United States: A Guide To PHMSA's Proposed Rule Expanding Natural Gas Pipeline Safety Requirements

The U.S. Department of Transportation's Pipeline and Hazardous Materials Safety Administration's ("PHMSA") recent notice of proposed rulemaking would significantly expand the safety requirements that apply to the nation's natural gas pipelines.1 Comments on the NPRM are due July 7, 2016. This White Paper provides a detailed guide to PHMSA's proposed rule and highlights four "take-aways" from the NPRM for executives and in-house counsel.


  1. We all have work to do. PHMSA has proposed major changes to its gas pipeline safety rules. Some of the proposed changes impose new duties that will take decades to fulfill, such as the duty to conduct assessments on a new category of pipeline segments—those located in Moderate Consequence Areas ("MCAs"). Other proposed duties will require immediate action by pipeline operators, such as the duty to immediately repair a pipeline when certain conditions are present. Some new duties are expressed by adding multiple pages of regulatory text, such as new Appendix F, which will govern the use of Guided Wave Ultrasonic Testing. Other new duties are expressed with deceptive brevity, such as PHMSA's proposal to require compliance with nine additional industry standards or reports by incorporating them by reference into the proposed rule. Stakeholders will need to dedicate significant time and effort to comply with the final rule that emerges from PHMSA's proposal.
  2. It is time to further integrate Integrity Management into other gas pipeline safety efforts. Under PHMSA's current gas pipeline safety rules, the Integrity Management rules set out in Subpart O of Part 192 could be viewed as a distinct program within the overall pipeline safety program. Currently, the requirements of Subpart O are defined primarily within Subpart O itself. PHMSA proposes to amend Subpart O to add more than 25 new references to requirements defined outside of Subpart O. Some of these requirements would be substantial, such as Section 192.506's new requirements applicable to "spike" hydrostatic pressure tests and Section 192.624's new requirements related to the verification of a segment's maximum allowable operating pressure. The proposed rule also applies Integrity Management principles outside of High Consequence Areas ("HCAs"), and thus outside the scope of Subpart O. The new interdependence between Subpart O and the rest of Part 192 will make it increasingly difficult to justify organizing employees into a separate Integrity Management group, especially if pipeline operators adopt, or are required to adopt, recommended industry practices related to pipeline safety management systems that would govern an operator's entire safety program.
  3. It is time to check in with your lawyers. The federal gas pipeline safety rules are based on, and refer liberally to, industry standards developed by engineers. For pipeline operators, employees with technical backgrounds are the essential resource for addressing pipeline safety compliance matters. Likewise, technical knowledge is critical to PHMSA's audit function. But there is an important role for lawyers as well. Pacific Gas & Electric Company ("PG&E") is being criminally prosecuted for its alleged failure to comply with PHMSA's pipeline safety regulations in connection with the San Bruno incident. The role of lawyers will grow in importance in response to PHMSA's proposed rule. In addition to imposing new substantive duties, PHMSA plans to transform the way operators must document compliance. As proposed, Section 192.13(e) states that: (i) each operator "must make and retain records that demonstrate compliance" with Part 192, keeping these records for the retention periods specified in Appendix A to Part 192; and (ii) these records "must be reliable, traceable, verifiable, and complete." Proposed Appendix A to Part 192 lists 85 separate record retention requirements. In light of the PHMSA's proposed rule and the criminal charges brought against PG&E, pipeline operators need to reevaluate how they document compliance with Part 192.
  4. There is no time like the present. Whether preparing comments on PHMSA's proposed rule or taking steps to comply with the final rule that emerges from PHMSA's proposal, an intense focus on pipeline safety will have clear benefits for the owners and operators of natural gas pipelines. In addition to the proposed rules, the NPRM identifies known regulatory gaps that PHMSA intends to address through future rulemakings. Moreover, future safety incidents may spur congressional or regulatory responses on an industry-wide basis and may give rise to civil or criminal claims against individual pipeline operators. It is difficult to imagine that pipeline safety matters will become less critical in the future.


