Pipeline Safety: Class Location Change Requirements

DEPARTMENT OF TRANSPORTATION

Pipeline and Hazardous Materials Safety Administration

49 CFR Part 192

[Docket No. PHMSA-2017-0151; Amdt. No. 192-155]

RIN 2137-AF29

Pipeline Safety: Class Location Change Requirements

AGENCY:

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

ACTION:

Final rule.

SUMMARY:

PHMSA is updating its regulations to allow operators to apply modern risk management principles in addressing the safety of gas pipelines affected by class location changes. Relying on an approach originally developed in the 1950s, PHMSA's regulations use class locations to provide an additional margin of safety in the design, construction, testing, operation, and maintenance of gas pipelines based on population density. When the class location of a pipeline changes due to an increase in population density, an operator may need to take certain actions to confirm or to revise the maximum allowable operating pressure of a segment. Because the methods traditionally used for that purpose do not account for modern risk management principles, PHMSA has granted special permits for more than two decades allowing operators to use an integrity-management-based alternative. This final rule adopts that `IM alternative' by regulation to provide operators with an additional method for confirming or restoring the maximum allowable operating pressure of certain eligible segments that experience class location changes.

DATES:

This rule is effective March 16, 2026. The incorporation by reference of certain material listed in this rule is approved by the Director of the Federal Register as of March 16, 2026. Comment related to the information collection may be submitted by March 16, 2026, as detailed in Section VII.H.

FOR FURTHER INFORMATION CONTACT:

Robert Jagger, Senior Transportation Specialist, at 202-557-6765 or

robert.jagger@dot.gov.

SUPPLEMENTARY INFORMATION:

I. Executive Summary

A. Purpose of the Regulatory Action

B. Summary of the Major Regulatory Provisions

C. Costs and Benefits

II. Background

A. Overview of Class Location Requirements

B. Origin of Class Location Requirements

C. Integrity Management Program Requirements

D. Class Location Special Permits

III. Summary of the NPRM

IV. Discussion of the Final Rule and Analysis of Comments

A. General

B. Definitions

C. Eligibility Criteria

i. General

ii. Original Class

iii. SMYS Limitations

iv. Subpart J Pressure Test

v. TVC Material Records

vi. Grandfathered or Alternative MAOP

vii. Wrinkle Bends and Geohazards

viii. Vintage Seam Types

ix. Pipe Coating for Cathodic Protection

x. Cracking

xi. Class Location Change Date—Special Permits

xii. Class Location Change Date—Prior Pressure Reductions

xiii. Previously Denied Special Permits

D. IM Program Requirements

i. Subpart O Incorporation

ii. Assessment Methods

iii. ILI Validation

iv. Baseline Assessment

v. Remediation Schedule

E. Additional Programmatic Requirements—One-Time and Recurring Obligations

i. General Programmatic Requirements

ii. Clear Shorted Casings

iii. Valve Requirements

iv. Notification Upon Use of the Program

v. Class Location Study

F. Adjustments to Class Locations Through Clustering

V. Section-by-Section Analysis

VI. Statutory Authority

VII. Regulatory Analysis and Notices

VIII. Regulatory Text

I. Executive Summary

A. Purpose of the Regulatory Action

The idea of using “class locations” to provide an additional, population-density-based margin of safety in the design, construction, and testing of gas pipelines dates to the second edition of the American Standard Code for Pressure Piping, Section 8, Gas Transmission and Distribution Piping Systems, ASA B31.1.8-1955.

1

Published in 1955, B31.1.8-1955 directed operators to use one-mile and 10-mile population density indices to determine the appropriate class location of a pipeline at the time of construction. B31.1.8-1955 recognized four different class locations, ranging from Class 1 for areas with the lowest population density to Class 4 for areas with the highest population density.

1

Am. Soc. of Mech. Eng'rs (ASME), American Standard Code for Pressure Piping, Section 8, ASA B31.1.8-1955,

Gas Transmission and Distribution Piping Systems

(1955).

B31.1.8-1955 also included provisions for operators to follow in determining the maximum allowable operating pressure (MAOP) of a pipeline. B31.1.8-1955 directed operators to select the lowest of three pressures in determining MAOP: (1) the design pressure, (2) the test pressure, and (3) the maximum safe operating pressure of the pipeline based on the information known about the strength and operating history. To provide an additional margin of safety, B31.1.8-1955 accounted for the class location of a pipeline in providing operators with more conservative design and test pressure factors to use in determining MAOP.

2

2

ASME retained these provisions in the ensuing editions of that standard, which became known as the B31.8. ASME, American Standard Code for Pressure Piping, Section 8, ASA B31.8-1958,

Gas Transmission and Distribution Piping Systems

(1959); ASME, American Standard Code for Pressure Piping, Section 8, ASA B31.8-1963,

Gas Transmission and Distribution Piping Systems

(1963); ASME, USA Standard Code for Pressure Piping, USAS B31.8-1967,

Gas Transmission and Distribution Piping Systems

(1967); ASME, USA Standard Code for Pressure Piping, USAS B31.8-1968,

Gas Transmission and Distribution Piping Systems

(1968).

The 1968 edition of the B31.8 added a new provision for addressing class location changes. The provision directed operators to conduct a study if an increase in the population density indicated that the class location of a pipeline had changed since the original installation. And, depending on the results of that study, the provision directed operators to confirm or to revise the MAOP of the pipeline, either by relying on a prior pressure test, by reducing the MAOP, or by conducting a new pressure test. Operators could also maintain the current MAOP by replacing the pipe in the affected segment.

Adopted by PHMSA

3

in 1970, the original version of the Federal Gas Pipeline Safety Regulations incorporated the B31.8's class location concept, albeit with certain modifications.

4

Rather than using population density indices, the 1970 final rule required operators to determine the class location of a pipeline based on the number of buildings intended for human occupancy in a “class location unit,” defined as an area extending 220 yards on either side of the centerline of any

continuous one-mile length of pipeline. The final rule also required operators to follow more stringent operation and maintenance (O&M) requirements as the class location increased in value.

3

For ease of reference, PHMSA and its predecessor agencies at the U.S. Department of Transportation that have regulated pipeline safety are referred to as PHMSA throughout this document.

4

Establishment of Minimum Standards,

35 FR 13248 (Aug. 19, 1970) (Minimum Standards).

Of particular significance here, the 1970 final rule required operators to consider class location in establishing the MAOP of a pipeline segment as well. Like the B31.8, the final rule required operators to consider the design pressure, test pressure, and maximum safe operating pressure of a pipeline in determining MAOP, along with the highest actual operating pressure experienced during the preceding five years for existing lines. To provide an additional margin of safety based on population density, the final rule also accounted for the class location of a pipeline in the design and test pressure factors that operators had to use in determining MAOP.

Finally, as in the B31.8, the 1970 final rule included requirements for addressing class location changes. The final rule required operators to conduct a study and, if necessary, to confirm or to revise the MAOP of a segment, either by relying on the results of a prior pressure test, by reducing the MAOP, or by conducting a new pressure test. An operator could also maintain the current MAOP by replacing the pipe in the affected segment.

After adopting the integrity management (IM) program for gas transmission lines in the early 2000s, PHMSA established a new policy for granting special permits (or waivers) of the requirements for addressing class location changes.

5

PHMSA adopted that policy on the grounds that IM principles could be used to manage effectively the integrity of class change segments, provided operators complied with a series of additional terms, conditions, and limitations. PHMSA has granted special permits to more than 45 operators in the two decades since issuing that policy, and no pipeline segment subject to a class location special permit has ever experienced a failure.

5

Pipeline Safety: Development of Class Location Change Waiver Criteria,

69 FR 38948 (June 29, 2004).

In this final rule, PHMSA is adopting an IM alternative as an additional option for addressing class location changes on gas transmission lines. Modeled on the successful class location special permit program, operators can use the IM alternative to confirm the MAOP of eligible Class 3 segments by complying with a comprehensive set of initial and recurring programmatic requirements. Operators can also use the IM alternative to restore the previously established MAOP of eligible Class 3 segments by complying with certain additional requirements. PHMSA concludes that the benefits and cost-savings of allowing operators to use the IM alternative justify their costs. PHMSA therefore adopts the IM alternative in this final rule.

B. Summary of the Major Regulatory Provisions

Subject

Final rule

Applicability

Section 192.611(a)(4) authorizes an IM alternative for managing class location changes that affect certain eligible gas transmission line segments in Class 3 locations.

Eligibility

Section 192.3 defines the eligible Class 3 segments that may use the IM alternative. That definition excludes segments that (1) contain bare pipe; (2) contain wrinkle bends; (3) have a longitudinal seam formed by lap welding or another method with a joint factor below 1.0; or (4) have experienced an in-service leak or rupture due to cracking on the segment or a pipe with similar characteristics within 5 miles.

A segment that experiences an in-service rupture or leak from the pipe body cannot continue using the IM alternative.

Subpart O Compliance

An eligible Class 3 segment applying the IM alternative must be designated as a high consequence area and comply with the requirements in Subpart O.

Initial Programmatic Requirements

An operator must comply with certain initial programmatic requirements within 24 months to use the IM alternative. Those requirements address: (1) integrity assessments and remediation, (2) pressure testing, (3) material records verification, (4) rupture mitigation valves, (5) cathodic protection and coating, and (6) depth of cover. An operator must also provide a notification to PHMSA.

Recurring Programmatic Requirements

An operator must comply with certain recurring programmatic requirements to use the IM alternative. Those requirements address: (1) gas quality, (2) close interval surveys, (3) patrolling, (4) leak surveys, (5) line markers, (6) class location studies, (7) shorted casings, and (8) exposed pipe and weld surface examinations.

Other Requirements

MAOP of a segment using the IM alternative may not exceed a hoop stress corresponding to 72 percent of specified minimum yield strength.

An operator of an eligible Class 3 segment may use the IM alternative to restore a previously established MAOP after complying with certain uprating and initial programmatic requirements.

C. Costs and Benefits

This final rule is expected to produce substantial cost-savings of $461 million annually, after accounting for the expected $61.5 million cost for operators to implement the IM alternative on segments that experience class location changes in a given year (both discounted at 7%). The final rule is also expected to avoid an estimated 1.3 billion cubic feet of gas losses per year from pipeline replacements. Other non-quantified benefits include reducing service disruptions and increasing regulatory certainty and flexibility. The Regulatory Impact Analysis (RIA) provided in the docket for this rulemaking includes additional information about the costs, benefits, and other impacts of the final rule.

II. Background

A. Overview of Class Location Requirements

Class locations use population density to provide an additional margin of safety for gas pipelines. Four class locations are used for that purpose, with Class 1 representing the areas with the least population density, Class 4 representing the areas with the highest population density, and Class 2 and Class 3 representing areas of

intermediate population density. To account for the additional risk to public safety, more stringent safety standards apply as the class location of a gas pipeline increases in value.

That principle, which is commonly referred to as a safety factor, is reflected in the first instance in determining the design pressure of a pipeline. Design pressure is calculated using a modified version of Barlow's formula, the results of which specify the maximum internal pressure piping can withstand before failure. A class-location-based design factor is incorporated into that formula to provide more margin

—i.e.,

a lower safety factor—as population density increases.

6

A similar concept applies in determining the test pressure of a pipeline.

7

Design and test pressure are two of the factors that limit MAOP, which is the highest pressure that a pipeline is permitted to operate at while in service.

8

6

See

49 CFR 192.105.

See also

ASME, Code for Pressure Piping, B31.8,

Gas Transmission and Distribution Piping Systems,

§ 805.2.3 (2018). This equation in full is: Design pressure = ((2*Yield Strength*wall thickness)/outside diameter) * class design factor * longitudinal joint factor * temperature factor.

7

49 CFR 192.619(a) (test requirements for establishing MAOP at time of installation, incorporating a class-location-based test factor which lowers MAOP as the class location increases).

8

See

49 CFR 192.3 (defining MAOP), 192.619 (prescribing requirements for determining MAOP).

Because Barlow's formula captures the relationship between maximum pressure, stress (

i.e.,

specified minimum yield strength (SMYS)), wall thickness, and diameter with the class safety factor, an increase in any one input will increase the other inputs.

9

In practical terms, this means that pipe with additional strength or wall thickness must be installed to maintain the same design pressure in higher class locations. That is because, as Figure 1 shows, a higher class location will lead to a lower MAOP if the other variables used in the formula remain constant.

9

See, e.g.,

Reid T. Stewart,

Strength of Steel Tubes, Pipes, and Cylinders under Internal Fluid Pressure,

34 J. Fluids Eng'g 312, 312-18 (1912);

Barlow's Formula,

Am. Piping Prods.,

https://amerpipe.com/reference/charts-calculators/barlows-formula/

(last accessed June 18, 2025).

ER14JA26.015

This phenomenon governs in applying Barlow's formula both at the time of installation and if the class location of a gas pipeline changes at a later point in time due to an increase in population density.

10

10

See, e.g., Confirmation or Revision of Maximum Allowable Operating Pressure; Alternative Method,

54 FR 24173, 24173-74 (June 6, 1989) (“Section 192.611 requires that, when the class location (population density) of a pipeline segment increases, the maximum allowable operating pressure (MAOP) must be confirmed or revised to be compatible with the existing class location.”).

Operators currently have three options for confirming or revising MAOP in response to class location changes. First, an operator may reduce the MAOP to reflect the design and test pressure factor applicable to the current class location. Second, an operator may confirm the MAOP through pressure testing, either based on the results of a previous test or by conducting a new test. Third, an operator may replace the pipeline with material of additional strength or wall thickness to maintain the current MAOP.

Each of these methods has drawbacks, particularly if a segment remains in satisfactory condition and can be safely operated at the current MAOP. Pipeline replacements cause construction-related impacts and can lead to service disruptions and natural gas emissions. Pressure testing requires a pipeline to be taken out of service—albeit for a shorter time—and results in similar service disruptions and natural gas emissions. MAOP reductions can affect all aspects of the supply chain, leading to service interruptions and higher costs for consumers.

These drawbacks can be avoided if operators are allowed to use modern risk management principles to confirm or restore the MAOP of class change segments. This final rule achieves that objective by adopting an IM alternative that operators can implement without resorting to unnecessary MAOP reductions, pressure testing, or pipeline replacements.

B. Origin of Class Location Requirements

In 1952, the American Society of Mechanical Engineers (ASME) released the American Standard Code for Gas Transmission and Distribution Piping Systems (B31.1.8-1952), the first industry safety standard specifically dedicated to gas transmission and distribution pipelines. In 1955, the second edition of that standard, B31.1.8-1955, introduced a new concept—using class locations to provide an additional margin of safety in the design, installation, and testing of

gas transmission and distribution pipelines.

11

11

Michael Rosenfeld & Rick Gailing,

Pressure Testing and Recordkeeping: Reconciling Historic Pipeline Practices with New Requirements,

at 2-3, 8-9 (Feb. 2013), available at:

https://www.applus.com/dam/Energy-and-Industry/GLOBAL/userfiles/file/Pressure-Testing-and-Recordkeeping-Reconciling-Historic-Pipeline-Practic.pdf.

B31.1.8-1955 directed operators to use two population density indices to classify the initial location of gas transmission and distribution lines at the time of construction.

12

The first population density index, applicable to one-mile lengths of the pipeline, required operators to count the number of buildings intended for human occupancy within a half-mile-wide zone that ran along those lengths. The second population density index, applicable to 10-mile lengths of the pipeline, directed operators to add the one-mile lengths together into 10-mile sections and divide the sum by 10.

12

ASA B31.1.8-1955, § 841.001(a)-(c).

B31.1.8-1955 provided four class locations that could be assigned based on the results of the one-mile and 10-mile population density indices. The least populated areas, known as Class 1 locations, included “waste lands, deserts, rugged mountains, grazing land, and farm land” with a 10-mile population density index of 12 or less and a one-mile population density index of 20 or less. Class 2 locations included “areas where the degree of development [was] intermediate,” such as “[f]ringe areas around cities and towns, and farm or industrial areas,” with a 10-mile index of 12 or more and a one-mile index of 20 or more. Class 3 locations included “areas subdivided for residential or commercial purposes where, at the time of construction of the pipeline or piping system, 10 percent or more of the lots abutting on the street or right-of-way in which the pipe is to be located are built upon.” Class 4 locations included “areas where multistory buildings” with four or more floors aboveground were “prevalent, and where traffic [was] heavy or dense and where there may be numerous other utilities underground.”

13

13

ASA B31.1.8-1955, §§ 841.011, 841.012, 841.013, 841.014. For ease of reading and public accessibility, in this document a string of cited material may be cited by a footnote in the final sentence of the paragraph addressing all material from that source.

To account for the additional risk to public safety, B31.1.8-1955 directed operators to consider the class location at the time of construction in determining the design pressure of the pipeline. Operators had to use a prescribed formula in making design pressure determinations, and that formula accounted for the SMYS, nominal outside diameter, nominal wall thickness, construction type design factor, longitudinal joint factor, and temperature derating factor for the pipe.

