PHMSA Proposes Amendments to Gas Pipeline Safety Regulations

On March 17, 2016, the Pipeline and Hazardous Materials Safety Administration (PHMSA) released an advance copy of the long-awaited notice of proposed rulemaking (NPRM) that would extensively modify the federal pipeline safety regulations applicable to gas transmission and gathering pipelines.  The NPRM reflects PHMSA’s response to congressional directives in the 2011 Pipeline Safety, Regulatory Certainty, and Job Creation Act (2011 Act), and recommendations of the National Transportation Safety Board (NTSB) and the Government Accountability Office.  In addition, PHMSA is expected to release additional documents, including a regulatory impact statement that will address the proposal’s costs and benefits, and an environmental analysis.  Comments will be due 60 days after the NPRM is published in the Federal Register, although requests to extend that deadline are expected to be filed. 

The NPRM is lengthy and detailed.  The summary below provides a topical overview of the following key proposed changes:  Records Verification, Maximum Allowable Operating Pressure (MAOP), Test Requirements, Non-Integrity Management (IM) Pipeline Assessments and Remediation Schedules, IM, Corrosion Control, Gathering Pipelines, Management of Change, Continuing Surveillance, and New and Revised Definitions. 

Records Verification (proposed revised 49 C.F.R. §§ 192.5 & 192.13(e) and new §§ 192.67, 192.127, 192.205, 192.607)

Material Documentation Plans.  Proposed new § 192.607 would require that operators of existing gas steel transmission pipelines develop comprehensive material documentation plans to verify that records of material properties for line pipe, valves, flanges and components are “reliable, traceable, verifiable and complete.”  The NPRM specifies the material information that must be validated.  The proposal would apply to transmission lines in Class 3 or Class 4 locations or high consequence areas (HCA) lacking reliable, traceable, verifiable, and complete material documentation records for line pipe, valves, flanges and components.  The proposal is intended to implement section 23 of the 2011 Act which directed PHMSA to require that owners and operators of gas transmission pipelines in Class 3 and 4 locations and Class 1 and 2 HCAs verify that records accurately reflect physical and operational characteristics of pipeline and confirm the established MAOP. 

Other Required Records.  Other NPRM provisions would require that operators of transmission pipelines acquire and maintain records documenting:  (1) class location determinations (§ 192.5); (2) original steel pipe manufacturing information (§ 192.67); (3) pipe design information (§ 192.127); and (4) manufacturing standard and pressure ratings for pipeline components (§ 192.205).  These provisions are not limited to lines lacking adequate material documentation records located in Class 3 or Class 4 locations or HCAs and, consequently, appear to apply more broadly than § 192.607.

Compliance Deadline.  Operators must develop their material documentation plans no later than 180 days after effective date of the final rule.

Maximum Allowable Operating Pressure (proposed revised 49 C.F.R. § 192.619 and new § 192.624)

New and Enhanced MAOP Requirements.  Also keying off section 23 of the 2011 Act, PHMSA proposes to revise existing MAOP regulations to increase test pressure factors and to require that operators of certain onshore steel pipelines establish MAOP through one of several methods, including a pressure test to at least 1.25 x MAOP (plus a spike test for “legacy” pipe), pressure reduction, engineering critical assessments, including an instrumented in-line inspection (ILI) tool, or pipe replacement. 

Applicability.  MAOP must be established for any line that:

(1) experienced a reportable incident since its last Subpart J pressure test because of a defect related to original manufacturing, or construction, installation, fabrication, or cracking, and is located in an HCA, a Class 3 or Class 4 location, or a “moderate consequence area” (MCA), a proposed new area affected by a pipeline’s potential impact circle that contains 5 or more buildings intended for human occupancy, an occupied site, or a right of way for a principal 4-lane road;

(2) lacks reliable, traceable, verifiable, and complete MAOP pressure test records and the line is in an HCA or a Class 3 or Class 4 location;

(3) has an MAOP established under § 192.619(c) (the grandfather clause) and is located in an HCA, a Class 3 or Class 4 location, or an MCA.

Compliance timeline.  Operators would be required to complete testing for 50% of affected mileage within 8 years of the effective date of the rule and 100% of mileage within 15 years. 

Grandfather clause.  The existing grandfather clause, under which certain pipelines may establish MAOP based on the line’s 5-year high operating pressure before July 1, 1970 without performing a Subpart J pressure test, would be available only for pipe segments outside of HCAs and MCAs.

