[Federal Register Volume 84, Number 190 (Tuesday, October 1, 2019)]
[Rules and Regulations]
[Pages 52180-52257]
[FR Doc No: 2019-20306]

Vol. 84

Tuesday,

No. 190

October 1, 2019

Part II

Department of Transportation

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Pipeline and Hazardous Materials Safety Administration

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49 CFR Parts 191 and 192

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

Federal Register / Vol. 84 , No. 190 / Tuesday, October 1, 2019 /
Rules and Regulations

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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.

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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<PHONE_NUMBER>. 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--
Sec.  192.607
    i. Applicability
    ii. Method
    B. MAOP Reconfirmation--Sec. Sec.  192.624, 192.632
    i. Applicability
    ii. Methods
    iii. Spike Test--Sec.  192.506
    iv. Fracture Mechanics--Sec.  192.712
    v. Legacy Construction Techniques/Legacy Pipe
    C. Seismicity and Other Integrity Management Clarifications--
Sec.  192.917
    D. 6-Month Grace Period for 7-Calendar-Year Reassessment
Intervals--Sec.  192.939
    E. ILI Launcher and Receiver Safety--Sec.  192.750
    F. MAOP Exceedance Reporting--Sec. Sec.  191.23, 191.25
    G. Strengthening Assessment Requirements--Sec. Sec.  192.150,
192.493, 192.921, 192.937, Appendix F
    i. Industry Standards for ILI--Sec. Sec.  192.150, 192.493
    ii. Expand Assessment Methods Allowed for IM--Sec. Sec.
192.921(a) and 192.937(c)
    iii. Guided Wave Ultrasonic Testing--Appendix F
    H. Assessing Areas Outside of HCAs--Sec. Sec.  192.3, 192.710
    i. MCA Definition--Sec.  192.3
    ii. Non-HCA Assessments--Sec.  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.\1\ A third rulemaking is
expected to address requirements related to gas gathering lines that
were proposed in the NPRM.\2\
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    \1\ RIN 2137-AF39.
    \2\ RIN 2137-AF38.
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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.\3\
Another requirement is that operators explicitly consider and account
for seismicity in identifying and evaluating potential threats.\4\ 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.
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    \3\ 2011 Pipeline Safety Act Sec.  5(e).
    \4\ 2011 Pipeline Safety Act Sec.  29.
    \5\ 2011 Pipeline Safety Act Sec.  23.
    \6\ MAOP means the maximum pressure at which a pipeline or
segment of a pipeline may be operated under this part.
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    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.\7\ 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),\8\ 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.
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    \7\ 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 Sec.  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.
    \8\ 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.
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    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) \9\ 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.
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    \9\ A MCA is defined in Sec.  191.3 as an onshore area within a
potential impact circle, as that term is defined in Sec.  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.
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    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]
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                                                  Annualized cost
                                         -------------------------------
                Provision                   3% Discount     7% Discount
                                               rate            rate
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1. MAOP Reconfirmation & Material                $25,848         $27,899
 Properties Verification................
2. Seismicity...........................            0.00            0.00
3. Six-Month Grace Period for Seven                 0.00            0.00
 Calendar-Year Reassessment Intervals...
4. In-Line Inspection Launcher/Receiver             27.4            37.5
 Safety.................................
5. MAOP Exceedance Reports..............            0.00            0.00
6. Strengthening requirements for                   0.00            0.00
 assessment methods.....................
7. Assessments outside HCAs.............           5,482           4,713
8. Related Records Provisions...........            0.00            0.00
                                         -------------------------------
    Total...............................          31,357          32,650
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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.\10\
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    \10\ 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 Sec.  192.903.
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    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 \11\ 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.
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    \11\ HCAs are defined at Sec.  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.
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    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.\12\ 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.\13\
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    \12\ U.S. Department of Energy, ``Appendix B: Natural Gas,''
Quadrennial Energy Review Report: Energy Transmission, Storage, and
Distribution Infrastructure, p. NG-28, April 2015.
    \13\ U.S. DOT Pipeline and Hazardous Materials Safety
Administration Data as of 4/26/2018.
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    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 \14\ and codified in the
PSR for jurisdictional \15\ gas gathering, transmission, and
distribution systems.
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    \14\ Title 49, United States Code, Subtitle VIII, Pipelines,
Sections 60101, et. seq.
    \15\ Typically, onshore pipelines involved in the
``transportation of gas''--see 49 CFR 192.1 and 192.3 for detailed
applicability.
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    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.\16\ 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.
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    \16\ ``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).
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    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.\17\ 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.
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    \17\ 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.
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    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.\18\ 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.
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    \18\ 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.).
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    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.\19\ 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.
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    \19\ 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.
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    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.\20\ 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 \21\ and improvements to a long-existing
industrial technique--hydraulic fracturing,\22\ 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.
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    \20\ 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.
    \21\ Directional drilling is the practice of drilling non-
vertical wells.
    \22\ The extraction of oil or gas deposits performed by forcing
open fissures in subterranean rocks by introducing liquid at high
pressures.
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    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,\25\ and natural gas production is projected to grow from the
2015 levels of 66.5 Bcf/d to more than 93.5 Bcf/d.\26\
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    \23\ 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.
    \24\ 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.
    \25\ U.S. Department of Energy, ``Appendix B: Natural Gas,''
Quadrennial Energy Review Report: Energy Transmission, Storage, and
Distribution Infrastructure, p. NG-28, April 2015.
    \26\ Id., at NG-6.
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Demand Changes
    The increase in domestic natural gas production has led to lower
average natural gas prices.\27\ In 2004, the outlook for natural gas
production and demand growth was weak. Monthly average spot prices at
Henry Hub \28\ 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.\29\ 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.\30\
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    \27\ Id., at NG-11.
    \28\ 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).
    \29\ Energy Information Administration, Natural Gas Spot and
Futures Prices, http://www.eia.gov/dnav/ng/ng_pri_fut_s1_m.htm,
retrieved August 2018.
    \30\ U.S. Department of Energy, ``Appendix B: Natural Gas,''
Quadrennial Energy Review Report: Energy Transmission, Storage, and
Distribution Infrastructure, p. NG-11, April 2015.
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    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.\31\ 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.
---------------------------------------------------------------------------