14

The construction type design factors used in the design pressure formula—0.72, 0.60, 0.50, and 0.40—were inversely proportional to the class location, which had the effect of lowering the MAOP of the pipeline as the population density increased. B31.1.8-1955 also directed operators to consider class location in testing the pipeline at the time of installation, generally requiring a progressively higher minimum test pressure to be achieved as the population density increased.

15

ASME retained these provisions in subsequently published editions of that standard, which became known as B31.8.

16

14

ASA B31.1.8-1955, § 841.1, tbl. 841.11.

15

ASA B31.1.8-1955, tbl. 841.412(d).

16

E.g.,

ASA B31.8-1958; ASA B31.8-1963; USAS B31.8-1967.

In 1968, ASME published an updated edition of the B31.8 that contained a new provision for addressing class location changes. The provision directed operators to conduct a study if an increase in the population density indicated that the class location of a pipeline had changed since the original installation. Depending on the results of that study, the provision directed operators to confirm or to revise the MAOP of the pipeline, either by relying on a prior pressure test, by reducing the MAOP, or by conducting a new pressure test. An operator could also maintain the current MAOP by replacing the pipe in the affected segment to provide the necessary design and test pressure.

17

17

USAS B31.8-1968, § 850.4.

In 1970, PHMSA incorporated the class location concept in adopting the original version of the Federal Gas Pipeline Safety Regulations in part 192.

18

But instead of requiring operators to use the one-mile and 10-mile population density indices as in B31.8, PHMSA required operators to count the number of buildings intended for human occupancy in a “class location unit,” defined as an area extending 220 yards on either side of the centerline of any continuous one-mile length of pipeline.

19

In other words, PHMSA narrowed the width of the zone to be considered in making class location determinations and replaced the one-mile and 10-mile population density indices with a continuous, or sliding, mile approach.

18

See Minimum Standards,

35 FR 13248.

See also

Natural Gas Pipeline Safety Act of 1968, Pub. L. 90-481, 82 Stat. 720 (Aug. 12, 1968) (authorizing PHMSA to prescribe and enforce minimum Federal safety standards for gas pipeline facilities and persons engaged in the transportation of gas). PHMSA discussed the full history of class locations in the notice of proposed rulemaking, 85 FR 65142, 65145-52 (proposed Oct. 14, 2020) (NPRM).

19

Minimum Standards,

35 FR at 13251, 13258.

PHMSA also used different criteria in defining the four class locations that could be assigned to each class location unit. PHMSA defined a Class 1 location as any class location unit that has “10 or less buildings intended for human occupancy,” and a Class 2 location as any class location unit that has “more than 10 but less than 46 buildings intended for human occupancy.” PHMSA defined a Class 3 location as any class location unit that has “46 or more buildings intended for human occupancy,” as well as an area where the pipeline lies within 100 yards of a “building that is occupied by 20 or more persons during normal use” or a “small, well-defined outside area that is occupied by 20 or more persons during normal use, such as a playground, recreation area, outdoor theater, or other place of public assembly.” PHMSA defined a Class 4 location as any class location unit “where buildings with four or more stories above ground are prevalent.”

20

20

Minimum Standards,

35 FR at 13259 (codifying § 192.5). For additional information about the treatment of Class 3 locations,

see

PHMSA, PI-81-001, Letter of Interpretation (Jan. 13, 1981), available at:

https://www.phmsa.dot.gov/regulations/title49/interp/pi-81-001.

Like B31.8, PHMSA required operators to follow more stringent construction and initial testing practices as the class location increased. The design and test pressure factors used in determining the MAOP of a pipeline had the same inversely proportional relationship to the class location, resulting in a lower MAOP for segments in more populated areas. PHMSA also went beyond B31.8 in requiring operators to consider class location in determining O&M requirements that applied after a pipeline went into service. As a result, class locations played a much greater role in determining the standards applicable to a pipeline under part 192 than had been the case under the comparable provisions in B31.8.

Of particular significance here, PHMSA included requirements in the 1970 regulations for confirming or revising the MAOP of a segment that experienced a change in class location after installation. Operators had to perform a study “[w]henever an increase in population density indicates a change in class location for a segment of an existing steel pipeline operating at hoop stress that is more than 40 percent

of SMYS, or indicates that the hoop stress corresponding to the established maximum allowable operating pressure for a segment of existing pipeline is not commensurate with the present class location.”

21

After completing that study, operators had to take certain actions to confirm or to revise the MAOP of the segment to align with the new class location. Those actions included reducing the MAOP, relying on a previous pressure test, conducting a new pressure test, or replacing the pipe.

22

In addition, to ensure that pipelines installed prior to the adoption of the part 192 regulations had an MAOP commensurate with the current location, PHMSA required operators to complete an initial study and, if necessary, to take action to confirm or to revise the MAOP of existing segments by certain deadlines.

23

The framework established in the original part 192 regulations for addressing class location changes has remained largely unchanged.

24

21

Minimum Standards,

35 FR at 13272 (codifying § 192.609).

22

PHMSA originally required these actions to be completed within one year of the date of the class location change, but subsequently extended that deadline to two years.

See Extension of Time for Confirmation or Revision of Maximum Allowable Operating Pressure,

36 FR 18194 (Sept. 10, 1971) (extending period to 18 months);

Pipeline Safety: Periodic Updates to Pipeline Safety Regulations (2001),

69 FR 32886, 32890 (June 14, 2004) (extending period to 2 years).

23

Minimum Standards, 35 FR at 13272 (codifying original version of § 192.607);

Regulatory Review; Gas Pipeline Safety Standards,

61 FR 28770, 28785 (June 6, 1996) (repealing original version § 192.607 as obsolete).

24

Slight modification extended the time to complete MAOP confirmation to two years,

see supra

note 23, repealing the class location study for pre-part 192 pipelines when that had completed,

see supra

note 24, and the specific test pressure,

see Confirmation or Revision of Maximum Allowable Operating Pressure; Alternative Method,

54 FR 24173 (June 6, 1989) (allowing the MAOP to be confirmed or revised based on a past pressure test, with test pressure tied to class location, rather than requiring a test pressure to at least 90 percent SMYS).

C. Integrity Management Program Requirements

In 2003, PHMSA issued a final rule establishing new IM program requirements for gas transmission lines (2003 Gas IM Rule). The 2003 Gas IM Rule required operators to apply modern risk management principles to ensure the integrity of pipeline segments located in high consequence areas (HCAs),

i.e.,

areas where an incident could cause more harm to people and property, such as Class 3 and Class 4 locations, areas containing facilities that house individuals who are confined, mobility impaired, or hard to evacuate, or places where people gather for recreational or other purposes.

25

The ability to use inline inspection (ILI) tools to conduct integrity assessments of covered segments was a core feature of the 2003 Gas IM Rule.

25

Pipeline Safety: Pipeline Integrity Management in High Consequence Areas,

68 FR 69778 (Dec. 15, 2003) (2003 Gas IM Rule);

see

Pipeline Safety Improvement Act of 2002, 49 U.S.C. 60109.

By way of background, the use of ILI tools as an internal inspection technology for pipelines dates to the 1960s.

26

Early generation ILI tools could only detect metal loss anomalies in the bottom quarter of a pipeline, and limitations in battery power capacity meant that inspections could extend for no more than 30 miles.

27

However, as the technology advanced, ILI tools became capable of detecting more anomalies and inspecting greater lengths of pipeline. Modern ILI technology allows multiple types of tools to be attached together, permitting detection of different threats at once. Modern ILI tools are also equipped with improved sensor technology, enabling detection of a wider range of defects with greater accuracy. These advances have increased both the probability of detection and probability of identification of pipeline anomalies—commercially available ILI tools today can detect pipe body crack sizing with 90 percent certainty to 1 millimeter via an Electromagnetic Acoustic Transducer (EMAT) tool, and corrosion depth sizing with 80 percent certainty to 0.1 times the wall thickness via axial Magnetic Flux Leakage (MFL-A) tools.

28

26

See

T.D. Williamson, Comments, Docket ID PHMSA-2017-0151-0024, at 1 (Sept. 29, 2018).

27

See

INGAA, Fact Sheet,

Response to NTSB Recommendation: Historic and Future Development of Advanced In-line Inspection (ILI) Platforms for Natural Gas Transmission Pipelines

(April 2012), available at:

https://ingaa.org/wp-content/uploads/2013/01/19697.pdf;

Anand Gupta & Anirbid Sircar,

Introduction to Pigging & a Case Study on Pigging of an Onshore Crude Oil Trunkline,

V Int'l J. Latest Tech in Eng'g, Mgmt. & Applied Sci. at 21 (Feb. 2016), available at:

https://www.researchgate.net/publication/307583466_Introduction_to_Pigging_a_Case_Study_on_Pigging_of_an_Onshore_Crude_Oil_Trunkline.

28

See, e.g.,

Rosen Swiss AG,

RoCorr MFL-A Service: In-line Ultra-High-Resolution Metal Loss Detection and Sizing

(2024), available at:

https://contenthub.rosen-group.com/api/public/content/729e05931aca4953ac0a47dbdf2c6566?v=f9378e13;

Rosen Swiss AG, R

oCD EMAT-C Service: In-line High-Resolution Detection and Sizing of Axial Cracks

(2024), available at:

https://contenthub.rosen-group.com/api/public/content/7e9f40578f924917a4403fa7fc5ba41e?v=0071d845.

Dramatic improvements in ILI technology have occurred in the 20 years since the adoption of the 2003 Gas IM Rule, facilitated, in part, by PHMSA's other technology notification process that allows operators to deploy more modern tools for conducting integrity assessments.

29

Tool manufacturers and operators have incorporated the experience gained by deploying ILI—which operators have expanded to a greater number of pipelines—to advance their ability to detect and model increasingly complex defect types.

30

Innovation in data processing and machine learning algorithms have enabled real-time analysis and improved interpretation of complex signals and deformation shapes, expediting decision-making.

31

Models can now overlay multiple data inputs involving different threats to provide a clearer understanding of the pipeline and greater knowledge about each possible anomaly. Compared with historical assessment practices like hydrostatic testing and direct assessment, modern ILI tools discover and identify more anomalies, offering greater proactive remediation.

32

29

See

Rosen USA, Comments, Docket ID PHMSA-2017-0151-0025, at 1 (Sept. 28, 2018).

See also

The Williams Companies, Inc. (Williams), Comments, Docket ID PHMSA-2024-0005-0421 at 3, 5 (Aug. 27, 2024) (noting how study and application between industry and PHMSA “drives the vendors to constantly improve and refine their tools,” and today “[o]perators . . . who regularly deploy this [ILI] technology across its enterprise of pipeline systems[] can assess risk with a level of detail and certainty that was not available 10 years ago”).

30

Just since 2012, operators have expanded the number of pipelines able to accommodate ILI from 60 percent to 74 percent of all gas transmission mileage in 2024.

See

PHMSA, Annual Reports. That number is likely to continue to increase in part as a result of continued PHMSA regulation driving inspection of these gas transmission pipelines.

See

Alisdair Blackley et. al., Argus,

Pigging Previously Unpiggable Pipelines,

Pipeline Pigging and Integrity Management Conference (Feb. 12-16, 2024), available at:

https://www.argusinnovates.com/public/download/files/244219.

31

See

Rosen, Comments, Docket ID PHMSA-2011-0151-0025, at 1; T.D. Williamson, Comments, Docket ID PHMSA-2017-0151-0024, at 2.

32

See

NTSB, SS-15-01,

Integrity Management of Gas Transmission Pipelines in High Consequence Areas

at 58 (Jan 27, 2015), available at:

https://www.ntsb.gov/safety/safety-studies/documents/ss1501.pdf

(finding 663 repairs per 1,000 miles assessed for ILI, compared to 264 for direct assessment, 35 for pressure tests, and 26 for other assessment techniques).

See also

Williams, Docket ID PHMSA-2024-0005-0421 at 5 (noting how “the data provided by the current generation of [ILI] tools gives [an operator] certainty and clarity around the risk assessment decisions . . . regarding potential threats”).

PHMSA has updated the IM regulations in Subpart O to capitalize on the recent advances in ILI technology. In 2022, PHMSA completed a multi-year process of strengthening its IM regulations to address congressional mandates and National Transportation Safety Board (NTSB) recommendations issued in response to a significant gas transmission line incident that occurred in San Bruno, California, in 2011.

33

The

enhancements to the IM regulations included new assessment procedures for ILI tools and updated requirements for the detection and remediation of anomalies. PHMSA's 2019 and 2022 Safety of Gas Transmission Rules also established a companion assessment and response schedule for other Class 3 and 4 pipelines.

34

These changes have created a comprehensive, risk-based scheme for pipeline anomaly detection and remediation, driven in large part by continuing improvements in ILI technology.

33

Safety of Gas Transmission Pipelines: Repair Criteria, Integrity Management Improvements,

Cathodic Protection, Management of Change, and Other Related Amendments,

87 FR 52224 (Aug. 24, 2022) (2022 Safety of Gas Transmission Rule);

Safety of Gas Transmission Pipelines: MAOP Reconfirmation, Expansion of Assessment Requirements, and Other Related Amendments,

84 FR 52180 (Oct. 1, 2019) (2019 Safety of Gas Transmission Rule).

34

For these non-high consequence segments, the assessment is every 10 years and scheduled repair is designated to occur within 2 years of detection, highlighting the different safety factor found in high consequence areas.

See

49 CFR 192.710(b)(2); 192.714(d)(2).

D. Class Location Special Permits

PHMSA's experience administering a comprehensive class location special permit program demonstrates that IM principles can be used safely to confirm or to restore the MAOP of pipeline segments in Class 3 locations. When issuing the original IM program requirements for gas transmission lines in 2003, PHMSA acknowledged that “[e]xperience may lead to future changes in the [regulatory] requirements,” and that the waiver, or “special permit,” process authorized by 49 U.S.C. 60118 and codified in 49 CFR 190.341 could be used to review segments changing class location for suitability to leverage IM principles in place of pipe replacement.

35

Specifically, PHMSA stated that:

35

2003 Gas IM Rule, 68 FR at 69782.

[a] benefit to be realized from implementing this rule is reduced cost to the pipeline industry for assuring safety in areas along pipelines with relatively more population. The improved knowledge of pipeline integrity that will result from implementing this rule will provide a technical basis for providing relief to operators from current requirements to reduce operating stresses in pipelines when population near them increases. Regulations currently require that pipelines with higher local population density operate at lower pressures. This is intended to provide an extra safety margin in those areas. Operators typically replace pipeline when population increases, because reducing pressure to reduce stresses reduces the ability of the pipeline to carry gas. Areas with population growth typically require more, not less, gas. Replacing pipeline, however, is very costly. Providing safety assurance in another manner, such as by implementing this [integrity management] rule, could allow [the Agency] to waive some pipe replacement. [The Agency] estimates that such waivers could result in a reduction in costs to industry of $1 billion over the next 20 years, with no reduction in public safety.

36

36

2003 Gas IM Rule, 68 FR at 69812.

See also

Final Regulatory Evaluation, 2003 Gas IM Rule, Docket ID PHMSA-RSPA-2000-7666-0356 (Dec. 2023).

While special permits are considered on a case-by-case basis, PHMSA developed certain threshold requirements for segments to be considered as candidates for a special permit.

37

As explained in the 2004 notice articulating those threshold requirements, PHMSA would only consider pipeline segments that operate below 72 percent of SMYS for a Class 3 location; underwent an eight-hour hydrostatic test to at least 1.25 times the MAOP; and did not have bare pipe, wrinkle bends, or significant anomalies. Older pipe and specific seam types would require further justification. PHMSA also explained that operators would be required to apply their IM program and assess the segment using ILI techniques for a distance upstream and downstream.

37

Pipeline Safety: Development of Class Location Change Waiver Criteria,

69 FR 38948 (June 29, 2004); PHMSA,

Criteria for Considering Class Location Waiver Requests

(June 30, 2024), available at:

https://www.phmsa.dot.gov/sites/phmsa.dot.gov/files/docs/technical-resources/pipeline/class-location-special-permits/64091/classchangewaivercriteria.pdf

(PHMSA, 2004 Special Permit Criteria).

PHMSA has issued 46 class location special permits since 2004. Thirty-six are active. Each special permit application undergoes individual review by PHMSA, is subject to public notice and comment, includes operational conditions if issued, and must be renewed after 10 years. There has never been a leak or rupture reported on a segment managed by a class location special permit. PHMSA has denied approximately half of the requests submitted, generally for having unsuitable pipe characteristics based on design and operating parameters. Having spent the past twenty years reviewing data, detail, and pipe characteristics in administering the class location special permit program, PHMSA is confident that IM principles can be used to confirm or restore the MAOP of Class 1 to Class 3 and Class 2 to Class 3 change segments.

38

38

PHMSA has never issued a special permit to waive the class location requirements for a pipeline segment in a Class 4 location.