PHMSA's proposed rule constitutes the primary federal regulatory response to a natural gas pipeline safety incident that occurred in San Bruno, California, on September 9, 2010. Following the San Bruno incident, PHMSA issued an Advanced Notice of Proposed Rulemaking addressing potential changes to its gas pipeline safety rules, the National Transportation Safety Board ("NTSB") issued a report on the incident, and Congress passed the 2011 Pipeline Safety Act.2 These responses to the San Bruno incident included a wide range of proposals, recommendations, and mandates intended to improve the safety of natural gas pipelines. In addition, the Department of Justice ("DOJ") filed criminal charges against PG&E, the owner and operator of the gas pipeline in question, alleging violations of PHMSA's pipeline safety rules.3

As reflected in PHMSA's proposed rule, the San Bruno incident has raised important questions about the agency's Integrity Management rules.4 Currently, PHMSA's pipeline safety rules are divided into two tiers—one set of rules applies to all gas transmission pipelines, while heightened Integrity Management requirements apply to pipeline segments located within HCAs. These Integrity Management rules require pipeline operators to: (i) identify each segment of a natural gas transmission pipeline located in an HCA (i.e., an area where a leak or rupture could do the most harm); (ii) develop and implement a "baseline" safety assessment plan that identifies the potential threats to each of these "covered segments"; (iii) prioritize covered segments for assessment; (iv) evaluate preventive and mitigative measures; (v) remediate conditions; and (vi) implement a process for continual evaluation and assessment of the integrity of the covered segment.5

The San Bruno incident also raised questions about how pipeline operators establish and verify the maximum allowable operating pressure, or "MAOP," of pipeline segments, particularly where a pipeline's MAOP was established using the "grandfather" clause. MAOP is an essential element of PHMSA's pipeline safety rules because it defines the highest pressure at which a pipeline can safely operate. The "grandfather" clause allowed pipeline operators to define a pipeline segment's MAOP as the highest actual operating pressure at which the pipeline operated during the five years preceding July 1, 1970.6 In contrast, for pipeline segments built after this date, MAOP had to be established based on the results of a post-construction hydrostatic pressure test and the design pressure of the weakest element of the pipeline segment.7

This White Paper discusses the following aspects of PHMSA's proposal:

  1. The shift to a three-tiered approach to safety by applying a subset of the Integrity Management requirements to newly defined "Moderate" Consequence Areas.
  2. The verification of MAOP, including the treatment of "grandfathered" pipeline facilities, as well as PHMSA's new focus on records retention and verification.
  3. The strengthening of Integrity Management requirements within HCAs.
  4. New requirements applicable to all gas pipelines, not just pipelines located in HCAs and MCAs.
  5. The expansion of requirements applicable to natural gas gathering lines.
  6. PHMSA's decision to postpone consideration of other potential additions to the gas pipeline safety rules.


PHMSA's proposed rule distinguishes between three tiers of gas transmission pipelines: (i) those located in HCAs; (ii) those located in MCAs; and (iii) those located outside of HCAs and MCAs. Pipeline segments located in MCAs constitute a middle tier of segments that will be subject to some, but not all, of the requirements that apply to HCAs. The creation of this third tier of pipeline segments reflects PHMSA's policy decision "to apply progressively more protection for progressively greater consequence locations."8 In developing this "middle" tier, PHMSA decided not to simply expand the definition of HCAs such that the full Integrity Management program would apply to more miles of pipeline, which would run counter to a "graded approach" based on risk.9 PHMSA states that its proposal "balances the need to provide additional protections for persons within the potential impact radius" of a pipeline rupture, even though located outside of a defined HCA, "and the need to prudently apply IM resources in a fashion that continues to emphasize the risk priority of HCAs."10

In proposing the use of MCAs, PHMSA rejected an alternative "tiered" approach, which would have applied less stringent Integrity Management rules to pipelines that operate at less than 30 percent of the line's specified minimum yield strength ("SMYS").11 Rather than use the 30 percent SMYS threshold to define the contours of the entire Integrity Management program, PHMSA's proposal continues to differentiate pipeline segments using the 30 percent SMYS threshold only with respect to specific requirements.12

