Pipeline Safety: Safety of Gas Transmission Pipelines: MAOP Reconfirmation, Expansion of Assessment Requirements, and Other Related Amendments

Federal RegisterOct 1, 2019

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DEPARTMENT OF TRANSPORTATION

Pipeline and Hazardous Materials Safety Administration

49 CFR Parts 191 and 192

[Docket No. PHMSA-2011-0023; Amdt. Nos. 191-26; 192-125]

RIN 2137-AE72

Pipeline Safety: Safety of Gas Transmission Pipelines: MAOP Reconfirmation, Expansion of Assessment Requirements, and Other Related Amendments

AGENCY:

Pipeline and Hazardous Materials Safety Administration (PHMSA), DOT.

ACTION:

Final rule.

SUMMARY:

PHMSA is revising the Federal Pipeline Safety Regulations to improve the safety of onshore gas transmission pipelines. This final rule addresses congressional mandates, National Transportation Safety Board recommendations, and responds to public input. The amendments in this final rule address integrity management requirements and other requirements, and they focus on the actions an operator must take to reconfirm the maximum allowable operating pressure of previously untested natural gas transmission pipelines and pipelines lacking certain material or operational records, the periodic assessment of pipelines in populated areas not designated as “high consequence areas,” the reporting of exceedances of maximum allowable operating pressure, the consideration of seismicity as a risk factor in integrity management, safety features on in-line inspection launchers and receivers, a 6-month grace period for 7-calendar-year integrity management reassessment intervals, and related recordkeeping provisions.

DATES:

The effective date of this final rule is July 1, 2020. The incorporation by reference of certain publications listed in the rule is approved by the Director of the Federal Register as of July 1, 2020. The incorporation by reference of ASME/ANSI B31.8S was approved by the Director of the Federal Register as of January 14, 2004.

FOR FURTHER INFORMATION CONTACT:

Technical questions: Steve Nanney, Project Manager, by telephone at 713-272-2855. General information: Robert Jagger, Senior Transportation Specialist, by telephone at 202-366-4361.

SUPPLEMENTARY INFORMATION:

I. Executive Summary

A. Purpose of the Regulatory Action

B. Summary of the Major Provisions of the Regulatory Action in Question

C. Costs and Benefits

II. Background

A. Detailed Overview

B. Pacific Gas and Electric Incident of 2010

C. Advance Notice of Proposed Rulemaking

D. National Transportation Safety Board Recommendations

E. Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011

F. Notice of Proposed Rulemaking

III. Analysis of Comments, GPAC Recommendations and PHMSA Response

A. Verification of Pipeline Material Properties and Attributes—§ 192.607

i. Applicability

ii. Method

B. MAOP Reconfirmation—§§ 192.624, 192.632

i. Applicability

ii. Methods

iii. Spike Test—§ 192.506

iv. Fracture Mechanics—§ 192.712

v. Legacy Construction Techniques/Legacy Pipe

C. Seismicity and Other Integrity Management Clarifications—§ 192.917

D. 6-Month Grace Period for 7-Calendar-Year Reassessment Intervals—§ 192.939

E. ILI Launcher and Receiver Safety—§ 192.750

F. MAOP Exceedance Reporting—§§ 191.23, 191.25

G. Strengthening Assessment Requirements—§§ 192.150, 192.493, 192.921, 192.937, Appendix F

i. Industry Standards for ILI—§§ 192.150, 192.493

ii. Expand Assessment Methods Allowed for IM—§§ 192.921(a) and 192.937(c)

iii. Guided Wave Ultrasonic Testing—Appendix F

H. Assessing Areas Outside of HCAs—§§ 192.3, 192.710

i. MCA Definition—§ 192.3

ii. Non-HCA Assessments—§ 192.710

I. Miscellaneous Issues

i. Legal Comments

ii. Records

iii. Cost/Benefit Analysis, Information Collection, and Environmental Impact Issues

IV. GPAC Recommendations

V. Section-by-Section Analysis

VI. Standards Incorporated by Reference

A. Summary of New and Revised Standards

B. Availability of Standards Incorporated by Reference

VII. Regulatory Analysis and Notices

I. Executive Summary

A. Purpose of the Regulatory Action

PHMSA believes that the current regulatory requirements applicable to gas pipeline systems have increased the level of safety associated with the transportation of gas. Still, incidents continue to occur on gas pipeline systems resulting in serious risks to life and property. One such incident occurred in San Bruno, CA, on September 9, 2010, killing 8 people, injuring 51, destroying 38 homes, and damaging another 70 homes (PG&E incident). In its investigation of the incident, the National Transportation Safety Board (NTSB) found among several causal factors that the operator, Pacific Gas and Electric (PG&E), had an inadequate integrity management (IM) program that failed to detect and repair or remove the defective pipe section. PG&E was basing its IM program on incomplete and inaccurate pipeline information, which led to, among other things, faulty risk assessments, improper assessment method selection, and internal assessments of the program that were superficial and resulted in no meaningful improvement in the integrity of the pipeline system nor the IM program itself.

The PG&E incident underscored the need for PHMSA to extend IM requirements and address other issues related to pipeline system integrity. In response, PHMSA published an ANPRM seeking comment on whether IM and other requirements should be strengthened or expanded, and other related issues, on August 25, 2011 (76 FR 53086).

The NTSB adopted its report on the PG&E incident on August 30, 2011, and issued several safety recommendations to PHMSA and other entities. Several of these NTSB recommendations related directly to the topics addressed in the 2011 ANPRM and are addressed in this final rule. Also, the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 (2011 Pipeline Safety Act) was enacted on January 3, 2012. Several of the 2011 Pipeline Safety Act's statutory requirements related directly to the topics addressed in the 2011 ANPRM and are a focus of this rulemaking.

Another incident that influenced this rulemaking was the rupture of a gas transmission pipe operated by Columbia Gas near Sissonville, WV, on December 11, 2012. The escaping gas ignited, and fire damage extended nearly 1,100 feet along the pipeline right-of-way and covered an area roughly 820 feet wide. While there were no fatalities or serious injuries, three houses were destroyed by the fire, and several other houses were damaged. The ruptured pipe was one of three in the area that cross Interstate 77, and the incident closed the highway in both directions for 19 hours until a section of thermally damaged road surface approximately 800 feet long could be replaced. Following this incident, the NTSB finalized an accident report on February 19, 2014, issuing recommendations to PHMSA to include principal arterial roadways,

including interstates, other freeways and expressways, and other principal arterial roadways as defined by the Federal Highway Administration, to the list of “identified sites” that establish a high consequence area (HCA) for the purposes of an operator's IM program.

On April 8, 2016, PHMSA published an NPRM to seek public comments on proposed changes to the gas transmission pipeline safety regulations (81 FR 20722). A summary of those proposed changes, and PHMSA's response to stakeholder feedback on the individual provisions, is provided below in section IV of this document (Analysis of Comments and PHMSA Response).

The purpose of this final rule is to increase the level of safety associated with the transportation of gas. PHMSA is finalizing requirements that address the causes of several recent incidents, including the PG&E incident, by clarifying and enhancing existing requirements. PHMSA is also addressing certain statutory mandates of the 2011 Pipeline Safety Act and NTSB recommendations. While the NPRM addressed 16 major topic areas, PHMSA believes the most efficient way to manage the proposals in the NPRM is to divide them into three rulemaking actions. PHMSA is finalizing the provisions in this final rule as a first step. PHMSA anticipates completing a second rulemaking to address the topics in the NPRM regarding repair criteria in HCAs and the creation of new repair criteria for non-HCAs, requirements for inspecting pipelines following extreme events, updates to pipeline corrosion control requirements, codification of a management of change process, clarification of certain other IM requirements, and strengthening IM assessment requirements.

A third rulemaking is expected to address requirements related to gas gathering lines that were proposed in the NPRM.

RIN 2137-AF39.

RIN 2137-AF38.

B. Summary of the Major Provisions of the Regulatory Action in Question

Several of the amendments made in this rule are related to congressional legislation from the 2011 Pipeline Safety Act. The Act provides a 6-month grace period, with written notice, for the completion of periodic integrity management reassessments that otherwise would be completed no later than every 7 calendar years.

Another requirement is that operators explicitly consider and account for seismicity in identifying and evaluating potential threats.

The Act also requires operators to report exceedances of the maximum allowable operating pressure (MAOP) of gas transmission pipelines.

5 6

PHMSA is incorporating these changes into the PSR at 49 CFR parts 190-199 in this final rule.

2011 Pipeline Safety Act § 5(e).

2011 Pipeline Safety Act § 29.

2011 Pipeline Safety Act § 23.

MAOP means the maximum pressure at which a pipeline or segment of a pipeline may be operated under this part.

This rule also requires operators of certain onshore steel gas transmission pipeline segments to reconfirm the MAOP of those segments and gather any necessary material property records they might need to do so, where the records needed to substantiate the MAOP are not traceable, verifiable, and complete. This includes previously untested pipelines, which are commonly referred to as “grandfathered” pipelines, operating at or above 30 percent of specified minimum yield strength (SMYS). Records to confirm MAOP include pressure test records or material property records (mechanical properties) that verify the MAOP is appropriate for the class location.

Operators with missing records can choose one of six methods to reconfirm their MAOP and must keep the record that is generated by this exercise for the life of the pipeline. PHMSA has also created an opportunistic method by which operators with insufficient material property records can obtain such records. These physical material property and attribute records include the pipeline segment's diameter, wall thickness, seam type, grade (the minimum yield strength and ultimate tensile strength of the pipe), and Charpy V-notch toughness values (full-size specimen and based on the lowest operational temperatures),

if applicable or required. PHMSA considers “insufficient” material property records to be those records where the pipeline's physical material properties and attributes are not documented in traceable, verifiable, and complete records.

PHMSA uses class locations throughout part 192 to provide safety margins and standards commensurate with the potential consequence of a pipeline failure based on the surrounding population. Class locations are defined at § 192.5. A Class 1 location is an offshore area or a class location unit with 10 or fewer buildings intended for human occupancy. A Class 2 location is a class location unit with more than 10 but fewer than 46 buildings intended for human occupancy. A Class 3 location is a class location unit with 46 or more buildings intended for human occupancy, and a Class 4 location is where buildings with 4-or-more stories above ground are prevalent.

A Charpy V-notch impact test and its values indicate the toughness of a given material at a specified temperature and is used in fracture mechanics analysis.

PHMSA is requiring operators to perform integrity assessments on certain pipelines outside of HCAs, whereas prior to this rule's publication, integrity assessments were only required for pipelines in HCAs. Pipelines in Class 3 locations, Class 4 locations, and in the newly defined “moderate consequence areas” (MCA)

must be assessed initially within 14 years of this rule's publication date and then must be reassessed at least once every 10 years thereafter. These assessments will provide important information to operators about the conditions of their pipelines, including the existence of internal and external corrosion and other anomalies, and will provide an elevated level of safety for the populations in MCAs while continuing to allow operators to prioritize the safety of HCAs. This action fulfills the section 5 mandate from the 2011 Pipeline Safety Act to expand elements of the IM requirements beyond HCAs where appropriate.

A MCA is defined in § 191.3 as an onshore area within a potential impact circle, as that term is defined in § 192.903, containing either (1) 5 or more buildings intended for human occupancy or (2) any portion of the paved surface, including shoulders, of a designated interstate, other freeway, or expressway, as well as any other principal arterial roadway with 4 or more lanes, as defined in the Federal Highway Administration's

Highway Functional Classification Concepts, Criteria and Procedures, Section 3.1.

This rule also explicitly requires devices on in-line inspection (ILI), launcher or receiver facilities that can safely relieve pressure in the barrel before inserting or removing ILI tools, and requires the use of a device that can indicate whether the pressure has been relieved in the barrel or can otherwise prevent the barrel from being opened if the pressure is not relieved. PHMSA is finalizing this requirement in this final rule because it is aware of incidents where operator personnel have been killed or seriously injured due to pressure build-up at these stations.

C. Costs and Benefits

Consistent with Executive Order 12866, PHMSA has prepared an assessment of the benefits and costs of the final rule as well as reasonable alternatives. PHMSA estimates the annual costs of the rule to be approximately $32.7 million, calculated using a 7 percent discount rate. The costs reflect additional integrity assessments, MAOP reconfirmation, and ILI launcher and receiver upgrades.

PHMSA is publishing the Regulatory Impact Analysis (RIA) for this rule in the public docket. The table below

provides a summary of the estimated costs for the major provisions in this rulemaking (see the RIA for further detail on these estimates). PHMSA finds that the other final rule requirements will not result in incremental costs. PHMSA did not quantify the cost savings from material properties verification under the final rule compared to existing regulations. PHMSA also elected to not quantify the benefits of this rulemaking and instead discusses them qualitatively. PHMSA estimated total annual costs of the rule of $31.4 million using a 3 percent discount rate, and $32.7 million using a 7 percent discount rate.

Summary of Annualized Costs, 2019-2039

[$2017 thousands]

Provision

Annualized cost

3% Discount rate

7% Discount rate

1. MAOP Reconfirmation & Material Properties Verification

$25,848

$27,899

2. Seismicity

0.00

3. Six-Month Grace Period for Seven Calendar-Year Reassessment Intervals

0.00

4. In-Line Inspection Launcher/Receiver Safety

27.4

37.5

5. MAOP Exceedance Reports

0.00

6. Strengthening requirements for assessment methods

0.00

7. Assessments outside HCAs

5,482

4,713

8. Related Records Provisions

0.00

Total

31,357

32,650

II. Background

A. Detailed Overview

Introduction

Recent significant growth in the nation's production and use of natural gas is placing unprecedented demands on the Nation's pipeline system, underscoring the importance of moving this energy product safely and efficiently. Changing spatial patterns of natural gas production and use and an aging pipeline network has made improved documentation and data collection increasingly necessary for the industry to make reasoned safety choices and for preserving public confidence in its ability to do so. Congress recognized these needs when passing the 2011 Pipeline Safety Act, calling for an examination of issues pertaining to the safety of the Nation's pipeline network, including a thorough application of the risk-based integrity assessment, repair, and validation system known as IM.

The IM regulations specify how pipeline operators must identify, prioritize, assess, evaluate, repair, and validate the integrity of gas transmission pipelines in HCAs that could, in the event of a leak or failure, affect high consequence areas in the United States. These areas include certain populated and occupied areas. See § 192.903.

This final rule advances the goals established by Congress in the 2011 Pipeline Safety Act and is consistent with the emerging needs of the natural gas pipeline system. This final rule also advances the important discussion about the need to adapt and expand risk-based safety practices. As some severe pipeline incidents have occurred in areas outside HCAs

where the application of IM principles are not required, and as gas pipelines continue to experience failures from causes that IM was intended to address, this conversation is increasingly important.

HCAs are defined at § 192.903. There are two methods that can be used to determine and HCA, the specific differences of which we do not address here. Very broadly and regardless of which method used, operators must calculate the potential impact radius for all points along their pipelines and evaluate corresponding impact circles to identify what populations are contained within each circle. Potential impact circles with 20 or more structures intended for human occupancy, or those circles with “identified sites” such as stadiums, playgrounds, office buildings, and religious centers, are defined as HCAs.

