DOT Pipeline Compliance News

January 2021 Issue

In This Issue

PHMSA Reauthorization – PIPES Act 2020

Contained within the $900 billion, 5,593 page ‘‘Consolidated Appropriations Act, 2021’’, you will find the “Protecting Our Infrastructure Pipelines and Enhancing Safety Act of 2020”, otherwise known as the PIPES Act of 2020. This was signed into law by President Trump on December 27th and authorizes funding for PHMSA to carry out its mission through fiscal year 2023.

The Act includes several mandates that will require future PHMSA rulemaking; some provisions that are effective immediately, that will likely be codified by PHMSA in the future; and requirements for various studies and reports to congress. Some highlights are provided below. For a copy of the PIPES Act of 2020, contact Jessica Foley at

PHMSA-Specific Mandates

PHMSA Workforce Development

  • Identify opportunities for distance learning
  • Increase inspector workforce and maintain a minimum inspector staffing levels throughout the duration of fiscal 2023
  • Recruiting and retainage incentives for new and existing workforce

Advancement of New Pipeline Safety  Technologies and Approaches

  • Encourages safety-enhancing testing programs to evaluate innovative technologies and operational practices testing the safe operation of hazardous liquid and natural gas pipelines
  • Establishes limitations and prohibitions where these safety enhancing testing programs may be performed

Self-Disclosure of Violations to PHMSA

  • Allows PHMSA to consider operator-disclosure and correction of violations, or actions to correct a violation prior to discovery by PHMSA, as mitigating factors when determining penalties

Due Process Protections in Enforcement Proceedings

  • Provides enhanced due process during enforcement proceedings
  • Opens formal hearings to the public

Automatic or Remote-Controlled Shut-Off Valves on Existing Pipelines

  • Mandates that the National Academy of Sciences conduct a study and report back to Congress their findings of potential methodologies or standards for the installation of automatic or remote-controlled shut-off valves on existing pipelines located within high consequence areas

All Pipeline Mandates

“Idled Pipe” operational status clarifications

  • Provides a definition of “Idled Pipe”
  • Mandates PHMSA develop regulations prescribing the applicability of the pipeline safety requirements related to Idled Pipe as well as resumption of service requirements within 2 years

Safety-Related Condition Reports

  • In addition to submitting SRC reports to PHMSA, an operator must also submit these reports to the appropriate State agency or, where no appropriate State agency exists, to the Governor of a State where the SRC occurred, or to the appropriate Tribe where the SRC occurred.

All Gas Pipeline Mandates

Leak Detection for Regulated Gas Pipelines

  • Mandates that PHMSA publish a final rule for regulated gas pipeline leak detection and repair programs for pipeline safety and environmental protection
  • Requires the use of advanced leak detection technologies and practices, including a schedule for repairing or replacing each potentially hazardous leaking pipe

Distribution Gas Pipeline Mandates

Distribution Integrity Management Plans

  • Mandates that PHMSA publish a final rule within 2 years to ensure that each distribution integrity management plan developed by an operator of a distribution system includes an evaluation of the risks resulting from the presence of cast iron pipes and mains in the distribution system and the risks that could lead to or result from the operation of a low-pressure distribution system at a pressure that makes the operation of any connected and properly adjusted low-pressure gas burning equipment unsafe
  • Distribution operators must make available to PHMSA and appropriate State agencies copies of their DIMP, Emergency Response Plans and O&M procedures, including submittal of any significant changes to their DIMP within 60 days of the change for review

Distribution Emergency Response Plans

  • Mandates that PHMSA update regulations within 2 years for gas distribution operators to update their emergency response procedures to include notification to response agencies, public officials and the public as appropriate

Distribution Operations and Maintenance Procedures

  • Mandates that PHMSA update regulations within 2 years for gas distribution operators to update their O&M procedures for responding to overpressurization indications, including specific actions and an order of operations for immediately reducing pressure in or shutting down portions of the gas distribution system, if necessary
  • These updates must have detailed procedures
    • For the management of change process for significant technology, equipment, procedural, and organizational changes to the distribution system
    • To ensure that relevant qualified personnel review and certify construction plans for accuracy, completeness, and correctness
    • To identify and manage traceable, reliable, and complete records, including maps and other drawings, critical to ensuring proper pressure controls for a gas distribution system, and updating these records as needed
    • To have at least one designated person monitor gas pressure at a site with the capability to promptly control overpressurization at a district regulator station during construction projects
    • To assess and upgrade each district regulator station of the operator to ensure that the risk of MAOP exceedance by a common mode of failure is minimized and the regulator station has secondary overpressure-protection safety technology