III. Summary of the NPRM

On July 31, 2018, PHMSA published an advance notice of proposed rulemaking (ANPRM) seeking public comment on whether to amend the requirements in part 192 for addressing class location changes.

39

PHMSA received 24 comments from a variety of stakeholders in response to the ANPRM, including operators such as Kinder Morgan, Inc. and the Williams Companies (Williams), the Pipeline Safety Trust (PST), the National Association of Pipeline Safety Representatives (NAPSR), the GPA Midstream Association, individual engineers and citizens, and a joint comment by the American Gas Association, American Petroleum Institute, American Public Gas Association, and Interstate Natural Gas Association of America. Many of the commenters reiterated concerns that had been raised in earlier proceedings, particularly from the industry perspective.

40

PHMSA also received a similar submission from 4,831 commenters recommending that current class location change requirements “remain in place pending further review through proposed rulemaking protocols” and to consider recommendations of the NTSB in light of prominent gas pipeline safety incidents.

41

39

Pipeline Safety: Class Location Change Requirements,

83 FR 36861 (July 31, 2018) (ANPRM).

40

This included feedback from a Notice of Inquiry in 2013,

Class Location Requirements,

78 FR 46560 (Aug. 1, 2013); public meetings in 2014; comments on the gas transmission NPRM in 2016; and comments to a DOT notice of regulatory review in 2017,

Notification of Regulatory Review,

82 FR 45750 (Oct. 2, 2017).

41

Comments, Docket ID PHMSA-2017-0151-0028 (Sept. 25, 2018). These NTSB recommendations were addressed in the 2019 Safety of Gas Transmission Rule.

See

84 FR at 52189.

After considering these comments, PHMSA issued a notice of proposed rulemaking (NPRM) on October 14, 2020.

42

The NPRM proposed to add an IM alternative for confirming the MAOP of certain class change segments. The NPRM reflected the extensive back and forth on the topic that had occurred between PHMSA, Congress, the public, and the regulated community over the previous years.

43

42

NPRM, 85 FR 65142.

43

See, e.g., supra

note 40; PHMSA,

Report to Congress: Evaluation of Expanding Pipeline Integrity Management beyond High-Consequence

Areas and Whether Such Expansion Would Mitigate the Need for Gas Pipeline Class Location Requirements

(June 6, 2016), available at:

https://www.phmsa.dot.gov/sites/phmsa.dot.gov/files/docs/news/55521/report-congress-evaluation-expanding-pipeline-imp-hcas-full.pdf.

PHMSA proposed a set of operating parameters and eligibility criteria in the NPRM for using an IM alternative. The segment would have to be changing from a Class 1 to a Class 3 location, be operating below a hoop stress corresponding to 72 percent SMYS, and be capable of assessment using ILI tools. Pipe with certain additional characteristics would be ineligible: bare pipe; pipe with wrinkle bends; pipe lacking traceable, verifiable, and complete material records; pipe without traceable, verifiable, and complete records of a pressure test to 1.25 times MAOP for at least eight hours; where the longitudinal seam had been formed by certain more vulnerable methods; poor external coating; pipe transporting gas not suitable for sale; pipelines with grandfathered MAOPs under § 192.619(c) or an alternative MAOP under § 192.619(d); or where the segment previously had a special permit denied. Many kinds of cracking found in or within five miles of the segment, or past experience of a leak or rupture due to cracking, would make a pipeline ineligible; cracking that may develop could subsequently remove a segment from eligibility. The NPRM proposed to also exclude pipe moving into Class 4 locations which are the areas of highest population density.

PHMSA further proposed that pipe coming into the program would need to follow the IM program in Subpart O and be assessed within 24 months of the change in class location by ILI tools validated to Level 3 under API Standard 1163.

44

Along with a reassessment interval of at least every seven years, the NPRM included a detailed anomaly response schedule for repairs needed based on the results of these assessments. The proposal included several other preventive and mitigative measures as well, such as requirements to perform close interval surveys, install a cathodic protection test station, install line markers, perform interference surveys, have adequate depth of cover, perform patrols and leak surveys at more frequent intervals, and clear shorted casings. Operators would also have to notify PHMSA of a new segment using this method, install remote-control or automatic shutoff valves, and examine pipe when otherwise excavated or uncovered.

44

Am. Petroleum Inst. (API), API Standard 1163,

In-line Inspection Systems Qualification

(2nd Ed. 2013).

A 60-day public comment period followed publication of the NPRM. PHMSA received 14 initial comments from a variety of stakeholders, including pipeline industry trade associations, members of NAPSR, the NTSB, public advocacy groups such as the PST and Accufacts Inc. (Accufacts), and operators including TC Energy Corporation (TC Energy). The pipeline trade associations submitted a joint comment from the American Gas Association, American Petroleum Institute, American Public Gas Association, GPA Midstream Association, Interstate Natural Gas Association of America, and NACE International Institute (collectively, the “Associations”). Several other operators, including NiSource, Southwest Gas, and Paiute Pipeline Company, submitted comments supporting the Associations' comment. Commenters across the spectrum supported expanding a strong IM option to manage class location changes. Industry representatives noted the efficiencies it would provide without a drop in safety, while public advocates appreciated how the proposal balanced eligible pipe, the IM requirements, and other supplemental program requirements.

PHMSA held a public meeting of the Gas Pipeline Advisory Committee (GPAC) on March 27 to 29, 2024, to review the NPRM and supporting analyses.

45

The meeting afforded time for additional public comments and discussion by members of the committee. Pursuant to 49 U.S.C. 60115, the GPAC assessed the technical feasibility, reasonableness, cost-effectiveness, and practicability of the standard proposed in the NPRM. The transcripts and the vote slides constitute the GPAC report for this rulemaking under 49 U.S.C. 60115; PHMSA acknowledged receipt of this report and responded.

46

45

See

GPAC,

Minutes for GPAC March 2024 Meeting,

Docket ID PHMSA-2024-0005-0408; GPAC,

Voting Slides,

Docket ID PHMSA-2017-0151-0068. The transcript for each day is available via docket number PHMSA-2024-0005 accessible through regulations.gov. GPAC members also reviewed comments received on the NPRM.

46

PHMSA,

Response to the GPAC's Report on the `Class Location Change Requirements' Proposed Rule,

Docket ID PHMSA-2024-0005-0424 (Dec. 11, 2024).

PHMSA provided an additional 150-day period for written public comment following the GPAC meeting.

47

PHMSA received 10 additional comments during that period from the Associations, the PST, individual operators including Enbridge and Williams, several members of the general public, as well as two then-members of the Committee, Andy Drake and Chad Zamarin, acting in their individual capacity.

47

Meeting Notice,

89 FR 26118 (Apr. 15, 2024). PHMSA extended the period for submitting written comments after the GPAC meeting to 150 days at the request of several industry associations.

PHMSA considered all comments submitted in response to the NPRM in developing this final rule, including the initial written comments, the oral comments provided at the GPAC meeting, and the written comments filed after the GPAC meeting. Public comments to the NPRM are available on the docket for this rulemaking, PHMSA-2017-0151, while comments in response to the GPAC are available on the docket PHMSA-2024-0005. Both are accessible through

regulations.gov.

IV. Discussion of the Final Rule and Analysis of Comments

The following subsections summarize the proposals in the NPRM, the relevant issues raised by the commenters, and the discussions and recommendations of the GPAC. Subsections conclude by providing PHMSA's responses as developed in preparing and issuing the final rule.

A. General

1. Summary of Proposal

The NPRM proposed to allow operators to use an IM alternative to confirm the MAOP of certain segments that experience class location changes. Modeled on PHMSA's class location special permit program, the proposed IM alternative included a list of eligibility criteria and required compliance with an ongoing program of IM and supplemental O&M requirements.

2. Comments Received

The Associations supported the IM alternative, stating that the objective of class locations to ensure an appropriate safety margin when population growth occurs around an existing pipeline “can now be accomplished using modern integrity management programs, which are a more effective, efficient, environmentally sound and less disruptive means of managing pipeline safety.”

48

The Associations suggested that the IM alternative in general will improve safety, is more cost effective, will reduce emissions, and reduce community impacts. Mr. Drake commented that the historical approach for addressing class changes is outdated and inefficient, observing that the

approach fails to account for the diameter, strength, and operating pressure of a pipeline, and for recent advancements in threat detection and assessment technology.

49

48

Associations, Comments, Docket ID PHMSA-2017-0151-0061 at 4 (Dec. 14, 2020).

49

See

Andy Drake, Comments, Docket ID PHMSA-2024-0005-0419 at 2 (Aug. 27, 2024).

Williams, which operates approximately one third of the Nation's natural gas transmission and gathering infrastructure, commended the regulatory flexibility provided by the IM alternative, noting that technological and methodological improvements allow operators to “assess risk with a level of detail and certainty that was not available 10 years ago.”

50

The proposed rule, Williams commented, would allow operators to benefit from these advancements in technology and improvements to IM in Subpart O through the 2022 Safety of Gas Transmission Rule and increase pipeline safety nationwide. Several private citizens similarly supported the proposal, noting that the IM alternative “offers solutions and incentives to improve” pipeline systems and provides benefits to consumers, as reductions in MAOP from population increases near pipelines would likely result in less reliable gas distribution.

51

50

Williams, Comments, Docket ID PHMSA-2024-0005-0421 at 3 (Aug. 27, 2024).

51

Alina Rutherford, Comments, Docket ID PHMSA-2017-0151-0031 (Dec. 2, 2020).

Members of NAPSR, an organization comprised of PHMSA's State pipeline safety partners, were divided on the proposal. Several members expressed support for the NPRM if each of the proposed requirements were accepted, noting that “it appears that adequate safeguards are in place to ensure safety is not compromised.”

52

On the other hand, several NAPSR members were concerned about relaxing class-based design requirements and using IM to manage class location changes based on their experience observing operators “poor management and decision making in implementing [IM] requirements,” pointing to the 2010 Marshall, Michigan incident.

53

Some of these NAPSR members feared that PHMSA would be sacrificing pipeline safety by adopting the proposed rule, stating that the issues of managing and implementing the IM alternative would be less reliable and effective than the design measures that would be replaced. Accufacts noted that though it had anticipated the implementation of IM would reduce the number of pipeline ruptures, several ruptures on pipelines operating at pressure below MAOP well before the times predicted by operators engineering assessments under IM had undercut that assumption. Accufacts stated that the number of ruptures occurring shortly after ILI tool runs is creating a “credibility gap” with the public that will only be compounded if ILI effectiveness continues to be “oversold and misrepresented as to its capability.”

54

But, Accufacts found that the proposal addressed these concerns by an articulated response schedule for eligible segments.

55

52

NAPSR, Comments, Docket ID PHMSA-2017-0151-0059 at 5 (Dec. 14, 2020).

53

Id.

at 2.

54

See

Accufacts, Comments, Docket ID PHMSA-2017-0151-0058 at 2 (Dec. 14, 2020).

55

Docket ID PHMSA-2017-0151-0058 at 3-4.

While the PST was “not convinced of the necessity of this rule, given the existing options for operators to manage their class location changes,” it appreciated the seriousness of PHMSA's proposal. The PST agreed that PHMSA's limitation on eligibility, plus O&M requirements added to the IM requirements, increased the likelihood that the rule will not decrease safety. However, the PST preferred the status quo of class location design requirements, plus special permits on a case-by-case basis, as a “safety backstop. . .to reduce the risk of a failure resulting from shortcomings in an IM plan.”

56

56

PST, Comments, Docket ID PHMSA-2017-0151-0063 at 2, 8 (Dec. 14, 2020).

NAPSR members agreed that, as proposed, the requirements for managing a class change without an improvement in design standards should exceed the IM requirements.

57

The PST agreed that PHMSA's limitation on eligibility, plus O&M requirements added to the IM requirements, demonstrated a careful proposal to “maintain[] an equivalent level of safety” that is provided by the historical management options.

58

Accufacts supported the proposal as written with the additional prescriptive requirements beyond the then-current IM regulations, noting that the additional requirements would help offset the limitations of ILI assessment methods. Accufacts noted how pipeline failures observed after operators perform ILI tool runs justified excluding certain pipe from eligibility and “the need to include a combination of additional prescriptive requirements to address shortcomings in many company applications of their IM approaches defined in Subpart O,” as did the proposal.

59

In addition, Mr. Drake argued that PHMSA's final rule should incorporate the “standard of care based on the latest technology for inspection, assessment, and repair criteria” established under the 2019 and 2022 Safety of Gas Transmission Rules.

60

57

See

Docket ID PHMSA-2017-0151-0059 at 2-3.

58

Docket ID PHMSA-2017-0151-0063 at 8.

59

Docket ID PHMSA-2017-0151-0058 at 2.

60

Docket ID PHMSA-2024-0005-0419 at 2.

An anonymous commenter viewed the GPAC recommendations for the rule (which are discussed in the ensuing sections) as “major changes” and suggested PHMSA “re-review the safety and integrity of changes proposed in the GPAC Voting Slides . . . and then re-notice the rule for public comment.”

61

Another anonymous commenter suggested that an environmental, cost-benefit, and safety analysis on the overall effect of the GPAC recommendations to the public in the area around pipelines should be developed and publicly noticed.

62

61

Anonymous, Comments, Docket ID PHMSA-2024-0005-0415 at 1 (Aug. 28, 2024).

62

Anonymous, Comments, Docket ID PHMSA-2024-0005-0422 at 1 (Aug. 28, 2024).

Many commenters lauded PHMSA's class location special permit program and noted the similarities between that program and the proposed rule. Highlighting how PHMSA stated in the 2003 Gas IM Rule that experience and data from special permits using IM may lead to future regulatory changes in the class change requirements, the Associations offered that decades of experience demonstrate the effectiveness of IM for managing class location changes.

63

Mr. Drake noted the “excellent performance record” of pipelines in the special permit program—improving pipeline safety and reducing environmental impacts—demonstrating “the feasibility and effectiveness of IM as an alternative to class location change pipe replacements or pressure reductions.”

64

63

See

Docket ID PHMSA-2017-0151-0061 at 5-8.

64

Docket ID PHMSA-2024-0005-0419 at 2.

The NTSB expressed concern with drawing conclusions from the operating history of special permit segments, based on the small sample size and small percentage of Class 3 gas transmission mileage. The NTSB noted how special permits are “rigorous by design” and encouraged PHMSA to “consider how [to] provide the same level of scrutiny and attention to detail on the larger scale of locations impacted by this regulation.”

65

65

NTSB, Comments, Docket ID PHMSA-2017-0151-0055 at 3-4 (Dec. 10, 2020).

The PST expressed appreciation for the “hard look” PHMSA engages in when considering each special permit, noting that it allows PHMSA to impose prescriptive measures specific to an operator's past performance and the type of pipe and environment in which

the pipe is located. In addition, the PST stated that the data and documents required for special permit applications, including National Environmental Policy Act compliance, benefit the public by providing notice of the application, the location of the waivers, material characteristics about the pipeline, and ensures PHMSA has the opportunity to review the details of each application before acting on it.

66

66

Docket ID PHMSA-2017-0151-0063 at 2.

While commending the record of special permits to date, the Associations raised several complications posed by the existing special permit process, including: the length of the review process, changing compliance conditions, an uncertain renewal process, and burdensome administrative work—all of which reduce operator participation. Codifying the IM alternative, the Associations argued, would provide more clarity, consistency, and alignment with other previously existing regulations.

67

67

Docket ID PHMSA-2017-0151-0061 at 11.

Commenters also noted the significant benefits of authorizing the IM alternative. Williams argued that the proposal would provide an additional benefit of lowering emissions by “avoiding [blowdowns and] the unnecessary replacement of perfectly good pipe.”

68

The Associations likewise observed that “the environmental benefits of applying integrity management requirements instead of replacing. . .pipe are as compelling as the safety benefits,” estimating that class change pipe replacements under the former regulatory regime resulted in up to “800 million standard cubic feet of natural gas blowdown to the atmosphere each year,” which “could meet the [natural gas] needs of over 10,000 homes for a year.”

69

68

Docket ID PHMSA-2024-0005-0421 at 3.

69

Docket ID PHMSA-2017-0151-0061 at 10-11.

The Associations estimated that “gas transmission pipeline operators spend $200-$300 million annually to replace pipe solely to satisfy the [historical] class location change regulations.” Instead of being allocated to replacing less than 75 miles of pipe per year, the Associations argued that this capital investment could be reallocated to “assess over 25,000 miles [of pipe] with in-line inspection, install [ILI tool] launchers and receivers to enable over 5,000 miles of pipeline to be assessed with in-line inspection tools for the first time, or conduct over 4,000 anomaly evaluation digs.”

70

Focusing these resources on segments changing class and expanding the 2019 and 2022 revisions to Subpart O IM regulations to greater pipeline mileage, Williams suggested, will increase safety in these class change segments, improve the IM program, and “reduc[e] risk across natural gas pipelines [throughout] the United States.”