This final rule strengthens IM requirements, including to ensure operators select the appropriate inspection tool or tools to address the pertinent identified threats to their pipeline segments, and clarifies and expands recordkeeping requirements to ensure operators have and retain the basic physical and operational attributes and characteristics of their pipelines. Further, this final rule establishes requirements to periodically assess pipeline segments in locations outside of HCAs where the surrounding population is expected to potentially be at risk from an incident, which are defined in the rule as MCAs. Even though these pipeline segments are not within currently defined HCAs, they could be located in areas with significant populations. This change facilitates prompt identification and remediation of potentially hazardous defects while still allowing operators to make risk-based decisions on where to allocate their maintenance and repair resources.

Natural Gas Infrastructure Overview

The U.S. natural gas pipeline network is designed to transport natural gas to and from most locations in the lower 48 States. Approximately two-thirds of the lower 48 States depend almost entirely on the interstate transmission pipeline system for their supply of natural gas.

One can consider the Nation's natural gas pipeline infrastructure as three interconnected parts—gathering, transmission, and distribution—that together transport natural gas from the production field, where gas is extracted from underground, to its end users, where the gas is used as an energy fuel or chemical feedstock. This final rule applies only to gas transmission lines and does not address gas gathering or natural gas distribution infrastructure and its associated issues. Currently, there are over 300,000 miles of onshore gas transmission pipelines throughout the U.S.

U.S. Department of Energy, “Appendix B: Natural Gas,”

Quadrennial Energy Review Report: Energy Transmission, Storage, and Distribution Infrastructure,

p. NG-28, April 2015.

U.S. DOT Pipeline and Hazardous Materials Safety Administration Data as of 4/26/2018.

Transmission pipelines primarily transport natural gas from gas treatment plants and gathering systems to bulk customers, local distribution networks, and storage facilities. Transmission pipelines can range in size from several inches to several feet in diameter. They can operate over a wide range of pressures, from a relatively low 200 pounds per square inch gage (psig) to

over 1,500 psig. They can be hundreds of miles long, and can operate within the geographic boundaries of a single State, or cross one or more State lines.

Regulatory History

PHMSA and its State partners regulate and enforce the minimum Federal safety standards authorized by statute

and codified in the PSR for jurisdictional

gas gathering, transmission, and distribution systems.

Title 49, United States Code, Subtitle VIII, Pipelines, Sections 60101,

et. seq.

Typically, onshore pipelines involved in the “transportation of gas”—see 49 CFR 192.1 and 192.3 for detailed applicability.

Federal regulation of gas pipeline safety began in 1968 with the creation of the Office of Pipeline Safety and the passage of the Natural Gas Pipeline Safety Act of 1968 (Pub. L. 90-481). The Office of Pipeline Safety issued interim minimum Federal safety standards for gas pipeline facilities and the transportation of natural and other gas by pipeline on November 13, 1968, and subsequently codified broad-based gas pipeline regulations on August 19, 1970 (35 FR 13248). The PSR were revised several times over the following decades to address different aspects of natural gas transportation by pipeline, including construction standards, pipeline materials, design standards, class locations, corrosion control, and MAOP.

In the mid-1990s, following models from other industries such as nuclear power, PHMSA started to explore whether a risk-based approach to regulation could improve safety of the public and reduce damage to the environment. During this time, PHMSA found that many operators were performing forms of IM that varied in scope and sophistication but that there were no uniform standards or requirements.

PHMSA began developing minimum IM regulations for both hazardous liquid and gas transmission pipelines in response to a hazardous liquid accident in Bellingham, WA, in 1999 that killed 3 people and a gas transmission incident in Carlsbad, NM, in 2000 that killed 12. PHMSA finalized IM regulations for gas transmission pipelines in a 2003 final rule.

The IM regulations are intended to provide a structure to operators to focus resources on improving pipeline integrity in the areas where a failure would have the greatest impact on public safety. The IM final rule accelerated the integrity assessment of pipelines in HCAs, improved IM systems, and improved the government's ability to review the adequacy of IM plans.

“Pipeline Safety: Pipeline Integrity Management in High Consequence Areas (Gas Transmission Pipelines).” 68 FR 69778; December 15, 2003. Corrected April 6, 2004 (69 FR 18227) and May 26, 2004 (69 FR 29903).

The IM regulations require that operators conduct comprehensive analyses to identify, prioritize, assess, evaluate, repair, and validate the integrity of gas transmission pipelines in HCAs. Approximately 7 percent of onshore gas transmission pipeline mileage is located in HCAs.

PHMSA and State inspectors review operators' IM programs and associated records to verify that the operators have used all available information about their pipelines to assess risks and take appropriate actions to mitigate those risks.

Per PHMSA's 2018 Annual Report, accessed April 9, 2019, 20,435 of the 301,227 miles of gas transmission pipelines are classified as being in HCAs.

Since the implementation of the IM regulations, sweeping changes in the natural gas industry have caused significant shifts in supply and demand, and the Nation's pipeline network faces increased pressures from these changes as well as from the increased exposure caused by a growing and geographically dispersing population. Also, long-identified pipeline safety issues, some of which IM set out to address, remain problems. A records search following the PG&E incident required by Congress in the 2011 Pipeline Safety Act, showed that some pipeline operators do not have the records they need to substantiate the current MAOP of their pipelines, as required under existing regulations, and lacked other critical information needed to properly assess risks and threats and perform effective IM.

PHMSA's inspection experience indicates pipelines continue to be vulnerable to failures stemming from outdated construction methods or materials. Finally, some severe pipeline incidents have occurred in areas outside HCAs where the application of IM principles is not required.

An effective IM program requires operators to analyze many data points regarding threats to their systems in addition to pipe attributes, including, but not limited to, construction data (year of installation, pipe bending method, joining method, depth of cover, coating type, pressure test records, etc.), operational data (maximum and minimum operating pressures, leak and failure history, corrosion monitoring, excavation data, corrosion surveys, ILI data, etc.).

Following the significant pipeline incident in 2010 at San Bruno, CA, in which 8 people died and more than 50 people were injured, Congress charged PHMSA with improving the IM regulations. Additionally, the NTSB and Government Accountability Office (GAO) issued recommendations regarding IM.

Comments in response to a 2011 ANPRM on these and related topics suggested there were many common-sense improvements that could be made to IM, as well as a clear need to extend certain IM provisions to pipelines outside of HCAs that were not covered by the IM regulations. A large portion of the transmission pipeline industry has voluntarily committed to extending certain IM provisions to non-HCA pipe, which demonstrates a common understanding of the need for this strategy.

More information on the NTSB recommendations being addressed in this rule are discussed in further detail in Section II. D. of this document “National Transportation Safety Board Recommendations.” See also, GAO-06-946, Natural Gas Pipeline Safety: Integrity Management Benefits Public Safety, but Consistency of Performance Measures Should be Improved,” September 8, 2006.

Through this final rule, PHMSA is making improvements to IM and is improving the ability of operators to engage in a long-range review of risk management and information needs, while also accounting for a changing landscape and a changing population.

Supply Changes

The U.S. natural gas industry increased production dramatically between 2005 and 2017, from 19.5 trillion cubic feet per year to 28.8 trillion cubic feet per year.

This growth was enabled by the production of “unconventional” natural gas supplies using improved technology to extract gas from low permeability shales. The increased use of directional drilling

and improvements to a long-existing industrial technique—hydraulic fracturing,

which began as an experiment in 1947—made the recovery of unconventional natural gas easier and economically viable. This has led to decreased prices and increased use of natural gas, despite a reduction in the production of conventional natural gas of about 14 billion cubic feet per day. Unconventional shale gas production now accounts for nearly 70 percent of overall gas production in the U.S.

U.S. Department of Energy, Energy Information Administration, “U.S. Natural Gas marketed Production”

https://www.eia.gov/dnav/ng/hist/n9050us2a.htm,

accessed 6/28/18.

Directional drilling is the practice of drilling non-vertical wells.

The extraction of oil or gas deposits performed by forcing open fissures in subterranean rocks by introducing liquid at high pressures.

Growth in unconventional natural gas production has shifted production away from traditionally gas-rich regions towards inland shale gas regions. To illustrate, in 2004, wells in the Gulf of Mexico's produced 5,066,000 million

cubic feet of natural gas per year (Mcf/year), approximately 20 percent of the Nation's natural gas production at the time. By 2016, that number had fallen to 1,220,000 Mcf/year, and approximately 4 percent of natural gas production in the U.S. During that same period, Pennsylvania's share of production grew from 197,217 Mcf/year to 5,463,783 Mcf/year, or approximately 17 percent of total natural gas production in the U.S.

23 24

An analysis conducted by the Department of Energy's Office of Energy Policy and Systems Analysis projects that the most significant increases in production through 2030 will occur in the Marcellus and Utica Basins in the Appalachian Basin,

and natural gas production is projected to grow from the 2015 levels of 66.5 Bcf/d to more than 93.5 Bcf/d.

U.S. Department of Energy, Energy Information Administration, “Gulf of Mexico—Offshore Natural Gas Withdrawals,”

https://www.eia.gov/dnav/ng/hist/na1060_r3fmtf_2a.htm,

accessed 6/28/18.

U.S. Department of Energy, Energy Information Administration, “Pennsylvania Natural Gas Gross Withdrawals,”

https://www.eia.gov/dnav/ng/hist/n9010pa2a.htm,

accessed 6/28/18.

U.S. Department of Energy, “Appendix B: Natural Gas,”

Quadrennial Energy Review Report: Energy Transmission, Storage, and Distribution Infrastructure,

p. NG-28, April 2015.

Id.,

at NG-6.

Demand Changes

The increase in domestic natural gas production has led to lower average natural gas prices.

In 2004, the outlook for natural gas production and demand growth was weak. Monthly average spot prices at Henry Hub

were high based on historic comparison of prices, fluctuating between $4 per million British thermal units (Btu) and $7 per million Btu. Prices rose above $11 per million Btu for several months in both 2005 and 2008.

Since 2008, after production shifted to onshore unconventional shale resources, and price volatility fell away following the Great Recession, natural gas has traded between about $2 per million Btu and $5 per million Btu.

Id.,

at NG-11.

Henry Hub is a Louisiana natural gas distribution hub where conventional Gulf of Mexico natural gas can be directed to gas transmission lines running to different parts of the country. Gas bought and sold at the Henry hub serves as the national benchmark for U.S. natural gas prices. (

Id.,

at NG-29, NG-30).

Energy Information Administration, Natural Gas Spot and Futures Prices,

http://www.eia.gov/dnav/ng/ng_pri_fut_s1_m.htm,

retrieved August 2018.

U.S. Department of Energy, “Appendix B: Natural Gas,”

Quadrennial Energy Review Report: Energy Transmission, Storage, and Distribution Infrastructure,

p. NG-11, April 2015.

These low prices have fueled consumption growth and changes in markets and spatial patterns of consumption. A shift towards natural gas-fueled electric power generation, cleaner than other types of fossil fuels, is helping to serve the needs of the Nation's growing population, and increased gas production and lower domestic prices have created opportunities for international export.

Plentiful domestic natural gas supply and comparatively low natural gas prices have changed the economics of electric power markets.

To accommodate recent growth and expected future growth in natural gas-fueled power, changes in pipeline infrastructure will be needed, including flow reversals of existing pipelines; additional lines to gas-fired generators; looping of existing networks, where multiple pipelines are laid parallel to one another along a single right-of-way to increase the capacity of a single system; and, potentially, new pipelines as well.

Id.,

at NG-9.

Increasing Pressures on the Existing Pipeline System Due to Supply and Demand Changes

Despite the significant increase in domestic gas production and the widespread distribution of domestic gas demand, significant flexibility and capacity in the existing transmission system mitigates the level of pipeline expansion and investment required. Some of the new gas production is located near existing or emerging sources of demand, which reduces the need for additional natural gas pipeline infrastructure. In many instances where new natural gas transmission capacity is needed, the network is being expanded by pipeline investments to enhance network capacity on existing lines rather than increasing coverage through new infrastructure. Additionally, operators have avoided building new pipelines by increasing pipeline diameters or operating pressures. In short, the nation's existing pipeline system is facing the brunt of this dramatic increase in natural gas supply and the shifting energy needs of the country.

In cases where use of the existing pipeline network is high, the next most cost-effective solution is to add capacity to existing lines via compression.

Compression requires infrastructure investment in the form of more compressor stations along the pipeline route, but it can be less costly, faster, and simpler for market participants in comparison to building a new pipeline. Adding compression, however, raises pipeline operating pressures and can expose previously hidden defects.

Gas can be reduced in volume by increasing its pressure. Therefore, operators can pack more gas into their lines if they can increase the pressure of the gas being transported.

New pipeline projects have been proposed to address pending supply constraints and higher prices. However, gaining public acceptance for natural gas pipeline construction has proved to be a substantial challenge. Pipeline expansion and construction projects often face significant challenges in determining feasible right-of-ways and developing community support for the projects.

Data Challenges

Operators and regulators must have an intimate understanding of the threats to, and operations of, their entire pipeline system. Data gathering and integration are important elements of good IM practices, and while operators have made many strides over the years to collect more and better data, several data gaps still exist. Ironically, the comparatively positive safety record of the Nation's gas transmission pipelines to date makes it harder to quantify some of these gaps. Over the 20-year period of 1998-2017, transmission facilities accounted for 50 fatalities and 179 injuries, or about one-sixth to one-seventh of the total fatalities and injuries caused by natural gas pipeline incidents in the U.S.

Given the relatively limited number of significant incidents that occur, it can be challenging to project the possible impact of low-probability but high-consequence events. See the RIA included in the public docket for a more detailed analysis of key types of incidents that may be mitigated by this final rule.

PHMSA, Pipeline Incident 20-Year Trends,

http://www.phmsa.dot.gov/pipeline/library/data-stats/pipelineincidenttrends

On September 9, 2010, a 30-inch-diameter segment of an intrastate natural gas transmission pipeline owned and operated by PG&E ruptured in a residential area of San Bruno, CA. The natural gas that was released subsequently ignited, resulting in a fire that destroyed 38 homes and damaged 70. Eight people were killed, many were injured, and many more were evacuated from the area.

The PG&E incident exposed several problems in the way data on pipeline conditions is collected and managed, showing that the operator had inadequate records regarding the physical and operational characteristics of their pipelines. These records are necessary for the correct setting and validation of MAOP, which is critically

important for providing an appropriate margin of safety to the public.

Much of operator data is obtained through the assessments and other safety inspections required by IM regulations. However, this testing can be expensive, and the approaches to obtaining data that are most efficient over the long term may require significant upfront costs to modernize pipes and make them suitable for automated inspection. As a result, there continue to be data gaps that make it hard to fully understand the risks to and the integrity of the Nation's pipeline system.

To evaluate a pipeline's integrity, operators generally choose between three methods of testing a pipeline: Inline inspection (ILI), pressure testing, and direct assessment (DA). In 2017, PHMSA estimates that about two-thirds of gas transmission interstate pipeline mileage was suitable for ILI, compared to only about half of intrastate pipeline mileage, and therefore, intrastate operators use more pressure testing and DA than interstate operators.

ILIs are performed using tools, referred to as “smart pigs,” which are usually pushed through a pipeline by the pressure of the product being transported. As the tool travels through the pipeline, it identifies and records potential pipe defects or anomalies. Because these tests can be performed with product in the pipeline, the pipeline does not have to be taken out of service for testing to occur, which can prevent excessive cost to the operator and possible service disruptions to consumers. Further, unlike pressure testing, ILI does not risk destroying the pipe, and it is typically less costly to perform on a per-unit basis than other assessment methods.