Gas Gathering Pipeline Mandates

Gas Gathering Lines

  • Mandates that PHMSA publish a final rule within 90 days related to the gas gathering portion of the proposed mega-rule ‘‘Pipeline Safety: Safety of Gas Transmission and Gathering Pipelines’’ (81 FR 20722; Docket No. PHMSA–2011–0023)

LNG Facility Mandates

Liquified Natural Gas Facilities

  • Update O&M standards requirements applicable to large-scale liquefied natural gas facilities (other than peak shaving facilities)
  • Allow for the creation of the National Center of Excellence for Liquefied Natural Gas Safety

Hazardous Liquid Pipeline Mandates

Unusually Sensitive Areas

  • Created definitions for Certain Coastal Waters as well as Coastal Beaches as they relate to Unusually Sensitive Areas
  • Mandates that PHMSA publish a final rule within 90 days that explicitly states that the Certain Coastal Waters and Coastal Beaches are USA ecological resources for purposes of determining whether a hazardous liquid pipeline is in a high consequence area

Gas Pipeline Regulatory Reform

PHMSA issued this Final Rule (Pipeline Safety: Gas Pipeline Regulatory Reform; Docket No. PHMSA-2018-0046; Amdt Nos. 191-29; 192-128) on January 5, 2021, and it has been submitted to the Office of the Federal Register for publication.  It is unclear when or if this rule will actually make it to the Federal Register before the next administration, and there is a risk of the rulemaking being sent back to PHMSA if that is the case.  The intent of this rule is to ease some regulatory burdens of regulated gas pipelines without compromising safety.  A summary of the provisions are included below.  If you would like a copy of this pending final rule, contact Jessica Foley.

Incident Report

  • PHMSA raised the reporting threshold for incidents that result in property damage to $122,000, consistent with inflation since 1984 when the threshold was set at $50,000.
  • PHMSA revised the definition of an Incident under §191.3 Definitions and added a new Appendix A to Part 191-Procedure for Determining Reporting Threshold.  The threshold for property damage now includes an inflationary adjustment formula based upon the average Consumer Price Indices for all Urban Consumers (CPI-U) published by the Bureau of Labor Statistics each month.

Annual Report

  • PHMSA removed annual reporting requirements for certain master meter, petroleum gas and farm tap systems.

Mechanical Fitting Failure (MFF) Reporting

  • PHMSA determined that further collection of MFF reports has limited value and have removed §§ 191.12 and 192.1009, eliminating the requirement for operators to submit MFF reports.
  • PHMSA is including a count of MFFs on the Gas Distribution Annual Report form and revision of the Gas Distribution Incident Report form to include information from the MFF report for incidents involving a failure of a mechanical joint.

Standards Incorporated By Reference (IBR)

  • ASTM International, ASTM D2513-18a – “Standard Specification for Polyethylene (PE) Gas Pressure Pipe, Tubing, and Fittings” (Aug. 1, 2018) has been IBR approved for Item I, Appendix B to Part 192.
  • ASTM F2620-19, “Standard Practice for Heat Fusion Joining of Polyethylene Pipe and Fittings,” approved February 1, 2019, (ASTM F2620) has been IBR approved for §§ 192.281(c) and 192.285(b).
  • API Standard 1104, “Welding of Pipelines and Related Facilities,” 20th edition, October 2005, including errata/addendum (July 2007) and errata 2 (2008), (API Std 1104), IBR approved for §§ 192.225(a); 192.227(a); 192.229(b) and (c); 192.241(c); and Item II, Appendix B.

Farm Taps

  • PHMSA revised §192.740 and §192.1003 to allow flexibility for an operator to choose whether they would maintain their farm taps using the prescriptive approach under §192.740 or include the farm taps in an operator’s DIMP under §192.1003.
  • PHMSA exempt farm tap service lines connected to unregulated gathering or production pipelines from annual reporting (§ 191.11), farm tap regulator maintenance (§ 192.740), and DIMP (part 192, subpart P).