PHMSA also decided that the creation of MCAs did not eliminate the need for continued reliance on "class" locations. A "class location unit" is an onshore area that extends 220 yards on either side of the centerline of any continuous one-mile length of pipeline as follows: (i) a Class 1 location unit has 10 or fewer buildings intended for human occupancy; (ii) a Class 2 location unit has more than 10 but fewer than 46 buildings intended for human occupancy; (iii) a Class 3 location unit has 46 or more buildings intended for human occupancy or a building or other occupied area within 100 yards of a pipeline occupied by 20 or more persons above a minimum amount of time; and (iv) a Class 4 location unit is one where buildings with four or more stories above ground are prevalent.13 For various elements of PHMSA's regulations, more extensive safety requirements apply as the "class" location increases. PHMSA proposes to retain distinctions between class location because the concept "is integral to determining MAOPs, design pressures, pipeline repairs, [HCAs], and operating and maintenance inspections and surveillance intervals."14

Because a class location unit is an area along "any contiguous 1-mile" length of a pipeline, a cluster of 46 or more buildings near one point on a pipeline can result in two miles of pipeline being classified as a Class 3 location. In contrast, an operator has the option of defining an HCA with more precision. An operator is permitted to define an HCA as the area within a "potential impact circle" containing: (i) 20 or more buildings intended for human occupancy (with some exceptions); or (ii) an "identified site."15 The purpose of a "potential impact circle" is to define the area around each potential point of failure along a pipeline that could be affected if the pipeline ruptures. Thus, the potential impact circle relies on a "potential impact radius," which is measured using a formula that takes into account the maximum allowable operating pressure and the nominal diameter of the pipeline segment.16 Alternatively, an operator has the option to define HCAs in a way that includes all pipelines within a Class 3 or 4 location.17

Conceptually, an "identified site" is an alternative way to identify areas where people are likely to be present, and thus affected by a pipeline rupture. An identified site means: (i) an outside area or open structure that is occupied by 20 or more persons on at least 50 days in any 12-month period, such as a beach, playground, or camping ground; (ii) a building that is occupied by 20 or more persons on at least five days a week for 10 weeks in any 12-month period, such as religious facilities, office buildings, community centers, or general stores; or (iii) a facility occupied by persons who are confined, are of impaired mobility, or would be difficult to evacuate, such as a hospital, prison, school, or retirement facility.18 Thus, whereas a "class location" is a broad designation that corresponds only roughly to a location where a rupture could do serious harm, operators have the option to define an HCA more precisely to identify a pipeline segment whose rupture could do the most harm.

Definition of "Moderate Consequence Areas"

PHMSA proposes to define an MCA using a modified version of the criteria used to define an HCA. A point along a pipeline segment is within an MCA if the "potential impact circle" around that point contains: (i) five or more buildings intended for human occupancy (with some exceptions) (as compared to 20 or more such buildings when defining an HCA); (ii) an "occupied site"; or (iii) "a right-of-way for a designated interstate, freeway, expressway, and other principal 4-lane arterial roadway" as defined by the Federal Highway Administration.19 An "occupied site" includes: (i) an outside area or open structure that is occupied by five or more persons on at least 50 days in any 12-month period, such as a beach, playground, or camping ground (as compared to 20 or more persons when defining an HCA); or (ii) a building that is occupied by five or more persons on at least five days a week for 10 weeks in any 12-month period, such as religious facilities, office buildings, community centers, or general stores (as compared to 20 or more persons when defining an HCA).20 Any area within an MCA that meets the more selective HCA criteria remains a "covered segment" subject to PHMSA's Integrity Management rules.

Integrity Management Requirements for Pipeline Segments in Moderate Consequence Areas

PHMSA proposes to add Section 192.710, which would require integrity assessments of onshore transmission pipelines located outside of an HCA but within a Class 3 or a Class 4 location or an MCA (but only if the segment can accommodate inspection by means of an instrumented in-line inspection tool, i.e., a "smart pig").21 A "smart pig" is a "device placed inside the pipeline to measure the thickness of the pipeline walls" and that "ultrasonically or electromagnetically detects defects in a pipe."22 For a pipeline segment subject to new Section 192.710, the operator must perform the initial assessments within 15 years of the rule's effective date and must perform periodic reassessments every 20 years thereafter.23