Pressure tests, also known as hydrostatic tests, are used by pipeline operators as a means to determine the integrity (or strength) of the pipeline immediately after construction and before placing the pipeline in service, as well as periodically during a pipeline's operating life. In a pressure test, water or an alternative test medium inside the pipeline is pressurized to a level greater than the normal operating pressure of the pipeline. This test pressure is held for a number of hours to ensure there are no leaks in the pipeline.

Direct assessment is the visual evaluation of a pipeline at a sample of locations along the line to detect corrosion threats, dents, and stress corrosion cracking of the pipe body and seams. In general, corrosion direct assessments are carried out by performing four steps. Operators will review records and other data, then inspect the pipeline through assessments that do not require excavation or use mathematical models and environmental surveys to find likely locations on a pipeline where corrosion is most likely to occur. For external corrosion, operators must use two or more complementary indirect assessment tools, including, for example, close interval surveys, direct current voltage gradient surveys, and alternating current voltage gradient surveys, to determine potential areas of corrosion to examine. For internal corrosion, operators must analyze data to establish whether water was present in the pipe, determine the locations where water would likely accumulate, and provide for a detailed examination and evaluation of those locations. Areas identified where corrosion may be occurring are then excavated, examined visually, and remediated as necessary. Operators also perform a post-assessment on segments where corrosion direct assessments are used to evaluate the effectiveness of the technique and determine re-assessment intervals as needed.

See PHMSA's fact sheet on DA at

https://primis.phmsa.dot.gov/Comm/FactSheets/FSdirectAssessmentGas.htm.

For cracking, operators collect and analyze data to determine whether the conditions for stress corrosion cracking are present, prioritize potentially susceptible segments of pipelines, and select specific sites for examination and evaluation. A DA would then evaluate the presence of stress corrosion cracking and determine its severity and prevalence. Operators are required to repair anomalies, if found, and determine further mitigation requirements as necessary.

Direct assessment can be prohibitively expensive to use on a wide scale and may not give an accurate representation of the condition of lengths of entire pipeline segments when the high expense leads the operator to select an insufficient number of observations. Further, as DA can only be used to validate specific threats, an operator that relies solely on a DA without performing a thorough risk analysis or running multiple tools specific to multiple threats might be leaving other threats unremediated in their pipelines.

Ongoing research and industry response to the ANPRM

and NPRM

indicate that ILI and spike hydrostatic pressure testing

is more effective than DA for identifying pipe conditions that are related to stress corrosion cracking defects. Regulators and operators agree that improving ILI methods as an alternative to hydrostatic testing is better for risk evaluation and management of pipeline safety. Hydrostatic pressure testing can result in substantial costs, occasional disruptions in service, and substantial methane emissions due to the routine evacuation of natural gas from pipelines prior to tests. Further, many operators prefer not to use hydrostatic pressure tests because it can be destructive.

ILI testing can obtain data along a pipeline not otherwise obtainable via other assessment methods, although this method also has certain limitations.

“Pipeline Safety: Safety of Gas Transmission Pipelines—Advanced Notice of Proposed Rulemaking,” 76 FR 5308; August 25, 2011.

“Pipeline Safety: Safety of Gas Transmission and Gathering Pipelines,” 81 FR 20722; April 8, 2016.

A “spike” hydrostatic pressure test is typically used to resolve cracks that might otherwise grow during pressure reductions after hydrostatic tests or as the result of operational pressure cycles.

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,

Page 96, 2011.

For example, ILI tools are ideal for gathering certain information about the physical condition of the pipe, including corrosion, deformations, or cracking. However, ILI technology cannot reliably detect other conditions, such as coating damage or environmental issues.

This final rule expands the range of permissible assessment methods and incorporates new guidelines to help operators in the selection of appropriate assessment methods. Promoting the use of ILI technologies, combined with further research and development by PHMSA as well as stakeholders to make ILI testing more accurate, is expected to drive innovation in pipeline integrity testing technologies that leads to improved safety and system reliability through better data collection and assessment.

Flow Reversals, Product Changes, and Manufacturing Defects

Significant growth of production outside the Gulf Coast region—especially in Pennsylvania and Ohio

—is causing a reorientation of the Nation's transmission pipeline network. The most significant of these changes will require reversing flows on pipelines to move gas from the Marcellus and Utica shale formations to the southeastern Atlantic region and the Midwest.

U.S. Energy Information Administration, “Annual Energy Outlook 2019,” p. 78—Dry shale gas production by region.

https://www.eia.gov/outlooks/aeo/pdf/aeo2019.pdf

Reversing a pipeline's flow can cause added stress on the system due to changes in gas pipeline pressure and temperature, which can increase the risk

of internal corrosion. Occasional failures on natural gas transmission pipelines have followed operational changes that include flow reversals and product changes.

Operators have recently submitted proposed flow reversals and product changes on gas transmission lines. In response to this phenomenon, PHMSA issued an Advisory Bulletin in 2014 notifying operators of the potentially significant impacts such changes may have on the integrity of a pipeline and recommended additional actions operators should consider performing before, during, and after flow reversals, product changes, and conversions to service, including notifications, operations and maintenance requirements, and IM requirements.

On September 29, 2013, the Tesoro High Plains pipeline leaked 20,000 barrels of crude oil in a North Dakota field. The location of pressure and flow monitoring equipment had not been changed to account for the reversed flow. On March 19, 2013, Exxon's Pegasus pipeline failed; the flow on that pipeline was reversed in 2006.

“Pipeline Safety: Guidance for Pipeline Flow Reversals, Product Changes, and Conversion to Service,”

ADB PHMSA-2014-0040,

79 FR 56121; September 18, 2014.

Data indicates that some pipelines are vulnerable to issues stemming from outdated construction methods or materials. Some gas transmission infrastructure was made before the 1970s using techniques that have proven to contain latent defects due to the manufacturing process. For example, pipe manufactured using low frequency electric resistance welding is susceptible to seam failure. Because these pipelines were installed before the Federal gas regulations were issued, many of those pipes were exempted from certain regulations, most notably the requirement to pressure test the pipeline segment immediately after construction and before placing the pipeline into service. A substantial amount of this type of pipe is still in service.

The IM regulations include specific requirements for evaluating such pipe if located in HCAs, but infrequent-yet-severe failures that are attributed to longitudinal seam defects continue to occur. The NTSB's investigation of the PG&E incident in San Bruno determined that the pipe failed due to a similar defect, a fracture originating in the partially welded longitudinal seam of the pipe. According to PHMSA's accident and incident database, between 2010 and 2017, 30 other reportable incidents were attributed to seam failures, resulting in over $18 million of reported property damage.

Currently, PHMSA's data shows that roughly 168,000 of the Nation's 301,000 miles of onshore gas transmission pipelines were installed prior to the 1970 requirement for hydrostatic pressure testing. See

https://hip.phmsa.dot.gov/analyticsSOAP/saw.dll?PortalPages.

Protecting the Safety and Integrity of the Nation's Pipeline System Beyond HCAs

The current IM program improves pipeline operators' ability to identify and mitigate the risks to their pipeline systems. IM regulations require that operators adopt procedures and processes to identify HCAs; determine likely threats to the pipeline within the HCA; evaluate the physical integrity of the pipe within the HCA; and repair, remediate, or monitor any pipeline defects found based on severity. Because these procedures and processes are complex and interconnected, effective implementation of an IM program relies on continual evaluation and data integration.

HCAs were first defined on August 6, 2002,

providing concentrations of populations with corridors of protection spanning 300, 660, or 1,000 feet, depending on the diameter and MAOP of the particular pipeline.

In a later NPRM,

PHMSA proposed changes to the definition of a HCA by introducing the concept of a covered segment, which PHMSA defined as the length of gas transmission pipeline that could potentially impact an HCA.

Previously, only distances from the pipeline centerline related to HCA definitions. PHMSA also proposed using Potential Impact Circles (PIC), Potential Impact Zones, and Potential Impact Radii (PIR) to identify covered segments instead of a fixed corridor width. The final Gas Transmission Pipeline Integrity Management Rule, incorporating the new HCA definition using the PIR and PIC concepts, was issued on December 15, 2003.

“Pipeline Safety: High Consequence Areas for Gas Transmission Pipelines,”

Final rule,

67 FR 50824; August 6, 2002.

The influence of the existing class location concept on the early definition of HCAs is evident from the use of class locations themselves in the definition, and the use of fixed 660 ft. distances, which corresponds to the corridor width used in the class location definition. This concept was later significantly revised, as discussed later, in favor of a variable corridor width based on case-specific pipe size and operating pressure.

“Pipeline Safety: Pipeline Integrity Management in High Consequence Areas (Gas Transmission Pipelines),”

Notice of Proposed Rulemaking,

68 FR 4278; January 28, 2003.

HCA and PIR definitions are in 49 CFR 192.903.

“Pipeline Safety: Pipeline Integrity Management in High Consequence Areas (Gas Transmission Pipelines),”

Final rule,

68 FR 69778; December 15, 2003.

The PG&E incident in 2010 motivated a comprehensive reexamination of gas transmission pipeline safety. In response to the PG&E incident, Congress passed the 2011 Pipeline Safety Act, which directed PHMSA to reexamine many of its safety requirements, including the expansion of IM regulations for transmission pipelines.

Further, both the NTSB and the GAO issued several recommendations to PHMSA to improve its IM program and pipeline safety. The NTSB noted in a 2015 study

that IM requirements have reduced the rate of failures due to deterioration of pipe welds, corrosion, and material failures. However, the NTSB noted that pipeline incidents in HCAs due to other factors increased between 2010 and 2013, and the overall occurrence of gas transmission pipeline incidents in HCAs has remained stable. Since 2013 there have been an average of 9 incidents within HCAs, which is below a peak of 12 incidents per year in 2012 and 2013, but still higher than the number of incidents in 2010 and 2011. The NTSB also found many types of basic data necessary to support comprehensive probabilistic modeling of pipeline risks are not currently available.

National Transportation Safety Board, “Safety Study: Integrity Management of Gas Transmission Pipelines in High Consequence Areas,”

NTSB SS-15/01,

January 27, 2015.

Looking at Risk Beyond HCAs

PHMSA posed a series of questions to the public in the context of an August 25, 2011, ANPRM titled “Safety of Gas Transmission Pipelines” (76 FR 53086), including whether the regulations governing the safety of gas transmission pipelines needed changing. In particular, PHMSA asked whether to add prescriptive language to IM requirements, and whether other issues related to system integrity should be addressed by strengthening or expanding non-IM requirements. PHMSA sought comment on the definition of an HCA and whether additional restrictions should be placed on the use of DA as an IM assessment method. PHMSA also requested comment on non-IM requirements, including valve spacing and installation, corrosion control, and whether regulations for gathering lines needed to be modified.

PHMSA received 103 submissions containing thousands of comments in response to the ANPRM, which are summarized in more detail below. This feedback helped identify a series of proposed improvements to IM, including improvements to assessment goals such as integrity verification, MAOP verification, and material documentation; adjusted repair criteria; clarified protocol for identifying threats,

risk assessments and management, and prevention and mitigation measures; expanded and enhanced corrosion control; requirements for inspecting pipelines after incidents of extreme weather; and new guidance on how to calculate MAOP in order to set operating parameters more accurately and predict the risks of an incident. PHMSA published an NPRM on April 8, 2016 (81 FR 20722), which is discussed in more detail below.

Many of these aspects of IM have been an integral part of PHMSA's expectations since the inception of the IM program. As specified in the first IM rule, PHMSA expects operators to start with an IM framework, evolve a more detailed and comprehensive IM program, and continually improve their IM programs as they learn more about the IM process and the material condition of their pipelines through integrity assessments.

Section 23 of the 2011 Pipeline Safety Act required PHMSA to have pipeline operators conduct a records verification to ensure that their records accurately reflect the physical and operational characteristics of their pipelines in certain HCAs and class locations, and to confirm the established MAOP of those pipelines. Based on the data received from operators following the records verification, incidents that have occurred in non-HCA areas, and other knowledge gained since the 2011 Pipeline Safety Act was passed, PHMSA has become increasingly concerned that a rupture on the scale of San Bruno, with the potential to cause death and serious injury, as well as damage to the environment or the disruption of commerce, could occur elsewhere on the Nation's pipeline system in both HCA and non-HCA pipeline segments. There have been several recent incidents in non-HCAs that show significant incidents can occur in non-HCAs. For example, on December 14, 2007, two men were driving in a pickup truck on Interstate 20 near Delhi, LA, when a 30-inch gas transmission pipeline owned by Columbia Gulf Transmission Company ruptured. One of the men was killed, and the other was injured.

Further, on December 11, 2012, a 20-inch-diameter gas transmission line operated by Columbia Gas Transmission Company ruptured about 106 feet west of Interstate 77 (I-77) in Sissonville, WV. An area of fire damage about 820 feet wide extended nearly 1,100 feet along the pipeline right-of-way. Three houses were destroyed by the fire, and several other houses were damaged. Reported losses, repairs, and upgrades from this incident totaled over $8.5 million, and major transportation delays occurred. I-77 was closed in both directions because of the fire and resulting damage to the road surface. The northbound lanes were closed for approximately 14 hours, and the southbound lanes were closed for approximately 19 hours while the road was resurfaced, causing delays to both travelers and commercial shipping.

Finally, on April 29, 2016, an incident occurred on a Texas Eastern Transmission Corporation gas transmission line operated by Spectra Energy near Delmont, PA, which is approximately 25 miles away from Pittsburgh, PA. The explosion seriously injured one person, destroyed a house, damaged three other homes and vehicles outside, and caused the evacuation of nine other homes in the area. Even though the pipeline was in a Class 1 rural area, it still had a significant impact on the local population.

The Nation's population is growing, moving, and dispersing, leading to changes in population density that can affect the class location of a pipeline segment, as well as whether it is in an HCA. The definition of HCA is not necessarily an accurate reflection of whether an incident will have an impact on people. Requiring assessment and repair criteria for pipelines that, if ruptured, could pose a threat to areas where any people live, work, or congregate would improve public safety and would improve public confidence in the Nation's natural gas pipeline system.

Some pipeline operators have said they are already moving towards expanding the protections of IM beyond HCAs. In 2012, the Interstate Natural Gas Association of America (INGAA) issued a “Commitment to Pipeline Safety,”

underscoring its efforts towards a goal of zero incidents, a committed safety culture, a pursuit of constant improvement, and applying IM principles on a system-wide basis. To accomplish this goal, INGAA's members committed to performing actions that include applying risk management beyond HCAs; raising the standards for corrosion management; demonstrating “fitness for service” on pre-regulation pipelines; and evaluating, refining, and improving operators' ability to assess and mitigate safety threats. These actions aim to extend protection to people who live near pipelines but not within defined HCAs. Further, this final rule takes important steps toward developing a comprehensive approach for the entire industry by finalizing requirements for assessments outside of HCAs.

Letter from Terry D. Boss, Senior Vice President of Environment, Safety and Operations to Mike Israni, Pipeline and Hazardous Materials Safety Administration, U.S. Department of Transportation, dated January 20, 2012, “

Safety of Gas Transmission Pipelines,

Docket No. PHMSA-2011-0023.” INGAA represents companies that operate approximately 65 percent of the gas transmission pipelines, but INGAA does not represent all pipeline operators subject to 49 CFR part 192.

This final rule implements risk management standards that most accurately target the safety of communities while also providing sufficient ability to prioritize areas of greatest possible risk and impact.