    \31\ 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.\32\ 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.
---------------------------------------------------------------------------

    \32\ 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.\33\ 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.
---------------------------------------------------------------------------

    \33\ 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.\34\
---------------------------------------------------------------------------

    \34\ 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 \35\ and NPRM
\36\ indicate that ILI and spike hydrostatic pressure testing \37\ 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.\38\ ILI testing can obtain data
along a pipeline not otherwise obtainable via other assessment methods,
although this method also has certain limitations.\39\
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    \35\ ``Pipeline Safety: Safety of Gas Transmission Pipelines--
Advanced Notice of Proposed Rulemaking,'' 76 FR 5308; August 25,
2011.
    \36\ ``Pipeline Safety: Safety of Gas Transmission and Gathering
Pipelines,'' 81 FR 20722; April 8, 2016.
    \37\ 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.
    \38\ 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.
    \39\ 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 \40\--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.
---------------------------------------------------------------------------

    \40\ 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.\41\ 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.\42\
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    \41\ 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.
    \42\ ``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.\43\ 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.
---------------------------------------------------------------------------

    \43\ 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,\44\ 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.\45\ In a later NPRM,\46\ 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.\47\ 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.\48\
---------------------------------------------------------------------------

    \44\ ``Pipeline Safety: High Consequence Areas for Gas
Transmission Pipelines,'' Final rule, 67 FR 50824; August 6, 2002.
    \45\ 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.
    \46\ ``Pipeline Safety: Pipeline Integrity Management in High
Consequence Areas (Gas Transmission Pipelines),'' Notice of Proposed
Rulemaking, 68 FR 4278; January 28, 2003.
    \47\ HCA and PIR definitions are in 49 CFR 192.903.
    \48\ ``Pipeline Safety: Pipeline Integrity Management in High
Consequence Areas (Gas Transmission Pipelines),'' Final rule, 68 FR
69778; December 15, 2003.
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    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 \49\ 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.
---------------------------------------------------------------------------

    \49\ 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,'' \50\ 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.
---------------------------------------------------------------------------

    \50\ 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.\51\
---------------------------------------------------------------------------

    \51\ 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,\52\ 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\ 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 \53\ that ``there are thousands of miles of
jurisdictional interstate pipelines installed prior to 1952,\54\ 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].'' \55\ 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.''
\58\
---------------------------------------------------------------------------

    \53\ The predecessor of the Federal Energy Regulatory
Commission.
    \54\ 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.
    \55\ ``Transportation of Natural and Other Gas by Pipeline:
Minimum Federal Safety Standards,'' 35 FR 13248; August 19, 1970.
    \56\ 35 FR 13248.
    \57\ This requirement is currently under Sec.  192.619(c).
    \58\ 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.'' \59\ 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.\60\
---------------------------------------------------------------------------

    \59\ ``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.
    \60\ 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).\61\ 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.
---------------------------------------------------------------------------

    \61\ https://www.regulations.gov/document?D=PHMSA-2011-0023-0118.
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    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.\62\ 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.
---------------------------------------------------------------------------

    \62\ 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.\63\
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.
---------------------------------------------------------------------------

    \63\ 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--Sec.
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 Sec.  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
Sec.  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 Sec.  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 Sec.
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
Sec.  192.607 and the MAOP reconfirmation requirements in Sec.
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 Sec.  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
Sec.  192.107(b)(1). Xcel Energy also stated that if an operator has
previously established MAOP as per the Sec.  192.619(a)(2) strength
test requirements or will do so per the proposed Sec.  192.624
methodology for pressure test or pressure reduction, the verification
of pipeline material proposed in Sec.  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 Sec. Sec.
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 Sec.  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 Sec.  192.7.
    PHMSA did not intend that the requirements proposed in Sec.
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 Sec.  192.607 are not
retroactive \64\ and apply only to transmission lines. However, PHMSA
believes that operators with IM programs that are properly following
subpart O, specifically Sec.  192.917(b), should already have this pipe
information.
---------------------------------------------------------------------------

    \64\ The material properties verification requirements are not
retroactive as they mandate the creation and retention of records as
operators execute the methodology in Sec.  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 Sec.  192.607. After
the effective date of the rule, operators with missing or inadequate
records must follow the verification methodology in Sec.  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--Sec.
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 Sec.  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 (Sec.  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
Sec.  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 Sec.  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 Sec.  192.18.
Operators may use an alternative sampling program 91 days after
submitting a notification per Sec.  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
Sec.  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 Sec.  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 Sec.  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 Sec.  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 Sec.  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--Sec. Sec.  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: