# Pipeline Safety: Class Location Change Requirements

- **operation:** document
- **citation:** 91 FR 1608
- **title:** Pipeline Safety: Class Location Change Requirements
- **source type:** rulemaking
- **agency:** Pipeline and Hazardous Materials Safety Administration
- **status:** historical
- **official:** true
- **published on:** 2026-01-14
- **effective on:** 2026-03-16
- **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.
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Federal Register, Volume 91 Issue 9 (Wednesday, January 14, 2026) [Federal Register Volume 91, Number 9 (Wednesday, January 14, 2026)] [Rules and Regulations] [Pages 1608-1655] From the Federal Register Online via the Government Publishing Office [ www.gpo.gov ] [FR Doc No: 2026-00566] [[Page 1607]] Vol. 91 Wednesday, No. 9 January 14, 2026 Part II Department of Transportation ----------------------------------------------------------------------- Pipeline and Hazardous Materials Safety Administration ----------------------------------------------------------------------- 49 CFR Part 192 Pipeline Safety: Class Location Change Requirements; Final Rule Federal Register / Vol. 91, No. 9 / Wednesday, January 14, 2026 / Rules and Regulations [[Page 1608]] ----------------------------------------------------------------------- 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 [email protected] . 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 [[Page 1609]] continuous one-mile length of pipeline. The final rule also required operators to follow more stringent operation and maintenance (O&M) requirements as the class location increased in value. --------------------------------------------------------------------------- \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 An operator must comply with certain Requirements. recurring programmatic requirements to use the IM alternative. Those requirements address: (1) gas quality, (2) close interval surveys, (3) patrolling, (4) leak surveys, (5) line markers, (6) class location studies, (7) shorted casings, and (8) exposed pipe and weld surface examinations. Other Requirements................ MAOP of a segment using the IM alternative may not exceed a hoop stress corresponding to 72 percent of specified minimum yield strength. An operator of an eligible Class 3 segment may use the IM alternative to restore a previously established MAOP after complying with certain uprating and initial programmatic requirements. ------------------------------------------------------------------------ C. Costs and Benefits This final rule is expected to produce substantial cost-savings of $461 million annually, after accounting for the expected $61.5 million cost for operators to implement the IM alternative on segments that experience class location changes in a given year (both discounted at 7%). The final rule is also expected to avoid an estimated 1.3 billion cubic feet of gas losses per year from pipeline replacements. Other non-quantified benefits include reducing service disruptions and increasing regulatory certainty and flexibility. The Regulatory Impact Analysis (RIA) provided in the docket for this rulemaking includes additional information about the costs, benefits, and other impacts of the final rule. II. Background A. Overview of Class Location Requirements Class locations use population density to provide an additional margin of safety for gas pipelines. Four class locations are used for that purpose, with Class 1 representing the areas with the least population density, Class 4 representing the areas with the highest population density, and Class 2 and Class 3 representing areas of [[Page 1610]] intermediate population density. To account for the additional risk to public safety, more stringent safety standards apply as the class location of a gas pipeline increases in value. That principle, which is commonly referred to as a safety factor, is reflected in the first instance in determining the design pressure of a pipeline. Design pressure is calculated using a modified version of Barlow's formula, the results of which specify the maximum internal pressure piping can withstand before failure. A class-location-based design factor is incorporated into that formula to provide more margin--i.e., a lower safety factor--as population density increases.\6\ A similar concept applies in determining the test pressure of a pipeline.\7\ Design and test pressure are two of the factors that limit MAOP, which is the highest pressure that a pipeline is permitted to operate at while in service.