Given the results of incident investigations, IM considerations, and the feedback from the ANPRM and the NPRM, PHMSA has determined it is appropriate to improve aspects of the current IM program and codify requirements for additional gas transmission pipelines to receive integrity assessments on a periodic basis to monitor for, detect, and remediate pipeline defects and anomalies. In addition, to achieve the desired outcome of performing assessments in areas where people live, work, or congregate, while balancing the cost of identifying such locations, PHMSA based the requirements for identifying those locations on effective processes already being implemented by pipeline operators and that protect people on a risk-prioritized basis.

Establishing integrity assessment requirements for non-HCA pipeline segments is important for providing safety to the public. Although those pipeline segments are not within defined HCAs, they will usually be in populated areas, and pipeline accidents in these areas may cause fatalities, significant property damage, or disrupt livelihoods. This final rule adopts a newly defined definition for MCAs to identify additional non-HCA pipeline segments that would require integrity assessments, thus assuring the timely discovery and repair of pipeline defects in MCA segments that could potentially impact people, property, or the environment. At the same time, operators can allocate their resources to HCAs on a higher-priority basis.

B. Pacific Gas and Electric Incident of 2010

On September 9, 2010, a 30-inch-diameter segment of a gas transmission pipeline owned and operated by PG&E ruptured in a residential neighborhood in San Bruno, CA, producing a crater approximately 72 feet long by 26 feet wide. The segment of pipe that ruptured weighed approximately 3,000 pounds, was 28 feet long, and was found 100 feet

south of the crater. Over the course of the incident, 47.6 million standard cubic feet of natural gas was released. The escaping gas ignited, and the resultant fire destroyed 38 homes, damaged another 70, killed 8 people, injured approximately 60 people (10 seriously), destroyed or damaged 74 vehicles, and caused the evacuation of over 300 more people. The initial 911 calls described the fire as a “gas station explosion” and a “possible airplane crash.” After 91 minutes, PG&E was able to shut off the flow of gas to the rupture site, which allowed firefighters to approach the rupture site and begin containment efforts. Firefighting operations continued for 2 days; more than 900 emergency responders from San Bruno and surrounding areas were part of the emergency response, 600 of which were firefighters and emergency medical services personnel.

National Transportation Safety Board. 2011.

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. Washington, DC.

The NTSB, in its pipeline accident report for the incident, determined that the probable cause of the accident was PG&E's inadequate quality assurance and control when it relocated the line in 1956 and an inadequate IM program. The NTSB determined that PG&E's IM program was deficient and ineffective because it was based on incomplete and inaccurate pipeline information, did not consider the pipeline's design and materials contribution to the risk of a pipeline failure, and failed to consider the presence of previously identified welded seam cracks as part of its risk assessment. These deficiencies resulted in the selection of an examination method that could not detect welded seam defects and led to internal assessments of PG&E's IM program that were superficial and resulted in no improvements. Ultimately, this inadequate IM program failed to detect and repair or remove the defective pipe section.

The NTSB found that PG&E's inaccurate geographic information system records at the time of the incident indicated that the ruptured segment was constructed from 30-inch-diameter seamless API 5L X42 steel pipe. However, seamless pipe has never been available in 30-inch diameter. According to PG&E employees who testified during the investigation, all 30-inch pipe purchased by PG&E at that time would have been double submerged arc welded, which has been found in cases to be susceptible to weld failure. This inaccuracy was compounded with the discovery that the material code from the journal voucher that PG&E's records were originally composed from erroneously indicated the ruptured segment was X52 grade pipe (52,000 pounds per square inch (psi)), not X42 grade pipe (42,000 psi). X52 pipe has a higher minimum yield strength than X42 pipe,

and incorporating such values into MAOP calculations would produce values that would be inconsistent with the pipeline's actual MAOP. PG&E also could not produce any design, material, or construction specifications from the 1956 construction project. In short, no one from PG&E could reliably determine what type of pipe was in the ground that ruptured.

52,000 psi vs. 42,000 psi.

The NTSB also noted that PHMSA's exemption of pipelines installed before 1970 from the regulatory requirement for pressure testing, which likely would have detected the installation defects, was a contributing factor to the accident. When the initial Federal minimum safety standards for natural gas transmission pipelines were finalized in 1970, an exemption was carved out for pre-1970s pipelines from the requirement for a post-construction hydrostatic pressure test. This exemption was not proposed in any of the NPRMs that preceded the initial regulations and was based on an assertion from the Federal Power Commission

that “there are thousands of miles of jurisdictional interstate pipelines installed prior to 1952,

in compliance with the then-existing codes, that could not continue to operate at their present pressure levels and be in compliance with [the proposed MAOP determination requirements].”

Upon reviewing the operating record of interstate pipeline companies, the Commission found “no evidence that would indicate a material increase in safety would result from requiring wholesale reductions in the pressure of existing pipelines which have been proven capable of withstanding present operating pressures through actual operation.” The Office of Pipeline Safety, at the time, determined it “[did] not now have enough information to determine that existing operating pressures are unsafe,” and taking into account the statements from the Federal Power Commission, included the “grandfather” clause in the final rule to permit the continued operation of pipelines at the highest pressure to which the pipeline had been subjected during the 5 years preceding July 1, 1970.

56 57

The 5-year limit was prescribed so that operators would be prevented from “using a theoretical MAOP which may have been determined under some formula used 20, 30, or 40 years ago.”

The predecessor of the Federal Energy Regulatory Commission.

Between 1935 and 1951, the B31 Code only required a pipeline be tested to a pressure of 50 psig in excess of the pipeline's proposed MAOP. The 1970 regulations required pressure testing to 125 percent in excess of the proposed MAOP.

“Transportation of Natural and Other Gas by Pipeline: Minimum Federal Safety Standards,” 35 FR 13248; August 19, 1970.

35 FR 13248.

This requirement is currently under § 192.619(c).

35 FR 13248.

The NTSB noted in its investigation that the “grandfathering” of the ruptured line resulted in missed opportunities to detect the defective pipe, as a hydrostatic pressure test to the prescribed levels for a Class 3 location would likely have exposed the defective pipe that led to the accident. Following the PG&E incident, the California Public Utilities Commission (CPUC) required PG&E and other gas transmission pipeline operators regulated by CPUC to either hydrostatically pressure test or replace certain transmission pipelines with grandfathered MAOPs, stating that gas transmission pipelines “must be brought into compliance with modern standards for safety” and that “historic exemptions must come to an end.”

Currently, PHMSA's data shows that roughly 168,000 of the Nation's 301,000 miles of onshore gas transmission pipelines were installed prior to the 1970 requirement for hydrostatic pressure testing.

“Decision Determining Maximum Allowable Operating Pressure Methodology and Requiring Filing of Natural Gas Transmission Pipeline Replacement or Testing Implementation Plans;” California Public Utilities Commission Order; June 9, 2011.

https://hip.phmsa.dot.gov/analyticsSOAP/saw.dll?PortalPages

On April 1, 2014, the Department of Justice indicted PG&E for multiple criminal violations of part 192 for the 2010 incident in San Bruno, CA. The trial began on June 14, 2016, and after a 5

1/2

week trial, a Federal jury found PG&E guilty of knowingly and willingly violating 5 sections of PHMSA's IM regulations and obstructing the NTSB investigation.

Specifically, with respect to the Federal Pipeline Safety Regulations, the jury found that between 2007 and 2010, PG&E knowingly and willfully failed to: (1) Gather and integrate existing data and information that could be relevant to identifying and evaluating potential threats on covered pipeline segments; (2) identify and evaluate all potential

threats to each covered pipeline segment; (3) include in its baseline assessment plan all potential threats on a covered segment and to select the most suitable assessment method; (4) prioritize high-risk pipeline segments for assessment where certain changed circumstances rendered the manufacturing threats on those segments unstable; and (5) prioritize pipeline segments containing low-frequency ERW pipe or other similar pipe as a high-risk segment for assessment if certain changed circumstances rendered a manufacturing seam threat on that segment unstable.

Congress required PHMSA, per the 2011 Pipeline Safety Act, to issue regulations to confirm the material strength of previously untested natural gas transmission pipelines located in HCAs and operating at a pressure greater than 30 percent of SMYS. Through this final rule, PHMSA is implementing that congressional directive and other safety measures. This final rule will improve the safety and public confidence of the Nation's onshore natural gas transmission pipeline system.

C. Advance Notice of Proposed Rulemaking

On August 25, 2011, PHMSA published an ANPRM to seek public comments regarding the revision of the Federal Pipeline Safety Regulations applicable to the safety of gas transmission pipelines. In the 2011 ANPRM, PHMSA requested comments on 122 questions spread through 15 broad topic areas covering both IM and non-IM requirements. Among the issues related to IM that PHMSA considered included whether the definition of an HCA should be revised and whether additional restrictions should be placed on the use of certain pipeline assessment methods. PHMSA also requested comment on non-IM regulations, including whether revised requirements are needed for mainline valve spacing and actuation, whether requirements for corrosion control should be strengthened, and whether new regulations are needed to govern the safety of gas gathering lines and underground natural gas storage facilities. Based on the comments received on several of the ANPRM topics, PHMSA developed proposals for some of those topics in a NPRM that is the basis for this final rule. That NPRM and the comments received, are discussed below. PHMSA did not find it appropriate to address all the topics in a single rulemaking. Those topics that were not discussed further in the NPRM for this final rule have been discussed or will be discussed in other rulemakings.

D. National Transportation Safety Board Recommendations

On August 30, 2011, following the issuance of the ANPRM, the NTSB adopted its report on the gas pipeline incident that occurred on September 9, 2010, in San Bruno, CA. On September 26, 2011, the NTSB issued safety recommendations P-11-8 through -20 to PHMSA. Several of the NTSB's recommendations related directly to the topics discussed in the 2011 ANPRM and 2016 NPRM, and they shaped the direction of this final rule. The NTSB recommendations addressed in this final rule include:

• Exemption of Facilities Installed Prior to the Regulations. NTSB Recommendation P-11-14:

Amend Title 49 Code of Federal Regulations 192.619 to repeal exemptions from pressure test requirements and require that all gas transmission pipelines constructed before 1970 be subjected to a hydrostatic pressure test that incorporates a spike test.”

• Pipe Manufactured Using Longitudinal Weld Seams. NTSB Recommendation P-11-15: “

Amend Title 49 Code of Federal Regulations Part 192 of the Federal pipeline safety regulations so that manufacturing- and construction-related defects can only be considered stable if a gas pipeline has been subjected to a post-construction hydrostatic pressure test of at least 1.25 times the maximum allowable operating pressure.”

• Incorporating interstates, highways, etc., into the list of “identified sites” that establish a HCA. NTSB Recommendation P-14-1:

“Revise Title 49 CFR Section 903, Subpart O, Gas Transmission Pipeline Integrity Management, to add principal arterial roadways including interstates, other freeways and expressways, and other principal arterial roadways as defined in the Federal Highway Administration's “Highway Functional Classification Concepts, Criteria and Procedures” to the list of “identified sites” that establish an HCA.

• Increase the use of ILI tools. NTSB Recommendation P-15-20: “

Identify all operational complications that limit the use of in-line inspection tools in piggable pipelines, develop methods to eliminate the operational complications, and require operators to use these methods to increase the use of in-line inspection tools.”

E. Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011

The 2011 Pipeline Safety Act relates directly to the topics addressed in PHMSA's ANPRM of August 25, 2011, and the NPRM issued on April 8, 2016. The related topics and statutory citations include, but are not limited to:

• Section 5(e)—Allow periodic reassessments to be extended for an additional 6 months if the operator submits sufficient justification.

• Section 5(f)—Requires the expansion of IM system requirements, or elements thereof, beyond HCAs, if appropriate.

• Section 23—Requires the reporting of each exceedance of the MAOP that exceeds the build-up allowed for the operation of pressure-limiting or -control devices.

• Section 23—Requires testing to confirm the material strength of previously untested natural gas transmission pipelines and pipelines lacking records that accurately reflect the pipeline's physical and operational characteristics.

• Section 29—Requires consideration of seismicity when evaluating pipeline threats.

F. Notice of Proposed Rulemaking

On April 8, 2016, PHMSA published an NPRM seeking public comments on the revision of the Federal Pipeline Safety Regulations applicable to the safety of gas transmission pipelines and gas gathering pipelines (81 FR 20721).

When developing the NPRM, PHMSA considered the comments it received from the ANPRM and proposed new pipeline safety requirements and revisions of existing requirements in several major topic areas, including those topics addressing congressional mandates and related NTSB recommendations. A summary of the NPRM proposals and topics pertinent to this rulemaking, the comments received on those specific proposals, and PHMSA's response to the comments received is below under the “Analysis of Comments and PHMSA Response” section.

https://www.regulations.gov/document?D=PHMSA-2011-0023-0118.

PHMSA determined it could more quickly move a rulemaking that focuses on the mandates from the 2011 Pipeline Safety Act by splitting out the other provisions contained in the NPRM into two other, separate rules. Promptly issuing a final rule focused on mandates will improve safety and respond to Congress, industry, and public safety groups.

As such, not all the topics from the NPRM nor the comments received on those topics are discussed as a part of this rulemaking. PHMSA intends to issue two additional final rules to address the remaining topics from the NPRM.

III. Analysis of NPRM Comments, GPAC Recommendations, and PHMSA Response

On April 8, 2016, PHMSA published an NPRM (81 FR 20722) proposing several amendments to 49 CFR part 192. The NPRM proposed amendments addressing topiic areas including verification of pipeline material properties, MAOP reconfirmation, IM clarifications, MAOP exceedance reports, ILI launcher and receiver safety, assessing areas outside of HCAs, and recordkeeping. The comment period for the NPRM ended on July 7, 2016. PHMSA received approximately 300 submissions containing thousands of comments on the NPRM. Submissions were received from groups representing the regulated pipeline industry; groups representing public interests, including environmental groups; State utility commissions and regulators; members of Congress; specific pipeline operators; and private citizens.

Some of the comments PHMSA received in response to the NPRM were comments beyond the scope or authority of the proposed regulations. The absence of amendments in this proceeding involving other pipeline safety issues (including several topics listed in the ANPRM) does not mean that PHMSA determined additional rules or amendments on those other issues are not needed. Such issues may be the subject of other existing rulemaking proceedings or future rulemaking proceedings.

The remaining comments reflect a wide variety of views on the merits of particular sections of the proposed regulations. PHMSA read and considered all the comments posted to the docket for this rulemaking.

The Technical Pipeline Safety Standards Committee, commonly known as the Gas Pipeline Advisory Committee (GPAC; the committee), is a statutorily mandated advisory committee that advises PHMSA on proposed safety standards, risk assessments, and safety policies for natural gas pipelines.

The GPAC is one of two pipeline advisory committees that focus on technical safety standards that were established under the Federal Advisory Committee Act (Pub. L. 92-463, 5 U.S.C. App. 1-16) and section 60115 of the Federal Pipeline Safety Statutes (49 U.S.C. Chap. 601). Each committee consists of 15 members, with membership divided among Federal and State agencies, regulated industry, and the public. The committees consider the “technical feasibility, reasonableness, cost-effectiveness, and practicability” of each proposed pipeline safety standard and provide PHMSA with recommended actions pertaining to those proposals.

49 U.S.C. 60115.

Due to the size and technical detail of this rulemaking, the GPAC met five times to discuss this rulemaking throughout 2017 and 2018.

During those meetings, the GPAC considered the specific regulatory proposals of the NPRM and discussed various comments made on the NPRM's proposal by stakeholders, including the pipeline industry at large, public interest groups, and government entities. To assist the GPAC in its deliberations, PHMSA presented a description and summary of the major proposals in the NPRM and the comments received on those issues. PHMSA also assisted the committee by fostering discussion and developing recommendations by providing direction on which issues were most pressing.