Test Regulations (proposed revised 49 C.F.R. § 192.503 and new § 192.506)

PHMSA proposes to modify testing regulations to require that certain existing steel pipelines be strength tested with a spike hydrostatic pressure test to substantiate the proposed MAOP.  Lines subject to this requirement are those operating at pressures producing hoop stress levels of 30% or more of specified minimum yield strength (SMYS) and with integrity threats that cannot be addressed by other means.  The NPRM also provides for the use of alternative technologies, subject to PHMSA providing a “no objection” letter.  This proposal responds to an NTSB recommendation, issued in response to the 2010 San Bruno, California, pipeline rupture and explosion, that gas transmission pipelines constructed before 1970 be hydrostatically tested. 

Non-IM Pipeline Assessments and Remediation Schedules (proposed revised 49 C.F.R. §§ 192.710 and new §§ 192.711 and 192.713)

Pipeline Assessments.  Operators would be required to assess the condition of onshore transmission pipe segments in Class 3 or Class 4 locations or in MCAs (if the pipe can accommodate ILI tools).  Pipeline segments subject to IM regulations would be excluded.  Assessments must be capable of identifying anomalies and defects associated with potential threats using one or more of the following methods:  ILI, pressure test, spike hydrostatic pressure test, excavation and in situ direct examination, Guided Waive Ultrasonic Testing (GWUT), direct assessment, or other technologies.  In addition, lines with MAOPs producing hoop stresses less than 30% of SMYS must be assessed for external and internal corrosion in accordance with new proposed requirements.

Data analysis.  Data must be analyzed by someone qualified, and any uncertainties in the reported results (such as tool tolerance) must be explicitly considered.

Assessment timeframe.  Initial assessments must be completed within 15 years of the effective date of the rule, with periodic reassessments performed every 20 years thereafter.

Remediation Schedules.  Operators would be required to repair conditions that could adversely affect safe pipeline operation pursuant to specified remediation schedules that vary based on the nature of the discovered condition.  The proposed rule identifies “immediate repair conditions,” “two-year conditions,” and “monitored conditions."  Remaining strength calculations must be based on data documented in reliable, traceable, verifiable, and complete records about pipe and materials properties.

Integrity Management (proposed revised 49 C.F.R. §§ 192.911, 192.917, 192.921, 192.923, 192.927, 192.929, 192.933, 192.935, 192.937, & 192.939)

Transmission pipeline segments located in HCAs would be subject to more stringent integrity management requirements.  Revised and new measures include:

Data Gathering and Integration.  PHMSA proposes to codify the requirements of ASME B31.8S specifying the pipeline attribute data that operators must integrate, verify and validate. 

Risk Assessments.  New requirements would apply to performing risk assessments.  In particular, in response to a post-San Bruno recommendation of the NTSB, operators would not be permitted to consider manufacturing and construction defects as stable unless the pipe segment has not experienced an in-service incident attributed to a manufacturing or construction-related defect since the date of the last pressure test. 

Modified Assessment Methods.  Assessment methods would include ILI (or similarly effective tool), pressure test, spike hydrostatic pressure test, excavation and in situ direct examination, GWUT, direct assessment to address corrosion and stress corrosion cracking (permitted if line cannot accommodate ILI tool and other methods are not practical), and other technology providing an equivalent understanding of the line pipe. 

Revised Remediation Schedules.  The NPRM would expand the number of immediate repair conditions and one-year repair conditions.

New Preventive and Mitigative (P&M) Measures.  Operators would be required to implement new and substantially enhanced P&M measures to protect covered segments from the threats of internal and external corrosion. 

Corrosion Control (proposed revised 49 C.F.R. §§ 192.461, 192.465, 192.473, 192.485 and new §§ 192.478, 192.493)

Operators would be subject to expanded and new corrosion control measures, including measures to detect coating damage after construction, minimize interference currents, and detect adverse effects of potentially corrosive constituents in gas. 

Gas Gathering (proposed revised 49 C.F.R. §§ 192.3, 192.8, 192.9; Part 191)

PHMSA is proposing to modify the definition of onshore gas gathering lines and to regulate some Class 1 (rural) gathering lines. 

Reporting requirements.  All gathering lines, regulated and unregulated, would be required to comply with PHMSA’s Part 191 reporting requirements.