71

70

Id.

at 5. The Associations note that this mileage figure equates to a replacement of less than 0.05 percent of the gas transmission pipeline network.

71

Docket ID PHMSA-2024-0005-0421 at 2.

3. PHMSA Response

PHMSA appreciates the strong public engagement that occurred throughout the rulemaking process. The NTSB, public advocates, and industry groups each commended the success of the class location special permit program, which provides two decades of data and real-world experience implementing the IM alternative. That data and experience, when combined with the significant improvements to the IM program that have occurred in recent years, strongly support adopting the requirements in this final rule.

PHMSA and operators have gained valuable experience applying the IM alternative through the class location special permit program. That program has led to the development of eligibility criteria and special permit conditions that have a proven track record of ensuring the safety and reliability of gas transmission lines. Rather than continuing to require the use of the special permit process to provide relief from outdated and unduly burdensome requirements, the final rule adopts the relevant eligibility criteria and conditions by regulation. This allows operators and PHMSA to direct their limited resources toward performing other critical safety functions.

As discussed in more detail in the ensuing subsections, the IM alternative that PHMSA is adopting in this final rule sets forth a standardized set of requirements to safely manage class location changes without requiring unnecessary MAOP reductions, pipe replacements, or pressure tests. The key features of the IM alternative include:

• First, the final rule defines under eligibility those pipeline characteristics that can safely be managed by the program.

• Second, to use the program, an eligible class change segment must be designated as an HCA and incorporated into an operator's IM program in Subpart O. The final rule also includes IM requirements for the baseline assessment, periodic reassessment, assessment methods, and remediation schedule specific to class change segments and their surrounding inspection area.

• Third, the final rule includes supplemental O&M measures based on historical special permit conditions.

• Fourth, the final rule requires maintaining an operating pressure no greater than the design factor corresponding to the original class location and retention of pipeline records. Any segment which experiences an in-service leak from the pipe itself cannot use the IM alternative.

Compliance with these requirements provides a margin of safety that meets or exceeds the historical approach for confirming the MAOP of segments that experience class location changes.

As multiple commenters favorably noted, the IM alternative proposed in the NPRM and adopted in this final rule retains the core elements of the successful class location special permit program. PHMSA agrees with commenters that each of these core elements is necessary to provide for the safety of the eligible Class 3 segments. PHMSA is incorporating the IM alternative directly into § 192.611 as a new paragraph (a)(4) instead of in an entirely new § 192.618 as proposed in the NPRM. For clarity, the program requirements are bifurcated into “one-time” programmatic requirements under § 192.611(a)(4)(i), which must be in place within a 24-month window, and “ongoing” programmatic requirements listed at § 192.611(a)(4)(ii) that must be carried out periodically. The requirements standardized in this final rule, based on years of success through the special permit program, no longer require the individual review of a special permit excepting regulatory requirements.

While several commenters expressed concerns with deficiencies or gaps identified in past incident investigations involving covered segments subject to Subpart O, PHMSA has taken significant actions to address those concerns in other recent rulemaking proceedings. As discussed in section II.C, PHMSA updated the Subpart O requirements in the 2022 Safety of Gas Transmission Rule in response to incidents that occurred after the original adoption of the IM program. PHMSA is confident in the strengthened IM framework that exists today, as were many participants at the GPAC and commenters following the meeting who encouraged PHMSA to incorporate those requirements into this rule.

Many of the requirements of the 2022 Safety of Gas Transmission Rule, such as the remediation criteria, were proposed in this NPRM and have historically been included in class location special permits. Those parts of the NPRM that have since been codified

into Subpart O no longer need duplication in this final rule and are included in the IM alternative by cross-reference to Subpart O, as was recommended by commenters and during the GPAC meeting. This streamlines and clarifies the IM alternative without substantive change. By incorporating the amendments from the 2022 Safety of Gas Transmission Rule into the IM alternative, PHMSA is responding to the concerns expressed by some commenters about incidents that occurred in the early stages of the IM program. PHMSA is also aligning the IM alternative with the conditions developed during the class location special program, as recommended by the commenters.

PHMSA reiterates its appreciation for the input received throughout the rulemaking process, particularly the comments submitted in response to the ANRPM, the NPRM, and the GPAC's report. These comments have allowed PHMSA to develop a final rule that embodies the views of multiple stakeholders and is supported by a well-developed administrative record.

B. Definitions

1. Summary of Proposal

The NPRM proposed to add definitions for three new terms in § 192.3. First, the NPRM proposed to define the precise segment changing class as the “Class 1 to Class 3 location segment.” Second, the NPRM proposed to define the span of the pipeline from the nearest upstream ILI launcher and downstream ILI receiver containing the class change segment as the “in-line inspection segment.” That definition was proposed to align with the phrase “special permit inspection area” as used in the class location special permit program. Third, the NPRM proposed to define the term “predicted failure pressure” as used in the Federal Pipeline Safety Regulations for many years.

2. Comments Received

Several commenters found using the term “Class 1 to Class 3 segment” to be confusing and restrictive, and sought a simpler definitional term. Further substantive comments regarding this term are expanded on in section IV.C.ii. Editorially, the Gas Piping Technology Committee (GPTC) stated that the inclusion of the word “and” between the numbered list within the “Class 1 to Class 3 location segment” could imply that if an operator does not confirm or revise a pipeline segment's MAOP in accordance with § 192.611(a)(4), the operator does not come into the IM alternative program and therefore cannot be eligible.

72

Oleksa and Associates suggested that the proposed changes to § 192.903 were “circular and confusing,” and that they seemed to imply that “an operator might not designate a Class 1 to Class 3 location segment as [an HCA] and that there might be some Class 1 to Class 3 location segments that are not [HCAs.]”

73

They requested PHMSA clarify and provided editorial suggestions for doing so.

72

See

GPTC, Comments, Docket ID PHMSA-2017-0151-0065 at 3 (Dec. 14, 2020).

73

Oleksa and Associates, Docket ID PHMSA-2017-0151-0067 at 1 (Dec. 9, 2020).

Regarding the proposed definition of “in-line inspection segment,” multiple commenters, including NAPSR, Sander Resources, and GPTC, recommended focusing on the IM alternative program only, since many operators already use that term to refer to any section of a pipeline between ILI launchers and receivers. In addition, commenters were concerned that the term could be misapplied or cause confusion because applicable segments may or may not contain segments using the IM alternative option.

74

Further, Sander Resources stated that PHMSA used the word “adjacent” within the proposed definition of “in-line inspection segment” without guidance to what that word means. It noted that the historical 25-mile distance PHMSA references in the NPRM is “significant and appears to be arbitrary without further direction” and requested PHMSA clarify that operators need not assume “large segments of pipe are subject to the review and [MAOP reestablishment] process” but can instead establish and justify their own area of review as appropriate.

75

74

See, e.g.,

GPTC, Docket ID PHMSA-2017-0151-0065 at 3-4; Sander Resources, Comments, Docket ID PHMSA-2017-0151-0064 at 3 (Dec. 14, 2020); NAPSR, Docket ID PHMSA-2017-0151-0059 at 4.

75

Docket ID PHMSA-2017-0151-0064 at 3.

Regarding the proposed definition of “predicted failure pressure,” NAPSR and GPTC recommended that PHMSA consider adding the phrase “as determined by the procedures in ASME/ANSI B31G or PRCI PR-3-805 (as incorporated by reference in § 192.7).” Each suggested that this addition would be consistent with similar language used in §§ 192.485 and 192.933(a) and would “provide the same limitations as currently found in [the] code.”

76

NAPSR members also recommended changing the term “appropriate engineering evaluation” to “acceptable engineering evaluation,” which, they argued, might provide “a stronger basis from which to argue potentially subjective engineering evaluations.”

77

The Associations suggested a minor change to the proposed definition clarifying that the safety factor is “added,” rather than “included.”

78

Oleksa and Associates requested PHMSA clarify the definition to indicate that it “applies only to failure by rupture” by modifying it such “that it would not apply to low-pressure, low-stress steel transmission lines” and limit its application “to steel pipelines operating at pressures above 20 percent SMYS.”

79

76

NAPSR, Docket ID PHMSA-2017-0151-0059 at 4; GPTC, Docket ID PHMSA-2017-0151-0065 at 4.

77

Docket ID PHMSA-2017-0151-0059 at 4.

78

Docket ID PHMSA-2017-0151-0061 at 32.

79

Docket ID PHMSA-2017-0151-0067 at 1.

3. PHMSA Response

PHMSA has made clarifying edits to the definitions as suggested by commenters to simplify application of the IM alternative. This final rule does not finalize a definition of “predicted failure pressure” as proposed in the NPRM. PHMSA adopted new anomaly assessment and remediation criteria that use the predicted failure pressure concept in a final rule issued after publication of the NPRM and is not modifying those requirements in this proceeding. PHMSA concludes that the new anomaly assessment and remediation criteria render the proposed definition of predicted failure pressure definition unnecessary, and that the term has been consistently used in the regulations for many years without need for additional clarity.

This final rule adopts the term “eligible Class 3 segment” to define the specific segments changing class using this IM alternative option. This replaces the proposed term “Class 1 to Class 3 location segment,” which numerous commenters noted was unnecessary lengthy and confusing, and resolves other editorial comments by GPTC and Oleksa and Associates. This final rule explicitly includes the eligible Class 3 segment in the definition of an HCA at § 192.903. PHMSA has also included several eligibility factors into this definition as discussed in section IV.C.

This final rule adopts the term “eligible Class 3 inspection area” to define the eligible Class 3 segment and the portion of pipeline extending to the nearest upstream ILI launcher and downstream ILI receiver. This term includes the eligible Class 3 segment and the surrounding ILI inspection area. While conceptually equivalent to what PHMSA proposed as an “in-line inspection area” and the “special permit inspection area” in class location

change special permits, this language avoids conflict with the oft used term “in-line inspection,” as commenters requested. Clearly defining the term also addresses concerns raised by Sander Resources regarding potential confusion with how pipelines outside of the class change area were handled in historical special permits. While the eligible Class 3 inspection area is not itself defined as an HCA under § 192.903, it is subject to certain IM requirements as specified in § 192.611(a)(4). These requirements are described in greater detail in section IV.D of this final rule.

The definitions of “eligible Class 3 segment” and “eligible Class 3 inspection area” are specifically limited to gas transmission lines. Section 192.611(a)(4)(vii) further clarifies that the IM alternative is not authorized for gas gathering or gas distribution lines. While the class location change requirements in § 192.611 apply broadly to all gas pipelines, PHMSA indicated in the NPRM and preliminary RIA that the proposed IM alternative would only apply to gas transmission lines. Having failed to address the applicability of that proposal to gas gathering or distribution lines in either document, PHMSA concludes that the IM alternative should be limited to gas transmission lines in the final rule.

80

80

PHMSA recognizes that some regulated gas gathering lines may experience class location changes that are subject to the requirements in § 192.611.

See

49 CFR 192.8, 192.9. However, PHMSA is not aware of any regulated gas gathering line operator ever filing an application for a class location special permit and does not have the information necessary to determine whether and to what extent the use of the IM alternative should be extended to gas gathering lines.

C. Eligibility Criteria

i. General

1. Summary of Proposal

The NPRM set out proposed eligibility criteria for use of the IM alternative. PHMSA developed these eligibility criteria from its experience applying the 2004 Special Permit Criteria, published following the initial 2003 Gas IM Rule. In the 2004 criteria and guidance, PHMSA established pipe criteria and conditions that would lead to “probable acceptance” of a special permit to manage a class location change consistent with pipeline safety.

81

Each of the criteria are discussed in further detail in individual sections below.

81

PHMSA, 2004 Special Permit Criteria.

2. Initial Comments

The NTSB supported the proposed eligibility criteria, observing how “[t]he majority of the restrictions . . . concur[red] with the NTSB's historical knowledge of higher risk pipelines.”

82

The PST found the eligibility exclusions appropriate and “absolutely necessary to ensure that [the IM alternative does] not jeopardize pipeline safety in these newly-populous areas.”

83

The PST was pleased the NPRM did not leave identification of eligible segments up to the operator. Accufacts similarly supported the eligibility criteria as technically sound and noted how the attributes reflect the strengths and weaknesses (or limitations) of various assessment approaches used in Subpart O and what pipe could suitably be assessed and managed by ILI.

84

Operators, like TC Energy, also agreed with the majority of the eligibility criteria.

85

82

Docket ID PHMSA-2017-0151-0055 at 4.

83

Docket ID PHMSA-2017-0151-0063 at 4.

84

Docket ID PHMSA-2017-0151-0058 at 3.

85

See

TC Energy, Comments, Docket ID PHMSA-2017-0151-0062 at 4-5 (Dec. 14, 2020). Oleksa and Associates, observing how the rule was aimed at protecting against pipeline incidents, noted that steel pipe operating at low stress levels cannot rupture and recommended that PHMSA make clear several eligibility criteria and other provisions do not apply to “pipe that operates at 100 psig or more,” or “pipelines that operate with an MAOP less than 20 percent of SMYS.” Docket ID PHMSA-2017-0151-0067 at 2. As this 20 percent of SMYS limit corresponds to the threshold at which a pipeline is a gas transmission line under § 192.3, and given this rule applies only to gas transmission lines, further clarification is not needed.

Sander Resources requested clarification that an operator with a pipe segment that does not meet the eligibility requirements may still use the special permit process governing class location changes.

86

Relatedly, the NTSB urged PHMSA to consider how to ensure operators will comply with the criteria without the extensive, individualized special permit process.

87

86

Docket ID PHMSA-2017-0151-0064 at 2.

87

Docket ID PHMSA-2017-0151 at 3-4.

3. GPAC Consideration

The GPAC discussed the NPRM's eligibility criteria during the public meeting on March 28 and March 29, 2024, with most members supporting the criteria establishing the types of pipe segments deemed suitable for the program, as discussed below in individual subsections.

4. Post-GPAC Comments

During the public comment period following the GPAC meeting, an anonymous commenter recommended PHMSA make no changes to the proposed eligibility criteria in consideration of the GPAC recommendations, stating they were not publicly noticed for comments and reviewed by the public for their impact on pipeline integrity, public safety, and environmental consequences.

88

88

Docket ID PHMSA-2024-0005-0422 at 1-2 (Aug. 28, 2024).

But see

GPAC,

Class Location NPRM GPAC Voting Slides,

Docket ID PHMSA-2024-0005-0275 (Apr. 5, 2024).

5. PHMSA Response

PHMSA is including eligibility criteria in the final rule to ensure that the IM alternative is only used to confirm or restore the MAOP of pipe or segments with appropriate characteristics. PHMSA has determined that segments with certain characteristics present an unacceptable risk to public safety and should not be eligible. That determination is supported by PHMSA's technical expertise and two decades of experience administering the class location special permit program. Operators of pipeline segments that do not meet the eligibility criteria may continue to seek special permits to manage class location changes. PHMSA may also consider modifying some of the eligibility criteria in subsequent rulemaking proceedings as additional information becomes available.

To eliminate unnecessary text and ensure consistency in the application of the IM alternative, the eligibility criteria are incorporated into the definition of an eligible Class 3 segment in § 192.3. Moreover, to more accurately account for their role as compliance obligations, several of the eligibility requirements proposed in the NPRM have been incorporated into the initial or ongoing programmatic requirements in the IM alternative. This better reflects that, for example, an operator can perform a pressure test on an eligible Class 3 segment to use the IM alternative, so that requirement is not

per se

a pipeline characteristic that dictates eligibility. The gas quality assurance is also an ongoing compliance requirement, not a criterion that needs to be satisfied beforehand to use the IM alternative. With those retained as compliance obligations, the eligibility criteria in § 192.3 are limited to immutable pipeline characteristics which define a segment as eligible to use the program.

Considering recommendations from the GPAC, public comments, and additional study by the Agency, PHMSA makes certain adjustments to the eligibility criteria in this final rule, as discussed throughout section IV.C below.

ii. Original Class

1. Summary of Proposal

The NPRM proposed an IM alternative to manage changes to Class

3 locations and specifically excluded pipe moving to a Class 4 location. The NPRM referred to the segment applying the IM alternative as the “Class 1 to Class 3 location segment” and proposed defining that term in § 192.3. PHMSA's class location special permit criteria categorizes as “probable acceptance” Class 2 to 3 changes, and Class 1 to Class 3 changes as “possible acceptance.”

89

89

PHMSA, 2004 Special Permit Criteria at 4.

2. Initial Comments

Many commenters questioned whether PHMSA intended to limit the IM alternative to Class 1 to Class 3 changes. TC Energy noted that the NPRM seemed to include all Class 1 design pipe, even if that pipe may first have changed to a Class 2 location before later changing into a Class 3 location.

90

Several commenters, including TC Energy and Sander Resources, recommended a different term than “Class 1 to Class 3 location segment” to avoid uncertainty over whether this method could include Class 2 to Class 3 changes.

91

The Associations suggested changing the term to “Class 3 location change segment.”