External Corrosion Control: Monitoring

  • PHMSA revised §192.465(b), “External corrosion control: Monitoring,” to clarify that operators may monitor rectifier stations remotely 6 times per year, but after January 1, 2022, rectifiers and impressed current power sources must be physically inspected annually.

Atmospheric Corrosion: Monitoring

  • PHMSA revised §192.481 to extend the frequency of atmospheric corrosion monitoring to 5 years for onshore distribution services lines.  However, if atmospheric corrosion is found, the next interval for inspection is 3 years.
  • PHMSA revised §192.491(c) to require operators of distribution service lines to retain records of the two most recent atmospheric inspections.
  • PHMSA revised §§ 192.1007(b) and 192.1015(b)(2) to clarify that consideration of corrosion risks under DIMP explicitly includes atmospheric corrosion.

Plastic Pipe

  • PHMSA allows the use of a 0.40 design factor for PE pipe produced on or after the effective date of the rule with a maximum diameter of 24 inches.
  • PHMSA made a few miscellaneous and editorial changes to various sections related to plastic pipe.

Test Requirements for Pressure Vessels

  • PHMSA revised §192.153(e)(1) which specifies a prefabricated unit or pressure vessel that is installed after July 13, 2004 is not subject to the strength testing requirements at §192.505(b) provided it has been tested in accordance with §192.153(a) or (b) and with a test factor of at least 1.3 times the intended MAOP, consistent with the hydrostatic pressure test factors in section VIII, division 1 of the ASME BPVC.  PHMSA also added a footnote to table 1 to the §192.619(a)(2)(ii) specifying that the factor for establishing the MAOP of a prefabricated unit or pressure vessel installed after July 14, 2004 is 1.3 times the MAOP.
  • PHMSA added requirements to inspect pre-tested pressure vessels after being placed at the vessel’s installation location on its support structure in §192.153(e)(3), allowing for those inspections to occur prior to the pressure vessel tie-in on-site with the pipeline.
  • PHMSA clarified that any pressure vessel that is temporarily or permanently installed in a pipeline facility must be inspected for damage as described above unless it has been pressure tested on its supports at its installation location.
  • PHMSA added §192.153(e)(6) that clarifies testing and inspection requirements for relocating an existing pressure vessel that has previously been used in service for permanent installation at a new location in a pipeline facility.

Welding Process Requirement

  • PHMSA revised §192.229(b) to specify that welders or welding operators may not weld with a particular welding process unless they have engaged in welding with that process within the preceding 7 ½ months (formerly 6 months prior to this revision) and the welds were tested and found acceptable in accordance with API Std 1104.

Pre-test Applicability

  • PHMSA added §192.507(d) to permit pre-testing on steel pipelines operating at a hoop stress less than 30 percent of SMYS and at or above 100 psig.

Pipeline Information Collection Notice and Request for Comments

[Docket No. PHMSA-2019-0172]

On December 17, 2020, PHMSA published a notice and request for comments for gas pipelines and gas storage facilities reporting requirements, as summarized below. 

PHMSA proposes to revise PHMSA F 7100.2-1 Annual Report for Natural and Other Gas Transmission and Gathering Pipeline Systems, to

  • add a section to collect data about the number of miles of gas transmission pipelines in high consequence areas (HCA) categorized by the HCA determination method found at 49 CFR 192.903 and the type of risk model used.
  • add Part G1 to collect data on the number of relief valve lifts and compressor station emergency shutdown (ESD) events that occurred within a calendar year.
  • amend the gas transmission and gathering incident report to exclude reporting of relief valve lifts and ESD events when the systems function as expected, which is a change in PHMSA’s interpretation of “intentional” releases.