Modified Onshore Gathering Line Definition.  PHMSA would discontinue relying on API Recommended Practice (RP) 80 to define gas gathering lines.  The NPRM proposes a new definition of gathering line, as well as other types of facilities, such as “onshore production facility” and “onshore production operation,” that are relevant to determining the beginning of gathering.  The proposed definition also would modify the end points of gathering, in particular, to restrict reliance on incidental gathering.

Determining Regulated Onshore Gathering.  The NPRM would create the following new subcategories of existing Type A and Type B gathering lines:

Type A Lines:  Metallic lines with MAOP producing hoop stress of 20% or more of SMYS or non-metallic lines with MAOP greater than 125 psig

Area 1:  Lines in Class 2, 3, 4 Locations
Area 2:  Lines in Class 1 locations with nominal diameter of 8 inches or greater in Class 1 locations

Type B Lines:  Metallic lines with MAOP producing hoop stress of less than 20% SMYS or non-metallic lines with MAOP 125 psig or less

Area 1:  Lines in Class 3 or 4 Locations
Area 2:  Class 2 Locations or within defined safety buffer

Subject to several exceptions, Type A, Area 1 lines would remain subject to the same regulations that apply to gas transmission lines.  Type A, Area 2 lines (i.e. Class 1 gathering lines 8 inches or more in diameter) would be subject to the same regulations as Type B lines, including requirements applicable to corrosion control, damage prevention, public education, MAOP, line markers, and leakage surveys. 

Compliance timeline.  Existing lines that become regulated as a result of the new rule would be required to comply with regulatory requirements within 2 years. 

Management of Change (proposed new 49 C.F.R. § 192.13(d)) 

Operators would be required to develop and follow a management of change process that addresses technical, design, physical, environmental, procedural, operational, maintenance, and organizational changes to the pipeline or processes, regardless of whether they are temporary or permanent.  The NPRM describes required elements of management of change plans. 

Continuing Surveillance (proposed new 49 C.F.R. § 192.613(c)) 

Within 72 hours after an extreme weather event ends, operators would be required to inspect all potentially affected transmission pipeline facilities to detect conditions that could adversely affect safe operations.  Inspection methods must be based on the nature of the event, and the affected pipeline’s physical characteristics, operating conditions, location and prior history.  Operators would be required to take appropriate remedial action. 

New and Revised Definitions (proposed revised 49 C.F.R. § 192.3) 

In addition to the new terms identified above, the NPRM proposes a number of new or revised defined terms, including close interval survey, distribution center, dry gas, electrical survey, gas processing plant, gas treatment facility, in-line inspection and in-line inspection tool, legacy construction techniques and legacy pipe, modern pipe, occupied site, onshore production facility/onshore production operation, safety-related condition, significant seam cracking, significant stress corrosion cracking, transmission line, and wrinkle bend.

PHMSA Rulemakings Update.  The tables below summarize the status of PHMSA’s rulemakings as reported in the Department of Transportation’s (DOT) March Significant Rulemaking Report and by the Office of Management and Budget’s (OMB) Office of Information and Regulatory Affairs (OIRA) in the Fall 2015 Unified Regulatory Agenda. Revised dates appear in bold.

Pending Notices of Proposed Rulemaking

Pending Final Rules

*Under Executive Order (EO) 12866, OMB reviews proposed significant rules to ensure they are consistent with applicable law, the President’s priorities, and the principles set forth in the EO, and to ensure the proposals do not conflict with another agency’s policies or actions.  OMB also analyzes the cost-benefit analyses in support of the proposals.  While the EO sets out deadlines for OMB evaluation, review periods are often extended.   

OTHER PHMSA UPDATES

DOT OIG recommends lowering the criminal liability standard for pipeline safety violations and modifying whistleblower provisions.  On March 8, the DOT’s Office of the Inspector General (OIG) submitted a letter to House Representative Michael Capuano recommending that the “knowingly and willfully” standard for proving criminal violations of the Pipeline Safety Laws be replaced with a “recklessly” standard, consistent with the hazardous materials transportation laws.  OIG stated the willful standard has discouraged the prosecution of potential criminal cases because of the difficulty of proving a willful violation.  The OIG also recommended including a whistleblower incentive provision in the Pipeline Safety Laws to encourage pipeline employees and other persons with knowledge of violations to report them.