90

See

Docket ID PHMSA-2017-0151-0062 at 2.

91

See id.;

Docket ID PHMSA-2017-0151-0064 at 3-4.

The Associations recommended that the IM alternative be available for Class 2 to Class 3 changes as well, explaining that “segments with a [C]lass 1 design factor that experienced a change to [C]lass 2 in prior years and then to [C]lass 3 . . . are no different than segments that jump” directly from Class 1 to Class 3. The Associations also observed that Class 2 pipe is required under § 192.619(a)(2) to be pressure tested to 1.25 times MAOP at the time of installation; while noting that “many operators `over test' [C]lass 2 segments today” to the Class 3 test pressure “to allow for the one-class bump provided under § 192.611,” the Associations stated that “this has not always been common practice” and there may be Class 2 segments with a 1.25 times MAOP pressure test that should be eligible for the IM alternative. Extending the IM alternative to Class 2 to Class 3 changes could avoid the higher 1.5 times MAOP pressure test required by § 192.611(a)(1) or (3) for a Class 2 design pipe “to continue operating at its original MAOP” after a change to a Class 3.

92

92

Docket ID PHMSA-2017-0151-0061 at 15.

3. GPAC Consideration

The GPAC voted 13-0

93

in favor of allowing operators to apply the IM alternative to Class 2 design pipe with a 1.25 times MAOP pressure. The GPAC also included the 1.25 times MAOP pressure test in its recommendations on grandfathered pipe and MAOP restoration.

93

Two votes occurred with this language, following extended discussions. First, a vote combining this recommendation and consideration of a public notification requirement passed 10-3. Second, a vote isolated just to this Class 2 pressure test passed 13-0.

4. Post-GPAC Comments

The Associations expressed support for the GPAC recommendation, observing that a 1.25 times MAOP pressure test provides an “acceptable safety factor to mitigate manufacturing and construction risks” for pipeline segments that experience Class 2 to Class 3 changes.

94

The PST also agreed with the GPAC recommendation to expand eligibility to Class 2 design pipe, so long as the other eligibility criteria are met.

95

94

Associations, Comments, Docket ID PHMSA-2024-0005-0423 at 5 (Aug. 27, 2024).

95

PST, Comments, Docket ID PHMSA-2024-0005-0417 at 2 (Aug. 27, 2024).

5. PHMSA Response

PHMSA agrees that the IM alternative should be available for Class 2 to 3 changes. PHMSA's 2004 Special Permit Criteria provided Class 2 to 3 changes merited “probable acceptance,” even more likely to warrant a special permit than the Class 1 to 3 changes that were marked for “possible acceptance.” After beginning primarily with one class changes, PHMSA's successful history with operators managing class location changes from Class 2 to 3 under special permits issued since 2004 led to more regular issuance of special permits for Class 1 to 3 changes. As a result, special permits have been granted in about equal part between segments moving from Class 1 locations into Class 3 and those moving from Class 2 locations into Class 3. PHMSA finds it consistent with pipeline safety to extend the applicability of this final rule to segments that have changed from Class 2 to Class 3. As several commenters note, this also makes clear that pipelines of Class 1 original design that were in a Class 2 location until subsequently changing to Class 3 can use the IM alternative all the same as if they transitioned directly from Class 1 to 3.

Ultimately, PHMSA does not expect a significant number of Class 2 to 3 changes to apply the IM alternative. Operators of these segments are likely to use the “one-class bump” afforded by a pressure test in accordance with § 192.611(a)(1) or (3). A pipeline is generally designed to tolerate the test pressure required for the next highest class location, enabling Class 2 design pipe to conduct the “one-class bump” pressure test to Class 3 design standards and complete the obligations to manage the class change. Managing a class change by pressure test lacks the additional program management requirements of the IM alternative. Because Class 1 design pipe often cannot tolerate a test pressure to two classes higher, the IM alternative enables a lower (1.25 times MAOP) test pressure balanced with additional program management requirements. There is no reason to apply a different approach to Class 2 design pipe. For example, as the Associations note, there may be some Class 2 pipe where an operator already has a 1.25 times MAOP pressure test, does not have a higher pressure test to Class 3 standards, and prefers the IM alternative program rather than perform a new pressure test at a higher test pressure. There is no reasonable safety basis to prohibit providing this option to operators of these lesser included pipelines.

As discussed in section IV.B, PHMSA is replacing the proposed term “Class 1 to Class 3 location segment” with the defined term “eligible Class 3 segment” in the final rule. PHMSA agrees with the commenters that the use of the former term in the NPRM created uncertainty as to whether the IM alternative could be applied to Class 2 to Class 3 changes. PHMSA is eliminating that uncertainty by using the term “eligible Class 3 segment” as defined in § 192.3.

iii. SMYS Limitations

1. Summary of Proposal

The NPRM proposed that pipeline segments eligible for the IM alternative must operate with an MAOP producing a hoop stress of 72 percent or less of SMYS. SMYS is an indication of the minimum stress that a steel pipe may experience before becoming permanently deformed. A 72 percent of SMYS limitation corresponds to the general requirement for steel pipe in Class 1 locations to satisfy a design factor of 0.72. PHMSA's class location change special permit criteria lists as “probable acceptance” pipelines operated at “less than or equal to 72 percent of SMYS.”

96

96

PHMSA, 2004 Special Permit Criteria at 4.

2. Initial Comments

Commenters generally agreed that 72 percent of SMYS threshold is

appropriate. Some industry commenters sought clarification on how this requirement would apply to Class 2 design pipe. TC Energy observed that the NPRM seemed to permit use of the IM alternative for pipeline segments “operating at a hoop stress over 60 [percent] of the SMYS and up to and including 72 [percent] of the SMYS” that have moved to a “Class 3 [location], independent of whether the original class location area was Class 1 or 2.”

97

97

Docket ID PHMSA-2017-0151-0062 at 2.

3. GPAC Consideration

Public comment from members representing industry noted the long history of the 72 percent SMYS limit, dating back to industry standards adopted in the 1950s. Recognizing that this requirement is well established, the GPAC did not offer a direct recommendation on the merits of PHMSA's proposed SMYS limitations for the IM alternative. The Committee, through its debates and votes on restoration of MAOP (

see

section IV.C.xii), grandfathered pipe (

see

section IV.C.vi), and vintage seam types (

see

section IV.C.viii), implicitly endorsed this longstanding element as a fundamental requirement for use of the IM alternative.

4. Post-GPAC Comments

No significant additional comments on this issue were submitted after the GPAC.

5. PHMSA Response

The 72 percent of SMYS limitation in the IM alternative is consistent across part 192 as the maximum safety limit of operating steel gas pipelines.

98

It corresponds to the 0.72 steel pipe design factor of Class 1 pipe under § 192.111. Without a design change, the SMYS limitation for a pipeline must remain consistent with the original design factor.

98

It is also consistent in the prevailing industry consensus standard, ASME B31.8-2022, §§ 840.2.2, 841.1.1(c). A design factor of up to 0.80 is authorized for Class 1 locations in limited circumstances in accordance with § 192.620 or with a special permit for waiving certain requirements at §§ 192.111 and 192.201; such segments would be ineligible for the IM alternative to class location changes.

In addition to retaining the 72 percent SMYS requirement, PHMSA has added a hoop stress threshold to facilitate Class 2 design pipe applying the IM alternative. Where a Class 2 design pipe changes to a Class 3 location, the IM alternative requires that the operator maintain an MAOP corresponding to a hoop stress of no more than 60 percent of SMYS. The 60 percent of SMYS limit for Class 2 design pipe corresponds to the 0.60 steel pipe design factor of Class 2 pipe under § 192.111.

iv. Subpart J Pressure Test

1. Summary of Proposal

The NPRM proposed that an operator must have records documenting an 8-hour test in accordance with Subpart J to a minimum test pressure of 1.25 times MAOP, or that the operator perform such a pressure test within 24 months of the class location change, for a segment to be eligible for the IM alternative. PHMSA has consistently requested records of a 1.25 times MAOP pressure test during consideration of class location special permit applications.

2. Initial Comments

Commenters generally supported the proposed pressure testing requirements. TC Energy and the Associations both observed that Subpart J includes limited circumstances under § 192.505(d) where fabricated units and short section of pipe may be tested for four hours, not eight.

99

TC Energy was also concerned that specifying the pressure test as Subpart J-compliant could, contrary to intent, exclude tests which meet the testing requirements but were conducted before Subpart J was adopted in 1970. NAPSR indicated that some of its members favored requiring a new Subpart J test within 24 months of the class change in all cases.

100

99

See

Docket ID PHMSA-2017-0151-0062 at 8; Docket ID PHMSA-2017-0151-0061 at 27.

100

Docket ID PHMSA-2017-0151-0059 at 5.

3. GPAC Consideration

While not separately offering a recommendation as to this proposal, the GPAC voted 13-0 to extend the 1.25 times MAOP pressure test requirement to Class 2 design pipe during the public meeting on the NPRM.

4. Post-GPAC Comments

The Associations repeated similar points as before requesting allowance for those limited circumstances where Subpart J permits a 4-hour pressure test.

101

101

See

Docket ID PHMSA-2024-0005-0423 at 15. INGAA provided similar comments in a May 2025 response to a DOT request for information,

see

INGAA, Comments, Docket ID DOT-OST-2025-0026-0872, 6-7 (May 5, 2025), regarding

Ensuring Lawful Regulation; Reducing Regulation and Controlling Regulatory Costs,

90 FR 14593 (Apr. 4, 2025).

5. PHMSA Response

A 1.25 times MAOP pressure test is required to use the IM alternative. This same test pressure requirement applies to Class 1 and Class 2 design pipe using the IM alternative. To meet this requirement, an operator may rely on a prior pressure test or conduct a new pressure test, consistent with the proposal in the NPRM.

102

As PHMSA has stated previously, “the safety margin [provided by the test] rather than the act of retesting is the critical factor under § 192.611.”

103

Operators must comply with the pressure testing requirement within the initial, 24-month compliance window.

102

See

NPRM, 85 FR at 65175 (proposed § 192.618(a)(4)(v)) (“Pipe that has not been pressure tested in accordance with subpart J for 8 hours at a minimum test pressure of 1.25 times MAOP (

unless the segment passes a subpart J pressure test for a minimum of 8 hours at a minimum pressure of 1.25 times MAOP within 24 months after the Class 1 to Class 3 location segment change

” (emphasis added)).

103

Confirmation or Revision of Maximum Allowable Operating Pressure; Alternative Method,

53 FR 1043, 1044 (proposed Jan. 15, 1988).

The test hold time must meet the requirements of Subpart J. This addresses those limited circumstances where an 8-hour test is not required under § 192.505(d). In most cases, Subpart J will require at least an 8-hour test hold time. But this provides for, as noted by INGAA and TC Energy, use of the IM alternative for fabricated units and short sections of pipe where a shorter duration pressure test is permitted under § 192.505(d). PHMSA understands that tests using the hold time designated by Subpart J provide an equivalent and acceptable level of safety compared to the proposed requirement for an 8-hour post-installation strength test—a 4-hour test under § 192.505(d) applies only in narrow cases for “small valve and gate sites or any other small segments of pipeline that have been tested off-site.”

104

Because fabricated units or short sections of pipe are aboveground during the preinstallation test, and operators can continuously and directly inspect them for leaks during the test, PHMSA sees no reason to disadvantage these tests against the application of § 192.611(c) or (d).

104

INGAA, Docket ID DOT-OST-2025-0026-0872, 6-7.

The pressure test must be for a duration consistent with the requirements in Subpart J, to a pressure of at least 1.25 times MAOP, to use the IM alternative. An operator may use a prior test, as PHMSA has previously clarified that the duration of the test is the key factor for a pressure test to manage a class change, rather than its date.

105

A test performed after 1970 must meet the requirements in Subpart J. A test performed before 1970 must have been for a consistent duration as under Subpart J. An operator without

such a test may successfully complete one during the initial 24-month compliance window and then benefit from this IM alternative.

105

Confirmation or Revision of Maximum Allowable Operating Pressure; Alternative Method,

54 FR 24173, 24174 (June 6, 1989).

Some commenters sought clarification regarding application to pre-1970 pressure tests. PHMSA addressed this very issue in a late 1980s rulemaking, noting that many pressure tests performed prior to the establishment of the Federal Pipeline Safety Regulations (and so before the Subpart J requirements were established) met the industry best practice or standard in place at the time and could provide an adequate level of safety to manage a class change.

106

A pre-1970 pressure test for a hold time of 8 hours, except where a 4-hour duration would be permitted consistent with Subpart J, provides equivalent safety.

106

See

53 FR at 1044; 54 FR at 24174 (permitting “any prior test pressure held for at least 8 hours”).

See also Minimum Federal Safety Standards for Gas Pipelines,

35 FR 5724 (proposed Apr. 8, 1970) (noting wide similarity between the Minimum Standards for pressure testing with pre-1970 industry standards).

v. TVC Material Records

1. Summary of Proposal

The NPRM proposed requiring that a pipeline segment have traceable, verifiable, and complete (TVC) material records to be eligible for the IM alternative.

107

The TVC records had to include the diameter, wall thickness, grade, seam type, yield strength, and tensile strength

108

of the class change segment.

107

Further explanation of TVC records is available at 2019 Safety of Gas Transmission Rule, 84 FR at 52218-19 and PHMSA,

[First Batch of] Frequently Asked Questions for the [2019 Safety of Gas Transmission Rule]: MAOP Establishment and Reconfirmation FAQs,

FAQ-30 (Sept. 15, 2020), available at:

https://www.phmsa.dot.gov/sites/phmsa.dot.gov/files/2023-06/Batch-1-FAQs-PHMSA-2019-0225-9-15-20.pdf.

108

Ultimate tensile strength, or tensile strength as used in this final rule, is defined as the maximum stress that a material can withstand while being stretched or pulled before breaking. This is compared to yield strength, which is the stress at which a material starts to deform permanently.

The TVC records requirement proposed in the NPRM is consistent with PHMSA's longstanding practice of requesting records related to, among other things, testing, in-line inspections, and cathodic protection when reviewing class location special permit applications. Class location special permits have previously required TVC pressure test records and imposed additional testing and examination requirements on pipeline segments lacking such records.

2. Initial Comments

Commenters supported the proposed TVC records requirement. The Associations suggested that segments without complete TVC material records should be allowed to obtain those records within the initial 24-month compliance window using the process prescribed in § 192.607.

109

The Associations opposed requiring TVC records of tensile strength, which they characterized as a data point “without practical utility” that is “not required for anomaly evaluation or MAOP calculations, whereas diameter, wall thickness, grade, seam type, and yield strength are needed for those calculations.”

110

109

See

Docket ID PHMSA-2017-0151-0061 at 20-21.

110

Docket ID PHMSA-2017-0151-0061 at 21.

3. GPAC Consideration

Industry representatives on the GPAC stressed that operators should be allowed to use the IM alternative so long as TVC records are collected within the initial 24-month compliance period. Industry GPAC members offered that TVC records of tensile strength are not necessary because, while yield strength plays a role in design and safety decisions, tensile strength is only used as a buffer or an extra measure of confidence. Public representatives on the GPAC noted that the specification API 5L

111

sets limits for both yield strength and tensile strength for steel line pipe and suggested that having TVC records with information about each would likely be valuable.

111

API Specification 5L,

Line Pipe

(46th ed. Apr. 6, 2018).

The GPAC voted 12-0 in favor of allowing operators to use § 192.607 to obtain any necessary missing pipe properties within 24 months of the class change. The Committee also recommended that PHMSA consider not requiring the TVC records for tensile strength.

4. Post-GPAC Comments

The Associations repeated similar points as before the GPAC meeting.

112

An anonymous commenter emphasized the importance of TVC records to include ultimate tensile strength, stating that operators cannot obtain an accurate value for pipe steel yield strength without that information. The anonymous commenter also noted that TVC records are required under §§ 192.619 and 192.624, and suggested barring use of the IM alternative if an operator lacks such records.

113

112

See

Docket ID PHMSA-2024-0005-0423 at 6.

113

See

Docket ID PHMSA-2024-0005-0415 at 1.

5. PHMSA Response

PHMSA is retaining the TVC records requirement in the final rule. The IM alternative requires an operator to have or obtain TVC records for the diameter, wall thickness, grade, seam type, yield strength, and tensile strength of an eligible Class 3 segment. Consistent with the industry comments and GPAC's unanimous recommendation, an operator may obtain any necessary TVC records during the initial 24-month compliance window by following the requirements in § 192.607. Section 192.607 prescribes a comprehensive process for verifying and documenting the material properties and attributes of pipeline segments through the performance of nondestructive or destructive tests, examinations, and assessments.

The IM alternative imposes a more stringent deadline for completing the materials verification process. Section 192.607 itself only applies on an “opportunistic” or “as needed” basis,

i.e.,

operators may verify the material properties and attributes of pipeline segments on a continuous or rolling basis.

