PHMSA proposes to amend gas pipeline safety standards and reporting requirements.  PHMSA Administrator named DOT’s Acting Inspector General.  Status of PHMSA Rulemakings.  PHMSA’s Technical Advisory Committees will meet in July.  PHMSA issues a notice of enforcement discretion regarding compliance deadlines under the Gas Transmission Rule.  PHMSA submits biennial reports to Congress regarding Research and Development projects.  Inspector General issues audit and recommendations regarding PHMSA’s LNG program.

PHMSA Proposes to Amend Gas Pipeline Safety Standards and Reporting Requirements

On May 28, the Pipeline and Hazardous Materials Safety Administration (PHMSA) released a pre-publication version of a Notice of Proposed Rulemaking (NPRM) that would amend Part 191 and Part 192 of the federal pipeline safety regulations.  The NPRM states that the proposed amendments are intended to ease regulatory burdens with respect to the construction, operation, and maintenance of gas transmission, distribution, and gathering pipeline systems.

PHMSA expects the NPRM to be published in the Federal Register on June 9, and that comments will be due August 9. 

Below is an overview of the proposed amendments. 

Distribution Integrity Management Programs (DIMP)  

Farm Taps (§§ 192.740 & 192.1003).  PHMSA proposes to provide operators of farm taps that originate at regulated pipelines the option of inspecting and maintaining the pressure regulating equipment at the farm tap pursuant to either the requirements of § 192.740 or the operator’s DIMP.  Farm taps originating at unregulated gathering or production lines would be exempt from DIMP and § 192.740, as well as the requirement to submit an annual report, but remain subject to other provisions of Part 192 and Part 191. 

The NPRM describes a farm tap as an individual service line directly connected to a gas transmission, gathering, or production pipeline.  In the NPRM and in recently proposed Farm Tap Frequently Asked Questions (FAQ), PHMSA states that the service line begins at the first aboveground point, such as the inlet to a valve or regulator, where the line is isolated from the source pipeline.  The service line continues until it terminates at the outlet of the customer’s meter or the connection to the customer’s piping, whichever is further downstream.  The NPRM states that if there is no isolation point, the farm tap is exempt from DIMP, § 192.740, and annual reporting, but is subject to all other requirements in parts 191 and 192 applicable to service lines even if the source pipeline is an unregulated gathering or production pipeline.  According to proposed FAQ #3, if there is no isolation point, then a service line that originates from the source pipe is considered part of the source pipe and is covered by the same federal pipeline safety regulations applicable to the source piping, if any. In this respect the NPRM appears to be inconsistent with the proposed FAQ.

PHMSA states that the NPRM is intended to address concerns that were raised after adoption of § 192.740 which requires that an operator inspect and test, every three years, pressure regulating equipment at individual service lines “directly connected to a production, gathering, or transmission line that is not operated as part of a distribution system.”  At that time, PHMSA also adopted § 192.1003(b) exempting from DIMP “individual service lines directly connected to a transmission, gathering or production pipeline.”  After PHMSA issued these regulations in 2017, industry stakeholders argued that PHMSA had underestimated the cost of complying with § 192.740 and requested that operators have the flexibility to address the safety of farm taps under either regulation.  In March 2019, PHMSA issued an Announcement of Enforcement Discretion Regarding Farm Taps stating that the agency would not initiate enforcement against an operator that elected to manage the safety of farm taps under DIMP instead of § 192.740  The NPRM is intended to codify this option.

Master Meter Operators (§§ 192.1003 and 192.1015).  The NPRM proposes to exempt master meter operators from DIMP because these operators, which operate small systems such as apartment complexes or mobile home parks, have difficulty effectively implementing DIMP requirements.  Moreover, PHMSA and state regulators have concluded that even proper implementation of DIMP by these operators yields little safety benefit.  Rather PHMSA and state regulators have concluded that focusing on other fundamental risk mitigation requirements would produce greater safety benefits.   Master meter operators would remain subject to other Part 192 requirements. 

The NPRM also requests public comment on whether PHMSA should repeal the incident reporting exception for master meter operators.

Reporting Requirements

Monetary Threshold for Defining an Incident (§ 191.3).  The NPRM proposes to increase from $50,000 to $122,000 the amount of property damage (excluding the cost of gas lost) for determining whether a release of gas is an incident (and therefore reportable to PHMSA).  PHMSA also seeks comments on the appropriate method and frequency for future updates to the monetary threshold. 