In January 2020, OMB approved changes to the Gas Transmission Annual Report form in conjunction with new regulations promulgated in a final rule titled “Safety of Gas Transmission Pipelines, MAOP Reconfirmation, Expansion of Assessment Requirements and Other Related Amendments” (84 FR 52180). During the OMB review period of the final rule, industry associations submitted joint comments on the proposed changes to the form. PHMSA’s responses to the Associations’ comments are as follows:

Industry Association CommentPHMSA Response
MCA-related reporting requirements should only apply to pipelines with a MAOP >=30% of SMYS.Disagree.  PHMSA is retaining this data collection element.
Report the total mileage of class 1 and class 2 non-HCA/non-MCA pipe segments assessed during the calendar year, but don’t break down this mileage into “baseline” and “reassessment.”Agreed.  PHMSA proposes to replace the current “baseline assessment” and “reassessed” categories with a single “miles assessed” data field.
Operators should not have to identify whether class 1 and 2 location segments that are non-HCA or non-MCA have complete MAOP records.Agreed for now.  PHMSA proposes to remove the requirement but reserves the right to pursue this data collection at a later time.
PHMSA should align the pressure test ranges in Part F with the pressure test factors specified in 49 CFR 192.619: [≥1.5], [<1.5 to ≥1.25], [<1.25 to ≥1.1], and [Less than 1.1 or no test].Agreed. The lowest allowable pressure test, in accordance with 49 CFR 192.619(a)(2), is 1.1. PHMSA proposes revising the form to combine the “1.1 to 1” and “no test” categories into a single category.
Collect mileage by individual test factor only in Part R of the form, and remove sections 3.1-3.3.Agreed. 
The revised Annual Report form should go into effect for the 2021 reporting year (due in March 2022), after operators have been required to identify those pipeline segments that are subject to the requirements of the final rule.PHMSA agrees with the timeframe and has already made the requested adjustments to the implementation schedule.

PHMSA proposes to revise PHMSA F 7100.2 Incident Report for Gas Transmission and Gathering Systems, to:

  • Revise the instructions to remove the requirement for operators to report relief valve lifts and compressor station ESD events when the systems function as expected. Instead of reporting these occurrences as incidents, operators would submit data on intentional gas releases on the Gas Transmission and Gathering Annual Report form PHMSA F 7100.2-1.
  • Return instructions that were inadvertently removed regarding when questions G6 through G8 were required to be completed. Previously, the form was clear that these questions are only required to be completed when part A14 (“onshore pipeline . . .” or “offshore pipeline . . .”) is answered.

PHMSA proposes to clarify several instructions and to modify the reporting of well counts on PHMSA F 7100.4-1 Underground Natural Gas Storage Facility Annual Report

Comments are due by February 16, 2021, and can be submitted via the Federal eRulemaking Portal, identified by docket number PHMSA-2019-0172.

For a copy of PHMSA’s Pipeline Information Collection Notice, contact Jessica Foley.

Hazardous Liquid Rulemaking FAQ’s Released

PHMSA released Frequently Asked Questions (FAQ) related to the final rule “Pipeline Safety: Safety of Hazardous Liquid Pipelines,” published on October 1, 2019.  Although FAQ’s are not enforceable, they do provide pipeline operators important guidance on how PHMSA interprets certain gray areas of code.  In this batch of final FAQ’s, PHMSA provides their response to the following questions.  For a copy of these FAQ’s or to inquire about RCP services, please contact Jessica Foley.

  • FAQ-1.0 What is the effective date for the new § 195.65 safety data sheets section?
  • FAQ-1.1 How can I provide a copy of the safety data sheets per § 195.65?
  • FAQ-2. Must I perform inspections and assessments required by these new regulations on “idled” pipelines?
  • FAQ-3. Can I proceed with using other technology without receiving a response from PHMSA when performing an assessment under § 195.416(d)?
  • FAQ-4. Is “discovery” of a condition for non-HCAs (§ 195.416(f)) the same as for “could affect” HCAs (§ 195.452(h)(2))?
  • FAQ-5. Must I use the same procedures for conducting assessments and making repairs on anomalies discovered by assessments performed under the new regulation § 195.416 as I use for § 195.452?
  • FAQ-6. For purposes of § 195.416(b), how often must assessments be performed for piggable, non-gathering, onshore line pipe not subject to IM requirements of § 195.452?
  • FAQ-7. Do I need to have a computational pipeline monitoring (CPM) leak detection system over all of my pipelines?
  • FAQ 7.1 Is patrolling alone a sufficient leak detection system per § 195.444?
  • FAQ-8. Do I necessarily have to redo my segment analysis under § 195.452(j)(2)?
  • FAQ-9. If the endpoints of covered segments are revised during the annual verification of covered segments required by § 195.452(j)(2), does that mean a baseline assessment is now required for pipe previously not identified as covered by IM?
  • FAQ-10. What is the effective date for the new § 195.454 Underwater Assessment section?
  • FAQ 10.1. If my onshore pipeline meets the requirement of § 195.454 do I need to assess the entire pipeline?
  • FAQ-11. Is the operator required to inspect its facilities under § 195.414 following a heavy rain?
  • FAQ-12. Is the operator required to perform inspections under § 195.414 following every extreme weather event or natural disaster?