114

Section 192.611(a)(4) requires that any necessary TVC records for an eligible Class 3 segment be obtained within the initial 24-month compliance window. This accelerates the collection of TVC records under § 192.607 and advances public safety.

114

Section 192.607(c) requires operators without adequate documentation of pipeline material properties and characteristics to “develop and implement procedures for conducting nondestructive or destructive tests, examinations, and assessments in order to verify the material properties of aboveground line pipe and components, and of buried line pipe and components.” As explained in FAQs, “[m]aterial properties, when unknown, must the gathered wherever the pipeline is excavated as defined in § 192.607(c). The data collection process for material properties must be completed however prior to completing the reconfirmation method [in § 192.624] if that method requires material properties.” PHMSA,

First Batch of FAQs for the 2019 Safety of Gas Transmission Rule,

FAQ-17 (Sept. 15, 2020).

In response to the GPAC's recommendation, PHMSA considered whether to exclude tensile strength from the TVC records requirement but decided to retain that provision. Many methodologies, including R-STRENG, B31G, and APTITUDE,

115

use tensile

strength to calculate the predicted failure pressure or remaining life of a pipeline in accordance with § 192.712, or require or use as an input the ultimate tensile strength of the pipe being modeled.

116

Having TVC records of the tensile strength for eligible Class 3 segments facilitates compliance with these provisions. Operators also benefit from having information about low or variable ultimate tensile strength properties in high-strength steel pipelines, which presents integrity concerns.

117

115

Y.S. Wang, Pipeline Research Committee Project, PRCI PR-3-805 (R-STRENG),

A Modified Criterion for Evaluating the Remaining Strength of Corroded Pipe,

(Dec. 22, 1989), available at:

https://doi.org/10.55274/R0012046

(software for evaluating the remaining strength of corroded pipe); ASME, American Standard Code for Pressure Piping, ASME/ANSI B31G-1991,

Manual for Determining the Remaining Strength of Corroded Pipelines

(June 27, 1991, Reaffirmed 2004) (evaluation of pipeline metal loss); APTITUDE: Crack Evaluation For Pressurized Cylinders,

Calculate A Predicted Failure Pressure And Remaining Life,

Structural Integrity Assocs. (Aug. 2022) available at:

https://www.structint.com/wp-content/uploads/2022/08/

APTITUDE-Crack-Evaluation-for-Pressurized-Cylinders.pdf

(model that calculates predicted failure pressure of crack or crack-like anomalies and “incorporates . . . if available, measured material properties such as material fracture toughness, yield strength, and ultimate tensile strength”).

116

See

PHMSA,

Second Batch of Frequently Asked Questions for the [2019 Safety of Gas Transmission Rule]: MAOP Establishment and Reconfirmation FAQs,

FAQ-62 (Apr. 19, 2023), available at:

https://www.phmsa.dot.gov/sites/phmsa.dot.gov/files/2023-05/Batch-2-RIN-1-FAQs.pdf.

117

See

PHMSA, ADB-09-01,

Pipeline Safety: Potential Low and Variable Yield and Tensile Strength and Chemical Composition Properties in High Strength Line Pipe,

74 FR 23930, 23931 (May 21, 2009).

PHMSA does not expect that obtaining tensile strength information will impose an undue burden on pipeline operators. An operator typically will receive tensile strength data in conducting the tests, examinations, and assessments needed to verify other properties and attributes of the pipe.

118

Only in the absence of TVC pipe grade records would an operator be required to obtain both yield strength and ultimate tensile strength information.

119

An operator may also be able to use an assumed value where actual tensile strength information is lacking. Common practice, as illustrated by a special permit issued to Alliance Pipeline, indicates that, at least in the case of modern pipe, an operator can assume that the ultimate tensile strength is the SMYS plus an additional 10,000 pounds per square inch (psi).

120

This assumption would need to be validated for older pipe vintages.

121

118

Common destructive tests will provide measurements of the yield strength, tensile strength, and other material properties of the specimen at the same time.

See

ASTM Intl'l, E8/E8M-22,

Standard Test Methods for Tension Testing of Metallic Materials,

§§ 7.7, 7.10 (2022). Note that destructive testing is not the only method to determine material properties under § 192.607.

119

See

PHMSA,

Second Batch of FAQs for the 2019 Safety of Gas Transmission Rule,

FAQ-62 (“If an operator does not have TVC records demonstrating the grade, the operator must conduct future testing for

both

minimum yield strength and ultimate tensile strength per § 192.607(c)(1) and (2).” (emphasis in original)).

120

See

Kiefner & Assoc., Inc.,

Validity of Standard Defect Assessment Methods for the Alliance Pipeline Operating at 80 percent of SMYS

(Sept. 6, 2018), available at:

https://www.phmsa.dot.gov/sites/phmsa.dot.gov/files/docs/technical-resources/pipeline/gas-transmission-integrity-management/65316/validityofcorrosionassessmentsr1.pdf.

121

See

Barry Oland, Mark Lower & Simon Rose, Oak Ridge Nat'l Lab.,

Review of Methods for Determining the Strength of Corroded Natural Gas Pipelines Based on Actual Remaining Wall Thickness

(May 2019), available at:

https://info.ornl.gov/sites/publications/Files/Pub126720.pdf.

vi. Grandfathered or Alternative MAOP

1. Summary of Proposal

The NPRM proposed that segments with an MAOP established under § 192.619(c) or (d) would not be eligible for the IM alternative. Section 192.619(c), commonly referred to as the “grandfather clause,” allows operators to establish the MAOP of pipeline segments in existence before the adoption of the original version of part 192 based solely on the highest actual operating pressure experienced during a five-year historical window that runs from July 1, 1965, to July 1, 1970. Section 192.619(d) refers to the alternative MAOP provisions in § 192.620, which permits a pipeline to operate with a less conservative design factor than would ordinarily be allowed in accordance with § 192.111 (

i.e.,

above 0.72 for Class 1 locations, above 0.67 for Class 2 locations, and 0.56 for Class 3 locations).

2. Initial Comments

While acknowledging that § 192.619(c) allows some grandfathered pipelines to operate at hoop stresses above 72 percent of SMYS, TC Energy stated that an operator should be permitted to use the IM alternative for these pipelines if adequate documentation is available to establish an MAOP under § 192.619(a) and the operator is willing to comply with the applicable requirements, including the 72 percent of SMYS limitation. Assuming those conditions are met, TC Energy argued that grandfathered pipelines “should be no less safe than [any other] pipelines that are currently operating at or below 72 [percent] of the SMYS that are eligible for” the IM alternative.

122

122

Docket ID PHMSA-2017-0151-0062 at 5.

3. GPAC Consideration

The GPAC recommended, with a unanimous 12-0 vote, that PHMSA consider whether to allow pipe segments operating in accordance with § 192.619(c) or (d) to be eligible for the IM alternative, provided the segment has an appropriate 1.25 times MAOP pressure test and an equivalent or greater level of pipeline safety can be maintained.

4. Post-GPAC Comments

The Associations and Enbridge agreed with the GPAC's unanimous recommendation. The Associations stated that “certain grandfathered pipe . . . with a pressure test greater than or equal to 1.25 [times] MAOP . . . can continue to be safely managed.”

123

Mr. Zamarin agreed, adding that the 1.25 times MAOP pressure test to permit pipelines operated in accordance with § 192.619(c) or (d) would provide the same safety assurance as other qualifying pipeline segments.

124

Mr. Drake did as well, noting that, “in many cases, [these grandfathered pipelines] have been pressure tested to at least 1.25 times the MAOP and, in some cases, for durations exceeding 24 hours,” which essentially meets or exceeds current Subpart J pressure testing requirements.

125

An anonymous commenter was concerned that “[a]llowing pipeline MAOPs above 72 [percent] SMYS was not publicly noticed” so any allowance of pressure above that threshold on pipelines operated in accordance with § 192.619(c) or (d) should be “re-notice[d] . . . for public comment.”

126

123

Docket ID PHMSA-2024-0005-0423 at 10.

See also

Enbridge, Comments, Docket ID PHMSA-2024-0005-0418 at 2 (Aug. 27, 2024).

124

See

Chad Zamarin, Comments, Docket ID PHMSA-2024-0005-0420 at 3 (Aug. 26, 2024).

125

Docket ID PHMSA-2024-0005-0419 at 3.

126

Docket ID PHMSA-2024-0005-0415 at 1.

5. PHMSA Response

PHMSA is not retaining the broad § 192.619(c) and (d) exclusions in the final rule. Two primary concerns led to these exclusions in the NPRM: (1) that pipelines with MAOPs established under § 192.619(c) and (d) may be operating at design factors above those specified at § 192.111 and at a stress level exceeding 72 percent SMYS, and (2) that pipelines with MAOPs established under § 192.619(c) and (d) may lack appropriate pressure test records or records of materials to properly establish the design pressure of the pipeline. Because operators must address both concerns to use the IM alternative, the § 192.619(c) and (d) exclusions are unnecessary. The requirements in the final rule effectively prohibit pipelines with MAOPs established under § 192.619(c) and (d) from using the IM alternative, eliminating the need for the exclusion proposed in the NPRM.

127

127

See

NPRM, 85 FR at 65159 (“PHMSA proposes that operators of pipelines that were previously operating in accordance with § 192.619(c) that

operate at or below 72 percent SMYS be eligible for the IM alternative only if the operator pressure tests any of those pipelines that do not have a record of a previous pressure test within 24 months after the class location change and have pipe material records for the segment.”).

As to the first concern, the IM alternative requires the MAOP of an eligible Class 3 segment to be confirmed or revised in accordance with the design limits in § 192.619(a), rather than the grandfather clause in § 192.619(c). Section 192.611(a)(4) explicitly recognizes that limitation and states that the MAOP of a segment confirmed under the IM alternative may not exceed 72 percent of SMYS. As to the second concern, the MAOP of an eligible Class 3 segment may only be confirmed or revised under the IM alternative if an operator satisfies the pressure testing and materials properties requirements, both of which are subject to recordkeeping provisions. These recordkeeping provisions directly address PHMSA's concerns about the potential absence of TVC design and test pressure records. For these reasons, there is no basis for retaining the proposed § 192.619(c) and (d) exclusions in the final rule.

vii. Wrinkle Bends and Geohazards

1. Summary of Proposal

The NPRM proposed to exclude pipeline segments with wrinkle bends from the IM alternative. Wrinkle bends are defined at § 192.3 as a bend formed in the field during construction that has ripples exceeding certain amplitude and length parameters. PHMSA has historically disfavored pipe segments with wrinkle bends when considering applications for class location special permits due to safety concerns.

128

128

See

PHMSA, 2004 Special Permit Criteria at 3.

2. Initial Comments

TC Energy recommended a “case-by-case” ILI assessment of wrinkle bends, stating that “[w]rinkle bends are generally stable features and excluding them entirely would do little to benefit pipeline safety,” noting the low failure rates across approximately 230,000 wrinkle bends in service.

129

The Associations suggested limiting this exclusion to those wrinkle bends presenting a geohazard threat.

130

Given that “only about 1 in 8,000 wrinkle bends have failed over approximately seventy years of service,” they saw “little safety benefit” to broadly excluding all wrinkle bends. The Associations were also concerned that requiring pipe replacement could create new risk of failure by presenting outside force on wrinkle bends just outside the class change segment.

131

129

Docket ID PHMSA-2017-0151-0062 at 5.

130

“Geohazard threats” are also known as geological hazards, geophysical hazards, or geo-technical hazards. PHMSA refers to these phenomena as “geohazards.” Geohazards include soil movement from natural causes—

e.g.,

earthquakes, landslides, sinkholes, erosion, and ground subsistence—and man-made causes—

e.g.,

construction activities. These hazards can occur independent of the product transported and have been observed in all 50 U.S. States and territories.

See

Stephen L. Slaughter,

Landslide Basics,

U.S. Geological Survey, available at:

https://www.usgs.gov/programs/landslide-hazards/landslide-basics

(last visited Aug. 18, 2025).

131

Docket ID PHMSA-2017-0151-0061 at 20.

The NTSB also encouraged PHMSA to consider excluding from the IM alternative pipe segments with a “known history of pipe movement,”

i.e.,

geohazards, noting the “significant risk to the integrity of natural gas pipelines” geohazards can pose.

132

132

Docket ID PHMSA-2017-0151-0055 at 4.

3. GPAC Consideration

Industry GPAC members noted that failures in segments containing wrinkle bends occur because those bends are not as strong as normal bends, which is why soil movement near a wrinkle bend can cause an incident. Public comments from industry representatives during the GPAC meeting added that while “there should be no wrinkle bends in geohazard areas,” wrinkle bends in non-geohazard areas should remain eligible for the IM alternative. GPAC members representing the public supported the eligibility criteria related to geohazards and recommended the identification and mitigation of geohazards under the IM alternative. GPAC members generally agreed that geohazards can constitute a threat to pipeline operations and safety and should be mitigated under the IM alternative. Members representing the public suggested that no pipe segment within 600 feet of a known geohazard should be eligible for the IM alternative, while members representing the industry disagreed with a blanket eligibility provision tied to the presence of geohazards near a pipeline segment.

The GPAC offered two recommendations that are relevant to the exclusion for wrinkle bends. First, with a 9-3 vote, the GPAC recommended that the IM alternative require operators to survey and assess a segment for an identified geohazard using procedures for pipe movement. This vote further recommended that, until PHMSA addresses geohazards in a future rulemaking, a pipeline segment should not be eligible for the IM alternative: (1) if an identified geohazard affects or could affect within 600 feet of the class change segment; or (2) if an identified geohazard affects or could affect pipe movement within 600 feet of the class change segment. Second, with a 12-0 vote, the GPAC recommended that where a geohazard is found on a segment using the IM alternative, PHMSA should require operators to develop procedures on how to evaluate and remediate the geohazard threat. This vote also recommended that the procedures operators develop address certain specified elements,

e.g.,

inspection tools, inspection intervals, patrols, employee and contractor training, finite element analysis, and girth weld repairs.

4. Post-GPAC Comments

Williams supported the recommendation that operators develop procedures to evaluate, remediate, and mitigate geohazard threats for a segment to be eligible for the IM alternative. Williams noted how “[i]n many circumstances, an operator can stabilize this threat. Where stabilization is adequately demonstrated, the segment should be eligible for inclusion into an operator's IM program.”

133

An anonymous commenter agreed that PHMSA should require the assessments and procedures discussed at the GPAC meeting related to geohazards because the rule allows Class 1 design pipe to remain in a Class 3 location.

134

133

See

Docket ID PHMSA-2024-0005-0421 at 10.

134

See

Docket ID PHMSA-2024-0005-0415 at 1.

The Associations opposed using geohazards as an independent eligibility factor, arguing that the GPAC recommendation to require operators to develop geohazard procedures was “duplicative and unnecessary.” “[G]eohazards can be extremely unique,” they argued, making a “blanket geohazard eligibility” exclusion unnecessary. The Associations further argued that “Subpart O already provides a rigorous and appropriate approach to manage geohazard threats,” noting that § 192.917 requires that “operators must evaluate potential weather related and outside force damage, including consideration of seismicity, geology, and soil stability.”

135

135

Docket ID PHMSA-2024-0005-0423 at 9-10.

The Associations also observed that “[i]dentification of weather-related and outside force damage threats trigger the same [IM] requirements to assess, monitor, remediate, and adopt preventative and mitigative measures as any other integrity-related threat.” The Associations noted that § 192.613(c) requires operators to assess their pipelines 72 hours after extreme weather events or natural disasters likely to damage pipeline facilities, and

suggested that such measures already ensure “operators will quickly evaluate the safety of the pipeline and determine if further actions are necessary to address a geohazard or other impacts to the pipeline.”

136

136

Id.

at 9-10.

5. PHMSA Response

PHMSA is retaining the wrinkle bend exclusion. The GPAC's proposal to limit the exclusion to wrinkle bends on segments with an identified geohazard risk does not address all concerns associated with using the IM alternative, though an operator may seek a special permit from PHMSA to remove the exclusion on a case-by-case basis.

PHMSA has historically excluded pipe segments with wrinkle bends from consideration under the class location special permit program. Operators used obsolete construction practices in forming wrinkle bends on pipelines prior to emergence of more modern bending technologies. Wrinkle bends are generally prohibited in pipelines that operate at a hoop stress of 30 percent or more of SMYS under § 192.315(a); they are known to fail in response to movement from temperature changes and other factors.

137

137

John F. Kiefner, Kiefner & Assoc., Inc., Final Report No. 05-12R,

Evaluating the Stability of Manufacturing and Construction Defects in Natural Gas Pipelines

(Apr. 2007), available at:

https://www.phmsa.dot.gov/sites/phmsa.dot.gov/files/docs/technical-resources/pipeline/gas-transmission-integrity-management/65321/evaluatingstabilityofdefects.pdf.