Specifically, the GPAC met on January 11-12, 2017; June 6-7, 2017; December 14-15, 2017; March 2, 2018; and March 26-28, 2018. Information on these meetings can be found at

regulations.gov

under docket PHMSA-2011-0023 and at PHMSA's public meeting page:

https://primis.phmsa.dot.gov/meetings/.

For the proposals finalized in this rulemaking, the committee came to consensus when voting on the technical feasibility, reasonableness, cost-effectiveness, and practicability of the NPRM's provisions. In many instances, the committee recommended changes to certain proposals that the committee found would make certain proposals more feasible, reasonable, cost-effective, or practicable.

The substantive comments received on the NPRM as well as the GPAC's recommendations are organized by topic below and are discussed in the appropriate section with PHMSA's response and resolution to those comments.

A. Verification of Pipeline Material Properties and Attributes—§ 192.607

i.—Applicability

1. Summary of PHMSA's Proposal

Section 23 of the 2011 Pipeline Safety Act requires the Secretary of Transportation to require the verification of records used to establish MAOP to ensure they accurately reflect the physical and operational characteristics of the pipelines and to confirm the established MAOP of gas transmission pipelines. Since 2012, operators have submitted information indicating that a portion of transmission pipeline segments do not have adequate records to establish MAOP or that accurately reflect the physical and operational characteristics of the pipeline. Therefore, PHMSA determined that additional regulations are needed to implement this requirement of the 2011 Pipeline Safety Act. Specifically, PHMSA proposed that operators conduct tests and other actions needed to confirm and document the physical and operational characteristics for those pipeline segments where adequate records are not available, and PHMSA proposed standards for performing these actions. PHMSA sought to appropriately address pipeline risk without extending the requirement to all pipelines where risk and potential consequences are not as significant, such as pipelines in remote, sparsely-populated areas. As a result, PHMSA proposed criteria that would require material properties verification for higher-risk locations through a new § 192.607; specifically, by adding requirements for the verification of pipeline material properties for existing onshore, steel, gas transmission pipelines that are located in HCAs or Class 3 or Class 4 locations.

2. Summary of Public Comment

Several citizen and public safety groups, including Pipeline Safety Trust (PST), Pipeline Safety Coalition, National Association of Pipeline Safety Representatives (NAPSR), Coalition to Reroute Nexus, Earthworks, and The Michigan Coalition to Protect Public Rights-of-Way, supported the proposed provisions for establishing adequate material properties documentation and records. Some of these groups noted that the need for this section in the regulations would suggest poor operator implementation of the IM requirements since the inception of subpart O back in 2003.

Trade associations and pipeline industry entities were largely opposed to the material properties verification requirements for several reasons outlined below.

Many trade association and pipeline industry commenters expressed concern that the material properties verification requirements were potentially retroactive. American Petroleum Institute (API) and American Gas Association (AGA) asserted that this proposal would require operators to document and verify the material properties of existing pipelines beyond

what was required by the regulations that were in place at the time those pipelines were put into service. These commenters stated that this retroactive requirement extends beyond the congressional authority provided to PHMSA. Several commenters, including AGL Resources, Dominion East Ohio, and New Jersey Natural Gas, expressed concern with the proposed provisions for verifying specific physical characteristics of pipelines, fittings, valves, flanges, and components for existing transmission pipelines. These stakeholders stated that it might be impossible to achieve “reliable, traceable, verifiable, and complete” records on a retroactive basis for existing pipelines. Some commenters, including AGA, stated that a pipeline's MAOP should be considered confirmed and there should be no need to further document material properties to verify the MAOP if operators had a pressure test record of a test conducted at 1.25 times MAOP for the pipeline segment.

Commenters also expressed concern about PHMSA's proposed new references to the material properties verification requirements under § 192.607 throughout part 192, which could be interpreted as being applicable not only to a subset of transmission pipelines but also to distribution pipelines. Commenters stated that PHMSA did not provide justification within the NPRM for applying material properties verification requirements to distribution systems, and such requirements would significantly impact distribution systems. These commenters requested that PHMSA explicitly exclude distribution pipelines from the proposed material properties verification requirements. Similarly, some commenters urged PHMSA to restrict these requirements only to gas transmission lines operating at greater than 30 percent SMYS based on the premise that lines operating below 30 percent SMYS, in most cases, tend to leak before rupture and are therefore less risky to the public. Additionally, commenters suggested that PHMSA review the various cross-references in the NPRM and eliminate those that would expand the applicability of the material properties verification requirements beyond onshore steel gas transmission pipelines in HCAs and Class 3 and Class 4 locations.

Some commenters recommended changing the size limit for small components that might trigger the material properties verification requirements from greater-than-or-equal-to 2 inches to greater-than 2 inches. A further comment on components discussed how the material properties verification provisions, as proposed, require the operator to know the weld-end bevel conditions for in-service valves and flanges. Operators noted, however, that once a weld-end is welded to a piece of pipe or other component, there is no method that can be employed to determine the condition of that bevel. Accordingly, the commenters requested this requirement be deleted or clarified. There was also a comment to delete the sampling requirement and not perform material properties verification if, when the applicable pipeline is excavated for repairs, a repair sleeve is installed. Other commenters felt that the proposed material properties verification requirements would not deliver clear, identifiable safety benefits and would lead to several unintended consequences that would decrease the integrity of pipeline systems and cause energy supply disruption. Accordingly, these commenters suggested PHMSA withdraw the proposed requirements for material properties verification.

Multiple commenters also expressed concerns that the revised provisions for establishing MAOP under § 192.619, specifically the requirement for operators to maintain all records necessary to establish and document a pipeline's MAOP as long as the pipeline remains in service, would impose extensive new recordkeeping requirements applicable to operators of distribution pipelines, including retroactive recordkeeping requirements. Commenters requested that PHMSA clarify that the new recordkeeping requirements in § 192.619(f) are applicable only to gas transmission pipelines.

Pipeline industry entities also provided comments on the relationship of the material properties verification requirements in § 192.607 and the MAOP reconfirmation requirements in § 192.624. The Gas Piping Technology Committee (GPTC) suggested that the proposed material properties verification requirements be revised to include an option of using the provisions of § 192.619(a)(1) for establishing MAOP when traceable, verifiable, and complete material property records are not available for calculating design pressure. Similarly, commenters suggested operators should be allowed to establish design yield strengths for unknown pipe grade as described at § 192.107(b)(1). Xcel Energy also stated that if an operator has previously established MAOP as per the § 192.619(a)(2) strength test requirements or will do so per the proposed § 192.624 methodology for pressure test or pressure reduction, the verification of pipeline material proposed in § 192.607 is not necessary for the purpose of ensuring safe operation.

Over the course of the meetings on June 7, 2017, and December 14, 2017, the GPAC had a robust discussion regarding the applicability of the material properties verification requirements. More specifically, the GPAC discussed the fact that two separate activities drive the need for material properties verification: (1) MAOP reconfirmation for pipelines lacking traceable, verifiable, and complete records to support the pipeline's current MAOP; and (2) the application of IM principles, especially where anomaly response and remediation calculations are concerned. The GPAC believed these aspects needed to be addressed separately in the final rule.

Subsequently, on December 14, 2017, the GPAC recommended that PHMSA modify the proposed rule by removing the applicability criteria of the material properties verification requirements and make material properties verification a procedure for obtaining missing or inadequate records or otherwise verifying pipeline attributes if and when required by MAOP reconfirmation requirements or by other code sections. In discussing the issue, the GPAC recognized that the broad applicability of the material properties verification requirements in the proposed rule was PHMSA's attempt to address the issue of inadequate records for MAOP verification, IM requirements and standard pipeline operations. The GPAC believed amending the proposed rule to remove the proposed applicability and instead explicitly refer back to the material properties verification requirements, when needed, in various regulatory sections, would more closely follow Congress' direction in the 2011 Pipeline Safety Act.

This change would also obviate the need for operators to create a material properties verification program plan per the originally proposed requirements, so the GPAC recommended PHMSA remove that requirement from the rule. Further, the committee recommended during a later meeting that PHMSA consider modifying the rule in both §§ 192.607 and 192.619 to clarify that the material properties verification requirements apply to onshore steel gas transmission lines and not to distribution or gathering pipelines.

3. PHMSA Response

PHMSA appreciates the information provided by the commenters regarding the scope and requirements for

reconfirming the material properties of pipelines with unknown or undocumented properties. PHMSA agrees that the need for this rule is caused, in part, by poor implementation of existing IM requirements. However, PHMSA disagrees that the requirements would not deliver safety benefits or would lead to decreased integrity of pipeline systems and cause energy supply disruption. The basic knowledge of pipeline material properties is essential to pipeline safety.

PHMSA disagrees that material properties verification is not needed if the pipeline segment has been pressure tested to 1.25 times MAOP. Other reasons for needing documented, confirmed material properties (

e.g.,

wall thickness, yield strength, and seam type) include IM program requirements, implementation of pipe repair criteria and determination of the design pressure of the pipeline segment. This rule supplements existing IM requirements by providing operators a method to reconfirm material properties without necessarily performing destructive testing of the pipe material. Operators can use this method in their IM programs, to reconfirm MAOP where needed, to implement repair requirements, and to otherwise comply with part 192 where necessary. Indeed, PHMSA hopes that operators will use this method for material properties verification even when not specifically required by part 192 because it provides a common-sense, opportunistic, and practical approach for gathering the records necessary to substantiate safe MAOPs, properly implement IM, and otherwise ensure the safe operation of the nation's pipeline network.

PHMSA also disagrees that material properties verification is only needed for pipeline segments operating at pressure greater than 30 percent of SMYS. IM requirements apply to all gas transmission pipeline segments in HCAs, including those that operate at less than 30 percent of SMYS. Moreover, the gas transmission subpart O integrity management regulations at § 192.917(b),

Data gathering and integration,

require operators to gather pipe attributes including pipe wall thickness, diameter, seam type and joint factor, manufacturer, manufacturing date, and material properties. These physical properties and attributes are explicitly outlined in ASME/ANSI B31.8S—2004 Edition, section 4, table 1—Data Elements for Prescriptive Pipeline Integrity Program, which is incorporated by reference in § 192.7.

PHMSA did not intend that the requirements proposed in § 192.607 would be retroactive or would apply to distribution or gathering lines. Therefore, PHMSA is clarifying the final rule to assure that the provisions finalized in § 192.607 are not retroactive

and apply only to transmission lines. However, PHMSA believes that operators with IM programs that are properly following subpart O, specifically § 192.917(b), should already have this pipe information.

The material properties verification requirements are not retroactive as they mandate the creation and retention of records as operators execute the methodology in § 192.607 on a prospective basis. Operators who have not verified their records in accordance with this methodology before the effective date of this rule will not be subject to enforcement action based on § 192.607. After the effective date of the rule, operators with missing or inadequate records must follow the verification methodology in § 192.607.

Regarding material properties verification for non-line pipe components, PHMSA is revising this final rule to apply the requirements to components greater than 2 inches and is removing the requirement to know the weld-end bevel conditions. PHMSA agrees with the GPAC members who commented that 2-inch pipe is not used in mainline applications and need not be subject to additional regulatory requirements to maintain safety. Also, fittings and flanges will have an ANSI class rating that will confirm whether the components meet or exceed the MAOP of the pipeline, so further regulatory requirements for components under 2 inches are not necessary to maintain safety.

To further address comments and the GPAC recommendations related to the scope and applicability of the material properties verification requirements, PHMSA is modifying this final rule to address MAOP reconfirmation and material properties verification separately from the application of IM principles. PHMSA believes this change will improve the organization of the rule. PHMSA is accomplishing this by removing the applicability criteria of the material properties verification requirements and making material properties verification a procedure for obtaining records for physical pipeline properties and attributes that are not documented in traceable, verifiable, and complete records or otherwise verifying physical pipeline properties and attributes when required by MAOP reconfirmation requirements, IM requirements, repair requirements, or other code sections. This obviates the need for all operators to create a material properties verification program plan per the originally proposed requirements, so PHMSA is removing that requirement from the rule as well. Instead, only operators who do not have traceable, verifiable, and complete records will be required to create such a plan.

A. Verification of Pipeline Material Properties and Attributes—§ 192.607

ii.—Method

1. Summary of PHMSA's Proposal

The conventional method for determining the properties of unknown steel pipe material is to cut test specimens known as “coupons” out of the pipe and perform destructive testing. Because of the large amount of pipe operators reported in Annual Report submissions for which there are unknown or inadequately documented properties, the cost of such a conventional approach would likely be onerous. Therefore, PHMSA proposed standards in § 192.607 by which operators could develop a material properties verification plan and use an opportunistic sampling technique to re-constitute and document material properties in a more cost-effective manner. More specifically, PHMSA proposed to allow operators to use recently developed technology to perform

in situ,

non-destructive examinations for determining the properties of unknown steel pipe material.

While PHMSA acknowledged in the preamble of the NPRM that such techniques may not be possible in every situation, PHMSA stated that it was aware that this option is already being widely deployed in the pipeline industry. Secondly, PHMSA proposed to allow operators to determine pipe properties at a sampling of similar locations and apply those results to the entire population of pipeline segments. PHMSA proposed to allow operators to take advantage of opportunities when the pipeline is exposed for other reasons, such as during maintenance and repair excavations, by requiring that material properties be verified whenever the pipe is exposed. This would reduce the number of excavations that might otherwise be required. Excavations are a large portion of the cost of re-constituting material properties for unknown pipe.

2. Summary of Public Comment

Several commenters suggested that the data required by the material properties verification process proposed by PHMSA can be obtained only through destructive pipe testing. These commenters asserted that the proposed requirements would lead to unnecessary service outages, increased methane emissions, and increased personnel

safety risks due to unnecessary excavation activities. Black Hills Energy stated that their pipeline system consists of mainly smaller-diameter transmission pipelines and that the proposed provisions would force them to take lines out of service to perform costly cutouts. API asserted that the expense and risk required for the excavations necessary to comply with the proposed provisions outweigh the value of obtaining and documenting material pipe properties. Some commenters suggested that it would be less costly for operators to simply replace pipe rather than obtain the material properties for pipe already in the ground. A commenter asserted that the proposed requirements would require unnecessary breaching of the pipeline coating, which is important for effective cathodic protection. API suggested that rather than requiring operators to gather documentation on material properties that may only be of marginal value for assessing pipeline safety, PHMSA should require a combination of hydrostatic pressure testing and ILI. API stated that, as opposed to the proposed rule's focus on the precise documentation of materials, this would appropriately shift the emphasis of the proposed regulations to confirming MAOP and away from material properties verification.

Several commenters stated that some of the data that PHMSA proposed operators verify is unnecessary for MAOP reconfirmation or other operational reasons. For example, the Interstate Natural Gas Association of America (INGAA) stated that several of the data elements that would need to be verified pursuant to the proposed material properties verification requirements are unnecessary for integrity management-related activities. Commenters suggested that PHMSA limit the required records to what is needed to calculate design pressure in order to determine MAOP. Commenters noted that the proposed requirements would require testing for stress corrosion cracking (SCC) in all cases, and that the requirement should be limited to only pipelines that are susceptible to SCC. Some commenters disagreed with the requirement to determine and keep a record for the chemical composition of steel transmission pipeline segments installed prior to the effective date of the final rule, suggesting that this information has not been previously required. Another commenter stated that the basis for having accurate chemical composition records is unclear. PG&E recommended that PHMSA recognize that chemical composition and manufacturing specifications provide limited information that can be used to evaluate the safety of an existing pipeline system. Piedmont Natural Gas stated that any requirement to retroactively obtain ultimate tensile strength and chemical composition is unnecessarily burdensome and detracts from the ultimate goal of pipeline safety by diverting valuable resources away from other risk-reduction efforts. A similar comment asserted there was no benefit in determining pipeline chemical compositions, as there is a high probability that many pipelines that might otherwise have adequate material documentation would fail the recordkeeping requirements because of a lack of existing chemical composition records and would subsequently be subject to the entire material properties verification process.

