAQ-40 (Sept. 15, 2020), available at:
https://www.phmsa.dot.gov/sites/phmsa.dot.gov/files/2023-06/Batch-1-FAQs-PHMSA-2019-0225-9-15-20.pdf.

PHMSA proposes to incorporate these models, which are appropriate for both gas and hazardous liquid pipelines, by regulation (other than proprietary software models, which cannot be codified) to provide greater clarity and certainty. Operators may still use other methods demonstrated to produce safe results; software derived from the explicitly accepted methods is likely acceptable. PHMSA also proposes editorial revisions to § 192.712(d) to express more clearly the requirement to calculate remaining life based on the amount of time required for the crack to grow to failure size, and to apply the same approach to hazardous liquid pipelines at § 195.415(d). With the models incorporated, the reference to Paris' law can be removed.

For cracks that survive pressure testing, PHMSA proposes a non-substantive edit to the requirement at paragraph (d)(2) for clarity and to adopt a similar provision for hazardous liquid pipelines. Pressure test results provide different inputs for analysis than ILI results: pressure testing establishes a minimum PFP for cracks but does not provide any size information.

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Source: Frix Law Library, https://www.frixlaw.com/law-library/documents/fr%3A2026-13805. Public record. Not legal advice.