Midstream Facilities Draft FAQ’s Released

[Docket No. PHMSA-2019-0199]

PHMSA published a notification in the Federal Register seeking public comments on a document titled ‘‘Pipeline Safety: Midstream Facilities Frequently Asked Questions,’’ a set of seven draft frequently asked questions developed by the Midstream Processing Working Group, established by the Gas Pipeline Advisory Committee and the Liquid Pipeline Advisory Committee. PHMSA received a request to extend the comment period to allow stakeholders more time to evaluate the frequently asked questions. PHMSA has extended the comment period from January 4, 2021, to February 4, 2021.

Comments can be submitted via the Federal eRulemaking Portal, identified by docket number PHMSA–2019–0199. For a copy of this notice, contact Jessica Foley.

Gas Transmission Rulemaking Draft FAQ’s Released

PHMSA has released a draft of “Batch 2” Frequently Asked Questions (FAQ) related to the final rule “Pipeline Safety: Safety of Gas Transmission Pipelines: MAOP Reconfirmation, Expansion of Assessment Requirements, and Other Related Amendments,” originally published October 1, 2019.  Batch 1 (Mega Rule FAQs – RCP Inc.) was finalized and released on September 15, 2020.  Comments can be made to PHMSA by going to the docket PHMSA-2019-0225-0031.  Once PHMSA has had the opportunity to review these comments, they will respond, similarly to Batch 1, with a final set of Batch 2 FAQ’s.  Our understanding is there is a 3rd Batch draft in progress and should be released soon.  In this draft Batch 2, there are numerous FAQ’s with PHMSA responses.  The following topics are addressed.  For a copy of these FAQ’s or to inquire about RCP services, please contact Jessica Foley (

  • Safety-Related Condition Reports
  • Operator Qualification reporting
  • MAOP of Type A and B gathering pipelines
  • Applicability to distribution lines
  • Material verification for pipeline components
  • Anomaly investigation of grandfathered pipe
  • Welder qualification records
  • Moderate Consequence Areas
  • Spike hydrostatic testing
  • Material verification
  • Maximum Allowable Operating Pressure establishment and reconfirmation
  • Assessments outside of High Consequence Areas

PHMSA Posts 2021 Inspection Protocols

PHMSA has published the updated 2021 inspection protocols for Gas Distribution, Gas Transmission, Hazardous Liquids, Liquified Natural Gas, Underground Gas Storage and Drug & Alcohol. Changes this year include D&A questions, new Liquid Rule content, new gas rule content and miscellaneous changes from the various content teams. You can access these on PHMSA’s Forms page: Pipeline Forms | PHMSA (

New Underground Damage Prevention Authority in Alabama

The State of Alabama has created a new organization as described in state regulations 910 – Underground Damage Prevention Authority.  The Authority has the power to write rules, adjudicate complaints, and issue penalties for violations of damage prevention laws and regulations.  The penalty provisions are as follows:

910-X-4-.01 Penalty Provisions

Any person who violates the provisions of Ala. Code § 37-15, et seq., or the rules adopted under the Authority, shall be subject to a civil penalty as follows:

  1. For a first violation, the violator shall complete a course of training concerning compliance or pay a civil penalty in an amount not to exceed five hundred dollars ($500) per incident, or both.
  2. For a second or subsequent violation within a twelve (12) month period, the violator shall complete a course of training concerning compliance or pay a civil penalty in an amount not to exceed one thousand dollars ($1000) per incident, or both.
  3. For a third or subsequent violation within a twelve (12) month period, the violator shall complete a course of training concerning compliance and pay a civil penalty in an amount not to exceed three thousand dollars ($3,000) per incident.
  4. Notwithstanding this subsection, if any violation was the result of gross negligence or willful noncompliance, the violator shall be required to complete a course of training concerning compliance and pay a civil penalty in an amount not to exceed ten thousand dollars ($10,000) per incident.