To perform an assessment, an operator must select one of the following methods: an internal inspection tool, a Subpart J pressure test, a "spike" hydrostatic pressure test, Guided Wave Ultrasonic Testing ("GWUT"), direct assessment,24 or another "technology or technologies" that an operator "demonstrates can provide an equivalent understanding of the line pipe for each of the threats to which the pipeline is susceptible."25 With a few adjustments, these are the same assessment methods applicable to covered segments within HCAs under PHMSA's Integrity Management rules, as those rules would be revised by the NPRM. As is true under the Integrity Management rules, under Section 192.710, an operator must select an assessment method "capable of identifying anomalies and defects associated with each of the threats to which the pipeline is susceptible[.]"26 In lieu of a new assessment, an operator is permitted to rely on a prior assessment if the assessment meets the requirements for in-line inspection defined in the Integrity Management rules.27

As discussed below, the proposed rule also requires pipelines operators to verify the MAOP of pipeline segments within MCAs in certain circumstances.

Implications of Establishing a Middle "Moderate" Tier of Pipeline Safety Requirements

Several aspects of the new Section 192.710 are intended to partially mitigate the burdens of the new requirement. First, the new integrity assessments would be required for a segment in an MCA only if the segment can accommodate inspection by means of a smart pig. Second, the schedule for assessing pipeline segments within MCAs would be longer than the schedule for assessing "covered segments" within HCAs. Third, there is a separate set of inspection requirements applicable to a segment with an MAOP less than 30 percent of SMYS (a "low stress segment") for purposes of assessing the threats of external corrosion and internal corrosion.28

PHMSA states that its proposal for MCAs is comparable to the 2012 voluntary commitment made by members of the Interstate Natural Gas Association of America ("INGAA"), and that this similarity "shows a common understanding of the importance of this issue and a path towards a solution."29 INGAA's commitment would extend the application of Integrity Management principles in four stages, which would result, by 2030, in applying Integrity Management principles to 100 percent of INGAA pipeline mileage along which people live, work, or congregate (which is 80 percent of INGAA's total pipeline mileage).30 After 2030, Integrity Management principles would be extended to the 20 percent of pipeline mileage where no population resides. It appears that PHMSA's new MCA requirements are being imposed in addition to INGAA's voluntary commitments rather than as a replacement for those commitments.31

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[1] Notice of Proposed Rule, Pipeline Safety: Safety of Gas Transmission and Gathering Pipelines, Docket No. PHMSA-2011-0023, 81 Fed. Reg. 20,722, 20,732 (April 8, 2016) ("proposed rule" or "NPRM"). See also 81 Fed. Reg. 29,830 (May 13, 2016) (extending comment due date to July 7, 2016).

[2] Advanced Notice of Proposed Rulemaking, Pipeline Safety: Safety of Gas Transmission Pipelines, Docket No. PHMSA-2011-0023, 81 Fed. Reg. 53,086 (Aug. 25, 2011) ("ANPRM"); National Transportation Safety Board, Pacific Gas and Electric Company Natural Gas Transmission Pipeline Rupture and Fire, San Bruno, California, September 9, 2010, Pipeline Accident Report NTSB/PAR-11/01 (Aug. 30, 2011) (the "NTSB San Bruno Report"); and Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011, Pub. L. 112-90, 125 Stat. 1904 (2012) ("2011 Pipeline Safety Act").

[3] Superseding Indictment, U.S. v. Pacific Gas and Electric Co., No. 3:14-cr-00175 (N.D. Cal. July 30, 2014), ECF No. 22 (the "San Bruno Indictment").

[4] See 49 C.F.R. Part 192, Subpart O. These rules went into effect in 2004. Pipeline Safety: Pipeline Integrity Management in High Consequence Areas, Final Rule, Docket No. RPSA-00-7666, 68 Fed. Reg. 69,788 (Dec. 15, 2003).

[5] 49 C.F.R. § 192.911.

[6] 49 C.F.R. § 192.619(c). The "grandfather" clause was available only when the pipeline segment was "found to be in satisfactory condition, considering its operating and maintenance history[.]" 49 C.F.R. § 192.619(c).