Pipeline industry entities also commented on the proposed sampling and testing requirements that would occur during excavations. Commenters asserted that the sampling requirements should be removed, and the number of excavations should not be specified. One commenter stated that the minimum number of excavations should be determined by the operator in their material properties verification plan and through statistical analysis aimed at achieving targeted confidence levels. Texas Pipeline Association (TPA) stated that there is no technical justification for the number of material properties tests being required at each test location by the proposed rule, and that the requirement of five tests in each circumferential quadrant for non-destructive tests and one test in each circumferential quadrant for destructive tests is unsupported in the proposal. TPA further stated that they are unaware of any indication that there is great variability in material properties within the body of a pipe, and that presently, material properties verification involves a single test per cylinder. Additionally, commenters stated this requirement could be unnecessarily costly and have a negative impact on pipeline safety, as the integrity of the pipeline would need to be compromised to perform these evaluations and a new joint of pipe would need to be welded onto the existing pipeline. Lastly, Spectra Energy Partners objected to the requirement that non-destructive testing be validated with unity plots comparing the results from non-destructive and destructive testing. They stated that this severely limits the value of non-destructive testing since the operator will have to remove samples for destructive testing to create the unity plots.

CenterPoint Energy stated that the definition of excavation is unclear, and that pipe may be excavated to a point for many operational activities, including spotting for construction safety and installing cathodic protection tests or current source wires. CenterPoint Energy stated that they do not view these types of excavations as opportunities for material properties verification data gathering because that would require the full exposure of a pipeline segment and the removal of good coating from the pipe. Another commenter suggested that confidence specifications for non-destructive testing would add significant cost due to inherently inaccurate test results.

Similarly, there were comments that encouraged consistency between the material properties verification requirements and the requirements for recordkeeping for materials, pipe design, and pipeline components. These comments suggested that inconsistencies between the documentation and the recordkeeping requirements could create scenarios where operators meet the recordkeeping requirements but do not have adequate documentation to prevent the material properties verification requirements from triggering.

Some commenters opposed the proposed requirement to obtain a “no objection” letter from PHMSA in order to use a new or other technology. PG&E recommended that PHMSA provide additional regulatory language to allow an operator to proceed with the new technology if a “no objection letter” to PHMSA is not received within 45 days prior to the planned use of technology. They stated that operators put in considerable time to set up contracts, schedule work, acquire permits, and that waiting on an approval or disapproval from PHMSA can dramatically impact schedule and costs. Further, commenters suggested that PHMSA's enforcement and regulatory procedures do not provide for “no objection” letters, and adding a new process that is not well-defined could cause additional confusion.

AGA proposed an alternative approach to material properties verification, MAOP reconfirmation, and integrity assessments outside of HCAs, which other pipeline industry entities supported. The approach included requiring operators to either pressure test or utilize an alternative technology that is determined to be of equal effectiveness on high-risk gas transmission pipelines that do not have

a record of a subpart J pressure test or are currently utilizing the grandfather clause for MAOP determination (§ 192.619(c)). AGA suggested a three-tiered approach that prioritized pipelines located in HCAs and operating at pressures greater than 30 percent SMYS. The approach also included the use of ILI tools on all gas transmission pipelines that are able to accommodate inspection by means of an instrumented ILI tool. The ILI tool used would be qualified to find defects that would fail a subpart J pressure test. Commenters stated that this alternative approach is simpler and would allow operators to focus resources on the areas of highest risk within pipeline systems. In conjunction with AGA's approach, commenters recommended including language that would allow the use of advanced ILI and non-destructive evaluations to comply with the proposed material properties verification requirements.

Certain commenters also suggested PHMSA provide a deadline by which operators must implement their material properties verification plan, as it was unclear in the proposal. Following committee discussion and PHMSA feedback, industry groups also recommended to allow operators to use their own statistical sampling plans when undertaking material properties verification rather than have PHMSA specify the number of samples that must be obtained.

At the GPAC meeting on December 14, 2017, the committee recommended that PHMSA modify the method for material properties verification by clarifying that operators are only required to confirm attributes pertinent to the goal of MAOP reconfirmation, integrity management, or other reasons when the material properties verification is being performed. The GPAC also recommended that PHMSA require operators keep records developed using the material properties verification method. The GPAC recommended that PHMSA retain the opportunistic approach of obtaining unknown or undocumented material properties when excavations are performed for repairs or other reasons, using a one-per-mile standard proposed by PHMSA, but allow operators to propose an alternative statistical approach and submit a notification to PHMSA with justification for their method. The GPAC also recommended that if operators notify PHMSA of an alternative sampling approach, and the operator does not receive an objection letter from PHMSA within 90 days of such a notification, the operator can proceed with their chosen method unless PHMSA notifies the operator that additional review time or additional information from the operator is needed for PHMSA to complete its review.

Similarly, the committee recommended PHMSA delete specified program requirements for how to address sampling failures and replace that with a requirement for operators to determine how to deal with sample failures through an expanded sample program that is specific to their system and circumstances. They further recommended that PHMSA require operators to notify PHMSA of the expanded sample program and establish a minimum standard that sampling programs must be based on a minimum 95 percent confidence level.

Further, the committee recommended that PHMSA retain the flexibility for operators to conduct either destructive or non-destructive tests when material properties verification is needed and requested PHMSA drop accuracy specifications but retain the requirement that any test methods used be validated and be performed with calibrated equipment. The GPAC also recommended PHMSA reduce the number of quadrants at which non-destructive evaluation tests be made from four to two.

Regarding the number of test locations and the number of excavations that must be performed, the GPAC recommended PHMSA accommodate situations where a single material properties verification test is needed (

e.g.,

additional information is needed for an anomaly evaluation/repair) and drop the mandatory requirements for testing multiple joints for large excavations. The GPAC also recommended PHMSA clarify the applicability of the requirements for developing and implementing procedures for conducting material properties verification tests on populations of undocumented or inadequately documented pipeline segments and the minimum number of excavations and tests that must be performed for those pipeline segments.

3. PHMSA Response

PHMSA appreciates the information provided by the commenters regarding the method for material properties verification. PHMSA disagrees with implementing the alternative approach proposed by AGA, but the underlying comments of AGA and others related to having an alternative approach are discussed in this rulemaking and are addressed below. PHMSA strongly believes that knowledge of pipeline physical properties and attributes are essential for a modern IM program (see § 192.917(b)—

Data gathering and integration

) as well as effective pipeline and public safety. The PG&E incident at San Bruno, CA, was caused, in part, by PG&E mistakenly classifying the pipe that failed as seamless pipe. That pipe was welded seam pipe, and the failure occurred at a partially welded seam.

The NPRM included a list of material properties that could be confirmed using the material properties verification process. One of them in particular, steel toughness, is conventionally obtained only through destructive testing. It was not PHMSA's intent that toughness would need to be confirmed every time an operator was performing material properties verification, thus in effect requiring destructive testing for every location. Therefore, PHMSA is modifying this final rule to address toughness properties in a separate paragraph and is allowing the use of techniques that are reliable without specifying destructive testing. This is intended to accommodate new, non-destructive techniques currently under development. The new paragraph with these requirements also makes it clear that toughness is required only where needed and not necessarily in every case. PHMSA is also modifying other sections of this final rule to provide reasonably conservative default toughness values so that operators may achieve the goals of IM and MAOP reconfirmation using assumed values without the need for destructive testing. These changes will be discussed further in subsequent sections of this document.

Similarly, PHMSA is modifying the verbiage related to the listing of material properties to which the material properties verification process would apply. The clarification will make it clear that the material properties verification process only applies to the pertinent properties needed to achieve the goals of the activity for which material properties verification is needed, such as MAOP reconfirmation or IM. This avoids the potential for requiring that all properties be documented each time an operator goes out to perform material properties verification when only a subset of properties is needed.

PHMSA is also replacing the prescriptive accuracy specifications and unity plot validation for non-destructive testing with more general verbiage that requires that methods are validated and that operators account for the accuracy of the method used. This change will help accommodate new technology and techniques currently under development and avoid situations that

might require destructive testing to validate the non-destructive methods.

In response to the comments, PHMSA is relaxing the number of test points for non-destructive tests from four quadrants to two quadrants. This allows the operator to perform material properties verification on the top half of the pipe and would avoid the need to access the bottom half of the pipe when the repair or maintenance activity would not otherwise require it. PHMSA is also removing the proposed requirement to conduct material verification at multiple locations within a single large excavation based on the number of joints of line pipe exposed. PHMSA believes the methods described in this final rule will provide operators accurate material properties information without requiring more excavation activities than necessary.

In this final rule, PHMSA is modifying § 192.607 to specifically list the types of excavations where operators that need to verify material properties should seek to conduct material properties verification. This revision intends to avoid requiring operators perform the material properties verification process at partial excavations that do not expose the pipeline segment. For example, PHMSA considers excavations associated with direct examinations of anomalies to be an opportunity to perform material properties verification. Similarly, PHMSA is modifying the language to acknowledge the need to perform one-time material properties verification activities at specific locations, such as when performing repairs. An operator who has complete material documentation for a particular pipeline segment would not need to undertake the sampling program at excavations on that particular segment. The sampling program is specifically required when the operator needs to document material properties for entire segments of pipelines.

PHMSA disagrees with the removal of the number of samples needed and is maintaining the minimum standard to define the number of excavations in the sampling program as 1 per mile or 150 if the population of pipeline segments is more than 150 miles, whichever is less. However, PHMSA is modifying the rule to provide operators the option of proposing an alternative sampling program if they send a notification and justification of the alternative program to PHMSA in accordance with the new notification procedures at § 192.18. Operators may use an alternative sampling program 91 days after submitting a notification per § 192.18 to PHMSA if the operator has not received a letter of objection or a request from PHMSA for more time to review.

PHMSA is also withdrawing the expanded sampling requirements to address cases where operators identify problems in the initial sampling program. Instead, operators may use an alternative sampling approach that addresses how the operator's sampling plan will address findings that reveal physical pipeline properties and attributes that are not consistent with all available information or existing expectations or assumed physical pipeline properties and attributes used for pipeline operations and maintenance in the past. Operators taking such an approach must notify PHMSA of the adverse findings and provide PHMSA with specific details of the alternative sampling plan with a justification for such a plan in a notification to PHMSA. The alternative sampling program must be designed to achieve a 95 percent confidence level. In accordance with the new notification procedures at § 192.18, operators may use an alternative sampling plan 91 days after submitting a notification to PHMSA if the operator has not received a letter of objection or a request from PHMSA for more time to review.

In response to committee discussion, PHMSA is modifying its notification process broadly throughout part 192 to allow operators to propose using methods and technologies by notifying PHMSA in accordance with the new procedures in § 192.18. If an operator does not receive a letter of objection or a request from PHMSA for more time to review within 90 days of the notification, then the operator may use the proposed method or technology. Some committee members were concerned that some provisions throughout the NPRM would require action from PHMSA in the form of a “no objection” letter. Members noted that such a process can leave companies unable to proceed until PHMSA provided affirmative approval of the request. Committee members suggested that it may be more efficient and less burdensome for PHMSA to issue letters to operators only when they specifically object to proposed plans or solutions, and otherwise allow the operator to proceed as planned in the absence of such a letter. Other members were concerned that PHMSA might authorize sub-optimal plans or technologies by missing a deadline. To this end, members recommended an approach where PHMSA could request additional time for review beyond the 90-day period. PHMSA noted at the meeting that this is a similar process that is used by PHMSA for state waivers and the change should improve regulatory efficiency.

PHMSA's letter or email of objection will specify the reasons PHMSA does not approve of the proposed method or technology, while a request from PHMSA for more time to review the notification will extend the review period beyond 90 days. Further, to establish a verifiable record, it will be PHMSA's policy to send a “no objection” letter or email, either before or after the 90-day review period, when PHMSA does not object to an operator's proposed method or technology. PHMSA is applying this approach to other places in this rulemaking that require notifications and has created a general notification provision in subpart A of part 192.

PHMSA is modifying the recordkeeping requirement for the material properties verification provisions to avoid potential conflicts with other provisions in this rulemaking, such as MAOP reconfirmation, to clarify that operators are required to keep any records created, for the life of the pipeline, when verifying specific properties using the methods in § 192.607. These records must also be traceable, verifiable, and complete. These recordkeeping requirements are not retroactive, as they mandate the creation and retention of records as operators execute the methodology in § 192.607 on a prospective basis.

PHMSA disagrees with commenters that asked for PHMSA to establish a deadline for operators to complete the sampling programs. The opportunistic approach PHMSA proposed and retained for this final rule requires material properties verification activities to occur at excavation sites where operators are directly examining anomalies; performing

in-situ

evaluations; or are performing repairs, remediation, or maintenance. PHMSA does not expect operators to perform material properties verification for unknown pipe properties on pipeline segments exposed during one-call excavations. PHMSA has determined this approach is reasonable and will minimize the cost impacts of this final rule. A deadline for the material properties verification requirements of this rulemaking is not practical because it is impossible to forecast the rate or timing at which opportunities would arise to perform material properties verification for a given population of pipe.

Lastly, operators should have most of the required pipe information from following § 192.917(b) since subpart O of part 192 was codified over 15 years

ago in 2003. Section 192.917(b) requires operators to identify and evaluate the potential threats to pipeline segments by gathering and integrating existing data and information on the entire pipeline that could be relevant to the pipeline segment. In performing this identification and evaluation, operators must follow the requirements in ASME/ANSI B31.8S, section 4, and at a minimum gather and evaluate the set of data specified in Appendix A to ASME/ANSI B31.8S. The material properties needed to establish and substantiate MAOP are included in these lists.

B. MAOP Reconfirmation—§§ 192.624 & 192.632

i.—Applicability

1. Summary of PHMSA's Proposal

In the NPRM, PHMSA proposed to require operators reconfirm MAOP for the following three categories of pipeline:

(1) Grandfathered pipe, in direct response to section 23(d) of the 2011 Pipeline Safety Act and NTSB recommendation P-11-14;

(2) Pipe for which documentation is inadequate to support the MAOP, in direct response to section 23(c) of the 2011 Pipeline Safety Act; and

(3) Pipe that has experienced a reportable in-service incident since its most recent successful subpart J pressure test due to an original manufacturing-related defect; a construction-, installation-, or fabrication-related defect; or a cracking-related defect, including, but not limited to, seam cracking, girth weld cracking, selective seam weld corrosion, hard spots, or stress corrosion cracking.

It is important to note that a given pipeline segment for which the MAOP reconfirmation process would apply might fit into one, two, or all three of these proposed categories. For pipeline segments where records of the pipeline physical properties and attributes to substantiate the current MAOP are not documented in traceable, verifiable, and complete records, only those segments located within an HCA or a Class 3 or Class 4 location would be subject to the MAOP reconfirmation process under the NPRM.