Maine Public Utilities Commission (MPUC) Rulemaking on Natural Gas and LNG Facility Operators

Proposed Rule Number: 2020-P234

The MPUC has initiated a rulemaking to amend Number 65-407 Ch. 420 – Safety Standards for Natural Gas and Liquefied Natural Gas Facility Operators. The proposed amendments are intended to update and modernize the Commission’s gas safety rules. 

The Commission held a public hearing on January 6, 2021, 1:30 p.m. remotely via Microsoft Teams. Interested persons may file initial comments on the proposed amendments to the rule using the Commission’s Case Management System (CMS), in Docket No. 2020-00282, on or before Friday, December 18, 2020. Interested persons may file final written comments on the proposed rule in CMS, in Docket No. 2020-00282, no later than Friday, January 22, 2021.

For questions, contact: Jody McColman, Maine Public Utilities Commission, 18 State House Station, Augusta, Maine 04333. Telephone: (207) 287-1365. Email:

Virginia Proposed Rule: Professional Engineering Stamps for Gas Projects

[Case No. URS-2020-00052]

The State of Virginia proposes to establish a new chapter, 20VAC5-360, Licensed Professional Engineer to Exercise Responsible Charge over Certain Natural Gas Engineering Projects. The new regulation requires that licensed professional engineers exercise responsible charge over certain pipeline projects undertaken by natural gas companies jurisdictional to the State Corporation Commission where such projects, among other things, present a material risk to public safety.  The proposed rule requires PE stamps for:

  1. New installation of district pressure regulator stations, compressor stations, or gate stations.
  2. Reconfiguration or physical facility changes performed at district pressure regulator stations, compressor stations, or gate stations that alter or modify the configuration or overpressure protection of equipment.
  3. Installation, uprating, repair, or abandonment of intrastate transmission pipelines.
  4. Any distribution main piping modifications or replacement work falling within established district regulator awareness zones as established by each operator.
  5. Any construction or maintenance work on distribution mains that changes the system operating pressure and requires a bypass or a change in the system operating pressure that involves more than two tie-ins.
  6. Installation of distribution mains where such mains attach to bridges or other engineered structures.
  7. Installation of distribution mains, including replacements and extension projects, that are within or cross any public right-of-way.
  8. Installation or abandonment of service lines connecting to transmission lines or a high-pressure distribution main with an MAOP that exceeds 90 PSIG.
  9. Installation of peak shaving facilities, to include any modifications or reconfigurations that would alter such a facility’s pressure delivery characteristics.
  10. Any other project in the judgment of the operator that poses a material risk to public safety.

On or before February 2, 2021, any interested person may file comments on the Proposed Rules by following the instructions found on the Commission’s website. Such comments may also include proposed modifications and hearing requests. All filings shall refer to Case No. URS-2020-00052. Any request for hearing shall state with specificity why the issues raised in the request for hearing cannot be addressed adequately in written comments. If a satisfactory request for hearing is not received, the Commission may consider the matter and enter an order based upon the papers filed herein.

For further information, you Really Cool People can contact: Lauren Govoni, Deputy Director, Utility and Railroad Safety Division, State Corporation Commission, Tyler Building, 1300 East Main Street, P.O. Box 1197, Richmond, VA 23218, telephone (804) 371-9590, FAX (804) 371-9734, or email

DOT COVID-19 Drug & Alcohol Testing Statement of Enforcement Discretion for Substance Abuse Professionals and Service Agents

On March 23, 2020, the U.S. Department of Transportation (DOT) Office of Drug and Alcohol Policy and Compliance (ODAPC) provided guidance about the impact of COVID-19 on DOT drug and alcohol testing requirements for employers, employees, and service agents.  On April 4, 2020, ODAPC provided supplemental information specific to performing remote evaluations by Substance Abuse Professionals (SAP) and the re-qualification timelines for collectors, Medical Review Officers (MRO), Screening Test Technicians (STT) and Breath Alcohol Technicians (BAT), and SAPs.  As of December 09, 2020, ODAPC has extended the statement and it continues to be effective through June 30, 2021. Click here to view the updated guidance.

We would welcome the opportunity to discuss our services with you.


Bill Byrd signature
W. R. (Bill) Byrd, PE
RCP Inc.