Wrinkle bends experience failures which may not be detectable using modern ILI technology. Suitability for assessment using ILI—or another appropriate integrity assessment method—is a fundamental element of the IM alternative. PHMSA's understanding is that ILI tools may not yet be able to conduct an effective integrity assessment of wrinkle bends. A study on ILI tools commissioned for PHMSA in 2004 supports that conclusion, noting that “[w]hile current ILI tools can accurately detect localized pitting and general metal loss in cylindrical pipe segments (

i.e.,

in sections without wrinkles or buckles) and standardized procedures are available to assess the pressure integrity of the pipe accounting for metal loss, it is unclear whether current ILI technology can accurately detect these same defects if they occur on or near a wrinkle or buckle because the effects of the pipe wall local curvature on the ILI tool signals can cause inaccuracies.”

138

PHMSA acknowledges that ILI technology, data analysis, and understanding of wrinkle bends is improving, but failures in 2010 and 2024 following ILI tool runs suggest room for further improvement.

139

Moreover, though the rate of rupture with wrinkle bends is low—most wrinkle bend failures are expressed as leaks—that may be aided by § 192.315 restricting pipe with wrinkle bends from being operated at or above 30 percent SMYS.

138

Michael Baker Jr., Inc, TTO No. 11 Final Report,

Pipe Wrinkle Study

(Oct. 2004), available at:

https://www.phmsa.dot.gov/sites/phmsa.dot.gov/files/docs/technical-resources/pipeline/gas-transmission-integrity-management/65286/tto11pipewrinklestudyfinalreportoct2004.pdf.

PHMSA notes that more recent ruptures also suggest that ILI technology may be limited in its ability to detect anomalies on pipe with wrinkle bends, as 7 of the 10 wrinkle-bend-related failures from 2009 to 2024 occurred within 7 years of the most recent axial magnetic flux leakage (MFL) and geometry/deformation ILI tool assessments.

139

PHMSA,

Pipeline Incident Flagged Files, Gas Transmission & Gathering 2010 to Present,

Incident Rep. No. 20100106-15588 (Dec. 21, 2010) and Incident Rep. No. 20240029-39272 (Mar. 1, 2024) (Pipeline Incident Files).

See also id.

Incident Rep. No. 20240029-41286 (Feb. 03, 2024) (wrinkle-bend related failure in Mississippi). In this case, the failure analysis found that ILI plus remediation criteria would not have prevented the incident, though the improved remediation criteria may have prevented nearby wrinkle bend failure that occurred in 2011, one year after an MFL ILI survey had been conducted. In the Matter of Tennessee Gas Pipeline Co., LLC, CPF No. 2-2024-009-CAO, 2024 WL 664786 (PHMSA Feb. 9, 2024), available at:

https://primis.phmsa.dot.gov/enforcement-documents/22024009CAO/22024009CAO_Corrective%20Action%20Order%20(Amended)_02092024_(24-298988)_text.pdf.

The failure analysis further found that the 2024 failure mechanism was different than the 2011 failure, and the 2024 failure was not associated with a previous repair.

PHMSA disagrees with the Associations' concern that pipe replacement activity might introduce new outside forces that could cause more wrinkle bends failures. Excluding pipe segments with wrinkle bends from the IM alternative should not result in additional outside forces to nearby segments if operators exhibit due care in performing construction activities. PHMSA expects operators to install pipe consistent with the requirements at § 192.319 “so that the pipe fits the ditch so as to minimize stresses and protect the pipe coating” and backfilling prevents damage to the pipe.

For these reasons, the IM alternative excludes pipe segments with wrinkle bends regardless of whether the wrinkle bend is in an area with an identified geohazard threat, consistent with the proposal and PHMSA's longstanding practice not to issue special permits to these segments. PHMSA continues to find it inconsistent with historical leak and failure history, current state of assessment technology, and the safety of populations near pipeline segments that have experienced a change in class location, for pipeline segments with wrinkle bends to be eligible for the IM alternative.

The wrinkle bend exclusion cannot be effectively narrowed to only those associated with an identified geohazard threat as recommended by the GPAC. Wrinkle bends are vulnerable to cold-weather conditions

140

and can fail more quickly due to geohazards, but that is not the only concern. While wrinkle bend failures sometimes involve areas of understood and studied geohazards,

141

PHMSA's analysis of historical failures involving wrinkle bends shows that they do not always correspond with the threat of land or pipe movement. For example, a 2015 wrinkle bend failure was caused by tensile overload,

142

and in 2023, a pipeline failed under a North Carolina highway due to corrosion in a wrinkle bend.

143

Neither involved a geohazard. A wrinkle bend exclusion limited to geohazard interactions might allow this type of threat into the IM alternative program, which the program is not suited to manage at this time.

140

See, e.g.,

PHMSA,

Pipeline Incident Files,

Incident Rep. No. 20210024-35593 (Feb. 20, 2021) (observing that “the temperature drop during the polar vortex in the [prior] week could have contributed to the failure in the wrinkle bend”).

141

Between 2009 and 2024, 9 of 10 reported incidents involving wrinkle bend failures occurred between November and March when soil temperatures are at their seasonal lows, causing pipe to be at its most brittle.

142

PHMSA,

Pipeline Incident Files,

Incident Rep. No. 20150040-17403 (Mar. 30, 2015) (noting operator was “unable to determine the source . . . of the tensile forces, but the tensile overload does not appear to be a result of third-party damage or observable land movement”).

143

PHMSA,

Pipeline Incident Files,

Incident Rep. No. 20230019-39287 (Feb. 22, 2023).

PHMSA finds that the wrinkle-bend-related geohazard concerns identified by GPAC members are captured under the wrinkle bend exclusion in the IM alternative. As several commenters noted, other current regulations and PHMSA guidance pertain to managing geohazard threats safely under the existing regulations. Section 192.917(a)(3) requires operators to identify “weather related and outside force damage, to include consideration of seismicity, geology, and soil stability of the area.” Section 192.613(c)(2) requires operators to assess their pipelines 72 hours after extreme weather events or natural disasters deemed likely to damage pipeline facilities via scouring, movement of the soil surrounding the pipeline, or movement of the pipeline. These geohazard mitigations occur on an ongoing basis.

144

Additional, specific

requirements for addressing geohazards near segments applying the IM alternative are not necessary at this time.

144

In 2022, PHMSA issued an updated advisory bulletin addressing geohazard identification and mitigation, and encouraged operators to “enhance

their preparations and procedures beyond the minimum Federal standards and to address the unique threats, vulnerabilities, and challenges of each individual pipeline facility.” PHMSA, ADB-2022-01,

Pipeline Safety: Potential for Damage to Pipeline Facilities Caused by Earth Movement and Other Geological Hazards

, 87 FR 33576, 33579 (June 2, 2022).

Accordingly, PHMSA disagrees with the GPAC's two recommendations regarding geohazards. While geohazards are a threat to the integrity of pipelines nationwide, the wrinkle-bend-related geohazard concerns identified by GPAC members are adequately addressed by the wrinkle bend exclusion in the IM alternative.

viii. Vintage Seam Types

1. Summary of Proposal

The NPRM proposed to exclude from the IM alternative pipe with seams manufactured by certain methods, including direct current (DC) electric resistance welding (ERW), low-frequency (LF) ERW, electric flash welding (EFW), or lap welding. PHMSA also proposed to exclude any pipe with a listed longitudinal joint factor at § 192.113 less than 1.0.

PHMSA has historically treated these vintage seam types as requiring a “substantial justification” to obtain a class location special permit.

145

PHMSA has issued several special permits to segments containing LF-ERW and EFW seams after completing individualized technical reviews, subject to certain additional integrity conditions. The additional conditions included a requirement that the segment be subject to a pressure test of 100 percent SMYS or replaced. Some special permits have been issued without requiring replacement of the segment.

145

PHMSA, 2004 Special Permit Criteria at 4.

2. Initial Comments

Accufacts expressed that IM assessments and repairs using ILI tools are not sufficient to demonstrate that Class 1 design pipe with these seam types are fit for service in Class 3 locations, and that such pipe is, “at this time, not appropriate for ILI assessment” and the IM alternative.

146

The PST generally lauded all proposed eligibility restrictions from the NPRM, including the seam type exclusion.

147

146

Docket ID PHMSA-2017-0151-0058 at 3.

147

See

Docket ID PHMSA-2017-0151-0063 at 4-5.

The Associations and TC Energy opposed PHMSA's proposal to exclude all pipeline segments with the identified vintage seam types, arguing that the integrity of such segments could be managed effectively through an IM program because “weld flaws are generally considered stable if they have been successfully tested to 1.25 [times] MAOP.”

148

The Associations referenced PHMSA research for seam threat management, including a 2013 Battelle report on longitudinal ERW seam failures and a 2007 Kiefner and Associates report evaluating the stability of manufacturing and construction defects in natural gas pipelines. The Associations also cited PHMSA data indicating that “manufacturing-related failures on onshore gas transmission pipelines have declined precipitously over the past two decades—including . . . a 75 [percent] decrease since the PG&E failure in San Bruno [California] in 2010,” and noted that incidents are rare on pipelines managed under Subpart O's IM program.

149

148

Docket ID PHMSA-2017-0151-0061 at 16;

see

TC Energy, Docket ID PHMSA-2017-0151-0062 at 4.

149

Docket ID PHMSA-2017-0151-0061 at 16.

TC Energy stated that they have “successfully managed risks associated with EFW and LF-ERW [seams] through continuous improvement utilizing [electromagnetic acoustic transducer ILI] inspections, proprietary crack assessment tools, risk analysis, and additional preventative and mitigative measures.”

150

The Associations noted that the proposal in the NPRM would require operators to assess for the threat of hard spots on a class change segment, and that operators “could run a hard spot ILI tool or equivalent assessment method and remediate hard spots that do not meet API 5L requirements.”

151

TC Energy also noted that “many existing class change special permits cover EFW and LF-ERW pipe” with no leaks or incidents reported “on these class change special permit segments[,] supporting that these threats can be safely managed.”

152

150

Docket ID PHMSA-2017-0151-0062 at 4.

151

Docket ID PHMSA-2017-0151-0061 at 16.

152

Docket ID PHMSA-2017-0151-0062 at 4.

In addition, both the Associations and TC Energy noted the lack of cyclic fatigue failures on natural gas transmission lines and, while “cyclic fatigue has caused failures of LF-ERW pipe,” such failures “generally [occur] on liquid pipelines.”

153

Given the analysis required in accordance with § 192.917(e)(2), the Associations stated that they would support excluding any pipeline segments with the identified seam types where the threat of significant cyclic fatigue is also present.

153

Docket ID PHMSA-2017-0151-0061 at 16;

see

TC Energy, Docket ID PHMSA-2017-0151-0062 at 4.

3. GPAC Consideration

Industry GPAC members argued that the vintage seam type exclusion in the NPRM swept too broadly and that pipe manufactured with ERW and EFW seams should be eligible for the IM alternative.

154

Specifically, Mr. Zamarin discussed how LF-ERW and EFW seams are considered a “stable threat” under the B31.8S standard.

155

Unlike corrosion, Mr. Zamarin explained, a seam defect will not deteriorate over time and can be treated as stable following a 1.25 times MAOP pressure test. Noting that the IM alternative requires such a test, Mr. Zamarin argued that the safety of pipe with ERW and EFW pipe can be established at the outset of the program, and that seam integrity can be maintained over time by complying with the provisions in Subpart O. Mr. Drake noted that improved testing methods have decreased seam failure rates to a level consistent with other pipe failure mechanisms, and that seams which pass a 1.25 times MAOP pressure test can be managed consistent with other pipeline characteristics. Mr. Drake also recommended that PHMSA capitalize on the recent improvements to Subpart O in managing seam integrity under the IM alternative, given the “overlap in the regulatory development of this rule and Subpart O.”

156

Mr. Weisker, another industry GPAC member, added that the IM requirements in Subpart O clearly recognize the principle that seam integrity can be established with a 1.25 times MAOP pressure test.

154

Industry GPAC members endorsed the continued exclusion from the IM alternative of lap welded seams or any seam with a longitudinal joint factor below 1.0.

See

GPAC,

Class Location Requirements Transcript March 29, 2024,

Docket ID PHMSA-2024-0005-0308, at 148 (Apr. 11, 2024).

155

ASME, American Standard Code for Pressure Piping, Supplement to ASME B31.8, ASME B31.8S-2018,

Managing System Integrity of Gas Pipelines

(2018).

156

GPAC,

Class Location Requirements Transcript March 29, 2024,

Docket ID PHMSA-2024-0005-0308, at 203.

Ms. Murphy, a public member, acknowledged the point about seam stability following a 1.25 times MAOP pressure test, but recommended deferring to PHMSA's expertise as to whether these seam types present a sufficient concern to require continuing review under special permits. Ms. Gosman, another public member, also deferred to PHMSA's expertise while noting that a more protective approach may be appropriate because the IM alternative applies to thinner walled pipe that is non-commensurate with its

current class location. Another public member asked PHMSA to review incident data. Mr. Danner, the Committee chair and a member representing government entities, preferred that PHMSA explore whether adequate testing procedures can be implemented to maintain safety and allow these seam types into the IM alternative.

157

157

See

GPAC,

Class Location Requirements Transcript March 29, 2024,

Docket ID PHMSA-2024-0005-0308, at 134-208.

In an 11-1 vote, the GPAC recommended that the seam eligibility restriction was technically feasible, reasonable, cost-effective, and practicable, if PHMSA considered alternatives, including the potential removal of the exclusion for LF-ERW and EFW pipe segments (1) while maintaining an equivalent or greater level of pipeline safety and (2) if it can be shown that operators are effectively managing these segments through the IM alternative.

4. Post-GPAC comments

Enbridge added its opposition to the proposed seam eligibility restriction, as did Mr. Drake.

158

The Associations expanded on their opposition, questioning the lack of “a specific rationale” from PHMSA “supporting this proposed exclusion.” The Associations argued that the identified seam features would be mitigated through the IM program by the crack repair criteria finalized in the 2022 Safety of Gas Transmission Rule, “especially the crack depth threshold of 50 percent [which] will help conservatively identify cracks before they result in an incident,” and § 192.917(e)(3)(i), which “provides an additional level of safety protection by requiring an integrity assessment if an incident occurs on selected vintage seam pipes.”

159

158

See

Docket ID PHMSA-2024-0005-0418 at 2; Andy Drake, Comments, Docket ID PHMSA-2024-0005-0419 at 3.

159

Docket ID PHMSA-2024-0005-0423 at 13-14.

The Associations also pointed to PHMSA's incident data as evidence that pipe with these seam types can be managed safely. The Associations identified 12 reported incidents over 15 years attributed to LF-ERW pipe seam failures out of 1,531 reportable incidents on about 298,000 miles of gas transmission lines, with none occurring in HCAs. In contrast, they cited 109 external corrosion and 90 internal corrosion incidents over that same period and stated that “[t]he comparison with corrosion is important because there are long-established practices of managing external and internal corrosion that integrity management enhances. If you apply the same logic to selected vintage seam pipe, then an equal or greater level of safety will be achieved by” placing these LF-ERW seams into the IM program.

160

160

Id.

at 12.

The Associations noted DC-ERW pipe came from a single manufacturer, Youngstown Steel and Tube, between 1930 to 1980 and, while “PHMSA proposed making all pipe from this mill ineligible,” process improvements at the mill in 1948 improved the quality of the pipe.

161

EFW pipe similarly was made by a single manufacturer, AO Smith Corporation, starting from about 1927 through 1969. The Associations reviewed PHMSA's incident data, which indicated there were 6 incidents on EFW pipe over the past 15 years, one of which was seam-related, with five related to cracking in hard spots in the pipe body; the Associations pointed to studies on how hard spots could safely be managed by operators.

161

Id.

An anonymous comment urged PHMSA not to allow pipe with EFW seams to be eligible for the IM alternative, noting that EFW pipe manufactured by AO Smith from the 1950s through the mid-1960s had seam weld failure issues and hard spot issues (cracking) in the pipe steel for which ILI tools and IM programs “have not been perfected or may not have qualified personnel for identifying,” unlike with other anomalies. The anonymous commenter also pointed to an NTSB report “on an Enbridge 30-inch EFW pipeline hard spot failure in Kentucky” that caused one fatality, injured others, and burned down several homes. The commenter rhetorically asked what has been done to remedy these types of pipe body and weld seam issues for Class 1 EFW pipe operating in Class 3 locations. Referencing a 2004 INGAA pipe seam report showing a total of 276 incidents attributed to EFW pipe issues, with 242 of them being seam failures and 34 pipe body failures, the anonymous commenter concluded that “PHMSA must review the manufacturing and inline inspection results/records, pressure test, leak, and rupture history . . . of all EFW pipe prior to it being considered for [the IM alternative]. EFW pipe must not be allowed in this rulemaking, as noted in the draft rule shown to the public for comments.”

162

162

Anonymous, Comments, Docket ID PHMSA-2024-0005-0414 at 1-2 (Aug. 16, 2024) (discussing E.B. Clark et al., Battelle,

Integrity Characteristics of Vintage Pipelines,

tbls. E-3 & E-5 (INGAA Found., Oct. 2004), available at:

https://ingaa.org/foundation/resources/integrity-characteristics-of-vintage-pipelines/

).