[7] Specifically, for pipeline segments installed after July 1, 1970, the MAOP of a pipeline segment equaled the lowest of the following: (i) a calculation based on the design pressure of the weakest element in the segment; (ii) a calculation based on the results of the segment's post-construction pressure test; (iii) the highest actual operating pressure at which the pipeline operated during the five years preceding November 12, 1970; or (iv) the pressure determined by the operator to be "the maximum safe pressure after considering the history of the segment[.]" 49 C.F.R. § 192.619(a).

[8] NPRM, 81 Fed. Reg. at 20,732.

[9] NPRM, 81 Fed. Reg. at 20,732.

[10] NPRM, 81 Fed. Reg. at 20,743.

[11] NPRM, 81 Fed. Reg. at 20,743.

[12] See, e.g., Proposed § 192.506(a), 81 Fed. Reg. at 20,830 (requiring a "spike" pressure test if certain integrity management threats are present on a line that is operated at 30% or more of SMYS); Proposed § 192.710(c)(8), 81 Fed. Reg. at 20,838 (for new integrity assessment requirements outside of HCAs, establishing separate inspection requirements applicable to a segment with an MAOP less than 30% of SMYS (a "low stress segment") for purposes of assessing the threats of external corrosion and internal corrosion ); and 49 C.F.R. § 192.939 (2015) (authorizing different integrity management reassessment intervals for segments, depending on the percentage of SMYS at which the segment operates).

[13] 49 C.F.R. § 192.5.

[14] NPRM, 81 Fed. Reg. at 20,743.

[15] 49 C.F.R. § 192.903.

[16] 49 C.F.R. § 192.903.

[17] 49 C.F.R. § 192.903. Under this second method, an operator can define an HCA as: (i) a Class 3 or 4 location; (ii) any area in a Class 1 or 2 location where the pipeline segment's "potential impact radius" is greater than 660 feet (200 meters), and the area within a potential impact circle contains 20 or more buildings intended for human occupancy; or (iii) any area in a Class 1 or 2 location where the pipeline segment's "potential impact circle" contains an identified site. Id.

[18] 49 C.F.R. § 192.903.

[19] Proposed § 192.3, 81 Fed. Reg. at 20,826.

[20] Proposed § 192.3, 81 Fed. Reg. at 20,826.

[21] Proposed § 192.710, 81 Fed. Reg. at 20,838-39.

[22] 8-S Williams & Meyers, Oil and Gas Law (LexisNexis Matthew Bender 2015) (citing Township of Piscataway v. Duke Energy, 488 F.3d 203, 211 (3rd Cir. 2007) and General Accounting Office, Trans-Alaska Pipeline 100 (GAO/RCED-91-89, July 19, 1991).

[23] Proposed § 192.710(b)(1), 81 Fed. Reg. at 20,838.

[24] Proposed § 192.71(c)(6), 81 Fed. Reg. at 20,838.

[25] Proposed § 192.710(c)(7), 81 Fed. Reg. at 20,838.

[26] Proposed § 192.710(c), 81 Fed. Reg. at 20,838.

[27] Proposed § 192.710(b)(2), 81 Fed. Reg. at 20,838 (referencing in-line inspection requirements in proposed § 192.921(a)(1)).

[28] Proposed § 192.710(c)(8), 81 Fed. Reg. at 20,838. The NPRM's requirements for pipelines operating at stress levels of less than 30% of SMYS are based on technical information provided in the Interstate Natural Gas Association of America/American Gas Association Final Report No. 13–180, Leak vs. Rupture Thresholds for Material and Construction Anomalies, December 2013. NPRM, 81 Fed. Reg. at 20,813.

[29] NPRM, 81 Fed. Reg. at 20,731.

[30] NPRM, 81 Fed. Reg. at 20,730.

[31] See, e.g., NPRM, 81 Fed. Reg. at 20,731 ("Given INGAA's commitment, feedback from the ANPRM, the results of incident investigations, and IM considerations, PHMSA has determined it is appropriate to improve aspects of the current IM program").

The content of this article is intended to provide a general guide to the subject matter. Specialist advice should be sought about your specific circumstances.

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