Mechanical Fitting Failure Reports (§§ 191.12 & 192.1009).  PHMSA is proposing to eliminate mechanical fitting failure (MFF) reports Because PHMSA states that it obtains the same information from existing incident reports and that proposed revisions to the gas distribution annual report form will require that operators submit the number of MFFs that resulted in hazardous leaks.  

Corrosion Control

External Corrosion Control Monitoring (§ 192.465).  PHMSA is proposing to allow operators to remotely monitor cathodic protection rectifiers and clarify that an inspection consists of recording amperage and voltage measurements.  Annual cathodic protection testing, however, would continue to require physical inspection.

Atmospheric Corrosion Monitoring (§§ 192.481, 192.1007, and 192.1015).  The NPRM proposes to require atmospheric corrosion inspections on service lines that had no observed corrosion during the last inspection every five years (not to exceed 63 months) instead of every three years (not to exceed 39 months).  This interval would align with the current frequency of leakage surveys for service lines that are located outside of business districts.  The three-year inspection interval would continue to apply to service lines on which corrosion was observed during the last inspection.

The NPRM also proposes to clarify that DIMP requires an operator to consider atmospheric corrosion when evaluating a facility’s risk of corrosion.  In addition, PHMSA stated that it expects operators of service lines in high-corrosion environments to conduct atmospheric corrosion inspections more frequently than the minimum required interval.

Plastic Pipelines

Design of Plastic Pipe (§§ 192.7 & 192.121, and App. B).  The NPRM proposes to incorporate by reference the 2018a edition of ASTM “Standard Specification for Polyethylene (PE) Gas Pressure Pipe, Tubing, and Fittings” (ASTM D2513-18a).  Consistent with that standard, the NPRM proposes to increase from 12 inches to 24 inches the diameter of PE pipe that may use a design factor of 0.4 and reflect these sizes in the PE minimum wall thickness table at § 192.121(c)(2)(iv).                   

Joining Procedures (§§ 192.281 and 192.283).  The NPRM would clarify requirements for joining procedures to provide operators with additional flexibility.  PHMSA proposes to incorporate by reference the 2019 edition of ASTM F2620, “Standard Practice for Heat Fusion Joining of Polyethylene Pipe and Fittings.”  PHMSA also proposes to amend the regulations to clarify that alternative written procedures may be used as long as the operator demonstrates that they provide an equivalent or better level of safety as ASTM F2620 and are proven by test or experience to produce strong gastight joints.  This clarification addresses a concern raised by the American Gas Association that the regulatory text approved in the 2018 Plastic Pipe final rule did not provide this flexibility.  The NPRM also proposes clarifications regarding requirements for testing and visual inspection of joints.

Other Proposed Amendments to Part 192

Test Factors for Pressure Vessels (§ 192.153).  The NPRM proposes to revise the test requirements for components fabricated by welding to exempt pressure vessels that were installed after July 14, 2004, from the strength testing requirements of § 192.505(b) and § 192.619(a)(2).  Such pressure vessels must be pressure tested in accordance the American Society of Mechanical Engineers Boiler and Pressure Vessel Code and with a test factor of at least 1.3 times maximum allowable operating pressure (MAOP).  The NPRM also proposes test durations for pressure vessels installed after July 14, 2004. 

Welder Requalification Scheduling (§ 192.229).  PHMSA is proposing to allow welders or welding operators to weld using a particular welding process if they have welded with that process within the preceding 7½ months and the welds were tested and found acceptable under API Standard 1104 “Welding of Pipelines and Related Facilities.”  The current regulation prohibits a welder from using a welding procedure if they have not welded using that process within the previous 6 months.  The proposal is intended to provide operators increased flexibility in scheduling welding activities to maintain welder requalification.  PHMSA also is proposing to incorporate by reference the 20th edition of API Standard 1104, dated October 2005, including a July 2007 errata and a 2008 addendum.

Pre-Test Applicability (§ 192.507).  Currently, PHMSA allows operators to test fabricated units and short segments of pipe prior to installation on steel pipelines operated at a hoop stress greater than 30% of Specified Minimum Yield Strength (SMYS) if a post-installation test is not practicable. The NPRM proposes to extend this allowance to steel pipe to be operated at a hoop stress less than 30% of SMYS and at or above 100 psi.

PHMSA Administrator Named DOT’s Acting Inspector General.   

On May 15, President Trump named PHMSA Administrator Howard R. “Skip” Elliott DOT’s Acting Inspector General.  Mr. Elliott will continue in his role as PHMSA Administrator.