5. PHMSA Response

PHMSA has conducted a comprehensive review and is removing the exclusion for LF-ERW, DC-ERW, and EFW seams. The 1.25 times MAOP pressure testing requirement and comprehensive integrity measures in the IM alternative provide an adequate basis for confirming the MAOP of eligible Class 3 segments with these vintage seam types. While PHMSA previously required a substantial justification for operators to obtain a class location special permit for pipe manufactured with LF-ERW, DC-ERW, and EFW seams, subsequent research, advances in ILI technology, and changes to the IM requirements, when combined with PHMSA's experience managing these class location special permits, demonstrate that such a justification is no longer needed. Accordingly, the final rule allows operators to use the IM alternative to confirm the MAOP of eligible Class 3 segments with LF-ERW, DC-ERW, and EFW seams.

Background

Historically, the manufacturing process for ERW and EFW pipe required the skelp (

i.e.,

metal before forming the pipe) to be cold rolled with current introduced to heat and bond the edges of the metal and weld the longitudinal seam—LF-ERW used low frequency alternating current induced at a frequency of around 120 (up to 360) cycles per second for that purpose, while DC-ERW and EFW used forms of direct current. The electrical current used in these manufacturing methods had a relatively wide heat affected zone, which coarsened more of the metal grain surrounding the seam.

163

Along with the quality of skelp used and quality of the metal edges before welding, pipe formed by these methods tends to fail from cold welds where the skelp edges do not fully bond, hook cracks where a j-shaped imperfection is introduced in layers of the skelp edges when welded together, and selective seam weld corrosion where metal loss occurs in the heat-affected zone and bondline and can advance more quickly.

164

163

J.F. Kiefner & K.M. Kolovich, Battelle, Task 1.4 Final Report No. 12-139,

ERW and Flash Weld Seam Failure,

in

The Comprehensive Study to Understand Longitudinal ERW Seam Failures,

at 2>-6 (Sept. 24, 2012) (noting that direct current tended to create a wider heat affected zone than low-frequency current). The

Comprehensive Study

can be accessed at:

https://primis.phmsa.dot.gov/rd/projects/390/.

164

See

Kiefner & Kolovich, Task 1.4, at 13, 39, 63-65; B.N. Leis et al., Battelle, Task 4.5,

Final Summary Report & Recommendations—Phase One,

in

The Comprehensive Study to Understand

Longitudinal ERW Seam Failures,

at 15 (Oct. 23, 2013).

Commonly adopted in the 1970s, manufacturers began using higher frequency currents of around 450 kilocycles per second to complete welds more quickly and create a smaller heat-affected zone on the pipe, leaving intact more of original steel's microstructure. The prevalence of that high-frequency ERW method, along with improved quality control and the use of “fully-killed” steels with lower carbon content that are more resistant to brittle fracture transition temperature, generally improved line pipe manufactured after 1980.

165

While prospective, these improvements did not affect pipe already manufactured with LF-ERW, DC-ERW, and EFW seams, which tended to experience failures at a disproportional rate.

166

165

Kiefner & Kolovich, Task 1.4, at 2, 7; J.D. Fields,

The Evolution of High-Frequency Welded Line Pipe,

(Feb. 20, 2025), available at:

https://www.jdfields.com/news-and-case-studies/the-evolution-of-high-frequency-welded-line-pipe.

166

See

Michael Baker Jr., Inc, Kiefner & Assoc., TTO No. 5 Final Report,

Low Frequency ERW and Lap Welded Longitudinal Seam Evaluation,

at 7 (Apr. 2004), available at:

https://www.phmsa.dot.gov/sites/phmsa.dot.gov/files/docs/technical-resources/pipeline/gas-transmission-integrity-management/65266/tto05lowfrequencyerwfinalreportrev3april2004.pdf

(“Recent ERW line pipe manufactured by the better pipe mills is of high-quality and offer one of the best choices of materials for pipeline construction. The concern relevant to seam-integrity assessment arises because this was not necessarily the case prior to about 1980. . . . Both good and poor-quality lots have been made by most of the manufacturers in the time period of interest (roughly 1930 through 1980).”); Kiefner & Kolovich, Task 1.4, at 139 (“[T]he track record of failures involving pipe of pre-1970 vintage is clearly not as good as that of pipe manufactured after 1970.”).

Acknowledging that trend, PHMSA issued a pair of pipeline safety alerts in the late 1980s advising operators of findings related to several recent failures of pipelines manufactured with ERW seams prior 1970. These notices advised operators that “hydrostatic testing of some ERW pipelines [have] reduc[ed] the risk of seam failures,” with pre-1970 ERW pipelines that operators have hydrotested largely operating safely since that test.

167

PHMSA recommended all gas transmission and hazardous liquid pipeline operators consider testing to 1.25 times the MAOP pre-1970 ERW pipe for which they not yet done so, or alternatively reduce the operating pressure by 20 percent.

168

PHMSA also advised operators to avoid increasing a pipeline's long-standing operating pressure, to assure effectiveness of the cathodic protection system, and to conduct metallurgical exams in the event of an ERW seam failure.

167

PHMSA, ALN-88-01,

Recent findings relative to factors contributing to operational failures of pipelines constructed with ERW prior to 1970

(Jan. 28, 1988).

168

See

PHMSA, ALN-89-01,

Pipeline Safety Alert Notice

(Mar. 8, 1989), available at:

https://www.phmsa.dot.gov/regulations/title49/interp/pi-89-001.

Following the 2009 rupture of a hazardous liquid pipeline with an LF-ERW seam in Carmichael, Mississippi, from which the NTSB found inspection and testing programs inadequate to identify reliably features associated with longitudinal seam failures of ERW pipe, PHMSA commissioned research into the potential integrity risks associated with vintage seamed pipe.

169

The “Comprehensive Study to Understanding Longitudinal ERW Seam Failures” featured over two-dozen studies by leading engineering researchers from 2011 to 2017.

170

Research conducted in the 2000s confirmed that a 1.25 times MAOP pressure test could remove any critical defects on ERW or EFW pipe, or prove none present.

171

The Comprehensive Study in the 2010s found that pressure tests and ILI could be used in combination for effective integrity management, pending further anticipated ILI tool improvements.

172

ILI technology had continued to improve in the 2010s, with higher probability of detection and an ability to detect smaller seam cracks, even compared to the decade prior, but ILI crack tools required further development in their ability to recognize seam anomalies and location.

173

169

See

NTSB, PAR-09-01,

Rupture of Hazardous Liquid Pipeline with Release and Ignition of Propane, Carmichael, MS, Nov. 1, 2007,

at 49-51 (Oct. 14, 2009), available at:

https://www.ntsb.gov/investigations/AccidentReports/Reports/PAR0901.pdf

(recommendation P-09-01).

170

The complete research docket is available at:

https://primis.phmsa.dot.gov/matrix/PrjHome.rdm?prj=390.

171

Baker, TTO No. 5, at 15; Kiefner,

Evaluating the Stability of Manufacturing and Construction Defects,

at 18.

172

See

Leis, Task 4.5, at 20; J.F. Kiefner, et al., Battelle, Task 1.3 Final Report 12-180,

Track Record of In-Line Inspection as a Means of ERW Seam Integrity Assessment,

in

The Comprehensive Study to Understand Longitudinal ERW Seam Failures,

at 120 (Nov. 15, 2012) (noting the combination may not be necessary upon expected improvements in ILI crack detection).

173

See, e.g.,

Leis, Task 4.5, at 33.

See also

Baker, TTO No. 5, at 6, 47, 60 (finding ILI tools in 2004 unreliable to identify longitudinal seam anomalies).

PHMSA amended the IM regulations in the 2019 and 2022 Safety of Gas Transmission Rules to address the potential integrity risks associated with older ERW pipe through two main additions. First, in 2019 PHMSA amended the § 192.917(e)(3) requirement that operators analyze pipe with manufacturing defects to require that an operator could only consider manufacturing defects (including seam defects) stable if an operator subjected them to a hydrostatic pressure test of at least 1.25 times the MAOP, with no subsequent reported incidents attributable to the defect. Second, for anomalies found to be preferentially affecting a longitudinal seam, § 192.933 as amended in 2022 accelerates the repair of DC-ERW, LF-ERW, and EFW seamed pipe by using a higher safety factor to more conservatively calculate the predicted failure pressure for preferential metal loss.

174

174

See

§ 192.933(d)(1)(iv), (2)(vi).

See also

§ 192.714(d)(1)(iv), (2)(vi).

The GPAC discussed each of these amendments in providing PHMSA with the recommendation to consider removing pipe with LF-ERW, DC-ERW, and EFW seams from the vintage seam exclusion in the IM alternative. Members discussed how a 1.25 times MAOP pressure test is an accepted method of stabilizing seam defects, and that the recent amendments to Subpart O should be considered in determining the appropriate means of assessing and, if necessary, remediating LF-ERW, DC-ERW, or EFW anomalies.

175

All members agreed that PHMSA should apply its technical expertise to review research evidence and incident data to consider whether these seams could safely apply the IM alternative with these safeguards in place.

175

See, e.g.,

GPAC,

Class Location Requirements Transcript March 29, 2024,

at 168-69, 183, 203 (Andy Drake).

Analysis

PHMSA has conducted a comprehensive review consistent with the GPAC's recommendation and concludes that the requirements in the IM alternative provide an adequate basis for confirming the MAOP of eligible Class 3 segments with LF-ERW, DC-ERW, and EFW seams. Any manufacturing defects associated with these seams can be treated as stable by virtue of the 1.25 times MAOP testing requirement in the IM alternative.

176

“Hydrostatic testing of the [pipe]line either removes any defects that have grown beyond critical size at the test pressure since the last test, or it proves

that no defects of critical size exist”;

177

the 1.25 times MAOP test required to use the IM alternative is the same as what is required under the IM program at § 192.917(e)(3). Several other interacting threats that might otherwise cause LF-ERW, DC-ERW, or EFW seam to become unstable are excluded from the IM alternative, like pipe with wrinkle bends or that is known to have stress corrosion cracking (SCC).

178

Ongoing seam integrity can be maintained by the regular assessment using ILI tools appropriate for the threats as is required by the IM alternative, with PHMSA's recent amendments to Subpart O providing a comprehensive framework for capitalizing on modern ILI tool capabilities for pipe with LF-ERW, DC-ERW, and EFW seams.

179

176

See

NTSB, Safety Recommendation, at 10 (Sept. 26, 2011), available at:

https://www.ntsb.gov/safety/safety-recs/recletters/P-11-008-020.pdf;

Kiefner,

Evaluating the Stability of Manufacturing and Construction Defects,

at 18 (“Any manufacturing defect or imperfection that survives a pre-service hydrostatic test to 1.25 times the [MAOP] is stable immediately after the test. . . . [E]xperience with gas pipelines tested to levels of 1.25 times their operating pressures validates the effectiveness of a test-pressure-to-operating-pressure ration of 1.25.”).

See also

ASME, B31.8S-2018, § 6.3.2.

177

Baker, TTO No. 5, at 15.

178

See

Kiefner,

Evaluating the Stability of Manufacturing and Construction Defects,

at 6-7.

179

See

Leis, Task 4.5, at 18 (noting “it is important to have the ILI option for seam-integrity assessment . . . via a reliable ILI tool” to “find and eliminate injurious defects on a scheduled basis” after a pressure test).

Improvements in tool probability of detection and sizing accuracy discussed in section II.C have been demonstrated in ILI tools on ERW and EFW seams, a marked development compared with a 2004 PHMSA study that previously questioned the use of ILI as an effective technology for managing pipe with these seam types.

180

Advanced ILI tools can now detect even the smaller anomalies that may have gone undetected in an initial pressure test, as shown by research as recent as 2017.

181

Though there are limits to current tools' ability to identify a seam crack's precise location and distinguish the type of anomaly feature as between,

e.g.,

cold welds, hook cracks, selective seam weld corrosion, this is mitigated by the heightened safety factor applied in the remediation criteria for these seam types in § 192.933(d).

182

Applying an IM program to LF-ERW, DC-ERW, and EFW seams in HCA locations, there have been no reported incidents due to material failure of pipe or weld since 2010.

183

180

Compare

Leis, Task 4.5, at 33 (Oct. 23, 2013) (“ILI done using SMFL and EMAT tools focused in part on crack-like features associated with stress-corrosion cracking (SCC) over almost 1500 miles of liquid, highly volatile liquid, and natural gas pipelines made using low as well as high frequency ERW processes showed the technology to detect cracking has recently improved significantly.”),

with

Baker, TTO No. 5, at 6, 60 (finding in 2004 that “the probability of detecting seam problems varied among the types of ILI tools used,” and recommending to not use it to evaluate the failure pressures of specific defects affecting pipe with these seam types).

181

Jennifer M. O'Brien & Bruce Young, Battelle,

Phase II Task 2—Pipe Inventory, Inspection by In-The-Ditch Methods and In-Line Inspection, and Hydrostatic Tests—a Continuation of Phase 1, Task 2,

in

The Comprehensive Study to Understand Longitudinal ERW Seam Failures,

at 57 (Aug. 2017).

182

Kiefner, Task 1.3, at 121 (advising added conservativism in the repair criteria and calculating predicted failure pressure in light of these deficiencies). ILI tools are expected to improve in this regard with further innovation and application.

See id.

at 120; Leis, Task 4.5, at 20 (“[T]he fact that the tools find some defects is encouraging, and further use of the tools will undoubtedly lead to better understanding of the capabilities.”); O'Brien & Young,

Pipe Inventory, Inspection by In-The-Ditch Methods and ILI, and Hydrostatic Tests,

at 41.

183

Conversely, 31 reported incidents by this mechanism occurred outside of HCAs during the same period.

Review of the decades of study and incident history indicate that, in PHMSA's expert judgment, LF-ERW, DC-ERW, and EFW seams can be safely managed under the IM alternative. Gas transmission lines are generally not subject to the heightened cyclic fatigue risk that applies to hazardous liquid pipelines.

184

The IM alternative also requires gas transmission operators to follow more stringent IM requirements when conducting the initial 24-month assessment on pipe with ERW or EFW seams. Specifically, an operator must select an assessment technology or technologies with a proven application capable of assessing seam integrity and seam corrosion anomalies regardless of whether the additional criteria in § 192.917(e)(4) are met. The TVC records requirement in the IM alternative provides an additional margin of safety for pipe with ERW or EFW seams. Operators lacking TVC seam type records must obtain that information before conducting the initial ILI assessment, as failing to do so could lead to the selection of improper ILI tool for pipe with an ERW or EFW seam and invalidate the results of the assessment.

184

See

Leis, Task 4.5, at 15. While the 1988 and 1989 advisories called to alarm 20 hazardous liquid pipeline failures (with 12 announced in January 1988, and an addition 8 in the March 1989 advisory) involving pipe seams manufactured by ERW, they noted but one such failure on a gas transmission pipeline.

See

ALN-89-01.

PHMSA concludes that the MAOP restoration provision in the IM alternative can be safely applied to LF-ERW, DC-ERW, and EFW seams as well. Studies indicate that pressure tests are not always effective to prevent failure where operating pressure surges, and that changes in operating pressure can destabilize a threat. To address these concerns, PHMSA is requiring operators to treat an MAOP restoration under § 192.611(d) as an MAOP increase under Subpart O, including for purposes of the seam susceptibility analysis and, more likely than not, prioritization of the ERW or EFW segment for reassessment under § 192.917(e)(3) and (4). These provisions ensure that the LF-ERW, DC-ERW, and EFW seams are properly assessed and remediated as part of an MAOP restoration.

In summary, PHMSA is removing LF-ERW, DC-ERW, and EFW seams from the vintage seam type exclusion. Having conducted a comprehensive review in response to the GPAC's recommendation, PHMSA concludes that the 1.25 times MAOP pressure testing requirement and other comprehensive integrity measures in the IM alternative provide an adequate basis for confirming or restoring the MAOP of eligible Class 3 segments with these seam types. As previously discussed, recent advances in ILI technology, particularly with respect to probability of detection and sizing accuracy, and changes to the IM requirements in Subpart O demonstrate that operators can safely manage the integrity of LF-ERW, DC-ERW, and EFW seams under the IM alternative. PHMSA has also included provisions in the IM alternative that exceed the IM requirements in Subpart O, such as for the selection of technologies capable of assessing seam integrity and seam corrosion anomalies during the initial 24-month assessment and the treatment of MAOP restorations as MAOP increases, which provide an additional margin of safety for LF-ERW, DC-ERW, and EFW seams.

The final rule retains the vintage seam type exclusion for lap welded pipe and pipe with a joint factor below 1.0.

185

Operators must confirm or revise the MAOP of pipe manufactured with these vintage seam types using the other methods authorized in § 192.611 in the event of a class location change. O

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