DOT OIG releases statement on top management challenges facing DOT.  On March 15, the DOT’s OIG issued a statement identifying DOT’s top management challenges for fiscal year 2016.  Among other things, OIG stated that PHMSA has not fully implemented safety measures included in the 2011 Act to improve operators’ assessments of gas pipelines, require leak detection systems on hazardous liquid pipelines, and establish regulations for transporting carbon dioxide by pipeline.

PHMSA forms Risk Modeling Work Group.  As a result of the September 2015 Pipeline Risk Modeling Methodologies Workshop, PHMSA has formed a Risk Modeling Work Group that will provide technical guidance and recommendations to PHMSA on state of the art pipeline risk modeling methods, tools, and data requirements for gas transmission and hazardous liquid pipelines.  The Group will meet April 12 – 14 in Washington, DC, and June 7 – 9 in Houston, Texas.

PHMSA accepting applications for 2016 HMEP grants.  On February 2, PHMSA announced that it is accepting applications for Hazardous Materials Emergency Preparedness Grants (HMEP) for States and Territories and Native American Tribes, which provide funding to increase effectiveness in safely and efficiently handling hazardous materials incidents and to aid implementation of the Emergency Planning and Community Right-to-Know Act of 1986.  Applications are due May 2.

UPDATES FROM INDUSTRY

Pipeline Association for Public Awareness releases updated emergency contact directory.  On March 15, the Pipeline Association for Public Awareness released an updated pipeline emergency contact directory, which provides a list of pipeline operators by state and county with emergency and non-emergency telephone numbers.

SELECT UPDATES FROM STATES

ARIZONA

On December 11, 2015, the Arizona Corporation Commission issued a supplemental notice of proposed rulemaking (Docket no. RG-00000A-15-0098) to incorporate by reference federal pipeline safety standards and forms that have been adopted through October 1, 2015, and to make certain rules consistent with the federal pipeline safety regulations.  Staff responses to certain questions were filed on March 2; public comments are due March 28.

CALIFORNIA

ACA11 (Gatto):  This Assembly Constitutional Amendment would propose to the voters of California an amendment to the California Constitution which would authorize the Legislature to relocate or reassign all or a portion of the functions of the California Public Utilities Commission (CPUC) to other state agencies.  The amendment would direct the Legislature to adopt structures to provide for greater accountability for state public utilities and to focus on safety, reliability, and ratesetting, and effective January 1, 2019, would repeal provisions of the California Constitution relating to the CPUC.  The amendment was introduced on March 9 and referred to the Committee on Utilities and Commerce.

INDIANA

On January 13, the Indiana Utility Regulatory Commission issued a notice of proposed rulemaking to reflect recent changes to the federal pipeline safety standards.  A public hearing was held on March 14; comments were due March 21.

NEW YORK

On March 8, the New York State Comptroller issued the results of an audit of the New York Public Service Commission’s (PSC) Department of Public Service (DPS), which conducts pipeline safety inspections and reports to the PSC. The audit concluded that DPS does not verify the accuracy of operator-provided information relating to employee and contractor qualifications, and that DPS does not perform comprehensive data analysis to better identify risks.  The audit also found that DPS relies too heavily on operator self-reporting of incidents, having been unaware of at least six gas-related incidents in 2015 that went unreported.  The audit recommends that DPS ensure that operator qualifications are accurately documented, develop procedures to identify reportable incidents that operators fail to report, and work with operators to identify all available sources of pipeline safety data and determine the type of analyses that will best identify risks and improve safety.

NORTH DAKOTA

On February 29, the North Dakota Industrial Commission issued a Full Notice of Intent to Adopt and Amend Administrative Rules announcing that it will convene four public hearings on April 11 – 14 regarding proposed regulatory changes that will affect, among other types of facilities, underground gathering pipelines capable of transporting crude oil, natural gas, carbon dioxide, or produced water and salt water handing facilities.  For pipelines, the proposed revised rules address information reporting, access to records, bonding, and a wide range of safety requirements, including construction, notification, design, installation, inspections, pipeline rights of way, geographic information system locational data, operations, leak detection, spill response, corrosion control, pipeline integrity, repairs, and abandonment.  The proposed rules also contain a number of provisions affecting saltwater handling facilities. 

VIRGINIA

HB1261 (Habeeb):  On March 7, Governor Terry McAuliffe approved HB1261 which, effective July 1, 2016, authorizes the State Corporation Commission (SCC) to seek an interstate agent agreement with PHMSA authorizing the SCC to inspect interstate gas pipelines located in the state of Virginia, and to collect inspection fees to be used to administer the program.