This proposal directly correlates to section 23 of the 2011 Pipeline Safety Act and NTSB recommendation P-11-14 regarding the need for spike hydrostatic testing where in-service incidents have occurred. The NTSB recommended such testing for all pipe manufactured before 1970.

For pipeline segments where operators established the MAOP in accordance with the grandfather clause at § 192.619(c) (

i.e.,

pipeline segments where the MAOP is based upon the highest actual operating pressure records from a 5-year interval between July 1, 1965, to July 1, 1970, and where operators therefore do not have pressure test or material property records) or for segments with a history of in-service incidents caused by cracks or crack-like defects, PHMSA proposed to restrict the applicability of MAOP reconfirmation to HCAs, Class 3 or Class 4 locations, or MCAs, if the MCA segment can accommodate an ILI tool. The proposed inclusion of pipeline segments in these locations and with these traits slightly expand on the mandate contained in section 23 of the 2011 Pipeline Safety Act, which applied only to previously untested pipeline segments operating at a pressure greater than 30 percent SMYS located in an HCA.

In recommendation P-11-14, the NTSB recommended that all pipe manufactured before 1970 be subjected to a hydrostatic pressure test that would include a spike hydrostatic test, which PHMSA considered in its process for reconfirming MAOP. PHMSA's preliminary evaluation concluded that doing so may not be cost-effective, since a large amount of such pipe could be in remote locations where the likelihood of personal injury or property damage as a result of an incident would be low.

PHMSA's proposal expanded the applicability of MAOP reconfirmation beyond the minimum required by the congressional mandate to include pipe operating at less than 30 percent SMYS. In addition, the NPRM expanded the location criteria to include some non-HCA locations in the form of MCAs and Class 3 and Class 4 locations. As PHMSA proposed in the definitions section of the NPRM, MCAs are areas that, while not meeting the HCA criteria, include 5 or more persons or dwellings intended for human occupation or are otherwise locations where people congregate, including the right-of-ways of major roadways. See section H of this final rule for additional background on the MCA definition. The NPRM also specified that the MAOP reconfirmation process would apply only to MCA pipeline segments able to accommodate an ILI tool. This provision would not preclude an operator from choosing to conduct a pressure test, but it would avoid forcing operators to conduct a pressure test because the pipeline segment was not “piggable.”

2. Summary of Public Comment

Many stakeholders provided input on the proposed provisions in § 192.624 that require MAOP reconfirmation for pipeline segments previously excluded from testing by the grandfather clause, pipeline segments without adequate documentation to substantiate the current MAOP, and pipeline segments that have experienced a reportable in-service incident.

Regarding the first criterion above, several commenters, including INGAA, AGA, and NAPSR, generally supported the provision requiring operators of pipeline segments where the MAOP was established via the grandfather clause to reconfirm the MAOP of those segments. Several of the pipeline industry trade associations and industry entities, however, did not support the proposed application of these criteria to all grandfathered pipeline segments within HCAs, Class 3 and Class 4 locations, and Class 1 and Class 2 piggable segments within MCAs. Gas Processors Association's Midstream Association (GPA) and AGA stated that while they support the congressional mandate to conduct testing to confirm the material strength of previously untested gas transmission pipelines in HCAs that operate at a pressure above 30 percent SMYS, they oppose the proposed provisions which extend to additional pipeline segments. INGAA and Washington Gas supported the applicability of MAOP reconfirmation in MCAs for pipelines operating at greater than or equal to 30 percent SMYS but disagreed with the proposed provisions that included MCA pipelines operating at less than 30 percent SMYS.

Some citizen groups, including PST, expressed concern that the proposed changes regarding the grandfather clause did not go far enough and suggested that PHMSA should fully implement the recommendations set forth by the NTSB. They stated that PHMSA should eliminate the grandfather clause given that the proposed provisions would not include the following groups of pipelines: (1) Pipelines in non-HCA areas within Class 1 and Class 2 locations; and (2) pipeline segments for which there is an inadequate record of a hydrostatic pressure test in areas newly designated as an MCA that are not capable of being assessed by an in-line tool. Conversely, Northeast Gas Association (NGA) stated that PHMSA should retain the grandfather clause as it prevents existing, historically safe, and maintained pipelines from being subjected to unwarranted requirements.

For pipeline segments where operators do not have adequate documentation to support the current MAOP and that PHMSA proposed would be subject to the new MAOP reconfirmation requirements, some commenters stated that they support the

requirement to the extent that it is consistent with the congressional mandate to reconfirm MAOP for pipeline segments with insufficient records within Class 3 and Class 4 locations and Class 1 and Class 2 HCAs. These commenters further stated that § 192.624(a)(2) within the proposed MAOP reconfirmation requirements should be revised to clarify that it applies only to those gas transmission pipeline segments in HCAs and Class 3 and Class 4 locations that were constructed and put into operation since the adoption of the Federal Pipeline Safety Regulations in 1970, stating that otherwise § 192.624(a)(2) would apply to those pipelines put into service prior to the implementation of Federal regulations where the requirement to maintain a pressure test record does not apply. Some commenters also stated that PHMSA should revise § 192.624(a) within the proposed MAOP reconfirmation requirements to make clear that operators that have used one of the proposed allowable methods for establishing MAOP in § 192.624(b) other than the pressure test method are not required to have a pressure test record to comply with the record requirements of the section. Washington Gas asserted that the MAOP reconfirmation requirements should apply to only pipeline segments in HCAs that operate at a pressure of greater than or equal to 30 percent SMYS. Other commenters, including Xcel Energy, stated that the proposed provisions should allow operator discretion regarding what constitutes a reliable, traceable, verifiable, and complete record to determine the necessary documentation to support a pressure test record and the necessary material properties for MAOP verification. Additionally, AGA recommended the deletion of the phrase “reliable, traceable, verifiable, and complete” from the proposed MAOP reconfirmation provisions in § 192.624(a)(2). Similarly, other commenters, including INGAA, recommended omitting “reliable” from the phrase and provided a suggested definition for “traceable, verifiable, and complete.”

Lastly, with regard to the third category of applicable pipeline segments to the proposed MAOP reconfirmation requirements, many commenters either disagreed or requested clarification for the requirement that MAOP must be reconfirmed in cases where an in-service incident occurred due to a manufacturing defect listed under § 192.624(a)(1). For example, INGAA stated that an operator can evaluate such manufacturing defects more effectively through ongoing operations and maintenance activities rather than through MAOP reconfirmation, and that the defects PHMSA is concerned with are already addressed through integrity management. Similarly, Boardwalk Pipeline stated that pipelines that have experienced an in-service incident because of the listed defects in § 192.624(a)(1) should be subject to integrity management measures rather than MAOP reconfirmation. TransCanada and TPA recommended adding text to the applicability section of the MAOP reconfirmation requirements that would exclude a pipeline segment from such requirements if the operator has already acted to address the cause of the reported incident. Additionally, one commenter suggested that this requirement should apply only to pipelines in HCAs. Some commenters, including AGA and Consolidated Edison of New York (Con Ed), also requested additional time to comply with the proposed MAOP reconfirmation provisions, asserting that operators would be required to replace many of their transmission mains to comply with the new requirements because their current records would not be satisfactory. Due to the urban density and scale of the service areas of certain operators, AGA and Con Ed stated that this replacement process would take longer than the 15-year schedule provided in the rule. One commenter suggested that if the applicability criteria for pipeline segments with in-service incidents and manufacturing defects remains in the rule, it should be limited to a more contemporary time frame, such as a rolling 15-year window or those in-service incidents that have occurred since 2003. Pipeline Safety Trust, on the other hand, stated that the proposed timeframe of 15 years is too long for operators to reconfirm MAOP in HCAs and complete critical safety work, and they urged PHMSA to adopt significantly shorter timelines in the final rule.

Additionally, AGA asserted that the proposed MAOP provisions do not address how the completion plan and completion dates of the section would apply to pipelines that might experience a failure in the future and would then be subject to the proposed MAOP reconfirmation requirements, or for pipelines that are not currently located in a MCA but may be in the future. Lastly, INGAA stated that section 23 of the 2011 Pipeline Safety Act requires that PHMSA consult with the Chairman of the Federal Energy Regulatory Commission (FERC) and State regulators before establishing timeframes for the testing of previously untested pipes, and it is not evident that PHMSA has complied with this requirement.

As a general comment, several stakeholders, including AGA, Louisville Gas & Electric, New Mexico Gas Company, National Grid, NW Natural, PECO Energy, TECO Pipeline Gas, and New York State Electric and Gas (NYSEG), proposed an alternative method for MAOP reconfirmation where operators would execute two separate sets of actions that they stated could be performed simultaneously or separately. First, operators would either assess high-risk gas transmission pipelines using a pressure test or an alternative technology that is determined to be of equal effectiveness. Operators would categorize these pipelines in three tiers and schedule them for testing depending on the pipeline's SMYS and class location. Second, operators would use an ILI tool on all gas transmission pipelines, regardless of class location, that are capable of accommodating ILI tools. The ILI tool used would be qualified to find defects that would fail a subpart J pressure test. These commenters stated that this alternative methodology was necessary because the proposed provisions would create operational inefficiencies that would likely result in excessive cost and limited public benefit. In addition to providing this alternative proposal, many of these commenters provided other assorted comments on the proposed provisions.

At the GPAC meeting on March 26, 2018, the GPAC recommended that PHMSA revise the scope of the proposed MAOP reconfirmation provisions by excluding lines with previously reported incidents due to crack defects. To go along with this, the GPAC also recommended PHMSA create a new section in subpart O of part 192, the natural gas IM regulations, to address pipeline segments with crack-related incident histories. Doing these actions would eliminate the need for the proposed definitions of “modern pipe,” “legacy pipe,” and “legacy construction techniques,” and the impact of this is discussed later in this document.

The GPAC also recommended that the MAOP reconfirmation provisions be revised to apply to pipeline segments in HCAs or Class 3 or Class 4 locations that do not have traceable, verifiable, and complete records necessary to establish MAOP under § 192.619. Previously, the provisions were applicable to those pipeline segments without traceable, verifiable, and complete subpart J pressure test records. Similarly, the GPAC recommended that the MAOP

reconfirmation provisions only apply to grandfathered pipelines in HCAs, Class 3 or Class 4 locations, or MCAs able to accommodate inspection with ILI tools, and that have MAOPs producing a hoop stress greater than or equal to 30 percent SMYS. In the NPRM, the provisions applied to all grandfathered pipelines in those locations regardless of SMYS. In making this recommendation, the GPAC also suggested PHMSA review the costs and benefits of applying the MAOP reconfirmation provisions to non-HCA Class 3 and Class 4 grandfathered pipe with MAOPs less than 30 percent SMYS.

During the meeting on March 27, 2018, the GPAC also recommended revisions to other sections related to the applicability of MAOP reconfirmation provisions, including withdrawing the proposed revisions to § 192.503, which tied general requirements of the subpart J pressure test to alternative MAOP and MAOP reconfirmation provisions, and withdrawing the proposed revisions to § 192.605(b)(5), which cross-referenced several sections related to the MAOP reconfirmation requirements to the requirements regarding an operator's procedural manuals.

The GPAC also examined the provisions related to the completion date of these actions and recommended that PHMSA revise the appropriate paragraph to account for pipelines that may be subject to these requirements in the future, such as for pipelines that are not in an HCA or Class 3 or Class 4 location now, but due to population growth or development may be in such a location in the future. More specifically, the GPAC recommended that an operator would have to complete all actions required by the MAOP reconfirmation provisions on 100 percent of their pipelines that meet the applicability requirements by 15 years after the effective date of the rule or as soon as practicable but no later than 4 years after the pipeline segment first meets the applicability conditions, whichever is later. The GPAC also recommended PHMSA consider a waiver or no-objection procedure if operators cannot meet the requirements within 4 years under this scenario.

3. PHMSA Response

PHMSA appreciates the information provided by the commenters regarding the applicability of MAOP reconfirmation. After considering these comments and as recommended by the GPAC input, PHMSA is modifying the rule to address many of these comments.

Regarding the applicability of the new MAOP reconfirmation requirements at § 192.624, PHMSA notes that a simplistic repeal of the “grandfather clause” at § 192.619(c) is not practical because it applies to gathering and distribution lines. As the proposed rule was primarily focused on the safety of gas transmission pipelines, a broad repeal of the grandfather clause was not contemplated in the proposed rule. Further, a major expansion of the MAOP reconfirmation requirements beyond the scope of the congressional mandate in the 2011 Pipeline Safety Act would be costly, and the GPAC noted at the meeting on March 26, 2018, that there may be cost-benefit concerns to test all grandfathered pipelines. The GPAC recommended PHMSA analyze requiring operators to reconfirm the MAOP of all grandfathered lines, and PHMSA considered this as an alternative in the RIA.

See section 5.9.1 of the RIA for further details.

In response to the comments received and the recommendations of the GPAC, PHMSA is modifying the applicability of the MAOP reconfirmation requirements as follows: (1) The applicability related to pipeline segments with past in-service incidents is being eliminated. As commenters mentioned, operational failures are already addressed within integrity management and other subparts of part 192. Section 192.617, for example, would require an operator of a gas transmission line that had an in-service incident caused by an incorrect MAOP to determine the proper MAOP of the segment before placing it back into service. Causes of in-service failures are also already incorporated into the risk analyses required by the current IM regulations. If the cause of an incident is an incorrect MAOP, for example, then operators would be required to reconfirm it following the incident within their IM program. However, PHMSA is adding a new paragraph to strengthen the IM requirements at § 192.917(e)(6) to specifically include actions operators must take to address pipeline segments susceptible to cracks and crack-like defects. (2) PHMSA is also modifying the applicability of these requirements by specifying the MAOP reconfirmation requirements are applicable to pipeline segments that do not have the pipeline physical properties and attributes needed to establish MAOP documented in traceable, verifiable, and complete records, specifically those records required to establish and substantiate the MAOP in accordance with § 192.619(a), including those records required under § 192.517(a). More specifically, these requirements to verify MAOP would apply to such pipelines without traceable, verifiable, and complete records in HCAs and Class 3 and Class 4 locations as specified in the congressional mandate. Further, PHMSA is dropping the word “reliable” from the applicability section of the regulatory text to be consistent with previous PHMSA advisory bulletins on this topic.

(3) PHMSA is modifying the applicability of the MAOP reconfirmation provisions for “grandfathered” pipeline segments to pipelines with an MAOP greater than or equal to 30 percent of SMYS, as specified in the congressional mandate. In addition to these requirements applying to grandfathered pipelines in HCAs, PHMSA is retaining the MAOP reconfirmation applicability requirement for grandfathered pipeline segments in Class 3 and Class 4 locations and in piggable MCAs to address the NTSB recommendation on this topic. As per the committee's suggestion, PHMSA analyzed whether it would be feasible to make the MAOP reconfirmation requirements applicable to non-HCA Class 3 and Class 4 pipe operating below 30 percent SMYS. This analysis is presented as an alternative in the RIA for this rulemaking. Ultimately, PHMSA did not choose to include these categories of pipelines in the scope for the applicability of the MAOP reconfirmation requirements because the GPAC recommended it was cost-effective for the provision to only apply to pipe operating above 30 percent SMYS in Class 3 and 4 locations and because those pipelines present the greatest risk to safety.