\8\ --------------------------------------------------------------------------- \6\ See 49 CFR 192.105. See also ASME, Code for Pressure Piping, B31.8, Gas Transmission and Distribution Piping Systems, Sec. 805.2.3 (2018). This equation in full is: Design pressure = ((2*Yield Strength*wall thickness)/outside diameter) * class design factor * longitudinal joint factor * temperature factor. \7\ 49 CFR 192.619(a) (test requirements for establishing MAOP at time of installation, incorporating a class-location-based test factor which lowers MAOP as the class location increases). \8\ See 49 CFR 192.3 (defining MAOP), 192.619 (prescribing requirements for determining MAOP). --------------------------------------------------------------------------- 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). [GRAPHIC] [TIFF OMITTED] TR14JA26.015 This phenomenon governs in applying Barlow's formula both at the time of installation and if the class location of a gas pipeline changes at a later point in time due to an increase in population density.\10\ --------------------------------------------------------------------------- \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 [[Page 1611]] 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, Sec. 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, Sec. Sec. 841.011, 841.012, 841.013, 841.014. For ease of reading and public accessibility, in this document a string of cited material may be cited by a footnote in the final sentence of the paragraph addressing all material from that source. --------------------------------------------------------------------------- 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, Sec. 841.1, tbl. 841.11. \15\ ASA B31.1.8-1955, tbl. 841.412(d). \16\ E.g., ASA B31.8-1958; ASA B31.8-1963; USAS B31.8-1967. --------------------------------------------------------------------------- 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, Sec. 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 Sec. 192.5). For additional information about the treatment of Class 3 locations, see PHMSA, PI-81-001, Letter of Interpretation (Jan. 13, 1981), available at: 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 [[Page 1612]] of SMYS, or indicates that the hoop stress corresponding to the established maximum allowable operating pressure for a segment of existing pipeline is not commensurate with the present class location.'' \21\ After completing that study, operators had to take certain actions to confirm or to revise the MAOP of the segment to align with the new class location. Those actions included reducing the MAOP, relying on a previous pressure test, conducting a new pressure test, or replacing the pipe.\22\ In addition, to ensure that pipelines installed prior to the adoption of the part 192 regulations had an MAOP commensurate with the current location, PHMSA required operators to complete an initial study and, if necessary, to take action to confirm or to revise the MAOP of existing segments by certain deadlines.\23\ The framework established in the original part 192 regulations for addressing class location changes has remained largely unchanged.\24\ --------------------------------------------------------------------------- \21\ Minimum Standards, 35 FR at 13272 (codifying Sec. 192.609). \22\ PHMSA originally required these actions to be completed within one year of the date of the class location change, but subsequently extended that deadline to two years. See Extension of Time for Confirmation or Revision of Maximum Allowable Operating Pressure, 36 FR 18194 (Sept. 10, 1971) (extending period to 18 months); Pipeline Safety: Periodic Updates to Pipeline Safety Regulations (2001), 69 FR 32886, 32890 (June 14, 2004) (extending period to 2 years). \23\ Minimum Standards, 35 FR at 13272 (codifying original version of Sec. 192.607); Regulatory Review; Gas Pipeline Safety Standards, 61 FR 28770, 28785 (June 6, 1996) (repealing original version Sec. 192.607 as obsolete). \24\ Slight modification extended the time to complete MAOP confirmation to two years, see supra note 23, repealing the class location study for pre-part 192 pipelines when that had completed, see supra note 24, and the specific test pressure, see Confirmation or Revision of Maximum Allowable Operating Pressure; Alternative Method, 54 FR 24173 (June 6, 1989) (allowing the MAOP to be confirmed or revised based on a past pressure test, with test pressure tied to class location, rather than requiring a test pressure to at least 90 percent SMYS). --------------------------------------------------------------------------- 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, RoCD 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 [[Page 1613]] enhancements to the IM regulations included new assessment procedures for ILI tools and updated requirements for the detection and remediation of anomalies. PHMSA's 2019 and 2022 Safety of Gas Transmission Rules also established a companion assessment and response schedule for other Class 3 and 4 pipelines.\34\ These changes have created a comprehensive, risk-based scheme for pipeline anomaly detection and remediation, driven in large part by continuing improvements in ILI technology. --------------------------------------------------------------------------- \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 o
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