Status of PHMSA Rulemakings 

The chart below shows the status of PHMSA’s pending pipeline safety rulemakings as reflected in (1) the Department of Transportation’s (DOT) February Significant Rulemaking Report, (2) PHMSA’s status Chart of legislatively mandated actions, and (3) the Office of Management & Budget’s (OMB) Office of Information and Regulatory Affairs (OIRA) Fall 2019 Unified Agenda of Regulatory and Deregulatory Actions.  The Unified Agenda appears in two principal parts, Current Agenda Agency Regulatory Entries for Active Actions and Current Long Term Actions.  New Information is provided in Bold

Pending Final Rules

Pending Notices of Proposed Rulemakings

Pending Advance Notices of Proposed Rulemakings

Other PHMSA Updates

PHMSA’s Technical Advisory Committees will meet in July.  We understand that PHMSA’s Gas Pipeline Advisory Committee and Liquid Pipeline Advisory Committee will convene a virtual meeting on July 22 and July 23, respectively.  Among the topics the committees will address will be PHMSA’s NPRM addressing Valves and Rupture Identification and Mitigation.  A notice will be published in the Federal Register. 

PHMSA issues a notice of enforcement discretion regarding compliance deadlines under the Gas Transmission rule.  On April 22, PHMSA issued a notice advising PHMSA-regulated gas pipeline operators that, in light of the President’s March 13, 2020 Proclamation of a National Emergency Concerning the Novel Coronavirus Disease Outbreak, the agency does not intend to take enforcement actions regarding the July 1, 2020 compliance deadlines contained in the Gas Transmission Final Rule, issued October 1, 2019.  Generally, these compliance deadlines apply to requirements to develop and follow a number of written procedures and to begin identifying, scheduling and performing assessments on piggable transmission line segments that operate at pressures above 30% of SMYS and that are located in moderate consequence areas.  Recognizing that operators may face personnel resource constraints, PHMSA will allow additional time to develop the required procedures.  According to the notice, PHMSA will resume its normal enforcement activities after December 31, 2020.  The notice does not apply to Part 191 reporting requirements or other later compliance deadlines contained in the final rule. 

PHMSA submits biennial reports to Congress regarding Research and Development projects.  On May 21, PHMSA submitted its biennial report to Congress summarizing PHMSA’s awarded Research and Development (R&D) projects carried out by federal and non-federal stakeholders, along with a review of how each project is designed to improve pipeline safety.  For fiscal years 2017 and 2018, PHMSA’s R&D program awarded over $12.7 million to support 34 projects. The projects were selected to address threat prevention, anomaly detection, leak detection, LNG, and underground natural gas storage.

On May 21, PHMSA submitted its biennial report to Congress providing an update on the progress and implementation of the Pipeline Safety R&D Five-Year Program Plan.  The Plan summarizes updated research needs and priorities, provides a general overview of the R&D program, highlights past successes, and describes Plan activities for fiscal years 2017 and 2018.  The report summarizes R&D program performance metrics, provides an itemized list of each R&D project and provides a review of how each project potentially improves safety. 

Inspector General issues audit and recommendations regarding PHMSA’s LNG program.  On April 28, DOT’s Office of Inspector General (OIG) published an audit report assessing PHMSA’s oversight of the safety of liquefied natural gas (LNG) facilities.  The audit examined PHMSA’s (1) inspection of existing interstate LNG facilities, (2) review of compliance with federal siting requirements by LNG project developers, and (3) evaluation of state gas programs’ oversight of LNG facilities.

The OIG report found that PHMSA’s inspections of existing interstate LNG facilities met the agency’s standards.  OIG, however, identified shortcomings in PHMSA’s procedures for evaluating compliance of LNG project developers with federal siting requirements.  Among other things, OIG found that PHMSA’s procedures for reviewing applications do not provide for second-level verifications of reviews conducted by Agency and subcontractor engineers.  OIG recommended that PHMSA adopt additional written procedures that include second-level verification steps to reduce the risk of incomplete or inconsistent analyses of LNG facility applications.

OIG also found that PHMSA’s evaluations of state gas programs missed deficiencies in the inspection intervals for LNG facilities and in LNG inspector training.  OIG attributed this to several factors, including that PHMSA evaluators did not maintain information to verify which state records were reviewed, inherent biases that affected decisions regarding which records to review, and the lack of a requirement in PHMSA’s guidelines for state inspections to require the lead state inspector to have completed all required training.  OIG recommended that PHMSA update its procedures for evaluating state gas programs to provide for random sampling in the selection of operators and facilities to be reviewed, identify the records or other evidence needed to support PHMSA’s evaluations, and update its guidelines to states to ensure that at least one member of each inspection team has completed all required training for lead inspectors.