Pipeline Safety: Verification of Records; 77 FR 26822; May 7, 2012;

https://www.govinfo.gov/content/FR-2012-05-07/pdf/2012-10866.pdf

With respect to the completion date, PHMSA acknowledges the comments received stating that pipeline segments could meet applicability criteria at some point in the future such that it would be difficult or impossible to meet the 15-year deadline for completion. Therefore, PHMSA agrees with the GPAC recommendation discussed above and is modifying the requirements in this final rule to include an alternative completion deadline of 4 years for pipeline segments that meet the applicability standards at some point in the future, for example for those pipeline segments that were in non-HCA locations that later become HCA locations. However, PHMSA emphasizes that this 4-year timeframe does not supersede, invalidate, or otherwise modify the existing requirements in § 192.611 for operators to confirm or revise the MAOP of

segments within 24 months of a change in class location.

PHMSA also acknowledges that some commenters thought the 15-year compliance timeframe for MAOP reconfirmation was too long. PHMSA believes a 15-year timeframe is necessary to be consistent with § 192.939, which allows operators to use a confirmatory direct assessment to confirm their MAOP in two, 7-year inspection cycles. This timeframe was discussed by the GPAC and was approved by unanimous vote. PHMSA will note that operators are required to have 50 percent of the applicable mileage completed within 8 years of the effective date of the rule. PHMSA would expect operators to prioritize and reconfirm the MAOP of the highest-risk segments first.

PHMSA is also withdrawing miscellaneous revisions to § 192.503, which tied general requirements of the subpart J pressure test to alternative MAOP and MAOP reconfirmation provisions, and miscellaneous revisions from § 192.605(b)(5), which cross-referenced several sections related to MAOP requirements to the requirements regarding an operator's procedural manuals. These changes were made to simplify the regulations.

Additionally, because PHMSA has eliminated pipeline segments with past in-service incident history from the scope of the MAOP reconfirmation requirements, PHMSA is striking the proposed references within the MAOP reconfirmation requirements to the alternative MAOP requirements at § 192.620(a)(ii). Operators who used the alternative requirements to establish the MAOP of their pipelines were required to have complete documentation

and therefore would not be subject to the MAOP reconfirmation requirements. If an operator had previously established the MAOP of a pipeline segment under the alternative MAOP requirements, but has since lost the records necessary to validate the alternative, they would have to reconfirm MAOP using the alternative MAOP requirements, or apply for a special permit to continue operation.

“Pipeline Safety: Standards for Increasing the Maximum Allowable Operating Pressure for Gas Transmission Pipelines; Final Rule;” October 17, 2008; 73 FR 62148. The effective date of the rule was November 17, 2008.

Per the requirement in section 23 of the 2011 Pipeline Safety Act, PHMSA consulted with members of FERC and State regulators, including representatives from NAPSR and the National Association of Regulatory Utility Commissioners, as appropriate, to establish the timeframes for completing MAOP reconfirmation. As a part of this consultation, which occurred as a function of the GPAC meetings from 2017 through 2018, PHMSA accounted for potential consequences to public safety and the environment while also accounting for minimal costs and service disruptions. These representatives provided both input and positive votes that the provisions surrounding MAOP reconfirmation were technically feasible, reasonable, cost-effective, and practicable if certain changes were made. As previously discussed, PHMSA has taken the GPAC's input into consideration when drafting this final rule and made the according changes to the provisions.

B. MAOP Reconfirmation—§§ 192.624 & 192.632

ii.—Methods

In developing regulations to reconfirm MAOP where necessary, Congress mandated that PHMSA consider safety testing methodologies that include pressure testing and other alternative methods, including in-line inspections, determined to be of equal or greater effectiveness. The NTSB recommended an expansive pressure test approach to address the safety issues identified in their investigation of the PG&E incident through recommendations P-11-14 and P-11-15. In response to the congressional mandate, PHMSA evaluated other methodologies and identified five additional methods that could provide an equivalent or greater level of safety. Therefore, PHMSA proposed to allow the following six methods for MAOP reconfirmation, including the conventional pressure test method.

Summary of PHMSA's Proposal: Method 1—Pressure Test

A pressure test is the most conventional assessment method by which an operator may reconfirm a pipeline segment's MAOP. PHMSA proposed standards for conducting pressure tests for MAOP reconfirmation in part to meet the intent of NTSB recommendations P-11-14 and P-11-15. First, PHMSA proposed minimum test pressure standards where a pipeline segment's MAOP would be equal to the test pressure divided by the greater of either 1.25 or the applicable class location factor. Second, if the pipeline segment might be susceptible to cracks or crack-like defects,

then the operator must incorporate a spike pressure feature into the pressure test procedure. PHMSA proposed standards for the spike hydrostatic test in § 192.506. If the operator has reason to believe any pipeline segment may be susceptible to cracks or crack-like defects, the operator would be required to also estimate the remaining life of the pipeline in accordance with the same standards specified in Method 3, the engineering critical assessment method.

These pipelines can include pipelines constructed with “legacy pipe” or using “legacy construction techniques;” pipelines with evidence or risk of stress corrosion cracking or girth weld cracks; or pipelines that have experienced an incident due to an original manufacturing-related defects, construction-related defects, installation-related defects, or fabrication-related defects.

Summary of Public Comment: Method 1—Pressure Test

Several commenters opposed the proposed provisions requiring a spike test to be conducted as part of the pressure test for the purposes of MAOP reconfirmation, and these comments are discussed further under the “spike test” portion of the proposal and comment summary of this rulemaking.

API suggested that a pipeline segment's MAOP can be best established through performing a combination of pressure tests and ILI examinations, and they discussed how operators could conduct hydrostatic pressure testing to determine the in-place yield strength of a segment of pipeline by conducting a “spike” test pressure held for a few minutes followed by a subpart J pressure test approximately 10 percent below the spike level. API further stated that using ILI tools in conjunction with this method would further substantiate the results, as geometry ILI tools capable of measuring inside diameter to detect yielding could further substantiate and quantify the results of the pressure test.

AGA stated that while they believe that pressure testing is a straightforward and well-established method, the proposed Method 1 MAOP reconfirmation requirements are unnecessarily complex. AGA further stated that subpart J provides different requirements and specifications for pressure tests based on the type of pipe being tested, and that Method 1 should refer to subpart J rather than to § 192.505(c) specifically, which requires unnecessarily stringent requirements. PG&E supported the proposed provisions and committed to pressure testing all pipes.

INGAA stated that since the basic strength properties of steel pipe do not change over time, PHMSA should not limit allowable tests to only those conducted after July 1, 1965, as was proposed in § 192.619(a)(2)(ii). They emphasized that the test parameters, not

the test date, should be considered for MAOP reconfirmation. Further, INGAA stated that recognizing the validity of earlier tests would not necessarily mean that no further pressure tests would be conducted, as periodic testing may be required to ensure the continued integrity of the pipeline segment under the operator's integrity management program. However, such additional tests are managed under IM, which is separate from MAOP reconfirmation.

Certain commenters stated that a spike test is not required to establish an adequate margin of safety for MAOP reconfirmation and suggested PHMSA eliminate spike testing from the pressure test method of MAOP reconfirmation.

Regarding the proposed definitions of “legacy pipe” and “legacy construction,” AGA and Xcel Energy commented that as proposed, the definitions could be interpreted to apply to distribution pipelines as well as gas transmission pipelines. Commenters requested that PHMSA explicitly exclude distribution pipelines from these definitions, which would be applicable to all part 192.

On March 26, 2018, the GPAC recommended that PHMSA delete the spike test requirements from the pressure test method of MAOP reconfirmation. The GPAC also recommended that PHMSA require operators to perform a pressure test in accordance with subpart J of part 192 rather than refer to specific requirements in § 192.505. Further, and as discussed during the meetings of December 2017 and March 26, 2018, if the applicable pressure test segment does not have traceable, verifiable, and complete MAOP records, the operator must use the best available information upon which the MAOP is currently based to conduct the pressure test. The GPAC recommended PHMSA create a requirement for the operator of such a pipeline segment to add the test segment to its plan for opportunistically verifying material properties in accordance with the material properties verification provisions. During the meeting, PHMSA noted that most pressure tests would present at least two opportunities for material properties verification at the test manifolds.

PHMSA Response: Method 1—Pressure Test

PHMSA appreciates the information provided by the commenters regarding the pressure test method of MAOP reconfirmation (Method 1). After considering these comments and as recommended by the GPAC, PHMSA is eliminating the spike testing requirement as part of the pressure test method of MAOP reconfirmation. As commenters stated, spike testing is primarily used for the mitigation of cracks and crack-like defects, and PHMSA has determined it would therefore be more appropriate to be placed within the context of threat management under IM. Additionally, PHMSA is removing the definitions for and related references to “legacy pipe” and “legacy construction” in this final rule because the applicability to pipe with “legacy pipe or construction” leaks or failures was dropped from the applicability criteria for MAOP reconfirmation. PHMSA also modified the rule to refer to subpart J pressure tests rather than paragraph § 192.505(c), specifically, and to recognize the validity of earlier pressure tests. Lastly, if an operator does not have traceable, verifiable, and complete records for the material properties needed to establish MAOP by pressure testing, PHMSA is requiring that operators test, in accordance with the material verification requirements, the pipe materials cut out from the test manifold sites at the time the pressure test is conducted. Further, if there is a failure during the pressure test, the operator must test any removed pipe from the pressure test failure in accordance with the material properties verification requirements to ensure that the segment of pipe is consistent with operator's sampling program established under § 192.607. This will avoid issues where operators may not have the documented and verified physical pipeline material properties and attributes that would otherwise be necessary to perform a hydrostatic pressure test to reconfirm MAOP.

Summary of Proposal: Method 2—Pressure Reduction

In the NPRM, PHMSA proposed that pipeline operators could choose to reduce the MAOP of the applicable pipeline segment to reconfirm the segment's MAOP. This approach would use the recent operating pressure as a

de facto

pressure test, and then an operator would set the pipeline segment's MAOP at a slightly lower pressure. PHMSA proposed that operators using this method set the pipeline's MAOP to no greater than the highest actual operating pressure sustained by the pipeline during the 18 months preceding the effective date of the final rule divided by the greater of either 1.25 or the applicable class location, which are the same safety factors as used for the pressure testing in Method 1. PHMSA included standards for establishing the highest actual sustained pressure for the purposes of reconfirming MAOP under this method and included standards for addressing class location changes. Additionally, PHMSA proposed that, if the operator has reason to believe any pipeline segment contains or may be susceptible to cracks or crack-like defects, the operator would be required to estimate the remaining life of the pipeline.

Summary of Public Comment: Method 2—Pressure Reduction

AGA commented that the 18-month look-back time frame listed in the pressure reduction MAOP reconfirmation method is a much too narrow time frame for consideration and that the section should be rewritten to clarify that the pressure reduction should be taken from either (1) the immediate past 18 months, or (2) 5 years from the time the last pressure reduction was taken, stating that tying the baseline pressure to the effective date of the rule is arbitrary. Enterprise Products recommended that PHMSA clarify the derating criteria used for pipes that use this method of reconfirming MAOP. Further, Piedmont expressed concern that this method does not account for the actual gap that can occur between MAOP and operating pressure. Some commenters questioned whether the MAOP from which to take a pressure reduction was based on the most recent pressure test or the historical highest-pressure test, and some commenters suggested PHMSA revise this provision to allow operators to reconfirm the MAOP based on the existing MAOP and not using an 18-month look-back period unless an incident caused by a material-related or construction-related defect has occurred on the pipeline since its last subpart J pressure test.

TPA stated that using this method unfairly penalizes operators in situations where the operator has prepared for future needs and has not operated at MAOP for a period greater than 18 months. Similarly, another commenter suggested that operators who have already reduced MAOP on pipeline segments to be proactive should not be penalized by having to take an additional reduction in MAOP.

Some commenters recommended limiting the applicability of this method to those pipelines operating at 30 percent SMYS or greater.

Regarding the pressure reduction method for MAOP reconfirmation, the GPAC recommended PHMSA increase the look-back period from 18 months to 5 years and remove the requirements for operators selecting to take the pressure reduction to reconfirm MAOP to

perform fracture mechanics analysis on those pipeline segments.

PHMSA Response: Method 2—Pressure Reduction

PHMSA appreciates the information provided by the commenters regarding the pressure reduction method of MAOP reconfirmation (Method 2). After considering these comments and as recommended by the GPAC, PHMSA is increasing the look-back period to 5 years from the publication date of the rule and is removing the requirements for operators to perform fracture mechanics analysis on those pipeline segments where the operator has selected Method 2. PHMSA made this change because the 5-year look-back period is consistent with IM requirements regarding MAOP confirmation.

Summary of PHMSA's Proposal: Method 3—Engineering Critical Assessment

Method 3 directly addresses the congressional mandate for PHMSA to consider safety testing methodologies that include other alternative methods, including ILI, determined to be of equal or greater effectiveness. Demonstrating that knowledge gained from an ILI assessment provides an equivalent level of safety as a pressure test is technically challenging. PHMSA used best safety practices gained from implementation of integrity management since 2003; development of class location special permits; and technical research on related topics, such as analysis of crack defects and seam defects. PHMSA applied these principles and analytical methods to develop an engineering critical assessment (ECA) methodology, which applies state-of-the-art fracture mechanics analysis to analyze defects in the pipe and determine if those defects would or would not survive a hydrostatic pressure test at the test pressure needed to establish MAOP. In addition, PHMSA proposed that if the operator has reason to believe any pipeline segment contains or may be susceptible to cracks or crack-like defects, the operator would be required to estimate the remaining life of the pipeline using the fracture mechanics standards PHMSA specified.

Summary of Public Comment: Method 3—Engineering Critical Assessment

Several trade associations and pipeline industry entities stated that ILI is the best and most practical method for MAOP reconfirmation due to its cost-effectiveness and environmentally friendly nature, and that PHMSA should allow operators to use ILI as a reconfirmation method. These commenters, however, also stated that the requirements proposed for the usage of ILI with an ECA are overly complicated and burdensome, and they specifically recommended that the final rule should be simplified so that this method will play a greater role in MAOP reconfirmation in lieu of a pressure test. For example, INGAA asserted that PHMSA should remove the requirements in the ECA related to operations, maintenance, and integrity management, arguing that these requirements do not factor into MAOP reconfirmation and would be covered elsewhere in part 192. Further, INGAA proposed additional alternatives for using the ECA method to obtain necessary data for MAOP reconfirmation, asserting that these alternatives would be less burdensome and equally effective. More specifically, INGAA suggested removing duplicate regulatory language, removing the pre-approval process for ILI, and adding unity plots as a method for operators to demonstrate that ILI is reliable for identifying and sizing actionable anomalies. TransCanada and PECO Energy Co. stated that for the ECA method to be used by industry, the detailed requirements listed under this method in the proposed rule should be replaced with the use of standard ECA best practices.

Some commenters suggested that operators have long relied on sound engineering judgments and conservative assumptions to account for record gaps. Commenters stated that, if stripped of the ability to use sound engineering judgment and conservative assumptions, operators would need to substantially invest in processes, procedures, tests, and project engineering and support to develop and implement a comprehensive material properties verification plan as outlined in the proposed regulations. Another commenter asked for clarification on using assumptions of Grade A pipe (30,000 psi) versus the use of 24,000 psi as noted in § 192.107(b)(2) if the SMYS or actual material yield strength and ultimate tensile strength is unknown or is not documented in traceable, verifiable, and complete records.

Another commenter suggested that in cases where a pipeline has been pressure tested, but not to the level of 1.25 times MAOP, PHMSA should allow operators to augment the origina

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